10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

OR

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

For the transition period from                     to                     .

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

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

Registrant	Title of Each Class	Name of Each Exchange on Which Registered
UNS Energy Corporation	Common Stock, no par value	New York Stock Exchange

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

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

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 (Exchange Act).

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

UNS Energy Corporation	Large Accelerated Filer	x	Accelerated Filer	¨
	Non-accelerated Filer	¨	Smaller Reporting Company	¨

Tucson Electric Power Company	Large Accelerated Filer	¨	Accelerated Filer	¨
	Non-accelerated Filer	x	Smaller Reporting Company	¨

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

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

The aggregate market value of UNS Energy Corporation voting Common Stock held by non-affiliates of the registrant was $1,855,552,035 based on the last reported sale price thereof on the consolidated tape on June 30, 2013.

As of February 14, 2014, 41,633,535 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of February 14, 2014, Tucson Electric Power Company had 32,139,434 shares of common stock outstanding, no par value, all of which were held by UNS Energy Corporation.

Tucson Electric Power Company meets the conditions set forth in General Instructions (I)(1)(a) and (b) on Form 10-K and is therefore filing this report with the reduced disclosure format.

Documents incorporated by reference: Specified portions of UNS Energy Corporation’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders are incorporated by reference into Part III.

ii

Table of Contents

Definitions	v
PART I
Item 1. – Business	K-1
Overview of Consolidated Business	K-1
Tucson Electric Power Company	K-3
UNS Electric	K-16
UNS Gas	K-18
Employees	K-20
Executive Officers of the Registrants	K-20
SEC Reports Available on UNS Energy’s Website	K-21
Item 1A. – Risk Factors	K-22
Item 1B. – Unresolved Staff Comments	K-27
Item 2. – Properties	K-27
Item 3. – Legal Proceedings	K-28
Item 4. – Mine Safety Disclosures	K-29
PART II
Item  5. – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Common Equity	K-30
Item 6. – Selected Financial Data	K-32
Item  7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations	K-34
UNS Energy Consolidated	K-34
Tucson Electric Power Company	K-41
UNS Electric	K-55
UNS Gas	K-59
Critical Accounting Policies	K-63
Recently Issued Accounting Pronouncements	K-66
Safe Harbor for Forward-Looking Statements	K-67
Item 7A. – Quantitative and Qualitative Disclosures about Market Risk	K-67
Item 8. – Consolidated Financial Statements and Supplementary Data	K-72
Management’s Reports on Internal Controls Over Financial Reporting	K-72
Reports of Independent Registered Public Accounting Firm	K-73
UNS Energy Corporation
Consolidated Statements of Income	K-75
Consolidated Statements of Comprehensive Income	K-76
Consolidated Statements of Cash Flows	K-77
Consolidated Balance Sheets	K-78
Consolidated Statements of Capitalization	K-80
Consolidated Statements of Changes in Stockholders’ Equity	K-81
Tucson Electric Power Company
Consolidated Statements of Income	K-82
Consolidated Statements of Comprehensive Income	K-83
Consolidated Statements of Cash Flows	K-84
Consolidated Balance Sheets	K-85
Consolidated Statements of Capitalization	K-87

iii

Consolidated Statements of Changes in Stockholder’s Equity	K-88
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies	K-89
Note 2. Pending Merger with Fortis	K-95
Note 3. Regulatory Matters	K-95
Note 4. Business Segments	K-101
Note 5. Utility Plant and Jointly-Owned Facilities	K-102
Note 6. Debt, Credit Facilities, and Capital Lease Obligations	K-105
Note 7. Commitments, Contingencies, and Environmental Matters	K-109
Note 8. Potential Purchase of Gas-Fired Generation Plant	K-114
Note 9. Income Taxes	K-114
Note 10. Employee Benefit Plans	K-118
Note 11. Share-Based Compensation Plans	K-125
Note 12. UNS Energy Earnings Per Share	K-127
Note 13. Stockholders’ Equity	K-128
Note 14. Supplemental Cash Flow Information	K-129
Note 15. Fair Value Measurements and Derivative Instruments	K-131
Note 16. Changes in Accumulated Other Comprehensive Income by Component	K-136
Note 17. Recently Issued Accounting Pronouncements	K-137
Note 18. Quarterly Financial Data (Unaudited)	K-137
Schedule II – Valuation and Qualifying Accounts	K-139
Item 9. – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	K-140
Item 9A. – Controls and Procedures	K-140
Item 9B. – Other Information	K-140
PART III
Item 10. – Directors, Executive Officers and Corporate Governance of the Registrants	K-141
Item 11. – Executive Compensation	K-143
Item  12. – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	K-143
Item 13. – Certain Relationships and Related Transactions and Director Independence	K-144
Item 14. – Principal Accountant Fees and Services	K-144
PART IV
Item 15. – Exhibits and Financial Statement Schedule	K-146
Signatures	K-147
Exhibit Index	K-150

iv

DEFINITIONS

The abbreviations and acronyms used in the 2013 Form 10-K are defined below:

ACC	Arizona Corporation Commission
APS	Arizona Public Service Company
BART	Best Available Retrofit Technology
Base O&M	A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business
Base Rates	The portion of TEP’s and UNS Electric’s Retail Rates attributed to generation, transmission, distribution costs, and customer charge; and UNS Gas’ delivery costs and customer charge. Base Rates exclude costs that are passed through to customers for fuel and purchased energy costs
Btu	British thermal unit(s)
Cooling Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DSM	Demand Side Management
ECA	Environmental Compliance Adjustor
Entegra	a subsidiary of Entegra Power Group LLC
FERC	Federal Energy Regulatory Commission
FVRB	Fair Value Rate Base
Fortis	FortisUS, Inc., a Delaware corporation whose ultimate parent company is Fortis Parent
Fortis Parent	Fortis, Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada
Four Corners	Four Corners Generating Station
GBtu	Billion British thermal units
GWh	Gigawatt-hour(s)
Gila River Unit 3	Unit 3 of the Gila River Generating Station
Heating Degree Days	An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65
kV	Kilo-volt
kWh	Kilowatt-hour(s)
LFCR	Lost Fixed Cost Recovery Mechanism
Millennium	Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation
MMBtu	Million British thermal units
MW	Megawatt(s)
MWh	Megawatt-hour(s)
Navajo	Navajo Generating Station
NTUA	Navajo Tribal Utility Authority
OATT	Open Access Transmission Tariff
OCRB	Original Cost Rate Base
PGA	Purchased Gas Adjustor, a Retail Rate mechanism designed to recover the cost of gas purchased for retail gas customers
PNM	Public Service Company of New Mexico
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
REC	Renewable Energy Credit
RES	Renewable Energy Standard
Regional Haze Rules	Rules promulgated by the EPA to improve visibility at national parks and wilderness areas

v

Retail Rates	Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service
San Juan	San Juan Generating Station
SCR	Selective Catalytic Reduction
SJCC	San Juan Coal Company
SNCR	Selective Non-Catalytic Reduction
Springerville	Springerville Generating Station
Springerville Coal Handling Facilities Leases	Coal handling facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities	Facilities at Springerville used in common by all four Springerville units
Springerville Common Facilities Leases	Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1	Unit 1 of the Springerville Generating Station
Springerville Unit 1 Leases	Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 2	Unit 2 of the Springerville Generating Station
Springerville Unit 3	Unit 3 of the Springerville Generating Station
Springerville Unit 4	Unit 4 of the Springerville Generating Station
SRP	Salt River Project Agricultural Improvement and Power District
Sundt	H. Wilson Sundt Generating Station
Sundt Unit 4	Unit 4 of the H. Wilson Sundt Generating Station
TCA	Transmission Cost Adjustor
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Therm	A unit of heating value equivalent to 100,000 Btus
Tri-State	Tri-State Generation and Transmission Association, Inc.
UED	UniSource Energy Development Company, a wholly-owned subsidiary of UNS Energy Corporation
UES	UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy, and intermediate holding company established to own the operating companies UNS Electric and UNS Gas
UNS Electric	UNS Electric, Inc., a wholly-owned subsidiary of UES
UNS Energy	UNS Energy Corporation (formerly known as UniSource Energy Corporation)
UNS Gas	UNS Gas, Inc., a wholly-owned subsidiary of UES

vi

PART I

This combined Form 10-K is being filed separately by UNS Energy Corporation (UNS Energy) and Tucson Electric Power Company (TEP) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. TEP does not make any representation as to information relating to any other subsidiary of UNS Energy.

This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. You should read forward-looking statements together with the cautionary statements and important factors included elsewhere in this Form 10-K (See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Safe Harbor for Forward-Looking Statements). Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions. Forward-looking statements are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs, or projections will be achieved or accomplished. In addition, UNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

ITEM 1. – BUSINESS

OVERVIEW OF CONSOLIDATED BUSINESS

UNS Energy is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets at December 31, 2013. TEP generates, transmits and distributes electricity to approximately 413,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).

UES holds the common stock of two regulated utilities, UNS Electric, Inc. (UNS Electric) and UNS Gas, Inc. (UNS Gas). UNS Electric is a regulated utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.

UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2013.

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

AGREEMENT AND PLAN OF MERGER

In December 2013, UNS Energy entered into an Agreement and Plan of Merger (the Merger Agreement) with FortisUS Inc., a Delaware corporation (Fortis), Color Acquisition Sub Inc., an Arizona corporation and a wholly owned subsidiary of Fortis (Merger Sub), and, solely for the purposes of Sections 5.5(c) and 8.15 of the Merger Agreement, Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador and the parent company of Fortis (Fortis Parent).

The Merger Agreement provides for a business combination whereby Merger Sub will merge with and into UNS Energy (the Merger). As a result of the Merger, the separate corporate existence of Merger Sub will cease and UNS Energy will continue as a wholly owned subsidiary of Fortis. The Boards of Directors of each of UNS Energy and Fortis Parent have approved the Merger.

Under the Merger Agreement, at the effective time of the Merger, each outstanding share of UNS Energy common stock (other than shares owned by UNS Energy, Fortis Parent, Fortis or Merger Sub or their subsidiaries) will be converted into the right to receive $60.25 in cash (the Merger Consideration). At the effective time and as a result of the Merger, each outstanding option to acquire UNS Energy common stock issued by UNS Energy will be converted into the right to receive the difference between

K-1

the Merger Consideration and the exercise price of the option, on a per-share basis, and each outstanding share of restricted stock, restricted stock unit, performance share and other equity-based awards will vest and be converted into the right to receive the Merger Consideration.

The Merger is subject to the approval of stockholders holding a majority of the outstanding shares of UNS Energy and other customary closing conditions, including, among other things:

• the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

• approvals of the Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC);

• confirmation of review, without unresolved concerns, from the Committee on Foreign Investment in the United States; and

• the absence of any injunction, order or other law prohibiting the Merger.

The obligations of each party to close the Merger are also subject to the accuracy of representations and warranties of, and compliance with covenants by, the other parties as set forth in the Merger Agreement, and, in the case of Fortis, the absence of any material adverse effect on UNS Energy.

The Merger Agreement provides that Fortis and UNS Energy may mutually agree to terminate the Merger Agreement before completing the Merger. In addition, either Fortis or UNS Energy may decide to terminate the Merger Agreement if, among other things:

• the Merger is not consummated by December 11, 2014, subject to extension to June 11, 2015 if regulatory approvals have not been obtained (or further if approvals have been obtained but have not yet become final orders), but other closing conditions have been satisfied or waived;

• UNS Energy stockholders fail to adopt the Merger Agreement;

• a court or other governmental entity issues a final and nonappealable order prohibiting the Merger; or

• the other party breaches the Merger Agreement in a way that would entitle the party seeking to terminate the Merger Agreement not to consummate the Merger, subject to the right of the breaching party to cure the breach.

UNS Energy may also terminate the Merger Agreement prior to receiving stockholder approval, after complying with certain procedures set forth in the Merger Agreement, in order to accept a superior takeover proposal upon payment of a termination fee of approximately $64 million (Termination Fee). Fortis may terminate the Merger Agreement and require payment of the Termination Fee if UNS Energy enters into an agreement with respect to a superior takeover proposal, or if the Board of Directors of UNS Energy recommends or proposes to approve or recommend any alternative takeover proposal with a third party, or withdraws, modifies or proposes publicly to withdraw or modify its approval or recommendation with respect to the Merger Agreement. The Merger Agreement further provides that, upon termination under certain other circumstances, UNS Energy may be obligated to reimburse up to $12.5 million of Fortis’ expenses with respect to the transaction and, if another takeover proposal is agreed or consummated, pay Fortis the Termination Fee (net of any expense reimbursement previously paid).

Fortis has agreed to maintain UNS Energy’s community involvement efforts and charitable donations for five years following the closing and to keep UNS Energy’s headquarters in Tucson, Arizona. Fortis has also agreed to retain four of UNS Energy’s current directors on the board of UNS Energy following the closing.

UNS Energy and Fortis have agreed to customary representations, warranties and covenants in the Merger Agreement, including, among others, covenants (i) with respect to the conduct of its business during the interim period between the execution of the Merger Agreement and consummation of the Merger, (ii) not to solicit proposals regarding alternative business combination transactions and (iii) not to engage in certain kinds of transactions during such period. UNS Energy and Fortis have agreed to use their reasonable best efforts to obtain required governmental approvals to effect the transaction.

On February 18, 2014, we filed definitive proxy materials with the SEC. We expect UNS Energy's shareholders to formally consider a proposal to approve the Merger Agreement at a meeting on March 26, 2014.

In January 2014, UNS Energy and Fortis Parent filed an application and supporting testimony with the ACC requesting approval of the Merger. The ACC administrative law judge (ALJ) assigned to this matter issued a procedural order that provides for settlement discussions to commence on April 28, 2014, and a hearing before the ALJ to commence on June 16, 2014. In February 2014, we filed an application with FERC requesting approval of the Merger. The Merger is expected to close by the end of 2014.

K-2

BUSINESS SEGMENT CONTRIBUTIONS

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

	2013		2012		2011
	Millions of Dollars
TEP	$	101	$	65	$	85
UNS Electric	12		17		18
UNS Gas	11		9		10
Other Non-Reportable Segments and Adjustments(1)	3		—		(3		)
Consolidated Net Income	$	127	$	91	$	110

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

See Note 4 for additional financial information regarding our business segments.

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

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

The rates charged to retail customers also include pass-through mechanisms that allow each utility to recover the prudently incurred actual costs of its fuel, transmission, and energy purchases.

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

TEP

TEP was incorporated in the State of Arizona in 1963. TEP is the principal operating subsidiary of UNS Energy. In 2013, TEP’s electric utility operations contributed 81% of UNS Energy’s operating revenues and comprised 83% of its assets at year end.

SERVICE AREA AND CUSTOMERS

TEP is a vertically integrated utility that provides regulated electric service to approximately 413,000 retail customers in southeastern Arizona. TEP’s service territory covers 1,155 square miles and includes a population of approximately one million people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells electricity to other entities in the western United States.

Retail Customers

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

K-3

Customer Base

The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years. In 2014, the retail energy consumption by customer class is expected to be similar to the historical distribution.

	2013		2012		2011
Residential	42	%	41	%	42	%
Commercial	23	%	24	%	23	%
Non-mining Industrial	23	%	23	%	23	%
Mining	12	%	12	%	12	%

Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. In 2013, 2012, and 2011, 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 2014 and 2015.

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 decreased by 1.2% in 2013 due in part to a higher occurrence of planned and unplanned maintenance at the mines that reduced the mines' demand for electricity.

See Part II, Item. 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, Sales to Mining Customers.

Retail Sales Volumes

During the past three years, economic conditions and state requirements for energy efficiency and distributed generation have negatively affected retail electricity sales. TEP’s retail sales volumes in 2013 were approximately 9,279 Gigawatt-hours (GWh). These volumes were 0.1% below 2010 levels.

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, Purchases and Interconnections, below.

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

Long-Term Sales

Long-term wholesale sales contracts cover periods of more than one year. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers. TEP’s two primary long-term contracts are with Salt River Project Agriculture Improvement and Power District (SRP) and the Navajo Tribal Utility Authority (NTUA). See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Long-Term Wholesale Sales.

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.

K-4

GENERATING AND OTHER RESOURCES

At December 31, 2013, TEP owned or leased 2,240 MW of generating capacity, as set forth in the following table:

	Unit		Date	Resource	Capacity	Operating	TEP’s Share
Generating Source	No.	Location	In Service	Type	MW	Agent	%	MW
Springerville Station(1)	1	Springerville, AZ	1985	Coal	387	TEP	100.0	387
Springerville Station	2	Springerville, AZ	1990	Coal	390	TEP	100.0	390
San Juan Station	1	Farmington, NM	1976	Coal	340	PNM	50.0	170
San Juan Station	2	Farmington, NM	1973	Coal	340	PNM	50.0	170
Navajo Station	1	Page, AZ	1974	Coal	750	SRP	7.5	56
Navajo Station	2	Page, AZ	1975	Coal	750	SRP	7.5	56
Navajo Station	3	Page, AZ	1976	Coal	750	SRP	7.5	56
Four Corners Station	4	Farmington, NM	1969	Coal	784	APS	7.0	55
Four Corners Station	5	Farmington, NM	1970	Coal	784	APS	7.0	55
Luna Generating Station	1	Deming, NM	2006	Gas	555	PNM	33.3	185
Sundt Station	1	Tucson, AZ	1958	Gas/Oil	81	TEP	100.0	81
Sundt Station	2	Tucson, AZ	1960	Gas/Oil	81	TEP	100.0	81
Sundt Station	3	Tucson, AZ	1962	Gas/Oil	104	TEP	100.0	104
Sundt Station	4	Tucson, AZ	1967	Coal/Gas	156	TEP	100.0	156
Sundt Internal Combustion Turbines		Tucson, AZ	1972-1973	Gas/Oil	50	TEP	100.0	50
DeMoss Petrie		Tucson, AZ	1972	Gas/Oil	75	TEP	100.0	75
North Loop		Tucson, AZ	2001	Gas	95	TEP	100.0	95
Springerville Solar Station		Springerville, AZ	2002-2010	Solar	6	TEP	100.0	6
Tucson Solar Projects		Tucson, AZ	2010-2012	Solar	12	TEP	100.0	12
Total TEP Capacity (2)								2,240

⁽¹⁾  Leased asset as of December 31, 2013.

⁽²⁾  Excludes 683 MW of additional resources, which consist of certain capacity purchases and interruptible retail load. At December 31, 2013, total owned capacity was 1,853 MW and leased capacity was 387 MW.

Springerville Generating Station

TEP leases 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 are accounted for as capital leases. The leases expire in January 2015 and include fair market value renewal and purchase options. TEP owns a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 megawatts (MW) of capacity.

Unit 2 of the Springerville Generating Station (Springerville Unit 2) is owned by San Carlos Resources, Inc. (San Carlos), a wholly-owned subsidiary of TEP. TEP’s other interests in the Springerville Generating Station (Springerville) include leasehold interests in the Springerville Coal Handling Facilities and in a one-half interest in certain other facilities at Springerville used in common by all four Springerville units (Springerville Common Facilities).

Springerville Unit 1 Leases

TEP leases 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 are accounted for as capital leases. The leases expire in January 2015 and include fair market value renewal and purchase options. In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 MW of capacity.

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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 expects to complete the purchases in December 2014 and in January 2015. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Unit 1.

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 a fixed-price purchase provision. The fixed prices to acquire the leased interests in the Springerville Common Facilities are $38 million in 2017 and $68 million in 2021.

Springerville Coal Handling Facilities Lease

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

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

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.

Future Generating Resources

Gila River Generating Station Unit 3

In December 2013, TEP and UNS Electric entered into an agreement (the Purchase Agreement) with a subsidiary of Entegra Power Group LLC (Entegra) to purchase Unit 3 of the Gila River Generating Station (Gila River Unit 3). The purchase price of $219 million is subject to adjustments to prorate certain fees and expenses through the closing and in respect of certain operational matters. Gila River Unit 3 is a gas-fired combined cycle unit with a capacity rating of 550 MW, located in Gila Bend, Arizona.

It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014. See TEP, Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and UNS Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3. See also Note 8.

The purchase of Gila River Unit 3, which would replace the expiring coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, is consistent with TEP's strategy to diversify its generation fuel mix. For more information on San Juan Unit 2, see Environmental Matters, Regional Haze Rules, San Juan, below.

Renewable Energy Resources

Owned Resources

As of December 31, 2013, TEP owned 18 MW of photovoltaic (PV) solar generating capacity. The Springerville solar system, which is located near the Springerville Generating Station, has a total capacity of 6 MW. TEP’s remaining 12 MW of PV solar generating capacity is located in the Tucson area.

In 2014, TEP expects to complete solar projects providing capacity of 20 MW at Ft. Huachuca, Arizona and 10 MW in Springerville, Arizona.

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Power Purchase Agreements

In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 124 MW of capacity from solar resources, 102 MW of capacity from wind resources and 4 MW of capacity from a landfill gas generation plant. At December 31, 2013, approximately 88 MW of contracted solar resources and 51 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.

Purchases and Interconnections

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

TEP typically uses generation from its gas-fired units, supplemented by power purchases, to meet the summer peak demands of its retail customers. Some of these 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.

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

Springerville Units 3 and 4

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

Peak Demand and Resources

Peak Demand	2013		2012		2011		2010		2009
	MW
Retail Customers	2,230		2,290		2,334		2,333		2,354
Firm Sales to Other Utilities	484		286		322		340		385
Coincident Peak Demand (A)	2,714		2,576		2,656		2,673		2,739
Total Generating Resources	2,240		2,267		2,262		2,245		2,229
Other Resources (1)	775		683		1,009		799		781
Total TEP Resources (B)	3,015		2,950		3,271		3,044		3,010
Total Margin (B) – (A)	301		374		615		371		271
Reserve Margin (% of Coincident Peak Demand)	11	%	15	%	23	%	14	%	10	%

⁽¹⁾  Other Resources include firm power purchases and interruptible retail and wholesale loads.

Peak demand occurs during the summer months due to the cooling requirements of TEP’s retail customers. Retail peak demand varies from year-to-year due to weather, economic conditions, and other factors. TEP’s retail peak demand declined over the period of 2009 to 2013 due primarily to weak economic conditions and the implementation of energy efficiency programs.

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

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margin to coincident peak demand. TEP’s reserve margin in 2013 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.

Forecasted retail peak demand for 2014 is 2,253 MW compared with actual peak demand of 2,230 MW in 2013. TEP’s 2014 estimated retail peak demand is based on weather patterns observed over a 10-year period. TEP believes existing generation capacity and power purchase agreements are sufficient to meet expected demand in 2014.

FUEL SUPPLY

Fuel and Purchased Power Summary

Resource information is provided below:

	Average Cost per kWh (cents per kWh)			Percentage of Total kWh Resources
	2013	2012	2011	2013		2012		2011
Coal	2.66	2.54	2.56	75	%	72	%	73	%
Gas	4.57	4.54	5.99	8	%	11	%	7	%
Purchased Power	4.83	3.44	3.94	17	%	17	%	20	%
All Sources	3.54	3.19	3.30	100	%	100	%	100	%

Coal

TEP’s principal fuel for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona and New Mexico. More than 90% of TEP’s coal supply is purchased under long-term contracts, which results in more predictable prices. The average cost per ton of coal, including transportation, was $48.51 in 2013, $45.84 in 2012, and $46.64 in 2011.

Station	Coal Supplier	2013 Coal Consumption (tons in 000’s)	Contract Expiration	Avg. Sulfur Content	Coal Obtained  From(1)
Springerville	Peabody Coalsales	3,172	2020	1.0%	Lee Ranch Coal Co.
Four Corners(2)	BHP Billiton	381	2016	0.8%	Navajo Indian Tribe
San Juan	San Juan Coal Co.	1,306	2017	0.8%	Federal and State Agencies
Navajo	Peabody Coalsales	560	2019	0.6%	Navajo and Hopi Indian Tribes

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

(2) Beginning in July 2016 through June 2031, the coal for Four Corners will be purchased from the Navajo Transitional Energy Company (NTEC). NTEC purchased the mine located near Four Corners from BPH Billiton and will begin operating the mine in 2016.

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.

Prior to 2010, Sundt Unit 4 was predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with methane, a renewable energy resource, 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. In 2014, TEP expects to fuel Sundt Unit 4 primarily with existing coal supplies at the site. See Note 7.

Generating Facilities Operated by Others

TEP also participates in jointly-owned coal-fired generating facilities at the Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo), and the San Juan Generating Station (San Juan). Four Corners, which is operated by Arizona Public Service (APS), and San Juan, which is operated by Public Service Company of New Mexico (PNM), are mine-mouth generating stations located adjacent to the coal reserves. Navajo, which is operated by SRP, obtains its coal supply from a nearby coal mine and a dedicated rail delivery system. The coal supplies are under long-term contracts administered by the

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operating agents. TEP expects the available coal reserves of the suppliers to these three jointly-owned generating facilities to be sufficient for the remaining estimated lives of the stations.

Natural Gas Supply

TEP typically uses generation from its facilities fueled by natural gas, in addition to energy from its coal-fired facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs. TEP purchases gas from Southwest Gas Corporation under a retail tariff for North Loop’s 95 MW of internal combustion turbines and receives distribution service under a transportation agreement for DeMoss Petrie, a 75 MW internal combustion turbine. TEP purchases capacity from El Paso Natural Gas (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.

TEP also purchases gas transportation for Luna Generating Station (Luna) from EPNG from the San Juan and Permian Basins, utilizing firm transportation agreements with 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.

TEP is participating in the continuation of the 500 kV transmission line from the Pinal West substation to the Pinal Central substation. This project is expected to be in service in 2014.  TEP is also finalizing the engineering design for a 40-mile 500-kV transmission line from the Pinal Central substation to TEP’s Tortolita substation northwest of Tucson to further enhance its ability to access the region’s energy resources. TEP expects the Pinal Central to Tortolita line to be in service in 2016. As a result of these transmission additions, TEP expects that its ability to import energy into its service territory would increase by at least 250 MW.

Discontinued Transmission Project

TEP and UNS Electric are parties to a transmission line project initiated in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales, Arizona. TEP had previously capitalized $11 million related to the project, including $2 million to secure land and land rights. UNS Electric had previously capitalized $0.4 million related to the project.

TEP and UNS Electric will not proceed with the project based on the estimated cost of the proposed line, the difficulty in reaching agreement with the Forest Service on a path for the line, and concurrence by the ACC of transmission plans filed by TEP and UNS Electric supporting the elimination of this project.  In 2012, TEP and UNS Electric wrote off a portion of the capitalized costs believed not probable of recovery and recorded a regulatory asset for the balance deemed probable of recovery. TEP and UNS Electric believe it is probable that we will recover at least $5 million and $0.2 million, respectively, of costs incurred through 2013. See Note 7.

RATES AND REGULATION

2013 TEP Rate Order

In June 2013, the ACC issued an order (2013 TEP Rate Order) that resolved the rate case filed by TEP in July 2012, which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013. See Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order.

Purchased Power and Fuel Adjustment Clause

The Purchased Power and Fuel Adjustment Clause (PPFAC) allows TEP to recover its fuel, transmission, and purchased power costs, including demand charges, and the prudent costs of contracts for hedging fuel and purchased power costs 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, net of 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.

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The 2013 TEP Rate Order approved a new PPFAC rate, effective July 1, 2013, which is a credit to retail customers of 0.14 cents per kWh. This PPFAC rate will be in effect until the rate is reset by the ACC in the second quarter of 2014.

TEP’s current PPFAC rate includes:

• a reduction in the PPFAC bank balance, recorded in June 2013 as an increase to fuel expense, of $3 million related to prior sulfur credits; and

• a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory asset to defer coal costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final insurance settlement.

Beginning on July 1, 2013, net lime expense is recovered through the PPFAC; these expenses were previously recorded in O&M expense.

At December 31, 2013, TEP had under-collected fuel and purchased power costs on a billed-to-customer basis of $14 million.

In February 2014, TEP filed a request with the ACC to reset the PPFAC in order to collect the under-collected balance from customers.

Renewable Energy Standard and Tariff

The ACC’s Renewable Energy Standard (RES) requires TEP, UNS Electric, and other affected utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. Affected utilities must file annual RES implementation plans for review and approval by the ACC. The approved cost of carrying out those plans is recovered from retail customers through the RES surcharge. In 2010, the ACC approved a funding mechanism that allows TEP to recover operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through RES funds until such costs are reflected in TEP’s Base Rates.

In October 2013, the ACC approved TEP's 2014 RES implementation plan. Under the plan, TEP expects to collect approximately $34 million from retail customers during 2014 to fund the following: the above market cost of renewable energy purchases; performance based incentives for customer installed distributed generation; a return on and of TEP's investments in company-owned solar projects; and various other program costs. The plan includes approval for a TEP investment of $28 million in 2014 for company-owned solar projects and an additional $12 million in 2015. TEP met the 2013 RES renewable energy target of 4.0% of retail kWh sales and expects to meet the 2014 target of 4.5%.

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 annual targeted retail kWh savings equal to 22% by 2020. Since the implementation of the Electric EE Standards, TEP’s cumulative annual energy savings is approximately 4.4% of retail kWh sales.

DSM programs approved by the ACC, direct load control programs, and energy efficient building codes are acceptable means to meet the Electric EE Standards as set forth by the ACC.

The 2013 TEP Rate Order approved (i) a Lost Fixed Cost Recovery (LFCR) mechanism that will allow TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to energy efficiency programs and distributed generation, and (ii) an energy efficiency provision that included a 2013 calendar year budget to fund programs that support the ACC's Electric EE Standards as well as a new performance incentive. See Item. 7-Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order.

Competition

Retail Electric Competition Rules

In 1999, the ACC approved the Retail Electric Competition Rules (Rules) that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004. During 2012 and 2013, several companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive

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retail electric services in TEP's service territory as an ESP. Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP's retail customers to use an alternative ESP.

In May 2013, the ACC considered the possibility of opening Arizona to retail electric competition. After receiving comments from various parties, the ACC voted to close the docket in September 2013 and did not take any steps to implement retail electric competition. See Item. 7—Management’s Discussion and Analysis of Financial Condition and Result of Operations, Tucson Electric Power, Factors Affecting Results of Operations, Competition, Retail Electric Competition Rules.

Technological Developments and Energy Efficiency

New technological developments and the implementation of the Electric EE Standards have reduced energy consumption by TEP's retail customers. TEP's customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP's services.

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TEP’S UTILITY OPERATING STATISTICS

	2013		2012		2011		2010			2009
Generation and Purchased Power – kWh (000)
Remote Generation	10,586,972		10,284,612		10,005,127		9,077,032			9,134,183
Local Tucson Generation (Oil, Gas, & Coal)	674,443		803,146		906,496		1,492,885			1,131,399
Renewable Generation	38,206		44,930		28,049		24,511			23,712
Purchased Power	2,328,581		2,328,420		2,686,918		2,846,005			3,809,890
Total Generation and Purchased Power	13,628,202		13,461,108		13,626,590		13,440,433			14,099,184
Less Losses and Company Use	885,026		789,613		822,220		879,423			936,206
Total Energy Sold	12,743,176		12,671,495		12,804,370		12,561,010			13,162,978
Sales – kWh (000)
Residential	3,866,665		3,820,637		3,888,011		3,869,540			3,905,696
Commercial	2,187,095		2,187,617		2,184,241		2,171,694			2,205,045
Industrial	2,113,659		2,132,214		2,145,163		2,138,749			2,160,946
Mining	1,079,150		1,092,518		1,083,071		1,079,327			1,064,830
Other	32,350		31,833		31,621		32,478			34,226
Total – Electric Retail Sales	9,278,919		9,264,819		9,332,107		9,291,788			9,370,743
Electric Wholesale Sales	3,464,257		3,406,676		3,472,263		3,269,222			3,792,235
Total Electric Sales	12,743,176		12,671,495		12,804,370		12,561,010			13,162,978
Operating Revenues ($000)
Residential	$	400,999	$	387,840	$	383,908	$	372,212		$	377,761
Commercial	252,547		247,157		241,044		233,567			236,836
Industrial	164,433		166,739		164,024		159,937			163,720
Mining	65,094		66,158		65,720		62,112			61,033
Other	2,809		2,693		2,601		2,593			2,723
RES, DSM, ECA and LFCR	48,475		45,292		46,633		37,767			25,443
Total – Electric Retail Sales	934,357		915,879		903,930		868,188			867,516
Wholesale Revenue- Long-Term	26,203		24,910		41,056		55,653			48,249
Wholesale Revenue- Short-Term	91,467		71,257		72,798		71,435			84,410
California Power Exchange Provision for Wholesale Refunds	—		—		—		(2,970		)	(4,172		)
Transmission	14,830		15,793		16,392		20,863			18,974
Other Revenues	129,833		133,821		122,210		112,098			84,361
Total Operating Revenues	$	1,196,690	$	1,161,660	1,156,386		$	1,125,267		$	1,099,338
Customers (End of Period)
Residential	372,411		369,480		367,396		366,217			365,157
Commercial	37,913		37,672		37,536		37,215			37,027
Industrial	617		632		636		635			629
Mining	4		4		4		4			4
Public Authorities	1,857		1,833		1,814		1,829			1,839
Total Retail Customers	412,802		409,621		407,386		405,900			404,656
Average Retail Revenue per kWh Sold (cents)
Residential	10.4		10.2		9.9		9.6			9.7
Commercial	11.5		11.3		11.0		10.8			10.7
Industrial and Mining	7.2		7.2		7.1		6.9			7.0
Average Retail Revenue per kWh Sold (excludes RES, DSM, ECA and LFCR)	9.5		9.4		9.2		8.9			9.0
Average Revenue per Residential Customer	$	1,077	$	1,050	$	1,045	$	1,016		$	1,035
Average kWh Sales per Residential Customer	10,383		10,341		10,583		10,566			10,696

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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 customers.

Hazardous Air Pollutant Requirements

The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules to set the standards for the control of mercury emissions and other hazardous air pollutants from power plants.

Navajo

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

San Juan

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

Four Corners

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

Springerville Generating Station

Based on the EPA’s final standards, Springerville Generating Station (Springerville) may require mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases by early 2015; after the completion of such purchases, 50.5% of environmental costs attributed to Springerville Unit 1 will be reimbursed by third party owners.

Sundt Generating Station

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

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility 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 the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.

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Navajo

In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, submitted an agreement to the EPA that would achieve greater NOx emission reductions than the EPA's proposed BART rule. In September 2013, the EPA issued a supplemental proposal incorporating the provisions of the agreement as a better-than-BART alternative.

Among other things, the agreement 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 SCR or an equivalent technology on the remaining two units by 2030. As part of the agreement, the current owners have committed to cease their operation of conventional coal-fired generation at Navajo no later than December 2044. The Navajo Nation can continue operation after 2044 at its election. If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each. The EPA could issue their decision as early as mid-2014.

San Juan

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

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

In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement (Settlement Agreement) that outlines an alternative to the FIP. The terms of the Settlement Agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of Selective Non-Catalytic Reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. The New Mexico Environmental Department (NMED) prepared a revision to the regional haze State Implementation Plan (SIP) incorporating the provisions of the Settlement Agreement, and in September 2013, the New Mexico Environmental Improvement Board approved the SIP revision. The SIP revision now awaits final EPA approval. The EPA is expected to issue a final BART determination in the second or third quarter of 2014.  TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $35 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. If San Juan Unit 2 is retired, TEP's coal-fired generating capacity would be reduced by 170 MW.

In connection with the implementation of the SIP revision and the 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 owners. The owners 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.

On October 17, 2013, the Tenth Circuit ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously-filed motion to stay the FIP. The Tenth Circuit placed the pending petitions for

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review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the Settlement Agreement is not implemented as contemplated, any party to the litigation may file a motion seeking to lift the abatement.

At December 31, 2013, the book value of TEP's share of San Juan Unit 2 was $113 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. TEP cannot predict the ultimate outcome of this matter.

Four Corners

In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. In December 2013, APS (the operator) decided to shut down Units 1-3 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 $35 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 Rule requiring further emission reduction are not likely to impact Springerville operations until after 2018.

Sundt

In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule and developed a timeline to issue a federal implementation plan for emissions sources including Sundt Unit 4. While TEP does not agree that Sundt Unit 4 is subject to BART, it submitted a better-than-BART proposal in November 2013 which called for the elimination of coal as a fuel source at Sundt by 2017. In January 2014, the EPA issued a BART proposal that would require TEP to either (i) install, by mid-2017, SNCR and other equipment 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 other necessary equipment would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is expected to issue a final BART determination by July 2014. At December 31, 2013, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

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. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.

For existing power plants, the President ordered the EPA to:

• propose carbon emission standards by June 1, 2014;

• finalize those standards by June 1, 2015; and

• require states to submit their implementation plans to meet the standards by June 30, 2016.

UNS Energy will continue to work with federal and state regulatory agencies to promote compliance flexibility in the rules impacting existing fossil-fuel fired power plants. We cannot predict the ultimate outcome of these matters.

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

Generating Facility	Estimated  Annual O&M Expense		Estimated Capital Expenditures		Regulation (Compliance Date)	Upgrades
	Millions of Dollars
Springerville Units 1 & 2(1)	$	3	$	5	MATS (2015)	Mercury Controls
San Juan Unit 1	1 - 6		35 - 200		Regional Haze/BART (2016)	SNCRs or SCRs
Navajo Units 1-3	3		86		MATS (2015) Regional Haze/BART (2030)	Mercury Controls; SCRs; Baghouses
Four Corners Units 4 & 5	3		36		MATS (2015) Regional Haze/BART (2018)	Mercury Controls; SCRs
Sundt Unit 4	5 - 6		12		Regional Haze (2017)	SNCR

⁽¹⁾ TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases by early 2015; after the completion of such purchases, 50.5% of environmental costs attributed to Springerville Unit 1 will be reimbursed by third party owners.

Certain environmental costs and investments can be recovered by TEP through a retail rate mechanism, called the Environmental Cost Adjustor, that was approved in the 2013 TEP Rate Order. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, TEP, Factors Affecting Results of Operations, 2013 TEP Rate Order.

Coal Combustion Residuals

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

The EPA has not yet indicated a preference for regulating CCRs. Each option would allow CCRs to be beneficially reused or recycled as components of other products. We expect the EPA to issue a final rule in late 2014. TEP cannot predict the outcome of this matter.

UNS ELECTRIC

SERVICE TERRITORY AND CUSTOMERS

UNS Electric is a vertically integrated electric utility company serving approximately 93,000 retail customers in Mohave and Santa Cruz counties. These counties have a combined population of approximately 250,000. UNS Electric’s annual retail customer growth rate was less than 1% from 2010 through 2013. We estimate that UNS Electric’s retail customer base will increase by less than 1% in 2014. UNS Electric’s customer base is primarily residential, with some commercial and industrial customers. Peak demand for 2013 was 423 MW.

POWER SUPPLY AND TRANSMISSION

Purchased Energy

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

Generating Resources

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

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

Renewable Energy Resources

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

Future Generating Resources

Gila River Generating Station Unit 3

In December 2013, UNS Electric entered into an agreement to purchase 25% of Gila River Unit 3 (137 MW) for approximately $55 million, with TEP purchasing the remaining 75% interest (413 MW). The purchase price is subject to adjustments to prorate certain fees and expenses through the closing and in respect of certain operational matters. TEP and UNS Electric may also modify the percentage ownership allocation between them. We expect the transaction to close in December 2014.

The purchase of a 25% interest of Gila River Unit 3 would be consistent with UNS Electric's strategy to reduce its reliance on wholesale market purchases to meet retail customer demand.

See TEP, Generating and Other Resources, Future Generating Resources, Gila River Generating Station Unit 3, above,and Note 8.

Renewable Energy Resources

UNS Electric expects to invest approximately $7 million in 2014 in company-owned solar PV capacity. See Note 3.

Transmission

UNS Electric imports the power generated at BMGS into its Mohave County service territory over Western Area Power Administration’s (WAPA) transmission lines. UNS Electric has transmission service agreements with WAPA for its transmission capacity that expire in June 2016.

UNS Electric imports the power generated at Valencia into its Santa Cruz County service territory over its own transmission lines.

Tucson to Nogales 138kV Transmission Line

UNS Electric completed construction of a 138kV transmission line from Tucson to Nogales at the end of 2013. This project replaces a 115kV transmission line that previously linked UNS Electric's load to the WAPA system. The new transmission line now connects UNS Electric's load in Nogales directly to TEP’s high voltage transmission system. The connection to TEP’s system eliminates a requirement to run local generation in Nogales that was required due to limitations on the WAPA system.

RATES AND REGULATION

2013 UNS Electric Rate Order

In December 2013, the ACC issued an order (2013 UNSE Rate Order) that resolved the rate case filed by UNSE in December 2012, which was based on a test year ended June 30, 2012. The 2013 UNSE Rate Order approved a $3 million non-fuel base rate increase and a new rate structure effective January 1, 2014. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2013 UNS Electric Rate Order.

Purchased Power and Fuel Adjustment Clause

The PPFAC, which is reset monthly, allows UNS Electric to recover its fuel, transmission, and purchased power costs, including demand charges, broker fees, and the prudent costs of contracts for hedging fuel and purchased power costs for its retail customers.

If the PPFAC bank balance becomes over collected by more than $10 million, UNS Electric must file for a PPFAC rate adjustment or justify why an adjustment is not necessary at this time. UNS Electric can request a surcharge to recover costs if

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the PPFAC bank balance is under-collected. At December 31, 2013, the PPFAC bank balance was over-collected by $14 million on a billed-to-customer basis. See Note 3.

Renewable Energy Standard and Tariff

As part of a rate order issued in 2010, the ACC authorized UNS Electric to recover operating costs, depreciation, property taxes, and a return on its investment in company-owned solar projects through RES funds until these costs are reflected in its Base Rates.

In October 2013, the ACC approved UNS Electric's 2014 RES implementation plan. Under the plan, UNS Electric will collect approximately $6 million from customers during 2014 to fund the following: the above market cost of renewable energy purchases; incentives for customer installed distributed generation; a return on and of UNS Electric's investments in company-owned solar projects; and various other program costs. The plan includes approval for a UNS Electric investment of $7 million in 2014 for company-owned solar projects.

Energy Efficiency Standards

Since the implementation of the Electric EE Standards in 2010, UNS Electric saved cumulative annual energy equal to approximately 4.7% of retail kWh sales. See TEP, Rates and Regulation, Electric Energy Efficiency Standards, above.

The 2013 UNS Electric Rate Order approved a LFCR mechanism that will allow UNS Electric to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to energy efficiency programs and distributed generation. See Item. 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Electric, Factors Affecting Results of Operations, 2013 UNS Electric Rate Order.

In December 2013, the ACC approved UNS Electric’s 2013-2014 Energy Efficiency implementation plan that included a 2014 calendar year budget to fund programs that support the ACC’s Electric EE Standards as well as a new performance incentive.

ENVIRONMENTAL MATTERS

UNS Electric is subject to environmental regulation of air and water quality, resource extraction, waste disposal, and land use by federal, state, and local authorities. UNS Electric believes that its facilities are in substantial compliance with all existing regulations and will be in compliance with expected environmental regulations. SeeNote 7.

UNS GAS

SERVICE TERRITORY AND CUSTOMERS

UNS Gas is a gas distribution company serving approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona. These counties comprise approximately 50% of the territory in the state of Arizona, with a population of approximately 700,000. UNS Gas’ customer base is primarily residential. Sales to residential customers provided approximately 61% of total revenues in 2013.

UNS Gas’ annual retail customer growth rate was less than 1% from 2010 through 2013. In 2014, we expect UNS Gas’ retail customer base to increase by less than 1%.

GAS SUPPLY AND TRANSPORTATION

UNS Gas directly manages its gas supply and transportation contracts. The market price for gas varies based upon the period during which the commodity is purchased and is affected by weather, production issues, the economy, and other factors. UNS Gas hedges its gas supply prices by entering into physical fixed price forward agreements and financial contracts in order to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of hedging at least 60% of the price of expected monthly gas consumption. UNS Gas hedged approximately 65% of its expected monthly consumption for the 2013/2014 winter season (November through March). Additionally, UNS Gas has approximately 60% of its expected gas consumption hedged for April through October 2014, and 40% hedged for the 2014/2015 winter season.

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

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UNS Gas has average capacity rights of approximately 655,000 therms per day on the EPNG pipeline system, with an average of 1,095,000 therms per day in the winter season (November through March) to serve its service territories. UNS Gas has average capacity rights of 230,000 therms per day on the San Juan Lateral and Mainline of the Transwestern pipeline. The Transwestern pipeline principally delivers gas to the portion of UNS Gas’ distribution system serving customers in Flagstaff and Kingman.

UNS Gas has a separate agreement with Transwestern for transportation capacity rights on the Phoenix Lateral Extension Line that expires in 2024. UNS Gas’ average daily capacity right is 126,000 therms per day, with an average of 222,000 therms per day in the winter season.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Liquidity and Capital Resources, Contractual Obligations.

RATES AND REGULATION

2012 UNS Gas Rate Order

In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a partial decoupling mechanism to recover lost fixed cost revenues as a result of implementing the Gas Energy Efficiency Standards (Gas EE Standards). See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Gas, Factors Affecting Results of Operations, 2012 UNS Gas Rate Order.

Purchased Gas Adjustor

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

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

In October 2013, the ACC approved an increase to the existing customer PGA credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At December 31, 2013, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.

Gas Energy Efficiency Standards and Decoupling

In 2010, the ACC approved Gas EE Standards which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. The Gas EE standards require increasing annual targeted retail therm savings equal to 6% by 2020. Since the implementation of the Gas EE Standards in 2010, UNS Gas’ customers have saved cumulative energy equal to approximately 0.5% of total retail therm sales.

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

In June 2013, the ACC approved the UNS Gas 2011-2012 Gas Energy Efficiency implementation plan with modifications and amendments. The approval included an annual energy efficiency budget of approximately $2 million and a waiver of the Gas EE Standards through 2013.

ENVIRONMENTAL MATTERS

UNS Gas is subject to environmental regulation of air and water quality, resource extraction, waste disposal, and land use by federal, state, and local authorities. UNS Gas’ facilities are in substantial compliance with existing regulations.

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EMPLOYEES (At December 31, 2013)

TEP had 1,398 employees, of which approximately 678 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.

UNS Electric had 143 employees, of which 27 employees were represented by the IBEW Local No. 387 and 87 employees were represented by the IBEW Local No. 769. The existing agreements with the IBEW Local No. 387 and No. 769 expire in February 2017 and June 2016, respectively.

UNS Gas had 188 employees, of which 109 employees were represented by IBEW Local No. 1116 and 5 employees were represented by IBEW Local No. 387. The agreements with the IBEW Local No. 1116 and No. 387 expire in June 2015 and February 2017, respectively.

SES had 248 employees, of which 216 are represented by IBEW Local No. 1116 and 19 by IBEW Local No. 570. These agreements expire in December 2014 and May 2016, respectively.

EXECUTIVE OFFICERS OF THE REGISTRANTS

Executive Officers – UNS Energy and TEP

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

Name	Age	Position(s) Held	Executive Officer Since
Paul J. Bonavia	62	Chairman and Chief Executive Officer	2009
David G. Hutchens	47	President and Chief Operating Officer	2007
Kevin P. Larson	57	Senior Vice President and Chief Financial Officer(1)	2000
Philip J. Dion III	45	Senior Vice President, Public Policy and Customer Solutions	2008
Kentton C. Grant	55	Vice President, Finance and Rates(2)	2007
Todd C. Hixon	47	Vice President and General Counsel	2011
Karen G. Kissinger	59	Vice President and Chief Compliance Officer	1991
Mark C. Mansfield	58	Vice President, Energy Resources	2012
Frank P. Marino	49	Vice President and Controller	2013
Thomas A. McKenna	65	Vice President, Energy Delivery	2007
Catherine E. Ries	54	Vice President, Human Resources and Information Technology	2007
Herlinda H. Kennedy	52	Corporate Secretary	2006

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

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

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Paul J. Bonavia	Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009. He also served as President from January 2009 to December 2011. Prior to joining UNS Energy, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
David G. Hutchens	Mr. Hutchens has served as President and Chief Operating Officer of UNS Energy and TEP since August 2013. In December 2011 Mr. Hutchens was named President of UNS Energy and TEP. In March 2011, Mr. Hutchens was named Executive Vice President of UNS Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UNS Energy and TEP. Mr. Hutchens joined TEP in 1995.
Kevin P. Larson	Mr. Larson has served as Senior Vice President and Chief Financial Officer of UNS Energy and TEP since September 2005. Mr. Larson is also Treasurer of UNS Energy. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He was elected Treasurer in August 1994 and Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer.

Philip J. Dion III	Mr. Dion has served as Senior Vice President, Public Policy and Customer Solutions of UNS Energy and TEP since August 2013. Mr. Dion was named Vice President, Public Policy in April 2010. Mr. Dion joined UNS Energy in February 2008 as Vice President of Legal and Environmental Services. Prior to joining UNS Energy, Mr. Dion was chief of staff and chief legal advisor to Commissioner Marc Spitzer of the FERC. Mr. Dion previously worked in various roles at the ACC, including as an administrative law judge and as an advisor to Mr. Spitzer, prior to his appointment to the FERC.
Kentton C. Grant	Mr. Grant has served as Vice President of Finance and Rates of UNS Energy and TEP since January 2007. Mr. Grant also serves as Treasurer of TEP. Mr. Grant joined TEP in 1995.
Todd C. Hixon	Mr. Hixon has served as Vice President and General Counsel of UNS Energy and TEP since May 2011. Mr. Hixon joined TEP’s legal department in 1998 and served in a variety of capacities, most recently serving as Associate General Counsel.
Karen G. Kissinger	Ms. Kissinger has served as Vice President and Chief Compliance Officer of UNS Energy and TEP since August 2013. Ms. Kissinger served as Vice President, Controller, and Chief Compliance Officer from 2001 to 2013. Ms. Kissinger joined TEP as Vice President and Controller in January 1991.
Mark C. Mansfield	Mr. Mansfield has served as Vice President, Energy Resources since 2012. He joined the company in 2008, most recently serving as Senior Director of Generation. Prior to joining TEP, Mr. Mansfield held various leadership positions at PacifiCorp Energy from 1992-2008.
Frank P. Marino	Mr. Marino has served as Vice President and Controller of UNS Energy and TEP since August 2013.  Mr. Marino joined UNS Energy as Assistant Controller in January 2013.  Prior to joining UNS Energy, he served various roles at the AES Corporation, a global power company. In 2012 he served as AES' Vice President for Business Demand and Outsourcing Management, and from 2007-2011 he served as Chief Financial Officer for two different business units.
Thomas A. McKenna	Mr. McKenna has served as Vice President, Energy Delivery since August 2013. Mr. McKenna was named Vice President, Engineering in January 2007. Mr. McKenna joined Nations Energy Corporation (a then wholly-owned subsidiary of Millennium) in 1998.
Catherine E. Ries	Ms. Ries has served as Vice President, Human Resources and Information Technology, since May 2013. Ms. Ries joined UNS Energy and TEP as Vice President of Human Resources in June 2007. Prior to joining UNS Energy, Ms. Ries worked for Clopay Building Products, a division of Griffon Corporation, from 2000 to 2007, and held the position of Vice President of Human Resources.
Herlinda H. Kennedy	Ms. Kennedy has served as Corporate Secretary of UNS Energy and TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999.

SEC REPORTS AVAILABLE ON UNS ENERGY’S WEBSITE

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

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

ITEM 1A. – RISK FACTORS

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

RISKS RELATED TO THE PROPOSED MERGER WITH FORTIS

The Proposed Merger with Fortis May Not Be Completed.

The proposed Merger with Fortis requires approval by UNS Energy shareholders, the FERC, the Committee on Foreign Investment in the United States, and the ACC. Such approvals may not be obtained. For example, the ACC may not approve the Merger or may seek to impose conditions on the completion of the transaction, which could cause the conditions to the Merger to not be satisfied or which could delay or increase the cost of the transaction. In addition, the occurrence of a material adverse effect or the failure to satisfy other closing conditions could result in a termination of the Merger Agreement by Fortis.

Termination Fee

UNS Energy will be obligated to reimburse up to $12.5 million of Fortis' expenses if (i) Fortis or UNS Energy terminates the Merger Agreement because the acquisition has not been completed by December 11, 2014 (which may be extended under certain circumstances) or Fortis terminates the Merger Agreement based on a breach of the Merger Agreement by UNS Energy, and (ii) a competing proposal has been made or publicly disclosed and not withdrawn prior to the termination of the Merger Agreement or applicable breach. In addition, if within twelve months after such termination, a definitive agreement providing for an acquisition transaction is entered into, or an acquisition transaction is consummated by UNS Energy with, the person who made the acquisition proposal prior to such termination or applicable breach or with any other third party making an acquisition proposal within three months following such termination, UNS Energy will be obligated to pay Fortis a termination fee of approximately $64 million (less any expense reimbursement previously paid). In no event will more than one termination fee be payable.

Access to Capital and Market Value of UNS Energy Common Stock

Failure to complete the Merger could: (i) affect the value of UNS Energy’s common stock, including by reducing it to a level at or below the trading range preceding the announcement of the Fortis transaction; and (ii) negatively affect our access to and cost of both equity and debt financing.

REVENUES

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

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 2009 through 2013 compared with average increases of approximately 2% in each year from 2004 to 2008. In 2013, total retail kWh sales were 0.2% above 2012 levels. TEP estimates that a 1% change in annual retail sales could impact pre-tax net income and pre-tax cash flows by approximately $6 million.

Similar impacts were felt at UNS Electric and UNS Gas. Annual average increases in the number of retail customers at both companies remained below 1% in 2009 through 2013 compared with average annual growth rates of 3% from 2004 to 2008. We estimate that a 1% change in annual retail sales at UNS Electric and UNS Gas could impact pre-tax net income and pre-tax cash flows by approximately $1 million.

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

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 and equipment. TEP and UNS

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Electric also are promoting DSM programs designed to help customers reduce their energy use, and these efforts will increase significantly under energy efficiency rules approved in 2010 by the ACC. Further development and use of these technologies and implementation of these rules would negatively impact the results of operations, net income, and cash flows of TEP and UNS Electric.

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

TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during the summer. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in its retail service territory. UNS Electric’s earnings follow a similar pattern, while UNS Gas’ sales peak in the winter during home heating season. Cool summers or warm winters may reduce customer usage at all three companies, adversely affecting operating revenues, cash flows, and net income by reducing sales.

TEP and UNS Electric are 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 and UNS Electric sell electricity to mines, military installations, and other large industrial customers. In 2013, 35% of TEP’s retail kWh sales, and 14% of UNS Electric’s retail kWh sales, were to industrial and mining customers. Retail sales volumes and revenues from these customer classes could decline as a result of, among other things: economic conditions; decisions by the federal government to close military bases; the effects of energy efficiency and distributed generation; 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 and UNS Electric’s large customers would negatively affect our results of operations, net income, and cash flows.

REGULATORY

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

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

The ACC is charged with setting retail electric and gas rates that provide utility companies with an opportunity to recover their costs of service and earn a reasonable rate of return. As part of the ACC’s process of establishing the retail electric and gas rates charged by TEP, UNS Electric and UNS Gas, the ACC could disallow the recovery of certain costs, such as: (i) the write-down of assets due to changes in federal regulations or due to applicable accounting rules; or (ii) any other expenses the ACC determines were not prudently incurred. The decisions made by the ACC on such matters impact the net income and cash flows of TEP, UNS Electric, and UNS Gas.

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

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

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

ENVIRONMENTAL

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

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

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

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

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

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

Based on the finding by the EPA in December 2009 that emissions of greenhouse gases endanger public health and welfare, the agency is in the process of regulating greenhouse gas emissions. In addition, there are proposals and ongoing studies at the state, federal, and international levels to address global climate change that could also result in the regulation of CO₂ and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. In 2013, 80% of TEP’s total energy resources came from its coal-fueled generating facilities.

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

FINANCIAL

Volatility or disruptions in the financial markets, 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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UNS Energy’s net income and cash flows can be adversely affected by rising interest rates.

At December 31, 2013, TEP had $215 million of tax-exempt variable rate debt obligations, $50 million of which was hedged with a fixed-for-floating interest rate swap through September 2014. The interest rates are set weekly or monthly. The average interest rates ranged from 0.06% to 0.48% in 2013. A 100 basis point increase in the average interest rates on this debt over a twelve-month period would increase TEP’s interest expense by approximately $2 million.

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

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

The expected purchase of Gila River and 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.

During 2013, TEP notified certain owner participants and their lessors that TEP elected to purchase their undivided ownership interests in Springerville Unit 1 upon the expiration of the lease term in January 2015. In total, TEP elected to purchase leased interests comprising 35.4% of Springerville Unit 1, representing 137 MW of capacity. In December 2014 and January 2015, TEP will be required to fund the purchase price of $65 million.

The Springerville Coal Handling Facilities can be purchased in April 2015 for a fixed price of $120 million. TEP also leases a 50% undivided interest in Springerville Common Facilities with primary lease terms ending in 2017 and 2021. Upon expiration of the Springerville Coal Handling and Common Facilities Leases (whether at the end of the initial term or any renewal term), TEP has the obligation under agreements with the owners of Springerville Units 3 and 4 to purchase such facilities. Upon acquisition by TEP, the owner of Springerville Unit 3 has the option and the owner of Springerville Unit 4 has the obligation to purchase from TEP a 14% interest in the Common Facilities and a 17% interest in the Coal Handling Facilities.

In December 2013, TEP and UNS Electric entered into a purchase agreement to acquire Unit 3 of the Gila River Generating Station (Gila River Unit 3). Gila River Unit 3 is a gas-fired combined cycle unit with a capacity rating of 550 MW. The transaction is expected to close in late 2014, upon which TEP and UNS Electric will be required to fund the purchase amount of $219 million.

In 2014 and 2015, TEP’s capital expenditures related to investments in its high voltage transmission system are expected to be $147 million.

Debt levels, liquidity, regulatory rules, and other restrictions could limit the ability of TEP, UNS Electric, and UNS Gas to make distributions to UNS Energy.

As a holding company, UNS Energy has no operations of its own and derives all of its revenues and cash flow from its subsidiaries. TEP, UNS Electric, and UNS Gas could experience reduced levels of liquidity, or face other restrictions, which could adversely impact their ability to pay dividends to UNS Energy.

The debt levels at TEP, UNS Electric, and UNS Gas:

• require UNS Energy's subsidiaries to dedicate a substantial portion of their cash flow to pay principal and interest on their debt, which could reduce the funds available for working capital, capital expenditures, acquisitions, and other general corporate purposes; and

• could limit their ability to borrow additional amounts for working capital, capital expenditures, acquisitions, dividends, debt service requirements, execution of their business strategy, or other purposes.

TEP, UNS Electric, and UNS Gas may be required to post margin under their power and fuel supply agreements which could negatively impact their liquidity. The agreements under which we contract for power and fuel include requirements to post credit enhancement in the form of cash or letters of credit (LOCs) under certain circumstances, including changes in market prices which affect contract values, or a change in creditworthiness of the respective companies. In order to post such credit enhancement, TEP, UNS Electric, and UNS Gas would have to use available cash, draw under their revolving credit agreements, or issue LOCs under their revolving credit agreements.

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Regulatory rules and other restrictions include:

• TEP's, UNS Electric's, and UNS Gas' inability to lend to affiliates without ACC approval; and

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

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 or UNS Electric’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 or UNS Electric’s generating stations and transmission and distribution systems operate below expectations, TEP or UNS Electric’s operating results could be adversely affected.

The lack of access to sufficient supplies of water could have a material adverse impact on TEP’s business and results of operations.

Natural gas and coal-fired generating plants require continuous water supply for their operation.  The region in which our power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies.  Any material reduction in the water supply for such facilities would limit the ability of TEP and UNS Electric to produce and market electricity from such facilities and could have a material adverse impact on our results of operations. Further, any change in regulations or the level of regulation with regard to use, treatment and discharge of water, or the licensing of water rights in the jurisdictions where TEP and UNS Electric operate, could have a material adverse impact on our results of operations.

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.

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

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

We may be subject to physical and/or cyber attacks.

As operators of critical energy infrastructure, we may face a heightened risk of physical and/or cyber attacks. Our electric generation, transmission, and distribution systems may be vulnerable to disability or failures as a result of physical or cyber acts of war or terrorism, vandalism or other causes.

Our corporate and information technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. In addition, our utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.

If, despite our security measures, a significant physical attack or cyber breach occurred, we could have our operations disrupted, property damaged, and customer information stolen; experience substantial loss of revenues, response costs, and

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other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on our business and results of operations.

TEP or UNS Electric might not be able to secure adequate right-of-way to construct transmission lines and distribution-related facilities, and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers.

TEP and UNS Electric rely on federal, state, and local governmental agencies to secure right-of-way and siting permits to construct transmission lines and distribution-related facilities. If adequate right-of-way and siting permits to build new transmission lines cannot be secured, TEP and UNS Electric may need to rely on more costly alternatives to provide energy to their customers, may not be able to maintain reliability in their service areas, or their ability to provide electric service to new customers may be negatively impacted.

ITEM 1B. – UNRESOLVED STAFF COMMENTS

None.

ITEM 2. – PROPERTIES

TEP PROPERTIES

Transmission facilities owned by TEP and by third parties, are located in Arizona and New Mexico and transmit the output from TEP’s remote electric generating stations at Four Corners, Navajo, San Juan, Springerville, and Luna to the Tucson area for use by TEP’s retail customers. The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. TEP has arrangements with approximately 140 companies to interchange generation capacity and transmission of energy. See Item 1. Business, TEP, Generating and Other Resources.

At December 31, 2013, TEP owned or participated in an overhead electric transmission and distribution system consisting of:

• 564 circuit-miles of 500-kV lines;

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

• 413 circuit-miles of 138-kV lines;

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

• 2,605 circuit-miles of lower voltage primary lines.

TEP’s underground electric distribution system includes 4,442 cable-miles of lines. TEP owns approximately 77% of the poles on which its lower voltage lines are located. Electric substation capacity consists of 104 substations with a total installed transformer capacity of 14,879,950 kilovolt amperes.

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

• on property owned by TEP;

• under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises, easements, or other rights which are generally subject to termination;

• under or over private property as a result of easements obtained primarily from the record holder of title; or

• over American Indian reservations under grant of easement by the Secretary of Interior or lease by American Indian tribes.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or 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,

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easements and leases for the plant, transmission lines and a water diversion facility located on land owned by the Navajo Nation. TEP also has acquired easements for transmission facilities related to San Juan, Four Corners, and Navajo across the Zuni, Navajo, and Tohono O’dham American Indian Reservations. TEP, in conjunction with PNM and Freeport McMoRan, holds an undivided ownership interest in the property on which Luna is located.

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

• possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs (BIA) and the American Indian tribes;

• possible inability of TEP to legally enforce its rights against adverse claimants and the American Indian tribes without Congressional consent; or

• failure or inability of the American Indian tribes to protect TEP’s interests in the easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants.

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

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

• Springerville Coal Handling Facilities;

• a 50% undivided interest in the Springerville Common Facilities; and

• Springerville Unit 1 and the remaining 50% undivided interest in the Springerville Common Facilities.

See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Tucson Electric Power Company, Factors Affecting Results of Operations, Springerville Unit 1 and Note 6.

UES PROPERTIES

At December 31, 2013, UNS Electric’s transmission and distribution system consisted of approximately 60 circuit-miles of 138-kV transmission lines, 274 circuit-miles of 69-kV transmission lines, and 3,651 circuit-miles of underground and overhead distribution lines. UNS Electric also owns the 62 MW Valencia plant, the 90 MW BMGS, as well as 40 substations having a total installed capacity of 1,549,000 kilovolt amperes.

At December 31, 2013, UNS Gas’ transmission and distribution system consisted of approximately 31 miles of steel transmission mains, 4,238 miles of steel and plastic distribution piping, and 138,951 customer service lines.

The gas and electric distribution and transmission facilities owned by UNS Electric and UNS Gas are located:

• on property owned by UNS Electric or UNS Gas;

• under or over streets, alleys, highways, and other places in the public domain, as well as national forests and state lands, under franchises, easements, or other rights which are generally subject to termination; or

• under or over private property as a result of easements obtained primarily from the record holder of title.

ITEM 3. – LEGAL PROCEEDINGS

Shareholder Lawsuits

Five putative shareholder class action lawsuits challenging the merger have been filed, four in the Superior Court of Pima County, Arizona: (i) Phillip Malenovshy v. UNS Energy Corporation, et al. (Case No. C20136942); (ii) Paul Parshall v. UNS Energy Corporation, et al. (Case No. C20136943); (iii) Hillary Kramer v. Paul J. Bonavia, et al. (Case No. C2014-0026); and (iv) Vandermeer Trust U/A DTD 03/11/1997 v. UNS Energy Corporation, et al. (Case No. C2014-0107); and one in federal court in the United States District Court for the District of Arizona: Milton Pfeiffer v. Paul J. Bonavia, et al. (Case No. 4:13-CV-02619-JGZ).

The lawsuits generally allege, among other things, that the directors of UNS Energy breached their fiduciary duties to shareholders of UNS Energy purportedly by agreeing to a transaction pursuant to an inadequate process and for failing to

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obtain the highest value for UNS Energy shareholders. The lawsuits allege that the Fortis entities also aided and abetted the directors of UNS Energy in the alleged breach of their fiduciary duties.

The lawsuits seek, in general, and among other things, (i) injunctive relief enjoining the transactions contemplated by the merger agreement, (ii) rescission or an award of rescissory damages in the event a merger is consummated, (iii) an award of plaintiffs’ costs including reasonable attorneys’ and experts’ fees, (iv) an accounting by the defendants to plaintiffs for all damages caused by the defendants, and (v) such further relief as the court deems just and proper.

These lawsuits are at a preliminary stage. UNS Energy, its directors and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.

Right of Way Matters

TEP previously reported it was a defendant in a class action filed in February 2009 in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs alleged, among other things, that the rights of way for defendants’ transmission lines on Navajo lands were improperly granted and that the compensation paid for such rights of way was inadequate. The plaintiffs were requesting, among other things, that the transmission lines on these lands be removed. In March 2010, the court entered a final judgment dismissing the case. The plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (BIA) in May 2010, appealing the BIA’s decision to grant the rights of way that were the subject of the now-dismissed complaint. In June 2010, the BIA found that the Notice of Appeal failed to meet the minimum filing requirements. In September 2010, the plaintiffs filed new Notices of Appeal concerning the same rights of way. In August 2013, the Interior Board of Indian Appeals dismissed the plaintiffs’ appeal for failure to meet procedural requirements. TEP cannot predict if the plaintiffs will again attempt to appeal the BIA’s decision to grant the rights of way.

In addition, see legal proceedings discussed in Note 7.

ITEM 4. – MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Stock Trading

UNS Energy’s Common Stock is traded under the ticker symbol UNS and is listed on the New York Stock Exchange. On February 14, 2014, the closing price was $60.21 with 7,392 shareholders of record.

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

Dividends

UNS Energy

UNS Energy’s Board of Directors expects to continue to authorize the payment of regular quarterly cash dividends on our Common Stock; however, such dividends are subject to the Board’s evaluation of our financial condition, earnings, cash flows, and dividend policy.

The merger agreement with Fortis allows UNS Energy's Board of Directors to authorize quarterly dividends of up to $0.48 per share until the merger is completed, including a pro rata dividend determined by the number of days from the last declared record date to the date the merger is completed. See Item. 1- Business, Overview of Consolidated Businesses, Agreement and Plan of Merger.

On February 24, 2014, UNS Energy declared a first quarter cash dividend of $0.48 per share of Common Stock. The first quarter dividend, totaling approximately $20 million, will be paid March 25, 2014 to shareholders of record at the close of business March 13, 2014. The table below summarizes UNS Energy’s dividends paid in 2011 through 2013.

	2013		2012		2011
Quarterly Dividend Per Common Share	$	0.435	$	0.43	$	0.42
Annual Dividend Per Common Share	$	1.74	$	1.72	$	1.68
Common Stock Dividends Paid	$72 million		$70 million		$62 million

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

TEP

TEP paid dividends to UNS Energy of $40 million in 2013 and $30 million in 2012. TEP did not pay any dividends to UNS Energy in 2011.

TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. At December 31, 2013, TEP was in compliance with the terms of the TEP Credit Agreement.

UNS Electric

UNS Electric paid dividends to UNS Energy of $10 million in 2013 and 2012. UNS Electric did not pay any dividends to UNS Energy in 2011. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. At December 31, 2013, UNS Electric was in compliance with the terms of its note purchase agreement.

UNS Gas

UNS Gas paid dividends to UNS Energy of $10 million in 2013, $20 million in 2012, and $10 million in 2011. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. At December 31, 2013, UNS Gas was in compliance with the terms of its note purchase agreement.

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Other Non-Reportable Segments

Millennium paid dividends to UNS Energy of $1 million in 2013, $14 million in 2012 and $3 million in 2011.

UED did not pay any dividends to UNS Energy in 2013 or 2012. UED paid dividends to UNS Energy of $39 million in 2011, of which $28 million represented a return of capital.

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

Common Stock Dividends and Price Ranges

	2013						2012
	Market Price per						Market Price per
	Share of Common				Dividends		Share of Common				Dividends
	Stock (1)				Declared		Stock (1)				Declared
Quarter:	High		Low				High		Low
First	$	49.13	$	43.10	$	0.435	$	38.66	$	35.83	$	0.43
Second	51.54		42.51		0.435		38.86		35.20		0.43
Third	51.86		43.81		0.435		42.71		38.43		0.43
Fourth	60.02		45.30		0.435		43.56		39.02		0.43
Total					$	1.74					$	1.72

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

Convertible Senior Notes

See Note 6.

Issuer Purchases of Common Equity

UNS Energy did not purchase any shares of Common Stock during 2013, 2012, or 2011.

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ITEM 6. – SELECTED FINANCIAL DATA

UNS Energy

	2013			2012			2011			2010			2009
	In Thousands (Except per Share Data)
Income Statement Data
Operating Revenues	$	1,484,560		$	1,461,766		$	1,478,702		$	1,425,947		$	1,396,606
Net Income	127,478			90,919			109,975			112,984			105,901
Basic Earnings Per Share	3.06			2.25			2.98			3.10			2.95
Diluted Earnings Per Share	3.04			2.20			2.75			2.86			2.73
Shares of Common Stock Outstanding:
Weighted Average	41,618			40,362			36,962			36,415			35,858
End of Year	41,538			41,344			36,918			36,542			35,851
Cash Dividends Declared per Share	$	1.74		$	1.72		$	1.68		$	1.56		$	1.16
Balance Sheet Data
Total Utility Plant – Net	$	3,534,837		$	3,300,363		$	3,182,263		$	2,961,498		$	2,785,714
Total Investments in Lease Debt and Equity	36,194			45,457			65,829			103,844			132,168
Other Investments and Other Property	34,971			36,537			34,205			61,676			60,239
Total Assets	4,273,069			4,140,429			3,989,279			3,796,246			3,615,211
Long-Term Debt	$	1,507,070		$	1,498,442		$	1,517,373		$	1,352,977		$	1,307,795
Non-Current Capital Lease Obligations	149,767			262,138			352,720			429,074			488,349
Common Stock Equity	1,130,784			1,065,465			888,474			830,756			759,329
Total Capitalization	2,787,621			2,826,045			2,758,567			2,612,807			2,555,473
Cash Flow Data
Net Cash Flows From Operating Activities	$	420,512		$	348,109		$	337,320		$	346,920		$	347,310
Capital Expenditures	(325,886		)	(307,277		)	(374,122		)	(330,629		)	(294,020		)
Net Cash Flows From Financing Activities	(135,742		)	(37,682		)	(1,441		)	(51,183		)	(28,916		)
Ratio of Earnings to Fixed Charges (1)	2.77			2.30			2.43			2.62			2.46

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TEP

	2013			2012			2011			2010			2009
	Thousands of Dollars
Income Statement Data
Operating Revenues	$	1,196,690		$	1,161,660		$	1,156,386		$	1,125,267		$	1,099,338
Net Income	101,342			65,470			85,334			108,260			90,688
Balance Sheet Data
Total Utility Plant – Net	$	2,944,455		$	2,750,421		$	2,650,652		$	2,410,077		$	2,261,325
Total Investments in Lease Debt and Equity	36,194			45,457			65,829			103,844			132,168
Other Investments and Other Property	33,488			35,091			32,313			43,588			31,813
Total Assets	3,556,060			3,461,046			3,277,661			3,078,411			2,924,108
Long-Term Debt	1,223,070			1,223,442			1,080,373			1,003,615			903,615
Non-Current Capital Lease Obligations	149,767			262,138			352,720			429,074			488,311
Common Stock Equity	925,923			860,927			824,943			709,884			650,591
Total Capitalization	2,298,760			2,346,507			2,258,036			2,142,573			2,042,517
Cash Flow Data
Net Cash Flows From Operating Activities	$	346,191		$	267,919		$	268,294		$	302,483		$	268,064
Capital Expenditures	(252,848		)	(252,782		)	(351,890		)	(277,309		)	(240,079		)
Net Cash Flows From Financing Activities	(140,937		)	11,987			51,452			(51,882		)	(29,320		)
Ratio of Earnings to Fixed Charges(1)	2.67			2.10			2.40			2.74			2.56

⁽¹⁾  For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount, interest on operating lease payments, and expense on indebtedness.

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

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

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

• outlook and strategies;

• operating results during 2013 compared with 2012, and 2012 compared with 2011;

• factors affecting our results and outlook;

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

• dividends; and

• critical accounting estimates.

UNS ENERGY CORPORATION

UNS Energy is a utility services holding company engaged, through its primary subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of TEP and UES.

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

OUTLOOK AND STRATEGIES

Agreement and Plan of Merger

In December 2013, UNS Energy entered into an Agreement and Plan of Merger with Fortis Parent, Fortis and Merger Sub. The Boards of Directors of each of UNS Energy and Fortis Parent have approved the Merger. At the completion of the Merger, each outstanding share of UNS Energy common stock will be converted into the right to receive $60.25 in cash and UNS Energy will become a wholly-owned subsidiary of Fortis.

The Merger is subject to the approval of stockholders holding a majority of the outstanding shares of UNS Energy and other customary closing conditions, including, among other things:

• the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

• approvals of the Arizona Corporation Commission and the Federal Energy Regulatory Commission;

• confirmation of review, without unresolved concerns, from the Committee on Foreign Investment in the United States; and

• the absence of any injunction, order or other law prohibiting the Merger.

On February 18, 2014, we filed definitive proxy materials with the SEC. We expect UNS Energy's shareholders to formally consider a proposal to approve the Merger Agreement at a meeting on March 26, 2014.

In January 2014, UNS Energy and Fortis Parent filed an application and supporting testimony with the ACC requesting approval of the Merger. The ACC administrative law judge (ALJ) assigned to this matter issued a procedural order that calls for settlement discussions to commence on April 28, 2014, and a hearing before the ALJ to commence on June 16, 2014. In February 2014, we filed an application with FERC requesting approval of the Merger. The Merger is expected to close by the end of 2014. If the Merger is completed, UNS Energy expects to record approximately $22 million of expenses related to the Merger in 2014.

Operating Plans and Strategies

Our 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:

• Completing the proposed Merger with Fortis including obtaining all necessary approvals;

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• Completing the purchases of Gila River Unit 3 and additional interests in Springerville Unit 1, which are both key components of our long-term diversification strategy for our generating portfolio. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.

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

• Developing strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas emissions. We are evaluating TEP's existing mix of generation resources and defining steps to achieve environmental objectives that protect the financial stability of our utility businesses.

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

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

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

RESULTS OF OPERATIONS

Contribution by Business Segment

The table below shows the contributions to our consolidated net income by business segment:

	2013		2012		2011
	Millions of Dollars
TEP	$	101	$	65	$	85
UNS Electric	12		17		18
UNS Gas	11		9		10
Other Non-Reportable Segments and Adjustments (1)	3		—		(3		)
Consolidated Net Income	$	127	$	91	$	110

⁽¹⁾  Includes: UNS Energy parent company expenses; Millennium; UED; and inter-company eliminations.

Executive Overview

2013 Compared with 2012

TEP

TEP reported net income of $101 million in 2013 compared with net income of $65 million in 2012. The increase in net income is due in part to: a $41 million increase in retail margin revenues related to a non-fuel base rate increase that was effective on July 1, 2013 and higher retail kWh sales resulting from favorable weather conditions; a $2 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; and a $9 million decrease in interest expense due in part to a reduction in capital lease obligation balances; partially offset by a $12 million increase in Base O&M due in part to planned and unplanned maintenance on TEP's generating facilities, as well as merger-related expenses of $6 million recorded in December 2013; and a $3 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

Additionally, TEP's net income in 2013 includes an income tax benefit of $11 million. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated. See Note 9. TEP's 2013 results also include additional fuel expense of $3 million related to a one-time credit to customers resulting from the 2013 TEP Rate Order. TEP's results in 2012 reflect a $3 million reduction

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to pre-tax income due to an unplanned outage at Springerville Unit 3 and a $5 million write-off of transmission related assets. See Tucson Electric Power Company, Results of Operations.

UNS Electric

UNS Electric reported net income of $12 million in 2013 compared with net income of $17 million in 2012. The decrease in net income was due in part to lower mining kWh sales during 2013 and the loss of an industrial customer in the second half of 2012. See UNS Electric, Results of Operations.

UNS Gas

UNS Gas reported net income of $11 million in 2013 compared with net income of $9 million in 2012. The increase in net income is due primarily to: higher sales volumes resulting from cold weather, which contributed to an improvement in retail margin revenues; and a non-fuel base rate increase that was effective in May 2012. See UNS Gas, Results of Operations.

2012 Compared with 2011

TEP

TEP reported net income of $65 million in 2012 compared with $85 million in 2011. The decrease in net income was due primarily to: a $7 million decline in retail margin revenues resulting from lower retail kWh sales due to milder summer weather than 2011, as well as the effects of the ACC’s energy efficiency and distributed generation requirements; an $8 million decline in long-term wholesale margin revenues resulting primarily from a change in the pricing of energy sold under the SRP wholesale contract that was effective on June 1, 2011; an $11 million increase in depreciation and amortization expense as a result of an increase in utility plant-in-service; and a $5 million decrease in pre-tax income related to the partial write-off of transmission-related assets. These factors were partially offset by a decrease in TEP’s Base O&M, resulting primarily from fewer planned generating plant outages. Net income in 2011 included the recognition of a $7 million pre-tax gain related to the settlement of a dispute with El Paso Electric. See Tucson Electric Power, Results of Operations.

UNS Electric and UNS Gas

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

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

Operations and Maintenance Expense

The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense. In 2013, Base O&M includes merger-related expenses of $7 million.

	2013		2012		2011
	Millions of Dollars
UNS Energy Base O&M (Non-GAAP)(1)	$	288	$	266	$	271
Reimbursed Expenses Related to Springerville Units 3 and 4	70		72		63
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs(2)	32		46		45
Total UNS Energy O&M (GAAP)	390		$	384	$	379

⁽¹⁾  Base O&M, a non-GAAP financial measure, should not be considered as an alternative to O&M, which is determined in accordance with generally accepted accounting principles (GAAP). We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties.

⁽²⁾  Represents expenses related to customer-funded renewable energy and DSM programs; these expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

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LIQUIDITY AND CAPITAL RESOURCES

UNS Energy Consolidated Liquidity

Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, UNS Energy will use, as needed, its revolving credit facility to assist in funding its business activities. The table below provides a summary of the liquidity position of UNS Energy and each of its segments:

Balances at December 31, 2013	Cash and  Cash Equivalents		Borrowings under Revolving Credit Facility(1)		Amount Available under Revolving Credit Facility
	Millions of Dollars
UNS Energy Stand-Alone	$	9	$	54	$	71
TEP	25		1		199
UNS Electric(2)	5		22		48
UNS Gas(2)	33		—		70
Other(3)	3		N/A		N/A
Total	$	75

⁽¹⁾  Includes Letters of Credit (LOCs) issued under revolving credit facilities.

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

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

In March 2014, TEP expects to issue a $15 million LOC to a subsidiary of Entegra to satisfy a condition of the Gila River Unit 3 purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement will be reduced by $15 million until the Gila River transaction closes and the LOC is terminated.

Dividends from UNS Energy’s subsidiaries represent the parent company’s main source of liquidity.

Dividends from Subsidiaries

UNS Energy received $40 million in dividends from TEP and $10 million in dividends from each of UNS Electric and UNS Gas in 2013, and $1 million from Millennium. In 2012, UNS Energy received dividends of $30 million from TEP, $20 million from UNS Gas, $14 million from Millennium, and $10 million from UNS Electric.

Short-term Investments

UNS Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update this policy in response to market conditions. At December 31, 2013, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit.

Access to Revolving Credit Facilities

We have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP Revolving Credit Facility and UNS Electric/UNS Gas Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Electric, and UNS Gas each issue LOCs from time to time to provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs for general corporate purposes.

We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. However, TEP will need to issue long-term debt or enter into additional short-term credit facilities by June 2014 to meet capital expenditure requirements and scheduled mid-year capital lease payments. See Item 7A Quantitative and Qualitative Disclosures about Market Risk.

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UNS Energy Consolidated Cash Flows

	Years Ended December 31,
	2013			2012			2011
	Millions of Dollars
Operating Activities	$	421		$	348		$	337
Investing Activities	(334		)	(263		)	(327		)
Financing Activities	(136		)	(37		)	(2		)
Net Increase (Decrease) in Cash	(49		)	48			8
Beginning Cash	124			76			68
Ending Cash	$	75		$	124		76

UNS Energy’s operating cash flows are generated primarily by retail and wholesale energy sales at TEP, UNS Electric, and UNS Gas, net of the related payments for fuel and purchased power. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer-peaking load. TEP, UNS Electric, and UNS Gas typically use their revolving credit facilities to assist in funding their business activities during periods when sales are seasonally lower.

Capital expenditures at TEP, UNS Electric, and UNS Gas represent the primary use of cash for investing activities.

Cash used for investing and financing activities can fluctuate year-to-year depending on: capital expenditures; repayments and borrowings under revolving credit facilities; debt issuances or retirements; capital lease payments by TEP; and dividends paid by UNS Energy to its shareholders.

Operating Activities

In 2013, net cash flows from operating activities were $73 million higher than they were in 2012. The following items affected the year-over-year change in operating cash flows: a $23 million increase in cash receipts from retail and wholesale sales, net of fuel and purchased power costs paid, due to a non-fuel base rate increase that became effective on July 1, 2013, an increase in sales volumes from warmer weather compared to 2012, and higher market prices for wholesale power; a $27 million decrease in operations and maintenance costs and wages paid, net of amounts capitalized, due in part to renewable prepayments made in 2012; and a $6 million decrease in interest paid on capital lease obligations due to a decline in the balance of capital lease obligations.

Investing Activities

Net cash flows used for investing activities increased $71 million in 2013 compared with 2012 due in part to: a $19 million increase in capital expenditures; a $17 million increase in REC purchases due to an increase in renewable energy PPAs; a $15 million decrease in proceeds from a note receivable; and a $10 million decrease in the return of investment in Springerville lease debt.

Capital Expenditures

	Actual		Estimated
	2013		2014		2015		2016		2017		2018
	Millions of Dollars
TEP	$	253	$	528	$	469	$	223	$	276	$	218
UNS Electric	56		95		39		33		37		49
UNS Gas	17		13		13		14		15		16
UNS Energy Consolidated	$	326	$	636	$	521	$	270	$	328	$	283

TEP's estimated capital expenditures include:

• $164 million for the purchase of 75% of Gila River Unit 3 in 2014;

• $65 million for the purchase of 35.4% of Springerville Unit 1 in 2014 and 2015, and $73 million for TEP's share of the expected purchase of interests in the Springerville Coal Handling facilities in April 2015;

• $147 million for TEP-related transmission investments during 2014 and 2015;

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• $35 million for TEP's share of potential environmental expenditures related to the installation of SNCR at San Juan Unit 1. See Item 1 Business, TEP, Environmental Matters andNote 7; and

• $38 million for TEP's share of the expected purchase of the Springerville Common Facilities upon the expiration of one of the two leases in 2017.

UNS Electric's estimated capital expenditures include the purchase of 25% of Gila River Unit 3 for approximately $55 million in 2014.

These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to changes in business conditions, construction schedules, environmental requirements, state or federal regulations and other factors. See Tucson Electric Power Company, Liquidity and Capital Resources, Investing Activities, Capital Expenditures.

Financing Activities

Net cash flows used for financing activities were $98 million higher in 2013 when compared with 2012 due to: a $10 million increase in scheduled capital lease payments; a $3 million increase in dividends paid on Common Stock; and the issuance of $150 million of long-term debt by TEP in 2012.

Capital Contributions

UNS Energy made no capital contributions to its subsidiaries in 2013 and 2012.

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

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

See  Tucson Electric Power Company, Liquidity and Capital Resources.

UNS Credit Agreement

The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. At December 31, 2013, there was $54 million outstanding at a weighted-average interest rate of 1.66%. The UNS Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UNS Credit Agreement also requires UNS Energy to meet a minimum cash flow to debt service coverage ratio determined on a UNS Energy stand-alone basis. Additionally, UNS Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UNS Credit Agreement, UNS Energy may pay dividends so long as it maintains compliance with the agreement. UNS Energy’s obligations under the agreement are secured by a pledge of the common stock of Millennium, UES, and UED.

At December 31, 2013, we were in compliance with the terms of the UNS Credit Agreement.

Interest Rate Risk

UNS Energy is subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. UNS Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if LIBOR and other benchmark interest rates increase. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

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Contractual Obligations

The following chart displays UNS Energy’s consolidated contractual obligations by maturity and by type of obligation as of December 31, 2013:

	UNS Energy Contractual Obligations
Payment Due in Years Ending December 31,	2014		2015		2016		2017		2018		Thereafter		Other		Total
	Millions of Dollars
Long-Term Debt
Principal(1)	$	—	$	130	$	132	$	—	$	100	$	1,146	$	—	$	1,508
Interest(2)	67		66		61		60		61		480		—		795
Capital Lease Obligations(3)	214		69		17		18		11		30		—		359
Operating Leases	4		4		3		2		2		14		—		29
Purchase Obligations(4):
Fuel(5)	103		83		80		75		49		345		—		735
Purchased Power	75		17		—		—		—		—		—		92
Transmission	7		13		12		12		11		27		—		82
Renewable Power Purchase Agreements (6)	36		37		37		37		37		485				669
RES Performance-Based Incentives(7)	9		9		9		9		9		85		—		130
Acquisition of Springerville Coal Handling & Common Facilities(8)	—		120		—		38		—		68		—		226
Other Long-Term Liabilities(9):
Pension & Other Post Retirement Obligations(10)	17		6		6		6		6		33		—		74
Unrecognized Tax Benefits	—		—		—		—		—		—		4		4
Total Contractual Obligations	$	532	$	554	$	357	$	257	$	286	$	2,713	$	4	$	4,703

⁽¹⁾  Certain of TEP’s variable rate industrial development revenue bonds (IDBs) or pollution control revenue bonds are secured by LOCs issued pursuant to the TEP Credit Agreement, which expires in 2016, and the 2010 TEP Reimbursement Agreement, which expires in 2019. Although the $115 million of variable rate bonds mature between 2022 and 2032, the above maturity reflects a redemption or repurchase of such bonds as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement in 2016 (that supports $78 million of variable rate bonds) and the 2010 TEP Reimbursement Agreement in 2019 (that supports $37 million of variable rate bonds). Additionally, TEP's 2013 variable-rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. Excludes approximately $1 million of debt discount.

⁽²⁾  Excludes interest on revolving credit facilities and includes interest on TEP's 2013 tax-exempt IDBs through the end of the current five-year term.

⁽³⁾  Capital lease obligations include the purchase of Springerville Unit 1 in December 2014 and January 2015. See Note 6. Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP are reimbursing TEP for various operating costs related to the common facilities on an ongoing basis, including a total of $14 million annually related to the Springerville Common and Springerville Coal Handling Facilities Leases. TEP remains the obligor under these capital leases, and Capital Lease Obligations do not reflect any reduction associated with this reimbursement.

⁽⁴⁾  Excludes the acquisition of Gila River Unit 3 pending regulatory approvals. See Note 8.

⁽⁵⁾  Excludes TEP’s liability for final environmental reclamation at the coal mines which supply the Navajo, San Juan and Four Corners generating stations as the timing of payment has not been determined. See Note 7.

⁽⁶⁾  TEP and UNS Electric have entered into 20-year PPAs with renewable energy generation producers to comply with the RES tariff. TEP and UNS Electric are obligated to purchase 100% of the output of these facilities. The table above includes estimated future payments based on expected power deliveries under these contracts. TEP and UNS Electric have entered into additional long-term renewable PPAs to comply with the RES; however, TEP's and UNS Electric's obligations to accept and pay for electric power under these agreements does not begin until the facilities are operational.

⁽⁷⁾  TEP and UNS Electric have entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance Based Incentives (PBIs) and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 3.

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⁽⁸⁾  TEP has agreed with the owners of Springerville Units 3 and 4 that, prior to expiration of the Springerville Coal Handling Facilities and Common Facilities Leases, TEP will either renew such leases or exercise its fixed price purchase option under such leases and acquire the leased facilities. TEP has the option of purchasing the facilities at the end of the initial lease term or after one or more renewal periods through 2025 for the Springerville Common Facilities and through 2035 for the Springerville Coal Handling Facilities. The table above reflects the purchase as if TEP exercised the fixed price purchase option at the end of the initial lease term. Upon such acquisitions by TEP, the owner of Springerville Unit 3 and the owner of Springerville Unit 4 have the obligation to purchase from TEP a 17% interest in the Springerville Coal Handling Facilities and a 14% interest in the Springerville Common Facilities.

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

⁽¹⁰⁾  These obligations represent TEP’s and UES’ expected contributions to pension plans in 2014, TEP’s expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP), and TEP’s expected retiree benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. TEP and UES do not know and have not included pension and retiree benefit contributions beyond 2014 for their funded plans due to the significant impact that returns on plan assets and changes in discount rates might have on such amounts.

We have reviewed our contractual obligations and provide the following additional information:

• We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.

• None of our contracts or financing arrangements contains acceleration clauses or other consequences triggered by changes in our stock price.

Income Tax Position

The 2010 Federal Tax Relief Act and the American Taxpayer Relief Act of 2012 include provisions that make qualified property placed in service between 2010 and 2013 eligible for bonus depreciation for tax purposes. In addition, the IRS issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits UNS Energy and TEP otherwise would have received over 20 years. As a result of these provisions, UNS Energy and TEP do not expect to pay any federal or state income taxes through 2017.

TUCSON ELECTRIC POWER COMPANY

RESULTS OF OPERATIONS

TEP’s financial condition and results of operations are the principal factors affecting the financial condition and results of operations of UNS Energy. The following discussion relates to TEP, unless otherwise noted.

2013 compared with 2012

TEP reported net income of $101 million in 2013 compared with net income of $65 million in 2012. The following factors affected TEP’s results in 2013:

• a $41 million increase in retail margin revenues due to a non-fuel base rate increase that was effective on July 1, 2013, $2 million of LFCR revenues recorded in the fourth quarter of 2013, and favorable weather during 2013 compared with the same period last year. Favorable weather conditions contributed to a 0.2% increase in retail kilowatt-hour (kWh) sales during 2013;

• a $2 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;

• a $3 million increase in pre-tax income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in 2012;

• a $9 million decrease in interest expense due to a reduction in the balance of capital lease obligations;

• an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. See Note 9; and

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• a $5 million increase in pre-tax income as a result of the 2012 write-off of a portion of the planned Tucson to Nogales transmission line;

partially offset by

• a charge of $3 million recorded to fuel and purchased energy expense resulting from the 2013 TEP Rate Order. See Factors Affecting Results of Operations, Purchased Power and Fuel Adjustor Clause, below;

• a $12 million increase in Base O&M due in part to higher planned and unplanned generating plant maintenance expense, as well as merger-related expenses of $6 million recorded in December 2013; and

• a $3 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

2012 compared with 2011

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

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

• an $8 million decline in long-term wholesale margin revenues resulting primarily from a change in the pricing of energy sold under the SRP wholesale contract effective June 1, 2011;

• a $3 million decrease in pre-tax income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in 2012;

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

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

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

partially offset by

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

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Utility Sales and Revenues

The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during 2013, 2012, and 2011:

	2013		2012		Percent(1)		2011	Percent(1)
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	3,867		3,821		1.2	%	3,888	(1.7	)%
Commercial(2)	2,187		2,187		—	%	2,184	0.2	%
Industrial	2,114		2,132		(0.9	)%	2,145	(0.6	)%
Mining	1,079		1,093		(1.2	)%	1,083	0.9	%
Other(2)	32		32		1.6	%	32	0.7	%
Total Electric Retail Sales	9,279		9,265		0.2	%	9,332	(0.7	)%
Retail Margin Revenues (in Millions):
Residential	$	271	$	248	9.3	%	252	(1.4	)%
Commercial	181		171		5.9	%	170	0.5	%
Industrial	97		93		5.4	%	95	(2.5	)%
Mining	34		30		11.5	%	32	(3.8	)%
Other	2		2		5.9	%	2	(15.0	)%
Total Retail Margin Revenues (Non-GAAP)(3)	585		544		7.7	%	551	(1.2	)%
Fuel and Purchased Power Revenues	300		327		(8.1	)%	307	6.5	%
RES, DSM, ECA and LFCR Revenues	49		45		6.8	%	46	(2.6	)%
Total Retail Revenues (GAAP)	$	934	$	916	2.0	%	904	1.3	%
Average Retail Margin Rate (Cents / kWh):(1)
Residential	7.02		6.50		8.0	%	6.48	0.3	%
Commercial	8.28		7.82		5.9	%	7.80	0.3	%
Industrial	4.61		4.33		6.5	%	4.42	(2.0	)%
Mining	3.14		2.78		12.9	%	2.92	(4.8	)%
Other	5.56		5.34		4.1	%	6.32	(15.5	)%
Average Retail Margin Revenue	6.31		5.87		7.5	%	5.90	(0.5	)%
Average Fuel and Purchased Power Revenue	3.24		3.52		(8.0	)%	3.29	7.0	%
Average RES, DSM, ECA and LFCR Revenue	0.52		0.49		6.1	%	0.50	(2.0	)%
Total Average Retail Revenue	10.07		9.88		1.9	%	9.69	2.0	%
Weather Data:
Cooling Degree Days
Year Ended December 31,	1,631		1,556		4.8	%	1,528	1.8	%
10-Year Average	1,491		1,484		NM		1,473	NM
Heating Degree Days
Year Ended December 31,	1,449		1,201		20.6	%	1,597	(24.8	)%
10-Year Average	1,404		1,394		NM		1,417	NM

⁽¹⁾  Calculated on un-rounded data and may not correspond exactly to data shown in table.

⁽²⁾  Retail kWh sales to commercial and other customers for 2012 and 2011 have been adjusted to reflect a change in the methodology for counting customers resulting from rate design changes from the 2013 TEP Rate Order.

⁽³⁾  Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

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2013 compared with 2012

Residential

Residential kWh sales were 1.2% higher in 2013 due in part to favorable weather conditions compared with 2012. A non-fuel base rate increase effective July 1, 2013 and higher sales volumes led to an increase in residential margin revenues of 9.3%, or $23 million. The average number of residential customers grew by 0.7% in 2013 compared with 2012.

Commercial

Commercial kWh sales were the same when compared with 2012. A non-fuel base rate increase effective July 1, 2013 contributed to an increase in commercial margin revenues of 5.9%, or $10 million.

Industrial

Industrial kWh sales decreased by 0.9% compared with 2012. Lower sales due to certain customers changing their usage patterns were more than offset by a non-fuel base rate increase effective July 1, 2013, which led to an increase in industrial margin revenues of $4 million.

Mining

Mining kWh sales decreased by 1.2% compared with 2012. One of TEP's mining customers performed maintenance on its facilities resulting in a temporary decrease in production. A non-fuel base rate increase effective July 1, 2013 led to an increase in margin revenues from mining customers of 11.5%, or $4 million. See Factors Affecting Results of Operations, Sales to Mining Customers.

2012 compared with 2011

Residential

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

Residential margin revenues in 2012 decreased by $4 million when compared with 2011.

Commercial

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

Industrial

Industrial kWh sales decreased by 0.6% in 2012 compared with 2011, while margin revenues declined by 2.5%. The decline in margin revenues resulted from a change in usage patterns by certain industrial customers that reduced their demand charges paid to TEP.

Mining

The continuation of high copper prices led to increased mining activity, resulting in a 0.9% increase in sales volumes in 2012 compared with 2011. However, margin revenues from mining customers decreased by 3.8% compared with 2011, due to changing usage patterns which resulted in lower demand charges paid to TEP.

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Wholesale Sales and Transmission Revenues

	2013		2012		2011
	Millions of Dollars
Long-Term Wholesale Revenues:
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)	$	7	$	5	$	13
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues	19		20		28
Total Long-Term Wholesale Revenues	26		25		41
Transmission Revenues	15		16		16
Short-Term Wholesale Revenues	92		70		73
Electric Wholesale Sales (GAAP)	$	133	$	111	$	130

⁽¹⁾  Long-term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change in Long-Term Wholesale Margin Revenues between periods provides useful information to investors because it demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business.

Long-Term Wholesale Margin Revenues in 2013 were higher when compared with 2012 due in part to higher market prices for wholesale power. Long-Term Wholesale Margin Revenues in 2012 were lower when compared with 2011 due to a change in the pricing of energy sold under the SRP contract. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, below.

Short-Term Wholesale Revenues

All revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.

Other Revenues

	2013		2012		2011
	Millions of Dollars
Revenue related to Springerville Units 3 and 4(1)	$	102	$	101	$	97
Other Revenue	28		33		26
Total Other Revenue	$	130	$	134	$	123

⁽¹⁾ Represents revenues and reimbursements from Tri-State and SRP, owners of Springerville Units 3 and 4, respectively, to TEP related to the operation of these plants.

In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include inter-company revenues from UNS Gas and UNS Electric for corporate services provided by TEP, and miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees.

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Operating Expenses

Fuel and Purchased Power Expense

TEP’s fuel and purchased power expense and energy resources for 2013, 2012 and 2011 are detailed below:

	Generation and Purchased Power						Fuel and Purchased Power Expense
	2013		2012		2011		2013			2012		2011
	Millions of kWh						Millions of Dollars
Coal-Fired Generation	10,254		9,702		9,946		$	273		$	247	$	254
Gas-Fired Generation	1,007		1,435		929		46			65		55
Renewable Generation	38		45		28		—			—		—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		—		7			7		8
Total Fuel	11,299		11,182		10,903		326			319		317
Total Purchased Power	2,329		2,328		2,687		112			80		106
Transmission and Other PPFAC Recoverable Costs	—		—		—		12			6		(1		)
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		—		(12		)	31		(6		)
Total Resources	13,628		13,510		13,590		$	438		$	436	$	416
Less Line Losses and Company Use	(885	)	(839	)	(786	)
Total Energy Sold	12,743		12,671		12,804

Generation

Total generating output increased in 2013 when compared with 2012 due in part to higher retail kWh sales than the same period last year. Coal-fired generation increased by 6% in 2013 when compared with 2012 due in part to the use of coal to fuel Sundt Unit 4 instead of natural gas.

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

	2013	2012	2011
	cents per kWh
Coal	2.66	2.54	2.56
Gas	4.57	4.54	5.99
Purchased Power	4.83	3.44	3.94
All Sources	3.54	3.19	3.30

O&M

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

	2013			2012			2011
	Millions of Dollars
Base O&M (Non-GAAP)(1)	$	246		$	234		$	238
O&M Recorded in Other Expense	(7		)	(6		)	(8		)
Reimbursed Expenses Related to Springerville Units 3 and 4	70			72			63
Expenses Related to Customer Funded Renewable Energy and DSM Programs(2)	26			35			38
Total O&M (GAAP)	$	335		$	335		$	331

⁽¹⁾  Base O&M is a non-GAAP financial measure and should not be considered as an alternative to O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is O&M less reimbursed expenses and expenses related to customer-funded renewable energy and DSM programs, provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business.

⁽²⁾  Represents expenses related to customer-funded renewable energy and DSM programs; these expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

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The table below summarizes TEP’s pension and other retiree benefit expenses included in TEP's Base O&M in 2013, 2012, and 2011. See Note 10.

	2013		2012		2011
	Millions of Dollars
Pension Expense Charged to O&M	$	10	$	10	$	10
Retiree Benefit Expense Charged to O&M	5		5		4
Total	$	15	$	15	$	14

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 TEP Rate Order

In June 2013, the ACC issued an order (2013 TEP Rate Order) that resolved the rate case filed by TEP in July 2012, which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

The provisions of the 2013 TEP Rate Order include, but are not limited to:

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

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

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

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

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

• a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant regulated by the ACC, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11 million annually; and

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

The 2013 TEP Rate Order also approved the following cost recovery mechanisms:

• A Lost Fixed Cost Recovery mechanism (LFCR) that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to energy efficiency programs and distributed generation. The LFCR rate will be adjusted annually and is subject to ACC review and a year-over-year cap of 1% of TEP's total retail revenues. TEP expects to file its first LFCR report with the ACC on or before May 15, 2014. We expect the new LFCR rate to become effective on July 1, 2014. TEP’s 2015 LFCR report may include an estimated $6 million to $8 million of unrecovered non-fuel costs incurred during 2014. In the fourth quarter of 2013, TEP recorded LFCR revenues of $2 million for unrecovered non-fuel costs incurred during 2013.

• An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA will be adjusted annually to recover environmental compliance costs and is subject to ACC approval and a cap of $0.00025 per kWh, which approximates 0.25% of TEP's total retail revenues. TEP expects to file its first ECA report on or before March 1, 2014. That report will include qualified investments and costs to be included in the ECA. TEP expects the new ECA rate to become effective on May 1, 2014. We estimate that the ECA could benefit pre-tax income by less than $1 million in 2014.

• An energy efficiency provision which includes a 2013 calendar year budget to fund programs that support the ACC's Electric Energy Efficiency Standards (Electric EE Standards), as well as a performance incentive. See Electric Energy Efficiency Standards, below.

• A new rate under TEP's PPFAC. See Purchased Power and Fuel Adjustment Clause, below.

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Competition

Retail Electric Competition Rules

In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona.  Certain portions of the ACC Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004.  During 2012, several companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP's service territory as an ESP.  Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP's retail customers to use an alternative ESP.

In May 2013, the ACC voted to commence a process to consider the possibility of opening Arizona to retail electric competition. The first step in the process was to solicit comments on questions raised by the ACC on the potential benefits and risks to Arizona electric customers associated with retail electric competition. In July 2013, various parties, including TEP and UNS Electric, filed comments. TEP and UNS Electric oppose opening Arizona to retail electric competition. Responsive comments from the parties were filed in August 2013. In September 2013, the ACC voted to close the docket and did not take any steps to implement retail electric competition. We cannot predict if the ACC will consider retail electric competition in the future.

Technological Developments and Energy Efficiency

New technological developments and the implementation of Electric EE Standards have reduced energy consumption by TEP's retail customers. TEP's customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP's services.

Coal-Fired Generating Resources

At December 31, 2013, approximately 70% of TEP's generating capacity was fueled by coal (of which 120 MW can be converted to 156 MW of natural gas capacity at Sundt Unit 4). Existing and proposed federal environmental regulations, as well potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is evaluating various strategies for reducing the proportion of coal in its fuel mix. TEP's ability to reduce its coal-fired generating capacity will depend on several factors, including, but not limited to:

• the resolution of the non-binding agreement between the State of New Mexico, the EPA, and PNM as it relates to San Juan, see Note 7;

• TEP's future ownership interest in Springerville Unit 1, see Springerville Unit 1; and

• the potential purchase of a combined cycle natural gas plant, see Gila River Generating Station Unit 3.

Springerville Unit 1

TEP leases 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 are accounted for as capital leases. The leases expire in January 2015 and include fair market value renewal and purchase options. In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 MW of capacity.

In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a capacity rating of 387 MW.

In August 2013, TEP notified certain owner participants and their lessors that TEP elected to purchase their undivided ownership interests in Springerville Unit 1, at the appraised value upon the expiration of the lease term in January 2015. In total, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million.

In October 2013, TEP agreed to purchase an additional 10.6% leased interest in Springerville Unit 1 for $20 million, the appraised value, with the purchase scheduled to occur in December 2014. The 10.6% ownership interest represents 41 MW of capacity.

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Upon the close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of capacity. Due to TEP’s purchase commitments, TEP and UNS Energy recorded an increase to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets in the aggregate amount of approximately $55 million.

TEP does not expect that its final undivided ownership interest in Springerville Unit 1 will exceed 49.5%, or 192 MW of capacity. The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, will be owned by third parties. TEP is not obligated to purchase any of the remaining power from Springerville Unit 1; however, TEP is obligated to operate Springerville Unit 1 for the remaining third-party owners following the expiration of the leases. TEP expects to replace the 195 MW of expiring leased capacity with the purchase of Gila River Unit 3. See Gila River Generating Station Unit 3, below.

Gila River Generating Station Unit 3

In December 2013, TEP and UNS Electric entered into an agreement (the Purchase Agreement) to purchase Gila River Unit 3 for $219 million from a subsidiary of Entegra. The purchase price is subject to adjustments to prorate certain fees and expenses through the closing and in respect of certain operational matters. It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014.

The Purchase Agreement is subject to, among other things:

• the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

• the approval of the FERC;

• an amendment satisfactory to TEP, UNS Electric and the owners of the other units of the Gila River Power Station of the agreement with the other unit owners to address the ownership, operations and maintenance of common facilities and future generation located at the station;

• the completion of certain other agreements associated with the operation of Gila River Unit 3; and

• other customary closing conditions.

TEP expects to provide a letter of credit in March 2014 for $15 million to satisfy a condition of the Purchase Agreement. The seller of Gila River Unit 3 would be entitled to draw upon the letter of credit and apply such amount as liquidated damages if it has validly terminated the Purchase Agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the letter of credit would be canceled.

The purchase of Gila River Unit 3, which would replace the expiring coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, is consistent with TEP's strategy to diversify its generation fuel mix. See Note 7.

In December 2013, UNS Electric filed an application requesting the ACC to approve an accounting order that would authorize UNS Electric to defer for future recovery specific non-fuel operating costs associated with its anticipated ownership of 25% of Gila River Unit 3. See UNS Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 8.

Springerville Units 3 and 4

TEP receives annual benefits in the form of rental payments and other fees and cost savings from operating Springerville Unit 3 on behalf of Tri-State and Unit 4 on behalf of SRP.

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

	2013			2012			2011
	Millions of Dollars
Other Revenues	$	102		$	101		$	97
Fuel Expense	(7		)	(7		)	(8		)
O&M Expense	(69		)	(72		)	(63		)
Taxes Other Than Income Taxes	(2		)	(1		)	(2		)

Long-Term Wholesale Sales

TEP’s two primary long-term wholesale contracts are with SRP and the Navajo Tribal Utility Authority (NTUA).

Salt River Project

From January 1, 2012, through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year. TEP does not receive a demand charge and the price of energy is based on a discount to the wholesale market price of on-peak power.

Navajo Tribal Utility Authority

TEP serves the portion of NTUA's load that is not served from NTUA's allocation of federal hydroelectric power. Over the last three years, sales to NTUA averaged 225,000 MWh. Prior to June 30, 2013, the power sold to NTUA was at a fixed price.  In May 2013, TEP amended its contract with NTUA and extended the contract term from December 2015 to December 2022.

As a result of the amendment, on July 1, 2013, TEP began receiving monthly capacity payments in exchange for providing 15 MW from July to September (June to September beginning in 2014 and thereafter) and 50 MW for the remainder of each year. Starting in 2016, the July to September capacity increases to 25 MW. TEP prices the energy sold to NTUA at its monthly PPFAC eligible cost rate. Any energy sold in excess of the seasonal capacity amounts will be indexed to the wholesale market price of natural gas.  TEP estimates that sales to NTUA will be approximately 225,000 MWh in 2014 and 2015.

Sales to Mining Customers

TEP's mining customers have indicated they are taking initial steps to increase production either through expansion of their current mining operations or by the re-opening of non-operational mine sites. If efforts to increase production are successful, TEP's mining load could increase by up to 100 MW over the next several years. The market price for copper and the ability to obtain necessary permits could affect the mining industry's expansion plans.

In addition to the mining customers that TEP currently serves, Augusta Resources Corporation filed a plan of operations with the United States Forest Service in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona.  The Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line for the construction and ongoing operation of the mine. The state line siting committee approved a Certificate of Environmental Compatibility (CEC) in 2011 for the 138 kV transmission line. In 2012, the ACC finalized the CEC. If the Rosemont Copper Mine is constructed and reaches full production, it would be expected to become TEP's largest retail customer, with TEP serving the mine's estimated load of approximately 85 MW.

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

Interest Rates

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under the TEP Revolving Credit Facility. At December 31, 2013, TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly or monthly. In 2013, the average rates paid ranged from 0.06% to 0.48%.

TEP has a fixed-for-floating interest rate swap to hedge $50 million of its tax-exempt variable rate debt.

TEP is also subject to interest rate risk resulting from changes in interest rates on its borrowings under the TEP Revolving Credit Facility. The interest paid on revolving credit borrowings is variable. If LIBOR and other benchmark interest rates

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increase, TEP may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

LIQUIDITY AND CAPITAL RESOURCES

TEP Cash Flows

The tables below show TEP's net cash flows after capital expenditures, scheduled lease debt payments, and payments on capital lease obligations:

	2013			2012			2011
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	346		$	268		$	268
Less: Capital Expenditures	(253		)	(253		)	(352		)
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)	93			15			(84		)
Less: Payments of Capital Lease Obligations	(100		)	(89		)	(74		)
Plus: Proceeds from Investment in Lease Debt	9			19			38
Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations (Non-GAAP)(1)	$	2		$	(55	)	$	(120	)

	2013			2012			2011
	Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)	$	346		$	268		$	268
Net Cash Flows – Investing Activities (GAAP)	(260		)	(228		)	(312		)
Net Cash Flows – Financing Activities (GAAP)	(141		)	12			52
Net Increase (Decrease) in Cash	(55		)	52			8
Beginning Cash	80			28			20
Ending Cash	$	25		$	80		$	28

⁽¹⁾  Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows—Operating Activities, which is determined in accordance with GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make required payments on lease debt and capital lease obligations, and pay dividends to UNS Energy before consideration of financing activities.

Liquidity Outlook

Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to assist in funding its business activities.

Additionally, due to capital expenditure requirements and scheduled mid-year lease payments, TEP will need to issue long-term debt or enter into additional short-term credit facilities by June 2014. Due to additional purchase commitments for Gila River Unit 3 and Springerville Unit 1, additional external financing will be needed by year-end 2014.

If the Merger Agreement is approved by all necessary parties, Fortis will contribute $200 million of equity capital to UNS Energy upon closing. If the contribution is made by December 2014, UNS Energy may then contribute this capital to TEP and UNS Electric to help fund the Gila River Unit 3 and Springerville Unit 1 purchase commitments.

Operating Activities

In 2013, net cash flows from operating activities were $78 million higher than in 2012. The increase was due primarily to: a $34 million increase in cash receipts from retail and wholesale sales, net of fuel and purchased power costs paid, resulting from a base rate increase that became effective on July 1, 2013, an increase in retail sales volumes, and an increase in wholesale power prices; a $30 million decrease in operations and maintenance costs paid due in part to lower renewable prepayments, lower incentive payments under DSM programs, and lower payments for remote plants; and a $6 million decrease in capital

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lease interest paid due to a decline in capital lease obligation balances; partially offset by a $6 million increase in wages paid (net of amounts capitalized).

Investing Activities

Net cash flows used for investing activities increased by $32 million in 2013 compared with 2012 due primarily to: a $14 million increase in purchases of RECs due to an increase in renewable energy PPAs; and $10 million in lower proceeds from investment in lease debt.

TEP’s capital expenditures were $253 million in each of 2013 and 2012.

TEP's forecasted capital expenditures are summarized below:

	2014	2015	2016	2017	2018
	Millions of Dollars
Transmission and Distribution	$135	$169	$84	$80	$81
Generation Facilities	109	101	63	83	61
Renewable Energy Generation	45	30	31	31	31
Springerville Lease Purchases(1)	20	119	—	38	—
Gila River Unit 3 Purchase	164	—	—	—	—
General and Other	55	50	45	44	45
Total	$528	$469	$223	$276	$218

⁽¹⁾   Includes: Springerville Unit 1 purchases of $65 million, $20 million in 2014, and $46 million in 2015; TEP's portion of the Springerville Coal Handling facilities purchase of $73 million in 2015; and Springerville Common facilities purchases of $38 million in 2017.

Financing Activities

In 2013, net cash from financing activities was $153 million lower than 2012. Financing activities in 2013 included a $10 million increase in dividend payments to UNS Energy and a $10 million increase in payments made on capital lease obligations. Financing activities in 2012 included: the issuance of $150 million of long-term debt; $7 million of repayments of long-term debt; and $10 million of repayments (net of borrowings) under the TEP Revolving Credit Facility.

TEP Mortgage Indenture

Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in Mortgage Bonds issued under the 1992 Mortgage. As a result of a credit rating upgrade, in October 2013, TEP (i) requested $423 million in Mortgage Bonds be returned to TEP for cancellation, and (ii) discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured. See Note 6.

TEP Credit Agreement

TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility and an $82 million LOC facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016.

In December 2013, TEP reduced its letter of credit facility from $186 million to $82 million, following the refinancing of $100 million of variable rate bonds and the cancellation of $104 million of LOCs supporting those bonds.

At December 31, 2013, there were no outstanding borrowings and $1 million of LOCs issued under the TEP Revolving Credit Facility.

In March 2014, TEP expects to issue a $15 million LOC to a subsidiary of Entegra to satisfy a condition of the Gila River Unit 3 purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement will be reduced by $15 million until the Gila River transaction closes and the LOC is terminated.

The TEP Credit Agreement contains restrictions on mergers and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UNS Energy. At December 31, 2013, TEP was in compliance with the terms of the TEP Credit Agreement. See Note 6.

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2010 TEP Reimbursement Agreement

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

In February 2014, TEP amended the 2010 TEP Reimbursement Agreement to extend the expiration date of the LOC from 2014 to 2019.

The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. At December 31, 2013, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement. See Note 6.

2013 Bond Issuances and Redemptions

In March 2013, approximately $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029 and may be redeemed at par on or after March 1, 2023. In April 2013, the proceeds of the bond issuance were used to redeem approximately $91 million of tax-exempt bonds with an interest rate of 6.375% and a maturity date of September 2029. See Note 6.

In November 2013, $100 million of unsecured tax-exempt industrial development revenue bonds were issued on behalf of TEP and sold in a private placement. The bonds bear interest at a variable rate, mature in April 2032, and may be redeemed at any time while the bonds are in variable rate mode and upon proper notice by TEP. Also in November 2013, TEP entered into a Lender Rate Mode Covenants Agreement (2013 Covenants Agreement), with the purchaser of the bonds. The 2013 Covenants Agreement contains covenants and events of default which are the same, in all material respects, as those in the TEP Credit Agreement, including restrictions on mergers and sale of assets and requiring TEP not to exceed a maximum leverage ratio.

Under the terms of the 2013 Covenants Agreement, TEP may pay dividends to UNS Energy so long as it maintains compliance with the agreement. In December 2013, the proceeds of the bond issuance were used to redeem $100 million of variable rate tax-exempt bonds with a maturity date of December 2018. See Note 6.

Capital Lease Obligations

At December 31, 2013, TEP had $317 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease obligations:

	Capital Lease  Obligation Balance As Of
Capital Leases	December 31, 2013		Expiration	Renewal/Purchase Option
	Millions of Dollars
Springerville Unit 1(1)	$	193	2015	Fair market value(2)
Springerville Coal Handling Facilities	28		2015	Fixed price purchase option of $120 million(3)
Springerville Common Facilities(4)	96		2017 and 2021	Fixed price purchase option of $106 million(3)
Total Capital Lease Obligations	$	317

⁽¹⁾  The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. The $193 million balance includes the present value of the lease purchase options elected and agreed to in August and October 2013. See Factors Affecting Results of Operations, Coal-Fired Generating Resources, Springerville Unit 1. Also see Note 6.

⁽²⁾  As determined in December 2011 in an appraisal procedure undertaken pursuant to the Springerville Unit 1 lease agreements. TEP elected and agreed to purchase certain interests in the Springerville Unit 1 lease agreements in August and October 2013. See Factors Affecting Results of Operations, Coal-Fired Generating Resources, Springerville Unit 1. Also see Note 6.

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

⁽⁴⁾  The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities.

TEP's capital lease obligation balances decline over time due to the normal capital lease payments made by TEP.

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Income Tax Position

See UNS Energy Consolidated, Liquidity and Capital Resources, Income Tax Position.

Contractual Obligations

The following chart displays TEP’s contractual obligations by maturity and by type of obligation as of December 31, 2013:

	TEP Contractual Obligations
Payment Due in Years Ending December 31,	2014		2015		2016		2017		2018		Thereafter		Other		Total
	Millions of Dollars
Long-Term Debt
Principal	$	—	$	—	$	78	$	—	$	100	$	1,046	$	—	$	1,224
Interest	54		53		54		53		54		443		—		711
Capital Lease Obligations	214		69		17		18		11		30		—		359
Operating Leases	3		3		2		2		2		14		—		26
Purchase Obligations(1):
Fuel	77		63		64		62		36		285		—		587
Purchased Power	27		5		—		—		—		—		—		32
Transmission	3		6		6		6		6		21		—		48
Renewable Power Purchase Agreements	30		31		31		31		31		410				564
RES Performance-Based Incentives	8		8		8		8		8		83		—		123
Acquisition of Springerville Coal Handling and Common Facilities	—		120		—		38		—		68		—		226
Other Long-Term Liabilities:
Pension & Other Post Retirement Obligations	15		6		6		6		6		33		—		72
Unrecognized Tax Benefits	—		—		—		—		—		—		2		2
Total Contractual Obligations	$	431	$	364	$	266	$	224	$	254	$	2,433	$	2	$	3,974

⁽¹⁾ Excludes the acquisition of Gila River Unit 3 pending regulatory approvals. See Note 8.

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

We have reviewed our contractual obligations and provide the following additional information:

• The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement contain pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings, and the amount of fees it pays for its LOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facility.

• The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement contain certain financial and other restrictive covenants, including a leverage test. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At December 31, 2013, TEP was in compliance with these covenants. See TEP Credit Agreement, above.

• TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of December 31, 2013, TEP had posted less than $1 million in LOCs as collateral with counterparties for credit enhancement.

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Dividends on Common Stock

TEP paid dividends to UNS Energy of $40 million in 2013 and $30 million in 2012. TEP did not pay any dividends to UNS Energy in 2011.

TEP can pay dividends to UNS Energy if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement. At December 31, 2013, TEP was in compliance with the terms of the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement.

UNS ELECTRIC

RESULTS OF OPERATIONS

UNS Electric reported net income of $12 million in 2013, $17 million in 2012, and $18 million in 2011. The decline in net income in 2013 is related to a reduction in mining kWh sales as well as the loss of an industrial customer during the fourth quarter of 2012.

Like TEP, UNS Electric’s operations are typically seasonal in nature, with peak energy demand occurring in the summer months. The table below provides summary financial information for UNS Electric:

	2013			2012			2011
	Millions of Dollars
Retail Electric Revenues	$	168		$	171		$	182
Wholesale Electric Revenues	6			17			6
Other Revenues	2			2			2
Total Operating Revenues	176			190			190
Purchased Energy Expense	7			81			91
Fuel Expense	76			10			7
Transmission Expense	13			11			12
Increase (Decrease) to Reflect PPFAC Recovery	(2		)	(1		)	(4		)
O&M	32			31			27
Depreciation and Amortization Expense	19			18			17
Taxes Other Than Income Taxes	6			4			4
Total Other Operating Expenses	151			154			154
Operating Income	25			36			36
Other Income	1			—			—
Interest Expense	7			8			7
Income Tax Expense	7			11			11
Net Income	$	12		$	17		18

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

	2013		2012		Percent(1)		2011		Percent(1)
Electric Retail Sales, kWh (in Millions):
Residential	844		836		1.0	%	828		1.0	%
Commercial	607		614		(1.2	)%	602		2.0	%
Industrial	185		213		(13.2	)%	221		(3.5	)%
Mining	61		91		(32.7	)%	200		(54.8	)%
Other	2		2		20.5	%	2		(1.7	)%
Total Electric Retail Sales	1,699		1,756		(3.2	)%	1,853		(5.3	)%
Retail Margin Revenues (in Millions):
Residential	$	32	$	32	0.9	%	$	31	2.6	%
Commercial	28		29		(1.7	)%	29		—	%
Industrial	8		9		(14.4	)%	9		—	%
Mining	4		7		(34.4	)%	7		(1.5	)%
Other	—		—		—	%	—		(33.3	)%
Total Retail Margin Revenues (Non-GAAP)(2)	$	72	$	77	(4.8	)%	$	76	0.8	%
Fuel and Purchased Power Revenues	88		83		5.0	%	99		71.2	%
RES & DSM Revenues	8		11		(31.9	)%	7		(15.9	)%
Total Retail Revenues (GAAP)	$	168	$	171	(1.8	)%	$	182	(5.8	)%
Weather Data:
Cooling Degree Days
Year Ended December 31,	3,278		3,489		(6.0	)%	3,243		7.6	%
10-Year Average	3,271		3,285		NM		3,283		NM

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

⁽²⁾  Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

In 2013, total retail kWh sales decreased by 3.2% and retail margin revenues decreased by 4.8% compared with 2012. The decline in sales volumes and resulting reduction in retail margin revenues is due primarily to one of UNS Electric's mining customers generating a portion of its own electricity and the loss of an industrial customer in the fourth quarter of 2012.

FACTORS AFFECTING RESULTS OF OPERATIONS

2013 UNS Electric Rate Order

In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric's 2010 rate order. UNS Electric's rate filing was based on a test year ended June 30, 2012.

In December 2013, the ACC approved a new rate structure for UNS Electric that became effective on January 1, 2014 (2013 UNS Electric Rate Order). The provisions of the 2013 UNS Electric Rate Order include, but are not limited to:

• an increase in non-fuel retail Base Rates of approximately $3 million;

• an Original Cost Rate Base (OCRB) of approximately $213 million and a Fair Value Rate Base (FVRB) of approximately $283 million;

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• a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;

• a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and

• a capital structure of 52.6% equity and 47.4% long-term debt.

The 2013 UNS Electric Rate Order also approved the following cost recovery mechanisms:

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

• a Transmission Cost Adjustment Mechanism (TCA) that will allow more timely recovery of transmission costs associated with serving retail customers at the level approved by FERC. UNS Electric's approved Base Rates include a transmission component based on UNS Electric’s current FERC Open Access Transmission Tariff (OATT) rate. The OATT rates are adjusted annually and the TCA will be limited to the recovery (or refund) of costs associated with future changes in UNS Electric’s OATT rate. UNS Electric expects to make an informational TCA filing with the ACC on or before May 1, 2014. The filing will include an updated retail transmission rate calculated pursuant to UNS Electric's OATT rate.

Gila River Generating Station Unit 3

In December 2013, TEP and UNS Electric entered into an agreement to purchase Gila River Unit 3 for $219 million. It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014. See Tucson Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 8.

Also in December 2013, UNS Electric filed an application requesting the ACC to approve an accounting order that would authorize UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3. If UNS Electric purchases 25% of Gila River Unit 3, the deferred costs, including depreciation, amortization, property taxes, O&M expense and a carrying cost on UNS Electric's investment in Gila River Unit 3, are expected to total approximately $9 million by the end of 2015. We cannot predict if the ACC will approve UNS Electric's request.

Competition

See Tucson Electric Power, Factors Affecting Results of Operations, Competition.

Fair Value Measurements

UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 15.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Electric expects operating cash flows to fund a portion of its construction expenditures during 2014. Additional sources of funding capital expenditures could include draws on the UNS Electric/UNS Gas Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.

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Cash Flows and Capital Expenditures

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

	2013			2012			2011
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	43		$	50		$	43
Investing Activities	(59		)	(37		)	(93		)
Financing Activities	13			(10		)	44
Net Increase/(Decrease) in Cash	(3		)	3			(6		)
Beginning Cash	8			5			11
Ending Cash	$	5		$	8		$	5

Operating Activities

Cash provided by operating activities decreased by $7 million in 2013 when compared with 2012 due primarily to a $6 million decrease in cash receipts from electric sales (net of fuel and purchased energy costs paid) caused by a lower PPFAC rate effective in June 2012, the loss of an industrial customer, and lower mining sales volumes.

Investing Activities

UNS Electric had capital expenditures of $56 million in 2013 compared with $38 million in 2012. The increase is related to a transmission line that was constructed to increase reliability to UNS Electric's service territory in Nogales, Arizona.

Financing Activities

Cash provided by financing activities at UNS Electric in 2013 increased by $23 million when compared with 2012. Financing activities in 2013 included $22 million of borrowings under the UNS Electric/UNS Gas Revolver (net of repayments) and a $2 million receipt related to a contribution in aid of construction from a large customer.

UNS Electric/UNS Gas Credit Agreement

The UNS Electric/UNS Gas Credit Agreement consists of a $100 million unsecured revolving credit and revolving letter of credit facility. Either company can borrow up to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The UNS Electric/UNS Gas Credit Agreement expires November 2016.

UNS Electric is only liable for UNS Electric’s borrowings, and similarly, UNS Gas is only liable for UNS Gas' borrowings under the UNS Electric/UNS Gas Credit Agreement.

The UNS Electric/UNS Gas Credit Agreement restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. At December 31, 2013, UNS Electric and UNS Gas each were in compliance with the terms of the UNS Electric/UNS Gas Credit Agreement.

UNS Electric expects to draw upon the UNS Electric/UNS Gas Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At December 31, 2013, UNS Electric had $22 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Electric/UNS Gas Credit Agreement.

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Contractual Obligations

	UNS Electric Contractual Obligations
Payment Due in Years Ending December 31,	2014		2015		2016		2017		2018		Thereafter		Other		Total
	Millions of Dollars
Long-Term Debt
Principal	$	—	$	80	$	—	$	—	$	—	$	50	$	—	$	130
Interest	7		7		4		4		4		17		—		43
Purchase Obligations(1):
Purchased Power	48		12		—		—		—		—		—		60
Transmission	4		7		6		6		5		6		—		34
Renewable Power Purchase Agreements	6		6		6		6		6		75		—		105
RES Performance-Based Incentives	1		1		1		1		1		2				7
Other Long-Term Liabilities:
Pension & Other Post Retirement Obligations	1		—		—		—		—		—		—		1
Unrecognized Tax Benefits	—		—		—		—		—		—		2		2
Total Contractual Obligations	$	67	$	113	$	17	$	17	$	16	$	150	$	2	$	382

⁽¹⁾ Excludes the acquisition of Gila River Unit 3 pending regulatory approvals. See Note 8.

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

Dividends on Common Stock

UNS Electric paid dividends to UNS Energy, through UES, of $10 million in both 2013 and 2012. UNS Electric did not pay any dividends to UNS Energy in 2011. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (i) no default or event of default exists, and (ii) it could incur additional debt under the debt incurrence test. At December 31, 2013, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Electric/UNS Gas Revolver.

UNS GAS

RESULTS OF OPERATIONS

UNS Gas reported net income of $11 million in 2013, $9 million in 2012, and $10 million in 2011. The increase in net income in 2013 is due primarily to an improvement in retail margin revenues caused by cold weather in the first and fourth quarters, which contributed to an increase retail therm sales, as well as a non-fuel base rate increase that was effective in May 2012.

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The table below provides summary financial information for UNS Gas:

	2013			2012		2011
	Millions of Dollars
Gas Revenues	$	131		$	128	$	148
Other Revenues	3			5		3
Total Operating Revenues	134			133		151
Purchased Gas Expense	73			72		85
Increase (Decrease) to Reflect PGA Recovery Treatment	(2		)	2		5
O&M	26			25		25
Depreciation and Amortization	9			9		8
Taxes Other Than Income Taxes	4			4		4
Total Other Operating Expenses	110			112		127
Operating Income	24			21		24
Interest Expense	6			6		7
Income Tax Expense	7			6		7
Net Income	$	11		$	9	$	10

The table below includes UNS Gas' therm sales and margin revenues:

	2013		2012		Percent(1)		2011		Percent(1)
Gas Retail Sales, Therms (in Millions):
Residential	76		67		12.7	%	74		(9.1	)%
Commercial	31		29		7.2	%	31		(5.7	)%
All Other	9		8		13.1	%	9		(13.5	)%
Total Gas Retail Sales	116		104		11.2	%	114		(8.5	)%
Negotiated Sales Program (NSP)	27		32		(15.2	)%	26		21.2	%
Total Gas Sales	143		136		5.1	%	140		(3.0	)%
Retail Margin Revenues (in Millions):
Residential	$	42	$	38	9.7	%	$	40	(3.5	)%
Commercial	12		11		7.4	%	11		0.9	%
All Other	2		2		14.3	%	2		(4.5	)%
Total Retail Margin Revenues (Non-GAAP)(2)	56		51		9.4	%	53		(2.7	)%
DSM Revenue	1		1		(18.2	)%	1		—	%
Transport and NSP	17		16		6.3	%	17		(4.2	)%
Retail Fuel Revenues	57		60		(4.5	)%	77		(22.5	)%
Total Gas Revenues (GAAP)	$	131	$	128	2.3	%	$	148	(13.2	)%
Weather Data:
Heating Degree Days
Year Ended December 31,	4,588		4,089		12.2	%	4.615		(11.4	)%
10-Year Average	4,401		4,431		NM		4,399		NM

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

⁽²⁾  Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business.

Retail therm sales in 2013 increased by 11.2% when compared with 2012 due to a 12.2% increase in Heating Degree Days. The increase in retail therm sales, as well as a Base Rate increase implemented in May 2012, contributed to an increase in retail margin revenues of 9.4%, or $5 million, when compared with 2012.

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FACTORS AFFECTING RESULTS OF OPERATIONS

Competition

New technological developments and the implementation of the ACC’s Gas Energy Efficiency Standards (Gas EE Standards) may reduce energy consumption by UNS Gas’ retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas.

2012 UNS Gas Rate Order

In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as a LFCR mechanism to enable UNS Gas to recover lost fixed-cost revenues as a result of implementing the Gas EE Standards. The LFCR is expected to recover lost fixed-cost revenues of less than $0.1 million in 2014, based on estimated lost retail therm sales from May 2012 through December 2013.

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

Fair Value Measurements

UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 15.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Outlook

UNS Gas expects operating cash flows to fund all of its construction expenditures during 2014. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements in future periods. Sources of funding future capital expenditures could include existing cash balances, draws on the UNS Electric/UNS Gas Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.

Cash Flows and Capital Expenditures

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

	2013			2012			2011
	Millions of Dollars
Cash Provided By (Used In):
Operating Activities	$	27		$	28		$	32
Investing Activities	(15		)	(15		)	(12		)
Financing Activities	(10		)	(20		)	(11		)
Net Increase/(Decrease) in Cash	2			(7		)	9
Beginning Cash	31			38			29
Ending Cash	$	33		$	31		$	38

UNS Gas' operating cash flows during 2013 were $1 million lower than 2012 due in part to the PGA credit that was effective in April 2012.

UNS Electric/UNS Gas Credit Agreement

At December 31, 2013, UNS Gas had no outstanding borrowings under the UNS Electric/UNS Gas Credit Agreement.

See UNS Electric, Liquidity and Capital Resources, UNS Electric/UNS Gas Credit Agreement.

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Interest Rate Risk

UNS Gas is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Gas may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Contractual Obligations

The following table displays UNS Gas’ contractual obligations as of December 31, 2013 by maturity and by type of obligation:

	UNS Gas Contractual Obligations
Payment Due in Years Ending December 31,	2014		2015		2016		2017		2018		Thereafter		Other		Total
	Millions of Dollars
Long-Term Debt
Principal	$	—	$	50	$	—	$	—	$	—	$	50	$	—	$	100
Interest	6		6		3		3		3		20		—		41
Operating Leases	1		1		1		—		—		—		—		3
Purchase Obligations:
Fuel	26		20		16		13		13		60		—		148
Other Long-Term Liabilities:
Pension & Other Post Retirement Obligations	1		—		—		—		—		—		—		1
Total Contractual Obligations	$	34	$	77	$	20	$	16	$	16	$	130	$	—	$	293

Dividends on Common Stock

UNS Gas paid dividends to UNS Energy, through UES, of $10 million 2013, $20 million in 2012, and $10 million in 2011. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.

The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (i) no default or event of default exists, (ii) it could incur additional debt under the debt incurrence test. At December 31, 2013, UNS Gas was in compliance with the terms of its note purchase agreement and had sufficient additional debt under the debt incurrence test to pay dividends.

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CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with GAAP requires management to apply accounting policies and to make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on UNS Energy’s other significant accounting policies can be found in Note 1.

Accounting for Regulated Operations

We account for our regulated electric and gas operations based on accounting standards that allow the actions of our regulators, the ACC and the FERC, to be reflected in our financial statements. Regulator actions may cause us to capitalize certain costs that would otherwise be included as an expense, or in Accumulated Other Comprehensive Income (AOCI), in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. We evaluate regulatory assets and liabilities each period and believe future recovery or settlement is probable. Our assessment includes consideration of recent rate orders, historical regulatory treatment of similar costs, and changes in the regulatory and political environment. If management's assessment is ultimately different than actual regulatory outcomes, the impact on our results of operation, financial position, and future cash flows could be material.

At December 31, 2013, regulatory liabilities net of regulatory assets totaled $103 million at TEP, $9 million at UNS Electric and $40 million at UNS Gas. There are no current or expected proposals or changes in the regulatory environment that impact our ability to apply regulated operations accounting. If we conclude, in a future period, that our operations no longer meet the criteria in this guidance, we would reflect our regulatory pension assets in AOCI and recognize the impact of other regulatory assets and liabilities in the income statements, both of which would be material to our financial statements. See Note 3.

Accounting for Asset Retirement Obligations

We are required to record the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. We incur legal obligations as a result of environmental and other governmental regulations, contractual agreements and other factors. To estimate the liability, management must use significant judgment and assumptions in: determining whether a legal obligation exists to remove assets; estimating the probability of a future event for a conditional obligation; estimating the fair value of the cost of removal; estimating when final removal will occur; and estimating the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs. Deferred costs are amortized over the life of the underlying asset.

A liability for the fair value of a legal asset retirement obligation (ARO) is recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a part of the carrying amount of the long-lived assets. The asset retirement cost is subsequently charged to depreciation expense over the useful life of the asset or lease term. Upon retirement of the asset, we will either settle the obligation for its recorded amount or incur a gain or loss if the actual costs differ from the recorded amount.

TEP identified legal obligations to retire generation plant assets specified in land leases for its jointly-owned Navajo and Four Corners Generating Stations. The land on which these stations reside is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Additionally, TEP and UNS Electric entered into ground lease agreements with certain land owners for the installation of photovoltaic (PV) assets. The provisions of the PV ground leases require TEP or UNS Electric to remove the PV facilities upon expiration of the leases. TEP's ARO related to the PV assets is estimated to be approximately $9 million at the retirement dates, and UNS Electric's ARO is estimated to be approximately $3 million. TEP also has certain environmental obligations at the Luna, San Juan, Sundt and Springerville Generating Stations. TEP estimates that its share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt and Springerville environmental obligations will be approximately $166 million at the retirement dates. No other legal obligations to retire generation plant assets were identified.

TEP, UNS Electric and UNS Gas have various transmission and distribution lines that operate under leases and rights-of-way that contain end dates and may contain site restoration clauses. TEP, UNS Electric and UNS Gas operate transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As such, there are no AROs for these assets.

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The total net present value of TEP's ARO liability was $22 million at December 31, 2013. The net present value of UNS Electric's ARO liability was $1 million at December 31, 2013. ARO liabilities are reported in Deferred Credits and Other Liabilities—Other on the balance sheets. UNS Gas has not identified any AROs associated with removal of its long-lived assets. See Note 5.

Additionally, the authorized depreciation rates for TEP, UNS Electric and UNS Gas include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances at December 31, 2013 representing non-legal asset retirement obligation accruals, less actual removal costs incurred, net of salvage proceeds realized, are included in Deferred Credits and Other Liabilities, Regulatory Liabilities – Noncurrent on the balance sheets. See Note 3.

Pension and Other Retiree Benefit Plan Assumptions

TEP, UNS Electric, and UNS Gas record plan assets, obligations, and expenses related to pension and other retiree benefit plans based on actuarial valuations, which include key assumptions on discount rates, expected returns on plan assets, compensation increases, and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally recorded or amortized over future periods. We believe that the assumptions used in recording obligations are reasonable based on prior experience, market conditions, and the advice of plan actuaries. Note 10 discusses the rate of return and discount rate used in the calculation of pension plan and other retiree plan obligations for TEP, UNS Electric, and UNS Gas.

TEP is required to recognize the underfunded status of its defined benefit pension and other retiree plans as a liability. The underfunded status is the difference between the fair value of the plans assets and the projected benefit obligation for pension plans or accumulated retiree benefit obligation for other retiree benefit plans. As the funded status, discount rates, and actuarial facts change, the liability will vary significantly in future years. TEP records the underfunded amount for its pension and other retiree obligations as a liability and a regulatory asset to reflect expected recovery of pension and other retiree obligations through the rates charged to retail customers.

At December 31, 2013, TEP discounted its future pension plan obligations at between 5.0% and 5.1% and its other retiree plan obligations at a rate of 4.7%. The discount rate for future pension plan and other retiree plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60^th and 90^th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments. For TEP’s pension plans, a 25-basis point change in the discount rate would increase or decrease the Projected Benefit Obligation (PBO) by approximately $10 million and the plan expense by $1 million. For TEP’s other retiree benefit plan, a 25-basis point change in the discount rate would increase or decrease the Accumulated Postretirement Benefit Obligation (APBO) by approximately $2 million. A 25-basis point change in the discount rate would not significantly impact plan expense.

TEP calculates the market-related value of pension plan assets using the fair value of the assets on the measurement date. TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7% at December 31, 2013. In establishing its assumption as to the expected return on assets, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward-looking views of the financial markets. Pension expense decreases as the expected rate of return on assets increases. A 25-basis point change in the expected return on assets would impact pension expense in 2014 by $1 million.

TEP used a current year health care cost trend rate of 6.7% in valuing its retiree benefit obligation at December 31, 2013. This rate reflects both market conditions and historical experience. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage point change in assumed health care cost trend rates would change the retiree benefit obligation by approximately $5 million and the related plan expense in 2014 by $1 million.

In 2014, TEP will incur pension costs of approximately $8 million and other retiree benefit costs of approximately $6 million. TEP expects to charge approximately $10 million of these costs to O&M expense, $3 million to capital, and $1 million to Other Expense. TEP expects to make pension plan contributions of $9 million in 2014. In 2009, TEP established a VEBA trust to fund its other retiree benefit plan. In 2014, TEP expects to make benefit payments to retirees under the retiree benefit plan of approximately $5 million and contributions to the VEBA trust of $1 million, net of distributions.

UNS Electric and UNS Gas discounted their future pension plan obligations using a rate of 5.2% at December 31, 2013. For UNS Electric and UNS Gas' pension plan, a 25-basis point change in the discount rate would impact the benefit obligation and pension expense by less than $1 million. UNS Electric and UNS Gas will record pension expense of $2 million in 2014, of which less than $1 million will be capitalized. UNS Electric and UNS Gas expect to make combined pension plan contributions of $1 million in 2014.

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UNS Electric and UNS Gas discounted their other retiree plan obligations using a rate of 4.7% at December 31, 2013. UNS Electric and UNS Gas will record retiree medical benefit expense and make benefit payments to retirees under the retiree benefit plan of less than $0.5 million in 2014.

Accounting for Derivative Instruments and Hedging Activities

Commodity Derivative Contracts

TEP, UNS Electric, and UNS Gas enter into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, or one year, within established limits to meet forecasted load requirements or to take advantage of favorable market opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. TEP and UNS Gas enter into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted gas purchases. UNS Electric enters into forward gas commodity price swap agreements to hedge the price risk associated with forward power purchase agreements that are indexed to natural gas prices.

For all commodity derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or regulatory liability on the balance sheets of TEP, UNS Electric, and UNS Gas based on our ability to recover the prudent costs of hedging activities entered into to mitigate energy price risk for retail customers. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC or PGA mechanisms.

The market prices used to determine fair values for TEP’s, UNS Electric’s, and UNS Gas' derivative instruments at December 31, 2013, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.

TEP, UNS Electric, and UNS Gas manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.

Interest Rate Swaps

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates tied to LIBOR on the Springerville Common Facilities Lease. As of December 31, 2013, approximately $25 million of variable rate lease debt for the Springerville Common Facilities Lease had been hedged through an interest rate swap agreement through July 1, 2014, and $34 million had been hedged through January 2, 2020. In August 2009, TEP entered into a swap that had the effect of converting $50 million of variable-rate IDBs to a fixed rate from September 2009 through September 2014.

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

Commodity Cash Flow Hedge

TEP hedges the cash flow risk associated with a six-year power wholesale supply agreement using a six-year power purchase swap agreement. Unrealized gains and losses are recorded in AOCI. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk, Commodity Price Risk and Note 1.

Revenue Recognition

TEP’s, UNS Electric’s, and UNS Gas' retail revenues, which are recognized in the period that electricity or energy is delivered and consumed by customers, include unbilled revenue based on an estimate of kWh/therms delivered at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated kWh/therms delivered to the kWh/therms billed to our retail customers. The excess of estimated kWh/therms delivered over kWh/therms billed is then allocated to the retail customer classes based on estimated usage by each customer class. We then record revenue for each customer class based on the various Retail Rates for each customer class. Due to the seasonal fluctuations of TEP and UNS Electric’s actual load, the unbilled revenue amount increases during the spring and summer and decreases during the fall and

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winter. Conversely the unbilled revenue amount for UNS Gas sales increases during the fall and winter and decreases during the spring and summer. A provision for uncollectible accounts is recorded as a component of O&M expense.

Plant Asset Depreciable Lives

TEP, UNS Electric, and UNS Gas have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and expected net removal costs. The useful lives of plant assets are further detailed in Note 5. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded in the income statements. The ACC approves depreciation rates for all generation and distribution assets. Depreciation rates for such assets cannot be changed without ACC approval. TEP and UNS Electric transmission assets are subject to the jurisdiction of the FERC. See Note 1.

The 2013 TEP Rate Order approved a change in authorized depreciation rates for generation and distribution plant from an average of 3.32% to 3.00% , effective July 1, 2013. The change in depreciation rates will have the effect of reducing depreciation expense by approximately $11 million annually.  The reduction in depreciation expense is primarily due to revised estimates of removal costs, net of estimated salvage value for interim and final retirements. See Note 3.

In January 2010, TEP obtained an updated depreciation study which indicated that its transmission assets’ depreciable lives should be extended. As a result, TEP adopted new FERC approved transmission depreciation rates effective January 2010.

Income Taxes

Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate at our balance sheet date.

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income and deductions as reported in the consolidated tax return.

A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. At December 31, 2013, UNS Energy had a $7 million valuation allowance. The valuation allowances related to unregulated investments’ losses are treated as capital losses for income tax purposes. If UNS Energy incurs additional capital losses in the future, a valuation allowance will be recorded against the deferred tax asset unless management can identify future capital gains to offset the losses. See Note 9.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The FASB issued guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors. This guidance will be effective in the first quarter of 2014. We do not expect the adoption of this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair value and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.

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The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such changes to be material. In addition, we do not expect any material changes in the presentations of our other financial statements.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UNS Energy and TEP are including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for UNS Energy or TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as “anticipates”, “estimates”, “expects”, “intends”, “plans”, “predicts”, “projects”, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of UNS Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other parts of this report: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of our pension and other retiree benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; cyber attacks or challenges to our information security; and the performance of TEP’s generating plants.

ITEM 7A. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

We are exposed to various forms of market risk. Changes in interest rates, returns on marketable securities, and changes in commodity prices may affect our future financial results.

See Safe Harbor for Forward-Looking Statements.

Risk Management Committee

We have a Risk Management Committee responsible for the oversight of commodity price risk and credit risk related to the wholesale energy marketing activities of TEP and the fuel and power procurement activities at TEP, UNS Electric, and UNS Gas. Our Risk Management Committee, which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, transmission and distribution operations, and generation operations departments of UNS Energy. To limit TEP, UNS Electric, and UNS Gas’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP, UNS Electric, and UNS Gas’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.

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Interest Rate Risk

Long-Term Debt

TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. TEP had $215 million at December 31, 2013 in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly or monthly. The average rate on TEP's weekly variable rate debt (excluding letter of credit fees) was 0.12% in 2013 and 0.17% in 2012. The average weekly interest rate ranged from 0.06% to 0.48% in 2013 and 0.06% to 0.26% during 2012. Although short-term interest rates have been relatively low and stable in 2013 and 2012, TEP may still be subject to volatility in its tax-exempt variable rate debt. A 100 basis point increase in average interest rates on this debt, over a twelve month period, would result in a decrease in TEP’s pre-tax net income of approximately $2 million.

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

TEP has fixed-for-floating interest rate swaps in place to hedge floating rate interest rate risk associated with $55 million of Springerville Common Facilities lease debt and $50 million of its variable rate IDBs.

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

Interest Rate Swaps

To adjust the value of TEP’s interest rate swaps, classified as cash flow hedges, to fair value in Other Comprehensive Income (Loss), TEP recorded the following net unrealized gains (losses):

	2013			2012			2011
	Millions of Dollars
Unrealized Gains (Losses)	$	(1	)	$	(2	)	$	(5	)

Revolving Credit Facilities

UNS Energy, TEP, UNS Electric, and UNS Gas are also subject to interest rate risk resulting from changes in interest rates on their borrowings under revolving credit facilities. Revolving credit borrowings may be made on the basis of a spread over LIBOR or an Alternate Base Rate. As a result, UNS Energy, TEP, UNS Electric, and UNS Gas may experience significant volatility in the rates paid on LIBOR borrowings under their revolving credit facilities.

Marketable Securities Risk

UNS Energy has a short-term investment policy which governs the investment of excess cash balances by UNS Energy and its subsidiaries. We review this policy periodically in response to market conditions to adjust, if necessary, the maturities and concentrations by investment type and issuer in the investment portfolio. At December 31, 2013, UNS Energy’s short-term investments consisted of liquid, highly-rated money market funds and certificates of deposit. These short-term investments are classified as Cash and Cash Equivalents on the balance sheet.

TEP had marketable securities comprised of investments in lease equity with an estimated fair value of $25 million at December 31, 2013, and $32 million of lease debt and equity at December 31, 2012. At December 31, 2013, the carrying value exceeded fair value by $11 million. No impairment was recorded as TEP expects to recover the full carrying value of its lease equity investment in future rates charged to retail customers. At December 31, 2012, the carrying value exceeded the fair value by $13 million. These securities represent TEP’s investments in lease debt and equity underlying certain of TEP’s capital lease obligations. Changes in the fair value of such debt securities do not present a material risk to TEP, as TEP intends to hold these investments to maturity.

Commodity Price Risk

TEP

TEP is exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, and coal. This risk is mitigated through hedging practices and a PPFAC mechanism which fully recovers the actual retail fuel and purchased power costs incurred on a timely basis from TEP’s retail customers. The PPFAC mechanism has a forward component and a true-up component. The forward component of the PPFAC rate is based on forecasted fuel and purchased

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power costs. The true-up component reconciles actual fuel and purchased power costs with the amounts collected in the prior year and any amounts under/over-collected will be collected from/credited to customers. If the actual price of power is higher than the forecasted PPFAC rate, TEP's operating cash flows are reduced by the price difference until the subsequent 12-month period when the true-up component is adjusted to allow the recovery of this difference.

Purchases and Sales of Energy

To manage its exposure to energy price risk, TEP enters into forward contracts to buy or sell energy at a specified price and future delivery period. Generally, TEP commits to future sales based on expected excess generating capability, forward prices and generation costs, using a diversified market approach to provide a balance between long-term, mid-term, and spot energy sales. TEP generally enters into forward purchases during its summer peaking period to ensure it can meet its load and reserve requirements, and account for other contracts and resource contingencies. TEP also enters into limited forward purchases and sales to optimize its resource portfolio and take advantage of geographical differences in price. These positions are managed on both a volumetric and dollar basis and are closely monitored using risk management policies and procedures overseen by the Risk Management Committee. For example, the risk management policies provide that TEP should not take a short physical position in the third quarter and must have owned generation backing up all physical forward sales positions at the time the sale is made. TEP’s risk management policies also place limits on the duration of transactions in both gas and power.

TEP enters into some forward contracts considered to be normal purchases and sales of electric energy and are therefore not accounted for as derivatives. TEP records revenues on its “normal sales” and expenses on its “normal purchases” in the period in which the energy is delivered. TEP also enters into forward contracts that are not considered to be “normal purchases and sales” and therefore are accounted for as derivatives. When TEP has derivative forward contracts, it marks them to market using actively quoted prices obtained from brokers for power traded over-the-counter at Palo Verde and at other Southwestern U.S. trading hubs. TEP believes that these broker quotations used to calculate the mark-to-market values represent accurate measures of the fair values of TEP’s positions because of the short-term nature of TEP’s positions, as limited by risk management policies, and the liquidity in the short-term market.

Long-Term Wholesale Sales

Through the end of the contract in May 2016, SRP is required to purchase 500,000 MWh of on-peak energy per year from TEP.  TEP does not receive a demand charge and the price of energy is based on a discount to the price of on-peak power on the Palo Verde Market Index. As of February 14, 2014, the average forward price of on-peak power on the Palo Verde Market Index for the calendar year 2014 was $46 per MWh.

Each $5 change in the per MWh market price of on-peak power can affect annual pre-tax income by approximately $3 million.

Natural Gas

TEP is also subject to commodity price risk from changes in the price of natural gas. In addition to energy from its coal-fired facilities, TEP typically uses power purchases, supplemented by generation from its gas-fired units to meet the summer peak demands of its retail customers and to meet local reliability needs. Some of these purchased power contracts are indexed to natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its increasing gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed power purchases, and spot market purchases with various instruments up to 3 years in advance. TEP purchases its remaining gas fuel and power needs in the spot and short-term markets.

As required by fair value accounting rules, for the year ended December 31, 2013, TEP considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted.

To adjust the value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, TEP recorded the following net unrealized gains (losses):

	2013		2012		2011
	Millions of Dollars
Unrealized Gains (Losses)	$	—	$	6	$	(2	)

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

	Unrealized Gain (Loss) of TEP’s Hedging Activities Millions of Dollars
Source of Fair Value at Dec. 31, 2013	Maturity 0 – 6 months			Maturity 6 – 12 months			Maturity over 1 yr.		Total Unrealized Gain (Loss)
Prices Actively Quoted	$	(1	)	$	1		$	1	$	1
Prices Based on Models and Other Valuation Methods	(1		)	(1		)	—		(2		)
Total	$	(2	)	$	—		$	1	$	(1	)

Sensitivity Analysis of Derivatives

TEP uses sensitivity analysis to measure the impact of favorable and unfavorable changes in market prices on the fair value of its derivative forward contracts. TEP records unrealized gains and losses as either a regulatory asset or regulatory liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. For TEP's non-cash flow power hedges, a 10% change in the market price of power would affect unrealized net losses reported as a regulatory asset by approximately $1 million; for gas swaps and collars contracts, a 10% change in the market price of energy would affect unrealized net gains reported as a regulatory liability by approximately $3 million.

Coal

TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants. This risk is mitigated through a PPFAC mechanism which allows for the recovery of costs from retail customers.

TEP's coal supply contract for Springerville Units 1 and 2 expires in 2020. TEP expects coal reserves to be sufficient to supply the estimated requirements for Units 1 and 2 for their presently estimated remaining lives. The coal price is determined by the cost of Powder River Basin coal delivered to Springerville Unit 3 subject to a floor and ceiling.

TEP does not have a long-term coal supply contract for Sundt Unit 4. TEP purchases coal for Sundt Unit 4 on the spot market and can supply that unit with natural gas when the price is competitive with coal. Coal burned at Sundt Unit 4 represents less than 10% of TEP’s total coal consumption.

TEP also participates in jointly-owned generating facilities at Four Corners, Navajo, and San Juan, where coal supplies are under long-term contracts administered by the operating agents. TEP expects coal reserves available to these three jointly-owned generating facilities to be sufficient for the remaining lives of the stations.

The contracts to purchase coal for use at the jointly-owned facilities require TEP to purchase minimum amounts of coal at an estimated average annual cost of $21 million for the next five years. See Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, UNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations and Note 7.

UNS Electric

UNS Electric is exposed to commodity price risk from changes in the price for electricity and natural gas. This risk is mitigated through hedging practices, and UNS Electric has a PPFAC mechanism which allows for the recovery of purchased power and fuel costs from retail customers.

The PPFAC allows UNS Electric to recover its fuel, transmission, and purchased power costs, including demand charges, broker fees, and the prudent costs of contracts for hedging fuel and purchased power costs for its retail customers.

As a result of the 2013 UNS Electric Rate Order, UNS Electric's PPFAC rate reflects a weighted, 12-month rolling average of actual fuel and purchased power costs incurred by UNS Electric. The PPFAC rate adjusts monthly, but the change in the PPFAC rate is banded, so the new monthly PPFAC rate cannot increase or decrease the total average retail purchased power and fuel rate by more than 0.83 percent from the preceding month’s rate. UNS Electric is required to file for a PPFAC rate adjustment if the PPFAC bank balance is over-collected by more than $10 million on a billed-to-customer basis. At December 31, 2013, the PPFAC bank balance was over-collected by $14 million on a billed-to-customer basis. The new PPFAC rate effective on January 1, 2014 is designed to address any over- or under-collected balances. See Note 3.

UNS Electric enters into various power supply agreements for periods of one to five years. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. Because of the new 12-month rolling average structure of the current PPFAC, costs are expected to be recovered on a more timely basis.

K-70

For UNS Electric’s forward power contracts, a 10% change in market prices would affect unrealized net losses reported as a regulatory asset by approximately $3 million.

UNS Electric hedges a portion of its natural gas exposure from gas-indexed purchased power agreements with fixed price contracts. In addition, UNS Electric hedges a portion of its anticipated natural gas exposure from plant fuel. UNS Electric will satisfy its remaining gas and purchased power needs through a combination of purchases in the short-term and spot markets.

As required by fair value accounting rules, for the year ended December 31, 2013, UNS Electric considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted.

To adjust the value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, UNS Electric recorded the following net unrealized gains (losses):

	2013		2012		2011
	Millions of Dollars
Unrealized Gains (Losses)	$	5	$	9	$	(1	)

For UNS Electric’s forward gas contracts, a 10% increase in market prices would result in an increase in unrealized net gains reported as a regulatory liability by approximately $5 million. A 10% decrease in market prices would result in a decrease in unrealized net gains reported as a regulatory liability by approximately $4 million.

UNS Gas

UNS Gas is subject to commodity price risk, primarily from the changes in the price of natural gas purchased for its customers. This risk is mitigated through the PGA mechanism which provides an adjustment to UNS Gas’ Retail Rates to recover the prudently incurred actual costs of gas and transportation. UNS Gas further reduces this risk by purchasing forward fixed price contracts or entering into financial gas swaps for a portion of its projected gas needs under its Price Stabilization Plan.

As required by fair value accounting rules, for the year ended December 31, 2013, UNS Gas considered the impact of non-performance risk in the measurement of fair value of its derivative assets and derivative liabilities net of collateral posted.

To adjust the value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, UNS Gas recorded the following net unrealized gains:

	2013		2012		2011
	Millions of Dollars
Unrealized Gains	$	4	$	6	$	1

For UNS Gas’ forward gas contracts, a 10% change in market prices would affect unrealized net gains reported as a regulatory liability by approximately $2 million.

Credit Risk

UNS Energy is exposed to credit risk in its energy-related marketing activities related to potential non-performance by counterparties. We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. We calculate counterparty credit exposure by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts. A positive value means that we are exposed to the creditworthiness of our counterparties. If exposure exceeds credit limits or contractual collateral thresholds, we may request that a counterparty provide credit enhancement in the form of cash collateral or a letter of credit. Conversely, a negative value means that a counterparty is exposed to the creditworthiness of TEP, UNS Gas, or UNS Electric. If such exposure exceeds credit limits or collateral thresholds, we may be required to post collateral in the form of cash or LOCs.

TEP, UNS Electric, and UNS Gas each have entered into short-term and long-term transactions with several financial institution counterparties with terms of one month through five years. As of December 31, 2013, the combined credit exposure to TEP, UNS Electric, and UNS Gas from financial institution counterparties was approximately $3 million.

As of December 31, 2013, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $15 million. TEP had one non-investment grade counterparty with exposure of greater than 10% of its total credit exposure, totaling approximately $3 million. TEP’s total exposure to non-investment grade counterparties was $3 million.

K-71

At December 31, 2013, TEP posted no cash collateral and less than $1 million in LOCs as credit enhancements with its counterparties, and did not hold any collateral from its counterparties.

UNS Gas is subject to credit risk from non-performance by its supply and hedging counterparties to the extent that these contracts have a mark-to-market value in favor of UNS Gas. As of December 31, 2013, UNS Gas had purchased under fixed price contracts approximately 30% of its expected consumption for the 2014/2015 winter season. At December 31, 2013, UNS Gas had no mark-to-market credit exposure under its supply and hedging contracts. As of December 31, 2013 UNS Gas had posted no cash collateral and no LOCs as credit enhancements with its counterparties, and did not hold any collateral from counterparties.

UNS Electric enters into energy purchase agreements as well as gas hedging contracts to hedge the risk in its gas-indexed power purchase agreements. To the extent that such contracts have a positive mark-to-market value, UNS Electric is exposed to credit risk under those contracts. At December 31, 2013, UNS Electric had less than $1 million in credit exposure under such contracts. As of December 31, 2013, UNS Electric had posted less than $1 million in LOCs and no cash collateral as credit enhancements with its counterparties, and had not collected any collateral margin from its counterparties.

ITEM 8. – CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

UNS Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of UNS Energy’s internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the 1992 Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control – Integrated Framework.

Based on management’s assessment using those criteria management has concluded that, as of December 31, 2013, UNS Energy’s internal control over financial reporting was effective.

The effectiveness of UNS Energy’s internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report in Item 8 of this Annual Report on Form 10-K.

Tucson Electric Power Company—Management’s Report on Internal Controls Over Financial Reporting

TEP’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of TEP’s internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the 1992 COSO Internal Control – Integrated Framework.

Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2013, TEP’s internal control over financial reporting was effective.

K-72

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

UNS Energy Corporation:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of UNS Energy Corporation and its subsidiaries at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

February 25, 2014

K-73

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of

Tucson Electric Power Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

February 25, 2014

K-74

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
	(Except Per Share Amounts)
Operating Revenues
Electric Retail Sales	$	1,102,769		$	1,087,279		$	1,085,822
Electric Wholesale Sales	135,160			125,414			132,346
Gas Retail Sales	125,478			123,133			145,053
Other Revenues	121,153			125,940			115,481
Total Operating Revenues	1,484,560			1,461,766			1,478,702
Operating Expenses
Fuel	332,279			327,832			324,520
Purchased Energy	252,532			224,696			276,610
Transmission and Other PPFAC Recoverable Costs	23,012			14,540			7,334
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(16,313		)	32,246			(4,932		)
Total Fuel and Purchased Energy	591,510			599,314			603,532
Operations and Maintenance	389,699			383,689			379,220
Depreciation	149,615			141,303			133,832
Amortization	27,557			35,784			30,983
Taxes Other Than Income Taxes	54,683			49,881			49,428
Total Operating Expenses	1,213,064			1,209,971			1,196,995
Operating Income	271,496			251,795			281,707
Other Income (Deductions)
Interest Income	534			1,106			4,568
Other Income	7,880			4,928			7,958
Other Expense	(3,463		)	(7,723		)	(5,278		)
Appreciation in Fair Value of Investments	2,833			1,892			329
Total Other Income (Deductions)	7,784			203			7,577
Interest Expense
Long-Term Debt	71,180			71,909			73,217
Capital Leases	25,140			33,613			40,359
Other Interest Expense	538			1,983			2,535
Interest Capitalized	(3,483		)	(2,153		)	(3,753		)
Total Interest Expense	93,375			105,352			112,358
Income Before Income Taxes	185,905			146,646			176,926
Income Tax Expense	58,427			55,727			66,951
Net Income	$	127,478		$	90,919		$	109,975
Weighted-Average Shares of Common Stock Outstanding (000)
Basic	41,618			40,362			36,962
Diluted	41,975			41,755			41,609
Earnings Per Share
Basic	$	3.06		$	2.25		$	2.98
Diluted	$	3.04		$	2.20		$	2.75
Dividends Declared Per Share	$	1.74		$	1.72		$	1.68

See Notes to Consolidated Financial Statements.

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2013		2012			2011
	Thousands of Dollars
Comprehensive Income
Net Income	$	127,478	$	90,919		$	109,975
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(1,850), $(743), and $964	2,825		1,134			(1,473		)
SERP Benefit Amortization, net of income tax (expense) benefit of $(572), $608, and $(804)	916		(840		)	1,158
Total Other Comprehensive Income (Loss), Net of Tax	3,741		294			(315		)
Total Comprehensive Income	$	131,219	$	91,213		$	109,660

See Notes to Consolidated Financial Statements.

K-76

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,208,967		$	1,197,390		$	1,163,537
Cash Receipts from Electric Wholesale Sales	160,947			149,722			183,151
Cash Receipts from Gas Retail Sales	138,775			141,590			159,529
Cash Receipts from Operating Springerville Units 3 & 4	114,258			107,927			104,754
Cash Receipts from Gas Wholesale Sales	3,740			5,233			12,404
Interest Received	517			2,947			6,334
Income Tax Refunds Received	11			1,821			4,672
Performance Deposits Received	—			200			7,050
Other Cash Receipts	35,142			24,105			23,937
Fuel Costs Paid	(285,812		)	(321,355		)	(277,386		)
Purchased Energy Costs Paid	(280,920		)	(250,231		)	(328,713		)
Payment of Operations and Maintenance Costs	(260,453		)	(291,512		)	(295,662		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(182,488		)	(187,257		)	(179,766		)
Wages Paid, Net of Amounts Capitalized	(131,710		)	(127,176		)	(122,370		)
Interest Paid, Net of Amounts Capitalized	(66,610		)	(69,478		)	(68,027		)
Capital Lease Interest Paid	(22,553		)	(28,788		)	(32,103		)
Income Taxes Paid	(316		)	—			(700		)
Performance Deposits Paid	—			(200		)	(4,550		)
Wholesale Gas Costs Paid	—			—			(11,822		)
Other Cash Payments	(10,983		)	(6,829		)	(6,949		)
Net Cash Flows—Operating Activities	420,512			348,109			337,320
Cash Flows from Investing Activities
Capital Expenditures	(325,886		)	(307,277		)	(374,122		)
Purchase of Intangibles—Renewable Energy Credits	(26,948		)	(10,317		)	(5,992		)
Return of Investments in Springerville Lease Debt	9,104			19,278			38,353
Change in Restricted Cash	4,134			(1,445		)	—
Proceeds from Note Receivable	—			15,000			—
Other, net	5,786			21,862			14,673
Net Cash Flows—Investing Activities	(333,810		)	(262,899		)	(327,088		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	139,000			359,000			391,000
Repayments of Borrowings Under Revolving Credit Facilities	(108,000		)	(381,000		)	(351,000		)
Payments of Capital Lease Obligations	(99,621		)	(89,452		)	(74,381		)
Common Stock Dividends Paid	(72,234		)	(69,648		)	(61,904		)
Proceeds from Stock Options Exercised	3,831			3,570			8,115
Proceeds from Common Stock Issuance	464			—			—
Proceeds from Issuance of Long-Term Debt	—			149,513			340,285
Repayments of Long-Term Debt	—			(9,341		)	(252,125		)
Other, net	818			(324		)	(1,431		)
Net Cash Flows—Financing Activities	(135,742		)	(37,682		)	(1,441		)
Net Increase (Decrease) in Cash and Cash Equivalents	(49,040		)	47,528			8,791
Cash and Cash Equivalents, Beginning of Year	123,918			76,390			67,599
Cash and Cash Equivalents, End of Year	$	74,878		$	123,918		$	76,390

See Note 14 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-77

UNS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2013			2012
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	5,192,122		$	5,005,768
Utility Plant Under Capital Leases	637,957			582,669
Construction Work in Progress	201,959			128,621
Total Utility Plant	6,032,038			5,717,058
Less Accumulated Depreciation and Amortization	(1,982,524		)	(1,921,733		)
Less Accumulated Amortization of Capital Lease Assets	(514,677		)	(494,962		)
Total Utility Plant—Net	3,534,837			3,300,363
Investments and Other Property
Investments in Lease Equity	36,194			36,339
Other	34,971			36,537
Total Investments and Other Property	71,165			72,876
Current Assets
Cash and Cash Equivalents	74,878			123,918
Accounts Receivable—Customer	104,596			93,742
Unbilled Accounts Receivable	52,403			53,568
Allowance for Doubtful Accounts	(6,833		)	(6,545		)
Materials and Supplies	88,085			93,322
Deferred Income Taxes—Current	59,681			34,260
Regulatory Assets—Current	52,763			51,619
Fuel Inventory	44,317			62,019
Derivative Instruments	5,629			3,165
Investments in Lease Debt	—			9,118
Other	15,354			33,567
Total Current Assets	490,873			551,753
Regulatory and Other Assets
Regulatory Assets—Noncurrent	150,584			191,077
Derivative Instruments	1,180			3,801
Other Assets	24,430			20,559
Total Regulatory and Other Assets	176,194			215,437
Total Assets	$	4,273,069		$	4,140,429

See Notes to Consolidated Financial Statements.

(Continued)

K-78

UNS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2013		2012
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	1,130,784	$	1,065,465
Capital Lease Obligations	149,767		262,138
Long-Term Debt	1,507,070		1,498,442
Total Capitalization	2,787,621		2,826,045
Current Liabilities
Current Obligations Under Capital Leases	167,659		90,583
Borrowings Under Revolving Credit Facilities	22,000		—
Accounts Payable—Trade	117,503		107,740
Regulatory Liabilities—Current	53,935		43,516
Accrued Taxes Other than Income Taxes	43,880		41,939
Customer Deposits	30,671		34,048
Accrued Employee Expenses	28,148		24,094
Accrued Interest	27,786		31,950
Derivative Instruments	7,534		14,742
Other	17,775		10,517
Total Current Liabilities	516,891		399,129
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	481,662		364,756
Regulatory Liabilities—Noncurrent	302,482		279,111
Pension and Other Retiree Benefits	90,923		159,401
Derivative Instruments	7,100		12,709
Other	86,390		99,278
Total Deferred Credits and Other Liabilities	968,557		915,255
Commitments, Contingencies, and Environmental Matters (Note 7)
Total Capitalization and Other Liabilities	$	4,273,069	$	4,140,429

See Notes to Consolidated Financial Statements.

(Concluded)

K-79

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

			December 31,
			2013			2012
			Thousands of Dollars
COMMON STOCK EQUITY
Common Stock-No Par Value			$	889,301		$	882,138
	2013	2012
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	41,538,343	41,343,851
Retained Earnings			247,532			193,117
Accumulated Other Comprehensive Loss			(6,049		)	(9,790		)
Total Common Stock Equity			1,130,784			1,065,465
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding			—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1			192,871			196,843
Springerville Coal Handling Facilities			27,878			48,038
Springerville Common Facilities			96,677			107,840
Total Capital Lease Obligations			317,426			352,721
Less Current Maturities			(167,659		)	(90,583		)
Total Long-Term Capital Lease Obligations			149,767			262,138
LONG-TERM DEBT
	Maturity	Interest Rate
UNS Energy:
Credit Agreement	2016	Variable	54,000			45,000
Tucson Electric Power Company:
Variable Rate Bonds	2016 - 2032	Variable	214,802			215,300
Fixed Rate Bonds	2020 - 2040	3.85% – 5.75%	1,008,268			1,008,142
UNS Electric and UNS Gas:
Senior Notes	2015 – 2026	5.39% – 7.10%	200,000			200,000
UNS Electric:
Term Loan	2015	Variable	30,000			30,000
Total Long-Term Debt			1,507,070			1,498,442
Total Capitalization			$	2,787,621		$	2,826,045

See Notes to Consolidated Financial Statements.

K-80

UNS ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Shares Outstanding	Common Stock		Retained Earnings			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Thousands of Shares	Thousands of Dollars
Balances at December 31, 2010	36,542	$	715,687	$	124,838		$	(9,769	)	$	830,756
Net Income				109,975						109,975
Other Comprehensive Loss, net of tax							(315		)	(315		)
Dividends Declared				(62,158		)				(62,158		)
Shares Issued for Stock Options	319	8,176								8,176
Shares Issued under Performance Share Awards	57	—								—
Share-based Compensation		2,040								2,040
Balances at December 31, 2011	36,918	725,903		172,655			(10,084		)	888,474
Net Income				90,919						90,919
Other Comprehensive Income, net of tax							294			294
Dividends Declared				(70,457		)				(70,457		)
Shares Issued on Conversion of Notes and Related Tax Effect	4,262	149,805								149,805
Shares Issued for Stock Options	133	3,511								3,511
Shares Issued under Performance Share Awards	31	—								—
Share-based Compensation		2,919								2,919
Balances at December 31, 2012	41,344	882,138		193,117			(9,790		)	1,065,465
Net Income				127,478						127,478
Other Comprehensive Income, net of tax							3,741			3,741
Dividends Declared				(73,063		)				(73,063		)
Shares Issued under Dividend Reinvestment Plan	10	464								464
Shares Issued for Stock Options	127	3,831								3,831
Shares Issued under Performance Share Awards	57	—								—
Share-based Compensation		2,868								2,868
Balances at December 31, 2013	41,538	$	889,301	$	247,532		$	(6,049	)	$	1,130,784

We describe limitations on our ability to pay dividends in Note 13.

See Notes to Consolidated Financial Statements.

K-81

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Operating Revenues
Electric Retail Sales	$	934,357		$	915,879		$	903,930
Electric Wholesale Sales	132,500			111,194			129,861
Other Revenues	129,833			134,587			122,595
Total Operating Revenues	1,196,690			1,161,660			1,156,386
Operating Expenses
Fuel	325,903			318,901			318,268
Purchased Power	112,452			80,137			105,766
Transmission and Other PPFAC Recoverable Costs	12,233			5,722			(1,435		)
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(12,458		)	31,113			(6,165		)
Total Fuel and Purchased Energy	438,130			435,873			416,434
Operations and Maintenance	335,321			334,553			330,801
Depreciation	118,076			110,931			104,894
Amortization	31,294			39,493			34,650
Taxes Other Than Income Taxes	43,498			40,323			40,199
Total Operating Expenses	966,319			961,173			926,978
Operating Income	230,371			200,487			229,408
Other Income (Deductions)
Interest Income	120			136			3,567
Other Income	5,770			3,953			5,364
Other Expense	(10,715		)	(13,574		)	(12,064		)
Appreciation in Fair Value of Investments	2,833			1,892			329
Total Other Income (Deductions)	(1,992		)	(7,593		)	(2,804		)
Interest Expense
Long-Term Debt	56,378			55,038			49,858
Capital Leases	25,140			33,613			40,358
Other Interest Expense	87			1,446			1,127
Interest Capitalized	(2,554		)	(1,782		)	(2,073		)
Total Interest Expense	79,051			88,315			89,270
Income Before Income Taxes	149,328			104,579			137,334
Income Tax Expense	47,986			39,109			52,000
Net Income	$	101,342		$	65,470		$	85,334

See Notes to Consolidated Financial Statements.

K-82

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2013		2012			2011
	Thousands of Dollars
Comprehensive Income
Net Income	$	101,342	$	65,470		$	85,334
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(1,793), $(887), and $941	2,738		1,354			(1,433		)
SERP Benefit Amortization, net of income tax (expense) benefit of $(572), $608, and $(804)	916		(840		)	1,158
Total Other Comprehensive Income (Loss), Net of Tax	3,654		514			(275		)
Total Comprehensive Income	$	104,996	$	65,984		$	85,059

See Notes to Consolidated Financial Statements.

K-83

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$	1,020,903		$	1,006,926		$	963,247
Cash Receipts from Electric Wholesale Sales	146,880			124,594			152,618
Cash Receipts from Operating Springerville Units 3 & 4	114,258			107,927			104,754
Reimbursement of Affiliate Charges	23,468			20,926			18,448
Cash Receipts from Gas Wholesale Sales	3,271			4,652			11,825
Interest Received	509			2,025			5,367
Income Tax Refunds Received	77			493			7,492
Other Cash Receipts	25,079			18,850			19,611
Fuel Costs Paid	(280,639		)	(313,742		)	(271,975		)
Payment of Operations and Maintenance Costs	(253,054		)	(282,752		)	(287,615		)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(144,849		)	(147,859		)	(139,728		)
Purchased Power Costs Paid	(115,008		)	(81,328		)	(117,224		)
Wages Paid, Net of Amounts Capitalized	(110,995		)	(104,955		)	(100,942		)
Interest Paid, Net of Amounts Capitalized	(52,589		)	(52,125		)	(45,433		)
Capital Lease Interest Paid	(22,553		)	(28,786		)	(32,103		)
Income Taxes Paid	—			(1,796		)	(2,346		)
Wholesale Gas Cost Paid	—			—			(11,822		)
Other Cash Payments	(8,567		)	(5,131		)	(5,880		)
Net Cash Flows—Operating Activities	346,191			267,919			268,294
Cash Flows from Investing Activities
Capital Expenditures	(252,848		)	(252,782		)	(351,890		)
Purchase of Intangibles—Renewable Energy Credits	(23,280		)	(8,889		)	(5,111		)
Return of Investments in Springerville Lease Debt	9,104			19,278			38,353
Change in Restricted Cash	4,134			(1,445		)	—
Other, net	3,228			15,957			6,637
Net Cash Flows—Investing Activities	(259,662		)	(227,881		)	(312,011		)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facility	78,000			189,000			220,000
Repayments of Borrowings Under Revolving Credit Facility	(78,000		)	(199,000		)	(210,000		)
Payments of Capital Lease Obligations	(99,621		)	(89,452		)	(74,343		)
Dividends Paid to UNS Energy	(40,000		)	(30,000		)	—
Proceeds from Issuance of Long-Term Debt	—			149,513			260,285
Repayments of Long-Term Debt	—			(6,535		)	(172,460		)
Equity Investment from UNS Energy	—			—			30,000
Other, net	(1,316		)	(1,539		)	(2,030		)
Net Cash Flows—Financing Activities	(140,937		)	11,987			51,452
Net Increase (Decrease) in Cash and Cash Equivalents	(54,408		)	52,025			7,735
Cash and Cash Equivalents, Beginning of Year	79,743			27,718			19,983
Cash and Cash Equivalents, End of Year	$	25,335		$	79,743		$	27,718

See Note 14 for supplemental cash flow information.

See Notes to Consolidated Financial Statements.

K-84

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31,
	2013			2012
	Thousands of Dollars
ASSETS
Utility Plant
Plant in Service	$	4,467,667		$	4,348,041
Utility Plant Under Capital Leases	637,957			582,669
Construction Work in Progress	180,485			98,460
Total Utility Plant	5,286,109			5,029,170
Less Accumulated Depreciation and Amortization	(1,826,977		)	(1,783,787		)
Less Accumulated Amortization of Capital Lease Assets	(514,677		)	(494,962		)
Total Utility Plant—Net	2,944,455			2,750,421
Investments and Other Property
Investments in Lease Equity	36,194			36,339
Other	33,488			35,091
Total Investments and Other Property	69,682			71,430
Current Assets
Cash and Cash Equivalents	25,335			79,743
Accounts Receivable—Customer	80,211			71,813
Unbilled Accounts Receivable	34,369			33,782
Allowance for Doubtful Accounts	(4,825		)	(4,598		)
Accounts Receivable—Due from Affiliates	6,064			5,720
Materials and Supplies	75,200			80,377
Deferred Income Taxes—Current	63,497			37,212
Fuel Inventory	44,027			61,737
Regulatory Assets—Current	42,555			34,345
Derivative Instruments	2,137			2,230
Investments in Lease Debt	—			9,118
Other	12,923			32,163
Total Current Assets	381,493			443,642
Regulatory and Other Assets
Regulatory Assets—Noncurrent	141,030			178,330
Derivative Instruments	167			1,354
Other Assets	19,233			15,869
Total Regulatory and Other Assets	160,430			195,553
Total Assets	$	3,556,060		$	3,461,046

See Notes to Consolidated Financial Statements.

(Continued)

K-85

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31,
	2013		2012
	Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity	$	925,923	$	860,927
Capital Lease Obligations	149,767		262,138
Long-Term Debt	1,223,070		1,223,442
Total Capitalization	2,298,760		2,346,507
Current Liabilities
Current Obligations Under Capital Leases	167,659		90,583
Accounts Payable—Trade	88,556		82,122
Accounts Payable—Due to Affiliates	9,153		3,134
Accrued Taxes Other than Income Taxes	34,485		33,060
Accrued Employee Expenses	24,454		20,715
Regulatory Liabilities—Current	23,701		20,822
Accrued Interest	22,785		26,965
Customer Deposits	21,354		24,846
Derivative Instruments	5,531		4,899
Other	9,244		7,085
Total Current Liabilities	406,922		314,231
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	420,878		319,216
Regulatory Liabilities—Noncurrent	263,270		241,189
Pension and Other Retiree Benefits	84,936		149,718
Derivative Instruments	5,161		10,565
Other	76,133		79,620
Total Deferred Credits and Other Liabilities	850,378		800,308
Commitments, Contingencies, and Environmental Matters (Note 7)
Total Capitalization and Other Liabilities	$	3,556,060	$	3,461,046

See Notes to Consolidated Financial Statements.

(Concluded)

K-86

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

			December 31,
			2013			2012
			Thousands of Dollars
COMMON STOCK EQUITY
Common Stock-No Par Value			$	888,971		$	888,971
	2013	2012
Shares Authorized	75,000,000	75,000,000
Shares Outstanding	32,139,434	32,139,434
Capital Stock Expense			(6,357		)	(6,357		)
Accumulated Earnings (Deficit)			49,185			(12,157		)
Accumulated Other Comprehensive Loss			(5,876		)	(9,530		)
Total Common Stock Equity			925,923			860,927
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding			—			—
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1			192,871			196,843
Springerville Coal Handling Facilities			27,878			48,038
Springerville Common Facilities			96,677			107,840
Total Capital Lease Obligations			317,426			352,721
Less Current Maturities			(167,659		)	(90,583		)
Total Long-Term Capital Lease Obligations			149,767			262,138
LONG-TERM DEBT
	Maturity	Interest Rate
Variable Rate Bonds	2016 - 2032	Variable	214,802			215,300
Fixed Rate Bonds	2020 - 2040	3.85% – 5.75%	1,008,268			1,008,142
Total Long-Term Debt			1,223,070			1,223,442
Total Capitalization			$	2,298,760		$	2,346,507

See Notes to Consolidated Financial Statements.

K-87

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY

	Common Stock		Capital Stock Expense			Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Loss			Total Stockholder’s Equity
	Thousands of Dollars
Balances at December 31, 2010	$	858,971	$	(6,357	)	$	(132,961	)	$	(9,769	)	$	709,884
Net Income						85,334						85,334
Other Comprehensive Loss, net of tax									(275		)	(275		)
Capital Contribution from UNS Energy	30,000											30,000
Balances at December 31, 2011	888,971		(6,357		)	(47,627		)	(10,044		)	824,943
Net Income						65,470						65,470
Other Comprehensive Income, net of tax									514			514
Dividends Declared						(30,000		)				(30,000		)
Balances at December 31, 2012	888,971		(6,357		)	(12,157		)	(9,530		)	860,927
Net Income						101,342						101,342
Other Comprehensive Income, net of tax									3,654			3,654
Dividends Declared						(40,000		)				(40,000		)
Balances at December 31, 2013	$	888,971	$	(6,357	)	$	49,185		$	(5,876	)	$	925,923

We describe limitations on our ability to pay dividends in Note 13.

See Notes to Consolidated Financial Statements.

K-88

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NATURE OF OPERATIONS

UNS Energy Corporation (UNS Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of December 31, 2013. TEP generates, transmits and distributes electricity to approximately 413,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).

UES wholly-owns two regulated utilities: UNS Electric, Inc. (UNS Electric) and UNS Gas, Inc. (UNS Gas). UNS Electric is a regulated utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.

UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2013.

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

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

See Note 2 for information regarding a pending merger with Fortis, Inc.

BASIS OF PRESENTATION

UNS Energy's consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 3. The consolidated financial statements include the accounts of UNS Energy and all of its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated if recovery from ratepayers is probable. See Note 4. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income. See Note 5.

USE OF ACCOUNTING ESTIMATES

Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect:

• Assets and liabilities on our balance sheets at the dates of the financial statements;

• Our disclosures about contingent assets and liabilities at the dates of the financial statements; and

• Our revenues and expenses in our income statements during the periods presented.

Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.

ACCOUNTING FOR REGULATED OPERATIONS

We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies.

K-89

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through FERC-approved transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future billing reductions.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 3.

TEP, UNS Electric, and UNS Gas apply regulatory accounting as the following conditions exist:

• An independent regulator sets rates;

• The regulator sets the rates to recover the specific enterprise’s costs of providing service; and

• Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2013, we adopted authoritative guidance that:

• Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 15.

• Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 16.

CASH AND CASH EQUIVALENTS

We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.

RESTRICTED CASH

Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets. Restricted cash was $2 million at December 31, 2013 and $7 million at December 31, 2012.

UTILITY PLANT

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

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

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

AFUDC and Capitalized Interest

AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.

K-90

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	2013		2012		2011
TEP	7.38	%	7.22	%	6.72	%
UNS Electric	8.07	%	7.89	%	8.18	%
UNS Gas	7.89	%	7.95	%	8.32	%

UNS Energy did not capitalize interest related to non-regulated construction activity in 2013 or 2012. UNS Energy capitalized interest on non-regulated construction activity at a rate of 3.30% for 2011.

Depreciation

We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 and Note 5. The Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant:

	2013		2012		2011
TEP	3.16	%	3.22	%	3.14	%
UNS Electric	3.94	%	3.99	%	4.02	%
UNS Gas	2.63	%	2.69	%	2.84	%

TEP Utility Plant Under Capital Leases

TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense—Capital Leases. The lease terms are described in Note 6.

Computer Software Costs

We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 15. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to the equity holders.

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

ASSET RETIREMENT OBLIGATIONS

TEP and UNS Electric have identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense, and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.

K-91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Depreciation rates for all of our utilities also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.

EVALUATION OF ASSETS FOR IMPAIRMENT

We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.

DEFERRED FINANCING COSTS

We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.

We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.

OPERATING REVENUES

We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity and gas sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.

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

TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned.

The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) associated with energy sales that no longer occur due to EE Standards and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.

ALLOWANCE FOR DOUBTFUL ACCOUNTS

We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions.

INVENTORY

We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.

FUEL AND PURCHASED ENERGY COST RECOVERY MECHANISMS

TEP and UNS Electric Purchased Power and Fuel Adjustment Clause

TEP and UNS Electric recover actual fuel, purchased power and transmission costs incurred to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts

K-92

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the PPFAC rate at which TEP and UNS Electric recover these costs. The difference between costs recovered through rates and actual fuel, purchased power and transmission costs prudently incurred to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 3.

UNS Gas Purchased Gas Adjustor

UNS Gas recovers actual gas costs incurred through a Purchased Gas Adjustor (PGA) mechanism that adjusts monthly. Gas cost over-recoveries are deferred as regulatory liabilities and under-recoveries are deferred as regulatory assets. See Note 3.

RENEWABLE ENERGY and ENERGY EFFICIENCY PROGRAMS

The ACC’s Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The 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. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates.

TEP, UNS Electric, and UNS Gas are required to implement cost-effective Demand-Side Management (DSM) programs to comply with the ACC’s Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail kWh savings equal to22% by 2020. The Gas EE Standards require increasing annual targeted retail therm sales equal to 6% by 2020.

Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP and UNS Electric recognize RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. Similarly, UNS Gas recognizes DSM surcharge revenue in Gas Retail Sales.

RENEWABLE ENERGY CREDITS

The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP or UNS Electric purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC.

When RECs are purchased, TEP and UNS Electric record the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount. See Note 3.

INCOME TAXES

Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized.

Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.  Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.

Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 3.

We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and are deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises.

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.

TAXES OTHER THAN INCOME TAXES

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

DERIVATIVE INSTRUMENTS

We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.

Cash Flow Hedges

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. UNS Electric uses a cash flow hedge to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP and UNS Electric account for cash flow hedges as follows:

• The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and

• When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.

We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.

Energy Contracts - Regulatory Recovery

TEP, UNS Electric and UNS Gas are authorized to recover the prudent costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC or PGA mechanism.

Master Netting Agreements

We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.

Normal Purchases and Normal Sales

We enter into forward energy purchase and sales contracts, including call options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Trading

We did not engage in trading of derivative financial instruments.

PENSION AND OTHER RETIREE BENEFITS

We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees.

We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees.

Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.

Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 10.

NOTE 2. PENDING MERGER WITH FORTIS

On December 11, 2013, UNS Energy announced that it had entered into an agreement and plan of merger, subject to shareholder and required regulatory approvals, to be acquired by Fortis for $60.25 per share of Common Stock in cash. Following the merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Board of Directors of each of UNS Energy and Fortis Parent have approved the merger.

NOTE 3. REGULATORY MATTERS

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP, UNS Electric, and UNS Gas. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and the pending merger. The FERC regulates terms and prices of transmission services and wholesale electricity sales, and the pending merger.

2013 TEP RATE ORDER

In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012 which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

The provisions of the 2013 TEP Rate Order include, but are not limited to:

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

• a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11 million annually; and

• an agreement by TEP to seek recovery of costs related to the discontinued Nogales transmission project from the FERC before seeking rate recovery from the ACC.

The 2013 TEP Rate Order also includes the following cost recovery mechanisms:

• a new Purchased Power and Fuel Adjustment Clause (PPFAC) credit of 0.1388 cents per kWh effective July 1, 2013. The credit reflects the following:

◦ a reduction in the PPFAC bank balance, recorded in June 2013, as an increase to fuel expense, of $3 million related to prior sulfur credits; and

◦ a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory asset to defer coal costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final settlement with the San Juan operator related to insurance proceeds.

• a modification of the PPFAC mechanism to include recovery of generation-related lime costs offset by sulfur credits.

• a Lost Fixed Cost Recovery mechanism (LFCR) to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation. In the fourth quarter of 2013, TEP recorded revenues of $2 million related to unrecovered non-fuel costs incurred during 2013.

• an Environmental Compliance Adjustor (ECA) mechanism to recover certain capital carrying costs to comply with government-mandated environmental regulations between rate cases. The ECA rate is capped at 0.025 cents per kWh, which approximates 0.25% of TEP's total retail revenues, and will be charged to customers beginning in May 2014 for any qualifying costs incurred between August 2013 and December 2013.

• an energy efficiency provision which includes a 2013 calendar year budget of approximately $21 million to fund programs that support the ACC's Electric Energy Efficiency Standards, as well as a $2 million performance incentive.

2013 UNS ELECTRIC RATE ORDER

In December 2013, the ACC issued the 2013 UNS Electric Rate Order that resolved the rate case filed by UNS Electric in December 2012 which was based on a test year ended June 30, 2012. The 2013 UNS Electric Rate Order approved new rates effective January 1, 2014.

The provisions of the 2013 UNS Electric Rate Order include, but are not limited to:

• an increase in non-fuel retail Base Rates of approximately $3 million;

• an OCRB of approximately $213 million and a FVRB of approximately $283 million;

• a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;

• a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and

• a capital structure of 52.6% equity and 47.4% long-term debt.

The 2013 UNS Electric Rate Order also includes the following cost recovery mechanisms:

• a LFCR mechanism to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation; and

• a Transmission Cost Adjustor (TCA), which will allow more timely recovery of transmission costs associated with serving retail customers.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2012 UNS GAS RATE ORDER

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

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

COST RECOVERY MECHANISMS

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

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is adjusted annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period unless suspended by the ACC.

TEP's PPFAC rate includes: 1) a forward component, under which TEP recovers or refunds differences between a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between prudently incurred actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.

Prior to the 2013 UNS Electric Rate Order, UNS Electric’s PPFAC rate was adjusted annually each June 1^st, effective for the subsequent 12-month period. As a result of the 2013 UNS Electric Rate Order, effective January 1, 2014, UNS Electric's PPFAC rate reflects a weighted 12-month rolling average of actual fuel and purchased power costs incurred by UNS Electric. The PPFAC rate adjusts monthly, but it is restricted from changing by more than 0.83 percent from the preceding month's rate. If the PPFAC deferral balance reflects an over-collection of $10 million or more on a billed-to-customer basis, UNS Electric must file for a PPFAC rate adjustment. At December 31, 2013, the PPFAC bank balance was over-collected by $14 million on a billed-to-customer basis.

The tables below summarize TEP’s and UNS Electric’s PPFAC rates:

	TEP
	2013		2012
	July - December	January - June	April - December	January - March
	Cents per kWh
PPFAC Rate	0.14	0.77	0.77	0.53
Competition Transition Charge (1)	—	—	—	(0.53	)
Net TEP PPFAC Rate	0.14	0.77	0.77	—

⁽¹⁾  TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.

	UNS Electric
	2013						2012
	September - December		June - August		January - May		June - December		January - May
	Cents per kWh
PPFAC Rate	(0.40	)	(0.92	)	(1.44	)	(1.44	)	(0.88	)

UNS Gas Purchased Gas Adjustor

The PGA mechanism allows UNS Gas to adjust Retail Rates to recover fluctuations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than 15 cents per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million or more on a billed-to-customer basis.

In October 2013, the ACC approved an increase to the existing PGA credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At December 31, 2013 and December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.

The PGA rate ranged from 0.4504 to 0.5280 cents per therm in 2013, and ranged from 0.5202 to 0.6501 cents per therm in 2012.

Renewable Energy Standards

TEP and UNS Electric are required to expand their use of renewable energy in order to meet the ACC’s RES. TEP and UNS Electric, through a customer surcharge, recover costs associated with meeting the RES. These costs include the purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates.

In October 2013, the ACC approved TEP's 2014 RES plan and authorized a total 2014 RES budget of $40 million with $34 million to be collected through the 2014 RES funding mechanism. TEP earned returns on solar investments of $2 million in each of 2013 and 2012 and $1 million in 2011.

In October 2013, the ACC approved UNS Electric's 2014 RES plan and authorized a total 2014 RES budget of $7 million with $6 million to be collected through the 2014 RES funding mechanism.  UNS Electric earned returns on solar investments of less than $0.5 million in 2013 and 2012. No return was earned in 2011.

Energy Efficiency Standards

TEP, UNS Electric, and UNS Gas are required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs.

In December 2013, the ACC approved UNS Electric’s 2013-2014 energy efficiency implementation plan that included a 2014 calendar year budget of approximately $5 million to fund programs that support the ACC’s Electric EE Standards as well as a performance incentive.

In June 2013, the ACC approved the UNS Gas 2011-2012 energy efficiency implementation plan with certain modifications. The approval included an annual energy efficiency budget of approximately $2 million and a waiver of the Gas EE Standards through 2013.

Lost Fixed Cost Recovery Mechanism

The LFCR is a mechanism to recover certain non-fuel costs that would go unrecovered due to lost sales as a result of implementing ACC approved EE Standards and distributed generation targets.

In April 2012, the ACC authorized a LFCR mechanism that enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards.

In June 2013, the ACC authorized a LFCR mechanism for TEP subject to a year-over-year cap of 1% of TEP's total retail revenues. TEP expects the LFCR rate which will recover 2013 costs, to be effective on July 1, 2014, upon review by the ACC of verified lost kWh sales.

In December 2013, as part of the 2013 UNS Electric Rate Order, the ACC authorized a LFCR for UNS Electric, to be effective on July 1, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

REGULATORY ASSETS AND LIABILITIES

The following tables summarize regulatory assets and liabilities:

	December 31, 2013
	TEP			UNS Electric			UNS Gas			UNS Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	20		$	—		$	—		$	20
Derivative Instruments (Note 15)	1			—			—			1
San Juan Mine Fire Cost Deferral (2)	10			—			—			10
PPFAC (2)	4			10			—			14
DSM and LFCR (2)	3			—			—			3
Other Current Regulatory Assets (3)	5			—			—			5
Total Regulatory Assets—Current	43			10			—			53
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	75			3			2			80
Income Taxes Recoverable through Future Revenues (4)	22			3			—			25
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	25			—			—			25
Discontinued Nogales Transmission Project (6)	5			—			—			5
Other Regulatory Assets (3)	14			2			—			16
Total Regulatory Assets—Noncurrent	141			8			2			151
Regulatory Liabilities—Current
PGA (2)	—			—			(15		)	(15		)
RES (2)	(22		)	(9		)	—			(31		)
Other Current Regulatory Liabilities	(2		)	(6		)	—			(8		)
Total Regulatory Liabilities—Current	(24		)	(15		)	(15		)	(54		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(254		)	(12		)	(26		)	(292		)
Income Taxes Payable through Future Rates	(5		)	—			(1		)	(6		)
Deferred Investment Tax Credit (8)	(4		)	—			—			(4		)
Total Regulatory Liabilities—Noncurrent	(263		)	(12		)	(27		)	(302		)
Total Net Regulatory Assets (Liabilities)	$	(103	)	$	(9	)	$	(40	)	$	(152	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	December 31, 2012
	TEP			UNS Electric			UNS Gas			UNS Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	18		$	—		$	—		$	18
Derivative Instruments (Note 15)	2			6			3			11
PPFAC (2)	7			8			—			15
DSM (2)	5			—			—			5
Other Current Regulatory Assets (3)	2			—			1			3
Total Regulatory Assets—Current	34			14			4			52
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	130			5			4			139
Income Taxes Recoverable through Future Revenues (4)	8			2			—			10
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	22			—			—			22
Discontinued Nogales Transmission Project (6)	5			—			—			5
Other Regulatory Assets (3)	13			1			1			15
Total Regulatory Assets—Noncurrent	178			8			5			191
Regulatory Liabilities—Current
PGA (2)	—			—			(17		)	(17		)
RES (2)	(19		)	(4		)	—			(23		)
Other Current Regulatory Liabilities	(2		)	(1		)	(1		)	(4		)
Total Regulatory Liabilities—Current	(21		)	(5		)	(18		)	(44		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(231		)	(11		)	(25		)	(267		)
Income Taxes Payable through Future Rates	(5		)	—			(1		)	(6		)
Deferred Investment Tax Credit (8)	(5		)	—			—			(5		)
Other Regulatory Liabilities	—			(1		)	—			(1		)
Total Regulatory Liabilities—Noncurrent	(241		)	(12		)	(26		)	(279		)
Total Net Regulatory Assets (Liabilities)	$	(50	)	$	5		$	(35	)	$	(80	)

Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets below. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets.

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

⁽²⁾  See Cost Recovery Mechanisms discussion above.

⁽³⁾  TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).

⁽⁴⁾  Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.

⁽⁵⁾  Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.

⁽⁶⁾  TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

⁽⁷⁾  Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.

⁽⁸⁾  The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

IMPACTS OF REGULATORY ACCOUNTING

If we determine that we no longer meet the criteria for continued application of regulatory accounting, we would be required to write off our regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on our financial statements.

NOTE 4. BUSINESS SEGMENTS

We have three reportable segments regularly reviewed by our chief operating decision makers to evaluate performance and make operating decisions.

(1) TEP, a regulated electric utility and our largest subsidiary

(2) UNS Electric, a regulated electric utility

(3) UNS Gas, a regulated gas distribution utility

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

	Reportable Segments
	TEP			UNS Electric			UNS Gas			Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
2013
Income Statement
Operating Revenues-External	$	1,180		$	174		$	131		$	2		$	(2	)	$	1,485
Operating Revenues-Intersegment (1)	17			2			3			17			(39		)	—
Depreciation and Amortization	149			19			9			—			—			177
Interest Income	—			1			—			—			—			1
Interest Expense	79			7			6			1			—			93
Income Tax Expense	48			7			7			(4		)	—			58
Net Income	101			12			11			3			—			127
Cash Flow Statement
Capital Expenditures	(253		)	(56		)	(17		)	—			—			(326		)
Balance Sheet
Total Assets	3,556			404			311			1,194			(1,192		)	4,273

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Reportable Segments
	TEP			UNS Electric			UNS Gas			Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
2012
Income Statement
Operating Revenues-External	$	1,145		$	189		$	129		$	—		$	(1	)	$	1,462
Operating Revenues-Intersegment (1)	17			1			4			18			(40		)	—
Depreciation and Amortization	150			18			9			—			—			177
Interest Income	—			—			—			1			—			1
Interest Expense	88			8			6			3			—			105
Income Tax Expense	39			11			6			—			—			56
Net Income	65			17			9			—			—			91
Cash Flow Statement
Capital Expenditures	(253		)	(38		)	(16		)	—			—			(307		)
Balance Sheet
Total Assets	3,461			370			310			1,121			(1,122		)	4,140
2011
Income Statement
Operating Revenues-External	$	1,141		$	188		$	149		$	—		$	1		$	1,479
Operating Revenue-Intersegment (1)	15			2			2			23			(42		)	—
Depreciation and Amortization	140			17			8			1			(1		)	165
Interest Income	4			—			—			1			—			5
Interest Expense	89			7			7			9			—			112
Income Tax Expense	52			11			7			(1		)	(2		)	67
Net Income	85			18			10			—			(3		)	110
Cash Flow Statement
Capital Expenditures	(352		)	(96		)	(13		)	(34		)	121			(374		)

⁽¹⁾  Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

⁽²⁾  Other includes the UNS Energy and UES holding companies, Millennium, and UED.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5. UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

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

	UNS Energy				TEP
	December 31,				December 31,
	2013		2012		2013		2012
	Millions of Dollars
Plant in Service:
Electric Generation Plant	$	1,974	$	1,932	$	1,889	$	1,847
Electric Transmission Plant	912		842		825		796
Electric Distribution Plant	1,529		1,495		1,298		1,271
Gas Distribution Plant	252		240		—		—
Gas Transmission Plant	18		18		—		—
General Plant	356		347		312		309
Intangible Plant - Software Costs (1) (2)	142		124		141		123
Intangible Plant - Other	5		5		—		—
Electric Plant Held for Future Use	4		3		3		2
Total Plant in Service	$	5,192	$	5,006	$	4,468	$	4,348
Utility Plant under Capital Leases(3)	$	638	$	583	$	638	$	583

⁽¹⁾  Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.

⁽²⁾  The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.

⁽³⁾  In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.

TEP Utility Plant under Capital Leases

All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term. See Note 6. At December 31, 2013, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:

	Years Ended December 31,
	2013		2012		2011
	Millions of Dollars
Lease Expense:
Interest Expense – Included in:
Capital Leases	25		$	34	$	40
Operating Expenses – Fuel	2		3		4
Other Expense	—		—		1
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel	5		4		3
Operating Expenses – Amortization	15		14		14
Total Lease Expense	$	47	$	55	$	62

Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2013, were as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	TEP
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant (1)	3.31%	22
Electric Transmission Plant	1.48%	32
Electric Distribution Plant (1)	2.08%	35
General Plant (1)	5.48%	11
Intangible Plant (2)	Various	Various

	UNS Electric
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant	2.56%	36
Electric Transmission Plant	3.36%	19
Electric Distribution Plant	3.97%	15
General Plant	8.01%	7
Intangible Plant (3)	Various	Various

	UNS Gas
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Gas Generation Plant	2.37%	41
Gas Transmission Plant	1.54%	54
General Plant	4.38%	7
Intangible Plant (4)	Various	Various

⁽¹⁾ In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.

⁽²⁾  The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life based on either the average lives of 3 to 5 years for smaller application software or remaining lives ranging from 5 to 19 years for large enterprise software.

⁽³⁾  UNS Electric's intangible plant primarily represents capitalized interconnection costs, which are amortized based on either an average life of 23 years or a remaining life of 35 years.

⁽⁴⁾  UNS Gas' intangible plant consists of miscellaneous intangible assets, which are amortized over an average life of either 15 or 25 years.

⁽⁵⁾  The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

JOINTLY-OWNED FACILITIES

At December 31, 2013, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:

	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Net Book Value
		Millions of Dollars
San Juan Units 1 and 2	50.0%	$	448	$	6	$	230	$	224
Navajo Units 1, 2, and 3	7.5%	152		1		110		43
Four Corners Units 4 and 5	7.0%	101		2		75		28
Luna Energy Facility	33.3%	53		—		2		51
Transmission Facilities	Various	330		43		190		183
Total		$	1,084	$	52	$	607	$	529

TEP is responsible for its share of operating costs for the above facilities as well as providing financing. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.

ASSET RETIREMENT OBLIGATIONS

The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:

	UNS Energy
	December 31,
	2013		2012
	Millions of Dollars
Beginning Balance	$	14	$	13
Liabilities Incurred	1		—
Accretion Expense or Regulatory Deferral	1		1
Revisions to the Present Value of Estimated Cash Flows (1)	7		—
Ending Balance	$	23	$	14

⁽¹⁾ Primarily related to changes in expected retirement dates of generating facilities.

The table above primarily reflects TEP's ARO obligations. UNS Electric's ARO obligations were less than $1 million at December 31, 2013 and 2012.

NOTE 6. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

Long-term debt matures more than one year from the date of the financial statements. We summarize UNS Energy’s and TEP’s long-term debt in the statements of capitalization.

UNS ENERGY CONVERTIBLE SENIOR NOTES

In 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. In 2012, UNS Energy converted approximately $147 million of the Convertible Senior Notes into approximately 4.3 million shares of Common Stock and redeemed $3 million for cash.

TEP DEBT ISSUANCES AND REDEMPTIONS

Unsecured Tax-Exempt Variable Rate Bonds

In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate Industrial Development Revenue Bonds (IDRBs), due April 2032. The lender resets the interest rate monthly based on a percentage of an index rate equal to one-month LIBOR plus a bank margin rate; the rate at December 31, 2013 was

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

0.948% per annum. These bonds are multi-modal bonds, and the initial term is set at five years through November 2018, at which time the bonds will be subject to mandatory tender for purchase. Proceeds were deposited with a trustee to redeem $100 million variable rate bonds in December 2013.

Secured Tax-Exempt Variable Rate Bonds and Interest Rate Swap

Certain of TEP's tax-exempt, variable rate bonds are secured by Letter of Credits (LOCs) issued under the TEP Credit Agreement and TEP Reimbursement Agreement, see below.

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

	Years Ended December 31,
	2013	2012	2011
Interest Rates on Bonds:
Average Interest Rate	0.10%	0.17%	0.18%
Range of Average Weekly Rates	0.06% - 0.25%	0.06% - 0.26%	0.05% - 0.34%

In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014.

Unsecured Tax-Exempt Fixed Rate Bonds

In March 2013, TEP issued approximately $91 million aggregate principal amount of Pima County, Arizona, unsecured tax-exempt Industrial Development Bonds (IDBs). The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 1, 2023. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013.

In June 2012, TEP issued approximately $16 million of Pima County, Arizona, unsecured tax-exempt IDBs. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $16 million of unsecured, tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033.

In March 2012, TEP issued $177 million of Apache County, Arizona, unsecured, tax-exempt pollution control bonds. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875% and maturity dates ranging from 2026 to 2033.

Unsecured Fixed Rate Notes

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

TEP MORTGAGE INDENTURE

Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP canceled $423 million in mortgage bonds and discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.

UNS ENERGY CREDIT AGREEMENT

The UNS Energy Credit Agreement consists of a $125 million revolving credit facility and revolving LOC facility and expires in November 2016. UNS Energy’s obligations under the agreement are secured by a pledge of the capital stock of Millennium, UES, and UED.

UNS Energy had $54 million of outstanding borrowings at December 31, 2013 and $45 million of outstanding borrowings at December 31, 2012, under its revolving credit facility. The weighted average interest rate on the revolver was 1.66% at

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2013 and 1.96% at December 31, 2012. We report the revolver borrowings in Long-Term Debt on the balance sheet as UNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 14, 2014, outstanding borrowings under the UNS Energy Credit Agreement totaled $52 million.

Interest rates and fees under the UNS Energy Credit Agreement are based on a pricing grid tied to UNS Energy’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.25% for Eurodollar loans or Alternate Base Rate plus 0.25% for Alternate Base Rate loans.

TEP CREDIT AGREEMENT

The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility, and a $82 million LOC facility to support tax-exempt bonds, and expires in November 2016. In December 2013, TEP reduced its letter of credit facility from $186 million to $82 million, following the refinancing of $100 million of variable rate bonds and the cancellation of $104 million of LOCs supporting those bonds.

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million LOC facility is 1.125%.

TEP had no borrowings and $1 million outstanding in LOCs issued under its revolving credit facility at December 31, 2013 and December 31, 2012. The revolving loan balance was included in Current Liabilities on UNS Energy’s and TEP’s balance sheets. The outstanding LOCs are off-balance sheet obligations of TEP. As of February 14, 2014, TEP had $90 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility.

2010 TEP REIMBURSEMENT AGREEMENT

A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010. In February 2014, TEP amended the agreement to extend the LOC expiration date from 2014 to 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 1.00% per annum.

UNS ELECTRIC/UNS GAS CREDIT AGREEMENT

The UNS Electric/UNS Gas Credit Agreement consists of a $100 million revolving credit and revolving LOC facility, and expires in November 2016. The maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. UNS Electric and UNS Gas each are liable for only their own individual borrowings under the UNS Electric/UNS Gas Credit Agreement. UES guarantees the obligations of both UNS Electric and UNS Gas. The UNS Electric/UNS Gas Credit Agreement may be used to issue LOCs, as well as for revolver borrowings. UNS Electric and UNS Gas issue LOCs, which are off-balance sheet obligations, to support power and gas purchases and hedges.

Interest rates and fees under the UNS Electric/UNS Gas Credit Agreement are based on a pricing grid tied to their credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans.

UNS Electric had $22 million in borrowings and less than $0.5 million in outstanding LOCs under the UNS Electric/UNS Gas Credit Agreement as of December 31, 2013. The revolving loan balance was included in Current Liabilities on UNS Energy’s balance sheet. UNS Electric had no borrowings outstanding and less than $0.5 million LOCs under UNS Electric/UNS Gas Credit Agreement as of December 31, 2012. The oustanding LOCs balances are not shown on the balance sheet. As of February 14, 2014, UNS Electric had $25 million in borrowings and less than $0.5 million in outstanding LOCs under the UNS Electric/UNS Gas Credit Agreement.

UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP

In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four years period ending August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

COVENANT COMPLIANCE

Our credit agreements, the 2010 TEP Reimbursement Agreement, and certain of our long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. The UNS Energy Credit Agreement also requires UNS Energy to meet a minimum cash flow to interest coverage ratio, and each of our credit agreements stipulate a maximum leverage ratio. UNS Energy and its subsidiaries may pay dividends so long as we maintain compliance with our credit agreements.

At December 31, 2013, we were in compliance with the terms of our long-term debt, credit agreements, and the 2010 TEP Reimbursement Agreement. No amounts of net income were subject to dividend restrictions.

TEP CAPITAL LEASE OBLIGATIONS

In January 2014, through scheduled lease payments, TEP reduced its capital lease obligations by $80 million.

Springerville Unit 1 Capital Lease Purchase Commitments

The Springerville Unit 1 Leases have an initial term to January 2015, and include a fair market value purchase option at the end of the initial lease term. In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a capacity rating of 387 MW.

In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value, upon the expiration of the lease term in January 2015.

In October 2013, TEP elected to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014.

Upon close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of capacity. Due to TEP's purchase commitments, TEP and UNS Energy recorded an increase of approximately $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets.

Springerville Coal Handling and Common Facilities Leases

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

The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. Instead of extending the leases, TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of the common facilities are $38 million in 2017 and $68 million in 2021.

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

Lease Debt and Equity

Investments in Springerville Lease Debt and Equity

In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2013 and December 31, 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Interest Rate Swaps—Springerville Common Facilities Lease Debt

TEP’s interest rate swaps hedge the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month London Interbank Offered Rate (LIBOR) plus a spread. The applicable spread was 1.75% at December 31, 2013 and December 31, 2012.

The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

Lease Debt Outstanding at December 31, 2013	Fixed Rate		LIBOR Spread
Swap 1 - Notional Amount $33 million - Effective Date June 2006	5.77	%	1.75	%
Swap 2 - Notional Amount $16 million - Effective Date May 2009	3.18	%	1.75	%
Swap 3 - Notional Amount $6 million - Effective Date May 2009	3.32	%	1.75	%

TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 15.

DEBT MATURITIES

Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:

	TEP Long-Term Debt Maturities (1)		TEP Capital Lease Obligations			TEP Total			UNS Electric		UNS Gas		UNS Energy Parent Company		Total
	Millions of Dollars
2014	$	—	$	214		$	214		$	—	$	—	$	—	$	214
2015	—		69			69			80		50		—		199
2016	78		17			95			—		—		54		149
2017	—		18			18			—		—		—		18
2018	100		11			111			—		—		—		111
Total 2014 – 2018	178		329			507			80		50		54		691
Thereafter	1,046		30			1,076			50		50		—		1,176
Less: Imputed Interest	—		(42		)	(42		)	—		—		—		(42		)
Total	$	1,224	$	317		$	1,541		$	130	$	100	$	54	$	1,825

⁽¹⁾  $115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 7. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS

At December 31, 2013, UNS Energy and TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases. UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas:

	UNS Energy Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	103	$	83	$	80	$	75	$	49	$	345	$	735
Purchased Power	75		17		—		—		—		—		92
Transmission	7		13		12		12		11		27		82
Renewable Power Purchase Agreements	36		37		37		37		37		485		669
RES Performance-Based Incentives	9		9		9		9		9		85		130
Operating Leases	4		4		3		2		2		14		29
Total Purchase Commitments	$	234	$	163	$	141	$	135	$	108	$	956	$	1,737

At December 31, 2013, TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases:

	TEP Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	77	$	63	$	64	$	62	$	36	$	285	$	587
Purchased Power	27		5		—		—		—		—		32
Transmission	3		6		6		6		6		21		48
Renewable Power Purchase Agreements	30		31		31		31		31		410		564
RES Performance-Based Incentives	8		8		8		8		8		83		123
Operating Leases	3		3		2		2		2		14		26
Total Purchase Commitments	$	148	$	116	$	111	$	109	$	83	$	813	$	1,380

Fuel

TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more than the minimum purchase obligations to meet its fuel requirements. TEP's fuel costs are recoverable from customers through the PPFAC.

UNS Gas purchases gas from various supplies at market prices. However, UNS Gas' risk of loss due to increased costs is mitigated through the use of the PGA, which provides for the pass-through of actual commodity costs to customers. UNS Gas' forward gas purchase agreements expire through 2016. Certain of these contracts are at a fixed price per Million British Thermal Units (MMbtu) and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected marked prices as of December 31, 2013. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2016 and 2023.

Purchased Power and Transmission

TEP and UNS Electric have agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in 2014 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP has agreements with other utilities to provide transmission services. These contracts expire in various years between 2018 and 2028. UNS Electric imports the power it purchases over the Western Area Power Administration's (WAPA) transmission lines. UNS Electric's transmission capacity agreements with WAPA provide for annual rate adjustments and expire in 2016.

TEP's and UNS Electric's purchased power and transmission costs are recoverable from customers through their respective PPFAC mechanisms.

Renewable Power Purchase Agreements and RES Performance-Based Incentives

TEP and UNS Electric have entered into 20 year Renewable Power Purchase Agreements (PPAs) which require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. TEP has entered into additional long-term renewable PPAs to comply with RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 3.

TEP and UNS Electric have entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 3.

Operating Leases

Our operating lease expense is primarily for rail cars, office facilities, land easements, and rights of way with varying terms, provisions, and expiration dates. UNS Energy's operating lease expense totaled $3 million in each of 2013, 2012, and 2011, and TEP's operating lease expense totaled $2 million in each of 2013, 2012, and 2011.

TEP CONTINGENCIES

Potential Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility; see Note 8.

Claim Related to San Juan Generating Station

San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The joint participants have applied to have the matter stayed until March 17, 2014 in furtherance of settlement talks.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.

In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. The coal supplier and Four Corners’ operating agent intend to contest the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. TEP cannot predict the outcome or timing of resolution of this claim.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $18 million at December 31, 2013 and $16 million at December 31, 2012.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows us to pass through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

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. 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 Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. See Note 3. 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.

Performance Guarantees

The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. TEP's joint participation agreements expire in 2016 through 2046.

UNS ELECTRIC CONTINGENCIES

Potential Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 8.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

ENVIRONMENTAL MATTERS

Environmental Regulation

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $5 million in 2013, $2 million in 2012, and $8 million in 2011 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $12 million in 2014 and $36 million in 2015. In addition, TEP recorded O&M expenses of $8 million in 2013, $15 million in 2012, and $12 million in 2011. TEP expects environmental O&M expenses to be $5 million in each of 2014 and 2015.

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.

Hazardous Air Pollutant Requirements

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATs) rule, additional emission control equipment will be required by 2015. The estimated costs include:

Estimated Emissions Control Costs:	Navajo		Four Corners		Springerville
	Millions of Dollars
Capital Expenditures - Mercury Emissions Control	$	1	$	1	$	5
Annual O&M Expenses	1		1		3

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

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility 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. 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.

In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install SCRs. Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.

TEP's estimated potential costs involved in meeting these rules are:

Estimated Potential Emissions Control Costs:	Navajo (1)		San Juan (2)	Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital - SCR	$	42	$ 180-200	$	35	$	—
Capital - SNCR	—		35	—		12
Annual O&M - SCR	1		6	2		—
Annual O&M - SNCR	—		1	—		5-6

⁽¹⁾ The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

⁽²⁾ The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

⁽³⁾ On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾ In January 2014, the EPA issued a proposal that would require TEP to either (i) install SNCR by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is expected to issue a final BART determination by July 2014. At December 31, 2013, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the plant was built after the BART-applicable dates.

NOTE 8. POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY

On December 23, 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Generating Station Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to regulatory approvals and other closing conditions. In December 2013, UNS Electric filed an application for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3.

TEP expects to provide a letter of credit in March 2014 for $15 million to satisfy a condition of the purchase agreement. The seller of Gila River Unit 3 would be entitled to draw upon the letter of credit and apply such amount as liquidated damages if it has validly terminated the Purchase Agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the letter of credit would be canceled.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 9. INCOME TAXES

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:

	UNS Energy									TEP
	Years Ended December 31,
	2013			2012			2011			2013			2012			2011
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	65		$	51		$	62		$	52		$	37		$	48
State Income Tax Expense, Net of Federal Deduction	8			7			8			7			5			6
Federal/State Tax Credits	(2		)	(1		)	(3		)	(2		)	(1		)	(2		)
Allowance for Equity Funds Used During Construction	(2		)	(1		)	(1		)	(1		)	(1		)	(1		)
Deferred Tax Asset Valuation Allowance	—			—			—			2			—			—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—			—			(11		)	—			—
Other	—			—			1			1			(1		)	1
Total Federal and State Income Tax Expense	$	58		$	56		$	67		$	48		$	39		$	52

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.

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

	UNS Energy									TEP
	Years Ended December 31,
	2013			2012			2011			2013			2012			2011
	Millions of Dollars
Current Tax Expense (Benefit):
Federal	$	(11	)	$	(2	)	$	(7	)	$	(8	)	$	(4	)	$	(5	)
State	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total Current Tax Expense (Benefit)	(13		)	(4		)	(9		)	(10		)	(6		)	(7		)
Deferred Tax Expense (Benefit):
Federal	61			51			64			47			38			50
Federal Investment Tax Credits	(1		)	—			(1		)	(1		)	—			(1		)
State	11			9			13			12			7			10
Total Deferred Tax Expense (Benefit)	71			60			76			58			45			59
Total Federal and State Income Tax Expense	$	58		$	56		$	67		$	48		$	39		$	52

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Gross Deferred Income Tax Assets:
Capital Lease Obligations	$	127		$	141		$	127		$	141
Net Operating Loss Carryforwards	94			72			104			85
Customer Advances and Contributions in Aid of Construction	33			34			19			19
Alternative Minimum Tax Credit	43			43			24			24
Accrued Postretirement Benefits	23			23			23			23
Renewable Energy Credit Up-Front Incentive Payments	—			26			—			20
Emission Allowance Inventory	10			10			10			10
Unregulated Investment Losses	7			9			—			—
Other	50			44			44			43
Total Gross Deferred Income Tax Assets	387			402			351			365
Deferred Tax Assets Valuation Allowance	(7		)	(7		)	(2		)	—
Gross Deferred Income Tax Liabilities:
Plant – Net	(708		)	(648		)	(615		)	(571		)
Capital Lease Assets – Net	(47		)	(34		)	(47		)	(34		)
Pensions	(21		)	(23		)	(22		)	(24		)
PPFAC	(5		)	(6		)	(2		)	(3		)
Other	(21		)	(15		)	(20		)	(15		)
Total Gross Deferred Income Tax Liabilities	(802		)	(726		)	(706		)	(647		)
Net Deferred Income Tax Liabilities	$	(422	)	$	(331	)	$	(357	)	$	(282	)

The net deferred income tax liability on the balance sheet is as follows:

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Deferred Income Taxes – Current Assets	$	60		$	34		$	64		$	37
Deferred Income Taxes – Noncurrent Liabilities	(482		)	(365		)	(421		)	(319		)
Net Deferred Income Tax Liability	$	(422	)	$	(331	)	$	(357	)	$	(282	)

The unregulated investment loss deferred tax asset includes $7 million of capital loss at December 31, 2013 and December 31, 2012. The deferred tax asset can only be used if the company has capital gains to offset the losses. Management believes that it is more likely than not that the company will not be able to generate future capital gains. As a result, UNS Energy recorded a $7 million valuation allowance against the deferred tax asset as of December 31, 2013, and December 31, 2012. Management believes that based on its historical pattern of taxable income, UNS Energy will produce sufficient income in the future to realize all other deferred income tax assets. TEP has recorded a $2 million valuation allowance against state tax credit carryforward deferred tax assets at December 31, 2013. Management believes TEP will not produce sufficient taxable income to use all state tax credits before they expire.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Tax Position

As of December 31, 2013, UNS Energy and TEP had the following carryforward amounts:

	UNS Energy			TEP
	Amount		Expiring Year	Amount		Expiring Year
	Millions of Dollars			Millions of Dollars
Capital Loss	$	7	2015	$	—	N/A
Federal Net Operating Loss	266		2031-33	286		2031-33
State Net Operating Loss	30		2032-33	99		2016-33
State Credits	5		2016-18	6		2016-18
Alternative Minimum Tax Credit	43		None	24		None
Investment Tax Credits	6		2032-33	6		2032-33

If the pending Merger is approved there would be an annual limitation on the amount of carryforwards that can be utilized.

Excess Tax Benefit Realized from Share-Based Compensation Plans

UNS Energy records excess tax benefits as an increase to Common Stock when tax deductions for share-based compensation exceed the expense recorded in the financial statements and they result in a reduction to income taxes payable. As of December 31, 2013, UNS Energy had $4 million of excess tax benefits that were not recorded in Common Stock. The excess benefits will be recorded in Common Stock when the Federal net operating loss carryforwards of $266 million are used.

Uncertain Tax Positions

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Unrecognized Tax Benefits, Beginning of Year	$	30		$	29		$	23		$	24
Additions Based on Tax Positions Taken in the Current Year	2			5			1			3
Reductions of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(4		)	(22		)	(4		)
Unrecognized Tax Benefits, End of Year	$	4		$	30		$	2		$	23

Unrecognized tax benefits, if recognized, would not reduce income tax expense at December 31, 2013. Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million at December 31, 2012 for both UNS Energy and TEP.

UNS Energy and TEP recognized a $1 million reduction to interest expense in 2013 and no reduction in 2012. UNS Energy and TEP had no interest payable balance at December 31, 2013 and $1 million at December 31, 2012. We have no penalties accrued in the years presented.

In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources.  These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation.  As a result of the IRS ruling in the first quarter of 2013, UNS Energy reduced unrecognized tax benefits by $28 million, and TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.

UNS Energy and TEP have been audited by the IRS through tax year 2010 and the IRS has provided notice of intent to audit the 2011 tax returns. UNS Energy and TEP are not currently under audit by any state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of ongoing IRS audits, but we are unable to determine the amount of change.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Tangible Property Regulations

In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. The adoption of these regulations by UNS Energy and TEP resulted in a $4 million increase to plant-related deferred tax liabilities and net operating loss deferred tax assets at December 31, 2013.

NOTE 10. EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

We sponsor three noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.

We also maintain a Supplemental Executive Retirement Plan (SERP) for executive management.

OTHER RETIREE BENEFIT PLANS

TEP provides limited health care and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. UNS Electric and UNS Gas provide retiree medical benefits for current retirees. UNS Electric's and UNS Gas' active employees are not eligible for retiree medical benefits.

TEP funds its other retiree benefits for classified employees through a Voluntary Employee Beneficiary Association (VEBA). TEP contributed $3 million in each of 2013 and 2012 and $2 million in 2011 to the VEBA. Other retiree benefits for unclassified employees are self funded.

TEP’s other retiree benefit plan was amended in 2012 to increase the participant contributions for classified employees who retire after February 1, 2014. The effect on the benefit obligation was less than $1 million.

REGULATORY RECOVERY

We record changes in our non-SERP pension plans and other retiree benefit plan, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income since SERP expense is not currently recoverable in rates.

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

	Pension Benefits						Other  Retiree Benefits
	Years Ended December 31,
	2013			2012			2013			2012
	Millions of Dollars
Regulatory Pension Asset Included in Other Regulatory Assets	$	75		$	129		$	4		$	10
Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)	(1		)	(2		)	(2		)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(28		)	(90		)	(63		)	(69		)
Accumulated Other Comprehensive Loss (related to SERP)	2			4			—			—
Net Amount Recognized	$	48		$	42		$	(61	)	$	(61	)

The table above includes accrued pension benefit liabilities for UNS Electric and UNS Gas of approximately $5 million at December 31, 2013 and $9 million at December 31, 2012. The table also includes an other retiree benefit liability of $1 million for UNS Electric and UNS Gas for each period presented.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

OBLIGATIONS AND FUNDED STATUS

We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2013 and December 31, 2012. The table below includes TEP’s, UNS Electric’s, and UNS Gas’ plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below:

	Pension Benefits						Other  Retiree Benefits
	Years Ended December 31,
	2013			2012			2013			2012
	Millions of Dollars
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	380		$	319		$	78		$	73
Actuarial (Gain) Loss	(38		)	51			(5		)	3
Interest Cost	15			15			3			3
Service Cost	13			10			3			3
Benefits Paid	(18		)	(15		)	(4		)	(4		)
Projected Benefit Obligation at End of Year	352			380			75			78
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year	289			245			7			5
Actual Return on Plan Assets	29			36			1			1
Benefits Paid	(18		)	(15		)	(4		)	(4		)
Employer Contributions (1)	23			23			6			5
Fair Value of Plan Assets at End of Year	323			289			10			7
Funded Status at End of Year	$	(29	)	$	(91	)	$	(65	)	$	(71	)

⁽¹⁾  TEP made $22 million in pension contributions and $6 million in other retiree benefits contributions in 2013 and $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012. In 2014, UNS Energy expects to contribute $10 million to the pension plans, including $9 million in contributions by TEP.

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

• Pension benefit obligations of $21 million at December 31, 2013 and $23 million at December 31, 2012;

• Plan assets of $16 million at December 31, 2013 and $14 million at December 31, 2012; and

• A retiree benefit obligation of $1 million at December 31, 2013 and December 31, 2012.

The following table provides the components of UNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:

	Pension Benefits				Other  Retiree Benefits
	Years Ended December 31,
	2013		2012		2013			2012
	Millions of Dollars
Net Loss	$	77	$	133	$	7		$	13
Prior Service Cost (Benefit)	—		1		(3		)	(3		)

The accumulated benefit obligation aggregated for all pension plans is $314 million at December 31, 2013 and $334 million at December 31, 2012.

Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
	December 31,
	2013	2012
	Millions of Dollars
Accumulated Benefit Obligation at End of Year	30	334
Fair Value of Plan Assets at End of Year	16	289

K-119

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At December 31, 2012, all four UNS Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets. Due to 2013 contributions, returns on plan assets, and the favorable impact of the increase in the discount rate on the accumulated benefit obligations, only the SERP, which is unfunded, and the UES plan have accumulated benefit obligations in excess of plan assets at December 31, 2013.

UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:

	Pension Benefits									Other Retiree Benefits
	Years Ended December 31,
	2013			2012			2011			2013			2012		2011
	Millions of Dollars
Service Cost	$	13		$	10		$	10		$	4		$	3	$	3
Interest Cost	15			16			15			3			3		4
Expected Return on Plan Assets	(20		)	(17		)	(16		)	(1		)	—		—
Prior Service Cost Amortization	—			—			—			(1		)	—		(1		)
Actuarial Loss Amortization	9			7			6			1			—		—
Net Periodic Benefit Cost	$	17		$	16		$	15		$	6		$	6	$	6

Approximately 21% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:

	Pension Benefits
	2013						2012					2011
	Regulatory Asset			AOCI			Regulatory Asset			AOCI		Regulatory Asset			AOCI
	Millions of Dollars
Current Year Actuarial (Gain) Loss	$	(46	)	$	(1	)	$	30		$	1	$	25		$	(2	)
Amortization of Actuarial Gain (Loss)	(8		)	—			(7		)	—		(5		)	—
Total Recognized (Gain) Loss	$	(54	)	$	(1	)	$	23		$	1	$	20		$	(2	)

	Other Retiree Benefits
	2013			2012		2011
	Regulatory Asset			Regulatory Asset		Regulatory Asset
	Millions of Dollars
Prior Service Cost (Credit)	$	—		$	—	$	(2	)
Current Year Actuarial (Gain) Loss	(6		)	2		—
Amortization of Actuarial (Gain) Loss	(1		)	—		—
Amortization of Prior Service (Cost) Credit	1			—		1
Total Recognized (Gain) Loss	$	(6	)	$	2	$	(1	)

For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $4 million estimated net loss and less than $1 million prior service cost from other regulatory assets and less than $1 million prior service cost from AOCI into net periodic benefit cost in 2014. The estimated prior service benefit for the other retiree benefit plan that will be amortized from other regulatory assets into net periodic benefit cost in 2014 is less than $1.0 million.

	Pension Benefits		Other Retiree Benefits
	2013	2012	2013	2012
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	5.0% - 5.2%	4.1%-4.3%	4.7%	3.8%
Rate of Compensation Increase	3.0%	3.0%	N/A	N/A

K-120

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Pension Benefits			Other Retiree Benefits
	2013	2012	2011	2013	2012	2011
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate	4.1%-4.3%	4.9% - 5.0%	5.5% - 5.6%	3.8%	4.7%	5.2%
Rate of Compensation Increase	3.0%	3.0%	3.0% - 5.0%	N/A	N/A	N/A
Expected Return on Plan Assets	7.0%	7.0%	7.0%	7.0%	7.0%	5.1%

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

We use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25^th percentile to the 75^th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward looking return expectations only. The above method is used for all asset classes.

Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. The assumed health care cost trend rates follow:

	December 31,
	2013	2012
Health Care Cost Trend Rate Assumed for Next Year	6.7%	6.9%
Ultimate Health Care Cost Trend Rate Assumed	4.5%	4.5%
Year that the Rate Reaches the Ultimate Trend Rate	2027	2027

Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2013, amounts:

	One-Percentage- Point Increase		One-Percentage- Point Decrease
	Millions of Dollars
Effect on Total Service and Interest Cost Components	$	1	$	(1	)
Effect on Retiree Benefit Obligation	6		(5		)

PENSION PLAN AND OTHER RETIREE BENEFIT ASSETS

Pension Assets

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

	TEP Plan Assets				UNS Electric and UNS Gas Plan Assets
	2013		2012		2013		2012
Asset Category
Equity Securities	50	%	50	%	50	%	56	%
Fixed Income Securities	40		41	%	40		33
Real Estate	7		7	%	10		11
Other	3		2	%	—		—
Total	100	%	100	%	100	%	100	%

K-121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:

	Fair Value Measurements of Pension Assets December 31, 2013
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap	—		80		—		80
United States Small Cap	—		17		—		17
Non-United States	—		65		—		65
Fixed Income	—		130		—		130
Real Estate	—		9		14		23
Private Equity	—		—		7		7
Total	$	1	$	301	$	21	$	323
	Fair Value Measurements of Pension Assets December 31, 2012
	Level 1		Level 2		Level 3		Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap	—		71		—		71
United States Small Cap	—		15		—		15
Non-United States	—		59		—		59
Fixed Income	—		116		—		116
Real Estate	—		8		13		21
Private Equity	—		—		6		6
Total	$	1	$	269	$	19	$	289

Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.

Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.

Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 85% of real estate assets tracked by the index in 2013 and comprising 87% in 2012.

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

The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UNS Electric and UNS Gas pension plan of $16 million at December 31, 2013 and $14 million at December 31, 2012.

The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.

K-122

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31, 2013
	Private Equity		Real Estate		Total
	Millions of Dollars
Beginning Balance at January 1, 2013	$	6	$	13	$	19
Actual Return on Plan Assets:
Assets Held at Reporting Date	1		1		2
Purchases, Sales, and Settlements	—		—		—
Ending Balance at December 31, 2013	$	7	$	14	$	21

	Year Ended December 31, 2012
	Private Equity		Real Estate		Total
	Millions of Dollars
Beginning Balance at January 1, 2012	$	4	$	11	$	15
Actual Return on Plan Assets:
Assets Held at Reporting Date	1		2		3
Purchases, Sales, and Settlements	1		—		1
Ending Balance at December 31, 2012	$	6	$	13	$	19

UNS Electric and UNS Gas have no pension assets classified as Level 3 in the fair value hierarchy.

Pension Plan Investments

Investment Goals

Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. We consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.

Risk Management

We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: plan status, plan sponsor financial status and profitability, plan features, and workforce characteristics. We have determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.

Relationship between Plan Assets and Benefit Obligations

The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation.

K-123

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Target Allocation Percentages

The current target allocation percentages for the major asset categories of the plan as of December 31, 2013 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.

	TEP Plan	UNS Electric and UNS Gas Plan	VEBA Trust
Fixed Income	41%	42%	38%
United States Large Cap	24%	24%	39%
Non-United States Developed	15%	14%	7%
Real Estate	8%	10%	—%
United States Small Cap	5%	5%	5%
Non-United States Emerging	5%	5%	9%
Private Equity	2%	—%	—%
Cash/Treasury Bills	—%	—%	2%
Total	100%	100%	100%

Pension Fund Descriptions

For each type of asset category selected by the Pension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds.

Other Retiree Benefit Assets

As of December 31, 2013, the fair value of VEBA trust assets was $10 million, of which $4 million were fixed income investments and $6 million were equities. As of December 31, 2012, the fair value of VEBA trust assets was $7 million, of which $3 million were fixed income investments and $4 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust.

ESTIMATED FUTURE BENEFIT PAYMENTS

TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate.

	2014		2015		2016		2017		2018		2019-2023
	Millions of Dollars
Pension Benefits	$	15	$	16	$	17	$	18	$	20	$	114
Other Retiree Benefits	5		5		5		5		5		29

One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million.

UNS Electric and UNS Gas expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $7 million in 2014 through 2018, and $9 million in 2019 through 2023.

DEFINED CONTRIBUTION PLAN

We offer a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account which may include a UNS Energy stock fund. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in each of 2013, 2012, and 2011. UNS Electric and UNS Gas made matching contributions of less than $1 million in each of 2013, 2012, and 2011.

K-124

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 11. SHARE-BASED COMPENSATION PLANS

Under the UNS Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), the Compensation Committee of the UNS Energy Board of Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted stock units, and performance shares. The total number of shares which may be awarded under the 2011 Plan cannot exceed 1.2 million shares.

STOCK OPTIONS

Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant, and expire on the tenth anniversary of the grant. We recognize compensation expense on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement-eligible officers, we recognize compensation expense immediately. No stock options were granted by the Compensation Committee in 2013, 2012, or 2011.

See summary of stock option activity in the table below:

	2013				2012				2011
Stock Options	Shares (000s)		Weighted Average Exercise Price		Shares (000s)		Weighted Average Exercise Price		Shares (000s)		Weighted Average Exercise Price
Outstanding, Beginning of Year	409		$	29.09	581		$	29.11	921		$	27.96
Exercised	(127	)	30.12		(132	)	26.54		(319	)	25.60
Forfeited/Expired	—		—		(40	)	37.88		(21	)	31.92
Outstanding, End of Year	282		28.63		409		29.09		581		29.11
Exercisable, End of Year	282		$	28.63	409		$	29.09	508		$	29.53
Aggregate Intrinsic Value of Options Exercised ($000s)			$	2,897			$	1,878			$	3,690

See summary of stock options in the tables below:

	December 31, 2013
Aggregate Intrinsic Value for Options Outstanding ($000s)	$	8,795
Aggregate Intrinsic Value for Options Exercisable ($000s)	$	8,795
Weighted Average Remaining Contractual Term of Outstanding Options	4.1 years
Weighted Average Remaining Contractual Term of Exercisable Options	4.1 years

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number  of Shares (000s)	Weighted Average Remaining Contractual Term	Weighted Average Exercise Price		Number  of Shares (000s)	Weighted Average Exercise Price
$26.11—$37.88	282	4.1 years	$	28.63	282	$	28.63

RESTRICTED STOCK UNITS AND PERFORMANCE SHARES

Restricted Stock Units

In 2013, 2012, and 2011, the Compensation Committee granted restricted stock units to non-employee directors. We recognize compensation expense equal to the fair valuin the tablee on the grant date over the one-year vesting period. The grant date fair value was calculated by reducing the grant date share price by the present value of the dividends expected to be paid on the shares during the vesting period. Fully vested but undistributed non-employee director stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. We issue Common Stock for the vested stock units in the January following the year the person is no longer a director.

In 2013, the Compensation Committee granted restricted stock units to certain management employees. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. The grant date fair value was the closing Common Stock market price on the date of grant. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.

K-125

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

See summary of restricted stock units awarded in the table below:

	Non-Employee Directors			Management Employees
Award Year	Restricted Stock Units	Grant Date Fair Value		Restricted Stock Units	Grant Date Fair Value
2013	8,870	$	48.99	21,560	$	46.23
2012	15,303	35.94		—	—
2011	14,655	37.53		—	—

Performance Shares

In 2013, 2012, and 2011, the Compensation Committee granted performance share awards to certain management employees. Half of the performance share awards will be paid out in Common Stock based on UNS Energy’s compound annualized Total Shareholder Return (TSR) relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period. The grant date fair values of these awards were derived based on a Monte Carlo simulation. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half will be paid out in Common Stock based on cumulative net income (CNI) for the three-year performance period. The grant date fair values of these awards were the closing Common Stock market prices on the dates of grant. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.

The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.

See summary of performance shares awarded in the table below:

		Grant Date Fair Value
Award Year	Performance Shares	TSR-Based Award		CNI-Based Award
2013	43,120	$	45.54	$	46.23
2012	80,140	32.71		36.40
2011	80,440	33.73		36.58

At December 31, 2013, upon completion of the three-year performance period, 68,158 shares were earned and vested based on goal attainment at 150% of target for the awards based on TSR and 57.8% of target for the awards based on CNI; 28,682 shares were unearned and forfeited. The vested performance shares also earned 8,521 in dividend equivalent shares.

See summary of restricted stock units and performance shares current year activity in the table below:

	Restricted Stock Units				Performance Shares
	Shares (000s)		Weighted Average Grant  Date Fair Value		Shares (000s)		Weighted Average Grant  Date Fair Value
Non-vested, Beginning of Year	15		$	35.94	145		$	34.83
Granted	31		47.04		52		44.94
Vested	(16	)	36.27		(52	)	35.35
Forfeited	(2	)	46.23		(32	)	37.57
Non-vested, End of Year	28		47.12		113		38.45

The total fair value of restricted stock units and performance shares vested were as follows:

	Restricted Stock Units						Performance Shares
	2013		2012		2011		2013		2012		2011
	Thousands of Dollars
Total Fair Value of Shares Vested	$	574	$	550	$	495	$	2,387	$	2,377	$	1,069

Common Stock shares totaling 57,253 in 2013, 31,058 in 2012, and 56,705 in 2011 were issued with no additional increase in equity as the expense was previously recognized over the vesting period.

K-126

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SHARE-BASED COMPENSATION EXPENSE

In 2013, UNS Energy and TEP recorded share-based compensation expense of $3 million. In 2012 and 2011, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. No share-based compensation was capitalized as part of the cost of an asset. UNS Energy did not realize a tax deduction from the exercise of share-based payment arrangements in 2013 or 2011. In 2012, the actual tax deduction realized from the exercise of share-based payment arrangements totaled less than $0.5 million.

At December 31, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $3 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At December 31, 2013, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.

NOTE 12. UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options, share-based compensation awards, or UNS Energy's Convertible Senior Notes were exercised or converted into Common Stock. We excluded anti-dilutive stock options and contingently issuable shares from the calculation of diluted EPS. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the notes were converted to Common Stock.

The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:

	Years Ended December 31,
	2013		2012		2011
	Thousands of Dollars
Numerator:
Net Income	$	127,478	$	90,919	$	109,975
Income from Assumed Conversion of Convertible Senior Notes (1)	—		1,100		4,390
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	127,478	$	92,019	$	114,365
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,446		40,212		36,780
Fully Vested Deferred Stock Units	172		150		129
Participating Securities	—		—		53
Total Weighted Average Common Stock Outstanding and Participating Securities—Basic	41,618		40,362		36,962
Effect of Dilutive Securities:
Convertible Senior Notes (1)	—		1,062		4,281
Options and Stock Issuable Under Share-Based Compensation Plans	357		331		366
Total Weighted Average Common Stock Outstanding —Diluted	41,975		41,755		41,609

⁽¹⁾ In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

K-127

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We excluded the following outstanding stock options, with an exercise price above market, and contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive:

	Years Ended December 31,
	2013	2012	2011
	Thousands of Shares
Stock Options	—	50	153
Restricted Stock Units	6	—	—
Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	50	153

NOTE 13. STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UNS Energy

UNS Energy’s ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium, and UED, as well as compliance with various debt covenant requirements. UNS Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2013; therefore, TEP and the other subsidiaries were not restricted from paying dividends.

The merger agreement with Fortis allows UNS Energy's Board of Directors to authorize quarterly dividends of up to $0.48 per share until the merger is completed, including a pro rata dividend determined by the number of days from the last declared record date to the date the merger is completed.

In February 2014, UNS Energy declared a first quarter dividend to shareholders of $0.48 per share of UNS Energy Common Stock. The dividend, totaling approximately $20 million, will be paid on March 25, 2014, to common shareholders of record as of March 13, 2014.

In the first half of 2012, $147 million of the Convertible Senior Notes outstanding were converted into approximately 4.3 million shares of UNS Energy Common Stock increasing common stock equity by $147 million.

TEP

TEP paid dividends to UNS Energy of $40 million in 2013 and $30 million in 2012. TEP paid no dividends to UNS Energy in 2011.

UNS Energy made no capital contributions to TEP in 2013 or 2012, and made capital contributions to TEP of $30 million in 2011.

K-128

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 14. SUPPLEMENTAL CASH FLOW INFORMATION

A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:

	UNS Energy
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Net Income	$	127,478		$	90,919		$	109,975
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense	149,615			141,303			133,832
Amortization Expense	27,557			35,784			30,983
Depreciation and Amortization Recorded to Fuel and O&M Expense	7,288			6,622			6,140
Amortization of Deferred Debt-Related Costs included in Interest Expense	3,050			3,000			3,985
Provision for Retail Customer Bad Debts	2,263			2,767			2,072
Use of Renewable Energy Credits for Compliance	17,706			5,935			5,695
Deferred Income Taxes	83,501			60,264			75,515
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—			—
Pension and Retiree Expense	22,783			21,856			21,202
Pension and Retiree Funding	(29,161		)	(29,058		)	(28,775		)
Share-Based Compensation Expense	3,399			2,573			2,599
Allowance for Equity Funds Used During Construction	(6,190		)	(3,464		)	(4,496		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(16,313		)	32,246			(4,932		)
PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
Competition Transition Charge Revenue Refunded	—			—			(35,958		)
Partial Write-off of Tucson to Nogales Transmission Line	—			4,668			—
Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,338		)	3,369			2,743
Materials and Fuel Inventory	16,197			(39,429		)	(20,864		)
Accounts Payable	3,223			595			8,792
Income Taxes	(15,868		)	(11,557		)	(2,739		)
Interest Accrued	4,875			6,922			14,344
Taxes Other Than Income Taxes	1,941			(58		)	2,857
Current Regulatory Liabilities	11,124			(684		)	2,644
Other	20,421			11,486			19,097
Net Cash Flows – Operating Activities	$	420,512		$	348,109		$	337,320

K-129

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	TEP
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Net Income	$	101,342		$	65,470		$	85,334
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	118,076			110,931			104,894
Amortization Expense	31,294			39,493			34,650
Depreciation and Amortization Recorded to Fuel and O&M Expense	6,219			5,384			4,509
Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,452			2,227			2,378
Provision for Retail Customer Bad Debts	1,678			1,871			1,447
Use of RECs for Compliance	15,990			5,071			5,190
Deferred Income Taxes	69,950			45,232			59,309
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—			—
Pension and Retiree Expense	19,878			19,289			18,816
Pension and Retiree Funding	(27,636		)	(25,899		)	(25,878		)
Share-Based Compensation Expense	2,709			2,029			2,027
Allowance for Equity Funds Used During Construction	(4,526		)	(2,840		)	(3,842		)
Increase (Decrease) to Reflect PPFAC Recovery	(12,458		)	31,113			(6,165		)
PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
Competition Transition Charge Revenue Refunded	—			—			(35,958		)
Partial Write-off of Tucson to Nogales Transmission Line	—			4,484			—
Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,041		)	(871		)	4,809
Materials and Fuel Inventory	16,145			(38,384		)	(19,789		)
Accounts Payable	334			1,115			14,561
Income Taxes	(10,790		)	(11,421		)	(5,582		)
Interest Accrued	4,859			8,055			14,268
Taxes Other Than Income Taxes	1,425			905			2,282
Current Regulatory Liabilities	3,331			(3,040		)	303
Other	19,711			5,655			18,122
Net Cash Flows – Operating Activities	$	346,191		$	267,919		$	268,294

NON-CASH TRANSACTIONS

In 2013, the following non-cash transactions occurred:

• TEP recorded an increase of $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in December 2014 and January 2015. See Note 6.

• In November 2013, TEP issued $100 million of tax-exempt bonds and the proceeds were deposited with the trustee to redeem debt in December 2013. TEP had no cash receipts or payments as a result of this transaction. See Note 6.

• In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. See Note 6.

K-130

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In 2012, the following non-cash transactions occurred:

• UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Shares. See Note 6; and

• TEP redeemed $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. See Note 6.

Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
	2013		2012		2011
	Thousands of Dollars
(Decrease)/Increase to Utility Plant Accruals(1)	$	4,995	$	4,813	$	(2,741	)
Net Cost of Removal of Interim Retirements(2)	25,182		35,983		31,626
Capital Lease Obligations(3)	9,039		11,967		15,162
Asset Retirement Obligations(4)	8,064		789		7,638

⁽¹⁾  The non-cash additions to Utility Plant represent accruals for capital expenditures.

⁽²⁾  The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.

⁽³⁾  The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.

⁽⁴⁾  The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

NOTE 15. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity.

K-131

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	14		$	14	$	—		$	—		$	—		$	14
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	7			—		3			4			(5		)	2
Total Assets	45			16		25			4			(5		)	40
Liabilities
Energy Contracts - Regulatory Recovery(3)	(7		)	—		(2		)	(5		)	5			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(15		)	—		(9		)	(6		)	5			(10		)
Net Total Assets (Liabilities)	$	30		$	16	$	16		$	(2	)	$	—		$	30

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery(3)	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

K-132

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	2			—		1			1			(1		)	1
Total Assets	26			2		23			1			(1		)	25
Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)	—		—			(2		)	1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(10		)	—		(7		)	(3		)	1			(9		)
Net Total Assets (Liabilities)	$	16		$	2	$	16		$	(2	)	$	—		$	16

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1		$	1	$	—		$	—		$	—		$	1
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	30			8		20			2			(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(3		)	—			1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(15		)	—		(13		)	(2		)	1			(14		)
Net Total Assets (Liabilities)	$	15		$	8	$	7		$	—		$	—		$	15

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

⁽³⁾  Energy Contracts include gas swap agreements (Level 2), power options (Level 2 or Level 3), gas options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.

(4) Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

K-133

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DERIVATIVE INSTRUMENTS

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

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

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.

We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. Beginning in the third quarter of 2013, the fair value of our power options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented.

We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.

Our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our contracts monthly.

Cash Flow Hedges

The interest rate swap agreements expire through January 2020. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 16. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $4 million.

Financial Impact of Energy Contracts

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:

	UNS Energy								TEP
	Years Ended December 31,
	2013			2012			2011		2013		2012			2011
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	(9	)	$	(21	)	$	2	$	—	$	(6	)	$	2

Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At December 31, 2013, UNS Energy and TEP have energy contracts that will settle through the fourth quarter of 2016.

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	December 31, 2013	December 31, 2012	December 31, 2013	December 31, 2012
Power Contracts GWh	1,583	2,228	779	820
Gas Contracts GBtu	33,371	17,851	9,615	7,958

K-134

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Level 3 Fair Value Measurements

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:

		Fair Value at
		December 31, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	1	$	(4	)	Market price per MWh	$	26.54		-	$	51.75
Option Contracts(2)	Option model	3		(2		)	Market Price per MMbtu	$	3.87		-	$	4.32
							Gas Volatility	25.05		%	-	35.07		%
Level 3 Energy Contracts		$	4	$	(6	)

⁽¹⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

⁽²⁾  TEP comprises less than $1 million of the option contract assets.

Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statement.

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(1		)	(2		)
Settlements	4			—
Balances at December 31, 2013	$	(2	)	$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	(1	)

	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(5		)	1
Settlements	10			(1		)
Balances at December 31, 2012	$	(5	)	$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Electric, or UNS Gas; credit rating downgrades; or a failure to meet certain financial ratios. In the

K-135

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.

Material adverse changes could trigger credit risk-related contingent features. At December 31, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $21 million for UNS Energy and $5 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $21 million for UNS Energy and $5 million for TEP.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:

• The carrying amounts of our current assets, current liabilities, including current maturities of long-term debt, and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.

• For Investment in Lease Debt, we calculated the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporated the impact of counterparty credit risk using market credit default swap data. TEP's Investment in Lease Debt matured in January 2013.

• For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.

• For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:

		December 31, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		25		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,507		1,521		1,498		1,583
TEP	Level 2	1,223		1,214		1,223		1,271

K-136

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 16. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The realized changes in AOCI by component are as follows:

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Year Ended December 31, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(1,377	)	$	(1,166	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(2,429		)	(2,429		)	Interest Expense Capital Leases
Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
Tax Benefit	1,801			1,718
Realized Losses on Cash Flow Hedges, Net of Taxes	(2,752		)	(2,624		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(1,488		)	(1,488		)	Other Expense
Tax Benefit	572			572
Amortization, Net of Taxes	(916		)	(916		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(3,668	)	$	(3,540	)

NOTE 17. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board (FASB) issued guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors. This guidance will be effective in the first quarter of 2014. We do not expect the adoption of this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair value and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such change to be material. In addition, we do not expect any material changes in the presentations of our other financial statements.

NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)

K-137

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the summer while UNS Gas’ sales generally peak during the winter. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

	UNS Energy
	First		Second		Third		Fourth
	Thousands of Dollars (Except Per Share Amounts)
2013
Operating Revenue	$	332,141	$	365,217	$	437,041	$	350,161
Operating Income	39,895		60,803		129,765		41,033
Net Income	11,345		34,618		67,990		13,525
Basic EPS	0.27		0.83		1.63		0.32
Diluted EPS	0.27		0.83		1.62		0.32
2012
Operating Revenue	$	315,387	$	363,998	$	434,108	$	348,273
Operating Income (1)	34,403		68,065		106,409		42,918
Net Income	6,476		26,273		50,664		7,506
Basic EPS	0.17		0.65		1.22		0.18
Diluted EPS	0.17		0.64		1.21		0.18

EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.

	TEP
	First			Second		Third		Fourth
	Thousands of Dollars
2013
Operating Revenue	$	247,751		$	304,263	$	371,239	$	273,437
Operating Income	22,747			53,433		123,177		31,014
Net Income	1,478			30,787		64,167		4,910
2012
Operating Revenue	$	223,978		$	299,419	$	366,910	$	271,353
Operating Income (1)	17,898			58,211		94,079		30,299
Net Income (Loss)	(1,461		)	21,910		44,569		452

⁽¹⁾Immaterial variances from quarterly amounts previously reported result from line item reclassifications.

K-138

Schedule II—Valuation and Qualifying Accounts – UNS Energy

Allowance for Doubtful Accounts (1)	Beginning Balance		Additions- Charged  to Income		Deductions		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	7	$	2	$	2	$	7
2012	16		4		13		7
2011	13		5		2		16

Other Reserves (2)	Beginning Balance		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	9	$	6
2012	6		9
2011	4		6

Schedule II—Valuation and Qualifying Accounts—TEP

Allowance for Doubtful Accounts (1)	Beginning Balance		Additions- Charged  to Income		Deductions		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	5	$	2	$	2	$	5
2012	14		3		12		5
2011	11		4		1		14

Other Reserves (2)	Beginning Balance		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	8	$	4
2012	4		8
2011	3		4

⁽¹⁾  TEP, UNS Electric, and UNS Gas record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.

⁽²⁾  As the Other reserves are not individually significant, additions and deductions need not be disclosed. Principally reserves for sales tax audits, litigation matters, and damages billable to third parties.

K-139

ITEM 9. – CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. – CONTROLS AND PROCEDURES

UNS Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UNS Energy’s and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UNS Energy’s and TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by UNS Energy and TEP in the reports that they file or submit under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, UNS Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UNS Energy’s and TEP’s disclosure controls and procedures are effective.

While UNS Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UNS Energy’s or TEP’s internal control over financial reporting during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.

UNS Energy’s and TEP’s Management’s Reports on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appear as the first two reports under Item 8 in UNS Energy’s and TEP’s 2013 Annual Report on Form 10-K, the Report of Independent Registered Public Accounting Firm for UNS Energy appears as the third report under Item 8, and the Report of Independent Registered Public Accounting Firm for TEP appears as the fourth report under Item 8.

ITEM 9B. – OTHER INFORMATION

None.

K-140

PART III

ITEM 10. – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS

Directors – UNS Energy

Name	Age	Board Committee*	Director Since
Paul J. Bonavia	62	None	2009
David G. Hutchens	47	None	2013
Lawrence J. Aldrich	61	1,2,3	2000
Barbara M. Baumann	58	1,2,4	2005
Larry W. Bickle	68	4,5	1998
Robert A. Elliott	58	1,2,3,4,5	2003
Daniel W.L. Fessler	72	2,3	2005
Louise L. Francesconi	61	1,2,3	2008
Ramiro G. Peru	58	1,4,5	2008
Gregory A. Pivirotto	61	1,2,4	2008
Joaquin Ruiz	61	3,5	2005

* Board Committees

(1) Audit

(2) Compensation

(3) Corporate Governance and Nominating

(4) Finance

(5) Environmental, Safety and Security

Paul J. Bonavia	Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. Prior to joining UNS Energy, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.
David G. Hutchens	Mr. Hutchens has served as President and Chief Operating Officer of UNS Energy and TEP since August 2013. In December 2011 Mr. Hutchens was named President of UNS Energy and TEP. In March 2011, Mr. Hutchens was named Executive Vice President of UNS Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UNS Energy and TEP. Mr. Hutchens joined TEP in 1995.
Lawrence J. Aldrich	Chairman and Executive Director, Arizona Business Coalition on Health, since October 2011; President and Chief Executive Officer of University Physicians Healthcare (UPH), a healthcare organization, from 2009 to 2010; Senior Vice President/Corporate Operations and General Counsel for UPH from 2007 to 2008; President of Aldrich Capital Company, an acquisition, management and consulting firm, since January 2007; Chief Operating Officer of The Critical Path Institute, a non-profit medical research company focusing in drug development, from 2005 to 2007.

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Barbara M. Baumann	President and Owner of Cross Creek Energy Corporation, a management consultant and investor company for oil and gas, since 2003; Director of Devon Energy Corporation, an oil and gas exploration company, since 2014; Director of SM Energy Company (formerly St. Mary Land & Exploration), an oil and gas production company, from 2002 - 2014; Member of the Board of Trustees of The Putnam Funds since 2010; Director of Cody Resources, a privately held energy, ranching and commercial real estate company, since 2010.
Larry W. Bickle	Director of SM Energy Company (formerly St. Mary Land & Exploration), an oil and gas production company, since 1994; Retired private equity investor since 2007; Managing Director of Haddington Ventures, LLC, a private equity fund, from 1997 to 2007; Non-executive Chairman of Quantum Natural Gas Storage, LLC, a natural gas storage company, since 2008; Co-founder, Chairman and CEO of TPC Corp (NYSE: TPC), a natural gas company, until sold to PacifiCorp in 1997.
Robert A. Elliott	President and owner of Elliott Accounting, an accounting, tax, management and investment advisory services firm, since 1983; Vice Chairman of AAA of Arizona, a regional automotive and travel club, since 2012 and Director since 2007; Director and Corporate Secretary of Southern Arizona Community Bank, a banking institution, from 1998 to 2010; Television Analyst/Pre-game Show Co-host for Fox Sports Arizona from 1998 to 2009; Chairman of the Board of the Tucson Airport Authority, an airport operator/manager, from January 2006 to January 2007; President and Chairman of the Board of the National Basketball Retired Players Association from 2011 to 2013; Director of University of Arizona Foundation, a philanthropic organization, since 2011.
Daniel W.L. Fessler	President of the California Public Utility Commission, a public utility regulatory agency, from 1991 to 1996; Professor Emeritus of the University of California, an educational institution, since 1994; Of Counsel for the law firm of Holland & Knight from 2003 to 2007; Partner in the law firm of LeBoeuf, Lamb, Greene & MacRae LLP from 1997 to 2003; previously served on the UNS Energy and TEP boards of directors from 1998 to 2003; Managing Principal of Clear Energy Solutions, LLC, a company that advocates coal-to-synthetic fuels, since December 2004.
Louise L. Francesconi	President of Raytheon Missile Systems, a defense electronics corporation, from 1997 to 2008; Director of Stryker Corporation, a medical technology company, since July 2006; Chairman of the Board of Trustees for TMC Healthcare, a hospital, since 1999; Director of Global Solar Energy, Inc., a manufacturer of solar panels and other solar-related products, from 2008 to 2011.
Ramiro G. Peru	Executive Vice President and Chief Financial Officer of Swift Corporation from June 2007 to December 2007; Executive Vice President and Chief Financial Officer of Phelps Dodge Corporation from 2004 to 2007; Senior Vice President and Chief Financial Officer of Phelps Dodge Corporation from 1999 to 2004; Director of WellPoint, Inc. since 2004.
Gregory A. Pivirotto	Adjunct Professor at the University of Arizona College of Law since 2013; President, Chief Executive Officer and Director of University Medical Center Corporation, in Tucson, from 1994 to 2010; certified public accountant since 1978; Director of Arizona Hospital & Healthcare Association, a trade association providing advocacy, education and service to hospitals and other healthcare organizations, from 1997 to 2005; Director of Tucson Airport Authority, an airport operator/manager, from 2008 - January 2014; Member of the Advisory Board of Harris Bank from 2010 - 2013. Director of the Arizona Donor Network Association from 1993 to 2006 and since 2012.
Joaquin Ruiz	Professor of Geosciences, University of Arizona, an educational institution, since 1983; Dean, College of Science, University of Arizona, since 2000; Executive Dean of the University of Arizona College of Letters, Arts and Science since 2009 and Vice President for Strategy and Innovation since 2012.

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Directors – TEP

Name	Age	Director Since
Paul J. Bonavia	62	2009
David G. Hutchens	47	2011
Kevin P. Larson	57	2009

Paul J. Bonavia

Mr. Bonavia has served as Chairman and Chief Executive Officer of UNS Energy and TEP since January 2009; he also served as President from January 2009 to December 2011. Prior to joining UNS Energy, Mr. Bonavia served as President of the Utilities Group of Xcel Energy. Mr. Bonavia previously served as President of Xcel Energy’s Commercial Enterprises business unit and President of the company’s Energy Markets unit.

David G. Hutchens

Mr. Hutchens has served as President of UNS Energy and TEP since December 2011. In March 2011, Mr. Hutchens was named Executive Vice President of UNS Energy and TEP. In May 2009, Mr. Hutchens was named Vice President of Energy Efficiency and Resource Planning. In January 2007, Mr. Hutchens was elected Vice President of Wholesale Energy at UNS Energy and TEP. Mr. Hutchens joined TEP in 1995.

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

Executive Officers of UNS Energy and TEP

See Item 1. Business, Executive Officers of the Registrants.

Information required by Items 401, 405, 406 and 407 (c)(3), (d)(4) and (d)(5) of SEC Regulation S-K will be included in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

ITEM 11. – EXECUTIVE COMPENSATION

Information concerning Executive Compensation will be contained in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

ITEM 12. – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

General

At February 14, 2014, UNS Energy had outstanding 41,633,535 million shares of Common Stock. At February 14, 2014, the number of shares of Common Stock beneficially owned by all directors and officers of UNS Energy as a group amounted to 0.7% of the outstanding Common Stock.

At February 14, 2014, UNS Energy owned 100% of the outstanding shares of common stock of TEP.

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Security Ownership of Certain Beneficial Owners

Information concerning the security ownership of certain beneficial owners of UNS Energy will be contained in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

Security Ownership of Management

Information concerning the security ownership of the Directors and Executive Officers of UNS Energy will be contained in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

Securities Authorized for Issuance Under Equity Compensation Plans

Information concerning securities authorized for issuance under equity compensation plans will be contained in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

ITEM 13. – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information concerning certain relationships and related transactions, and director independence of UNS Energy and TEP will be contained under Transactions with Management and Others, Director Independence and Compensation Committee Interlocks, and Insider Participation in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

ITEM 14. – PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information concerning UNS Energy's principal accountant fees and services will be contained in UNS Energy’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders, which will be filed with the SEC not later than 120 days after December 31, 2013, which information is incorporated herein by reference.

Pre-Approved Policies and Procedures

Rules adopted by the SEC in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. UNS Energy’s Audit Committee has adopted a policy pursuant to which audit, audit-related, tax and other services are pre-approved by category of service. Recognizing that situations may arise where it is in the Company’s best interest for the auditor to perform services in addition to the annual audit of the Company’s financial statements, the policy sets forth guidelines and procedures with respect to approval of the four categories of service designed to achieve the continued independence of the auditor when it is retained to perform such services for UNS Energy. The policy requires the Audit Committee to be informed of each service and does not include any delegation of the Audit Committee’s responsibilities to management. The Audit Committee may delegate to the Chair of the Audit Committee the authority to grant pre-approvals of audit and non-audit services requiring Audit Committee approval where the Audit Committee Chair believes it is desirable to pre-approve such services prior to the next regularly scheduled Audit Committee meeting. The decisions of the Audit Committee Chair to pre-approve any such services from one regularly scheduled Audit Committee meeting to the next shall be reported to the Audit Committee.

Fees

The following table details fees paid to PwC for professional services during 2012 and 2013. The Audit Committee has considered whether the provision of services to TEP by PwC, beyond those rendered in connection with their audit and review of the Company’s financial statements, is compatible with maintaining their independence as auditor.

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TEP's fees for principal accountant services are as follows:

	2013		2012
Audit Fees	$	941,942	$	970,791
Audit-Related Fees	46,500		54,878
Tax Fees(1)	61,612		186,605
All Other Fees	53,273		10,800
Total	$	1,103,327	$	1,223,074

Notes:

1) The decrease in tax fees is for work performed by PWC on behalf of the Company’s Tax Services department to evaluate the tax treatment of repairs and review of the TEP tax rate case during 2012.

Audit fees include fees for the audit of TEP’s consolidated financial statements included in the Company’s Annual Report on Form 10-K and review of financial statements included in the Company’s Quarterly Reports on Form 10-Q. Audit fees also include services provided by PwC in connection with the audit of the effectiveness of internal control over financial reporting and on management’s assessment of the effectiveness of internal control over financial reporting, comfort letters, consents and other services related to SEC matters and financing transactions, statutory and regulatory audits.

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PART IV

ITEM 15. – EXHIBITS AND FINANCIAL STATEMENT SCHEDULE

	Page
(a)    (1)     Consolidated Financial Statements as of December 31, 2013 and 2012 and for Each of the Three Years in the Period Ended December 31, 2013
UNS Energy Corporation
Report of Independent Registered Public Accounting Firm	K-73
Consolidated Statements of Income	K-75
Consolidated Statements of Comprehensive Income	K-76
Consolidated Statements of Cash Flows	K-77
Consolidated Balance Sheets	K-78
Consolidated Statements of Capitalization	K-80
Consolidated Statements of Changes in Stockholders’ Equity	K-81
Notes to Consolidated Financial Statements	K-89
Tucson Electric Power Company
Report of Independent Registered Public Accounting Firm	K-74
Consolidated Statements of Income	K-82
Consolidated Statements of Comprehensive Income	K-83
Consolidated Statements of Cash Flows	K-84
Consolidated Balance Sheets	K-85
Consolidated Statements of Capitalization	K-87
Consolidated Statements of Changes in Stockholder’s Equity	K-88
Notes to Consolidated Financial Statements	K-89
(2)     Financial Statement Schedule
Schedule II
Valuation and Qualifying Accounts	K-139
(3)     Exhibits

Reference is made to the Exhibit Index commencing on page K-150.

K-146

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		UNS ENERGY CORPORATION
Date:	February 25, 2014	By:	/s/ Kevin P. Larson
			Kevin P. Larson
			Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date:	February 25, 2014	/s/ Paul J. Bonavia*
		Paul J. Bonavia
		Chairman of the Board and Chief Executive Officer
		(Principal Executive Officer)
Date:	February 25, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)
Date:	February 25, 2014	/s/ Frank P. Marino*
		Frank P. Marino
		Vice President and Controller
		(Principal Accounting Officer)
Date:	February 25, 2014	/s/ Lawrence J. Aldrich*
		Lawrence J. Aldrich
		Director
Date:	February 25, 2014	/s/ Barbara M. Baumann*
		Barbara M. Baumann
		Director
Date:	February 25, 2014	/s/ Larry W. Bickle*
		Larry W. Bickle
		Director
Date:	February 25, 2014	/s/ Robert A. Elliott*
		Robert A. Elliott
		Director

K-147

Date:	February 25, 2014		/s/ Daniel W.L. Fessler*
			Daniel W.L. Fessler
			Director
Date:	February 25, 2014		/s/ Louise L. Francesconi*
			Louise L. Francesconi
			Director
Date:	February 25, 2014		/s/ Ramiro Peru*
			Ramiro Peru
			Director
Date:	February 25, 2014		/s/ Gregory A. Pivirotto*
			Gregory A. Pivirotto
			Director
Date:	February 25, 2014		/s/ Joaquin Ruiz*
			Joaquin Ruiz
			Director
Date:	February 25, 2014	By:	/s/ Kevin P. Larson
			Kevin P. Larson
			As attorney-in-fact for each of the persons indicated

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		TUCSON ELECTRIC POWER COMPANY
Date:	February 25, 2014	By:	/s/ Kevin P. Larson
			Kevin P. Larson
			Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

K-148

Date:	February 25, 2014		/s/ Paul J. Bonavia*
			Paul J. Bonavia
			Chairman of the Board and Chief Executive Officer
			(Principal Executive Officer)
Date:	February 25, 2014		/s/ Kevin P. Larson
			Kevin P. Larson
			Senior Vice President, Chief Financial Officer and Director
			(Principal Financial Officer)
Date:	February 25, 2014		/s/ Frank P. Marino*
			Frank P. Marino
			Vice President and Controller
			(Principal Accounting Officer)
Date:	February 25, 2014		/s/ David G. Hutchens*
			David G. Hutchens
			Director
Date:	February 25, 2014	By:	/s/ Kevin P. Larson
			Kevin P. Larson
			As attorney-in-fact for each of the persons indicated

K-149

EXHIBIT INDEX

*2(a)	—	Agreement and Plan of Merger, dated as of December 11, 2013, among FortisUS Inc., Color Acquisition Sub Inc., UNS Energy Corporation and solely for purposes of Section 5.5(a) and 8.15, Fortis Inc. (Form 8-K, dated December 12, 2013, File No. 1-13739 - Exhibit 2.1)
*2(b)(1)	—	Asset Purchase and Sale Agreement, dated as of December 23, 2013, between Gila River Power LLC and Tucson Electric Power Company and UNS Electric, Inc. (Form 8-K, dated December 27, 2013, File No. 1-13739 - Exhibit 2.1)
2(b)(2)	—	First Amendment, dated February 14, 2014, to the Asset Purchase and Sale Agreement between Gila River Power LLC and Tucson Electric Power Company and UNS Electric, Inc.
*3(a)	—	Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for the year ended December 31, 1996, File No. 1-5924-Exhibit No 3(a)).
*3(a)(1)	—	TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-1379 – Exhibit 3(a))
*3(b)	—	Bylaws of TEP, as amended as of August 31, 2009 (Form 10-Q for the quarter ended September 30, 2009, File No. 13739 – Exhibit 3.1).
*3(c)	—	Amended and Restated Articles of Incorporation of UNS Energy, as amended. (Form 8-K, dated May 10, 2012, File No. 1-13739 – Exhibit 3.1).
*3(d)	—	Revised and restated bylaws of UNS Energy, as revised and restated December 14, 2011 (Form 8-K, dated December 15, 2011, File No. 13739 – Exhibit 3.1)
*4(a)(1)	—	Loan Agreement, dated as of October 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 — Exhibit 4(a)).
*4(a)(2)	—	Indenture of Trust, dated as of October 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form 10-Q for the quarter ended September 30, 1982, File No. 1-5924 — Exhibit 4(b)).
*4(a)(3)	—	First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(h)(3)).
*4(a)(4)	—	First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form S-4, Registration No. 33-52860 — Exhibit 4(h)(4)).
*4(b)(1)	—	Loan Agreement, dated as of December 1, 1982, between the Pima County Authority and TEP relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 — Exhibit 4(k)(1)).

K-150

*4(b)(2)	—	Indenture of Trust dated as of December 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for the year ended December 31, 1982, File No. 1-5924 — Exhibit 4(k)(2)).
*4(b)(3)	—	First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and TEP relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 — Exhibit 4(i)(3)).

*4(b)(4) — First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860 — Exhibit 4(i)(4)).

*4(c)(1)	—	Indenture of Trust, dated as of March 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Industrial Development Revenue Bonds, 2008 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 19, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(a)).
*4(c)(2)	—	Loan Agreement, dated as of March 1, 2008, between the Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 2008 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 19, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(b)).

*4(d)(1)	—	Indenture of Trust, dated as of June 1, 2008, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Industrial Development Revenue Bonds, 2008 Series B (Tucson Electric Power Company Project). (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(a)).
*4(d)(2)	—	Loan Agreement, dated as of June 1, 2008, between The Industrial Development Authority of the County of Pima and TEP relating to Industrial Development Revenue Bonds, 2008 Series B (Tucson Electric Power Company Project). (Form 8-K dated June 25, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4(b)).
*4(e)(1)	—	Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(A)).
*4(e)(2)	—	Loan Agreement, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company San Juan Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(B)).
*4(f)(1)	—	Indenture of Trust, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(C)).
*4(f)(2)	—	Loan Agreement, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-13739- Exhibit 4(D)).

K-151

*4(g)(1)	—	Indenture of Trust, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-13739 Exhibit 4(a)).
*4(g)(2)	—	Loan Agreement, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-13739 Exhibit 4(b)).
*4(h)(1)	—	Indenture of Trust, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(c)).
*4(h)(2)	—	Loan Agreement, dated as of December 1, 2010, between the Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Bonds, 2010 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(d)).
*4(i)(1)	—	Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-13739, Exhibit 4(a)).
*4(i)(2)	—	Loan Agreement, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-13739, Exhibit 4(b)).
*4(j)(1)	—	Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-13739, Exhibit 4(a)).
*4(j)(2)	—	Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-13739, Exhibit 4(b)).
*4(k)(1)	—	Indenture of Trust, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-13739, Exhibit 4(a)).
*4(k)(2)	—	Loan Agreement, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-13739, Exhibit 4(b)).
*4(l)(1)	—	Indenture of Trust, dated as of November 1, 2013, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Springerville Project). (Form 8-K dated November 14, 2013, File No. 1-13739 - Exhibit 4(a)).

K-152

*4(l)(2)	—	Loan Agreement, dated as of November 1, 2013, between The Industrial Development Authority of the County of Apache and Tucson Electric Power Company, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Springerville Project). (Form 8-K dated November 14, 2013, File No. 1-13739 - Exhibit 4(b)).
*4(l)(3)	—	Lender Rate Mode Covenants Agreement, dated as of November 1, 2013, between Tucson Electric Power Company and STI Institutional & Government, Inc. (Form 8-K dated November 14, 2013, File No. 1-13739 - Exhibit 4(c)).
*4(m)(1)	—	Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank National Association, as trustee, authorizing unsecured Notes (Form 8-K dated November 8, 2011, File 1-13739 — Exhibit 4.1).
*4(m)(2)	—	Officers Certificate, dated November 8, 2011, authorizing 5.15% Notes due 2021. (Form 8-K dated November 8, 2011, File No. 1-13739 - Exhibit 4.2).
*4(m)(3)	—	Officers Certificate, dated September 14, 2012, authorizing 3.85% Notes due 2023. (Form 8-K dated September 14, 2012, File No. 1-13739 - Exhibit 4.1).
*4(n)(1)	—	Note Purchase and Guaranty Agreement dated August 11, 2003 among UNS Gas, Inc., UniSource Energy Services, Inc., and certain institutional investors. (Form 8-K dated August 21, 2003, File Nos. 1-5924 and 1-13739 — Exhibit 99.2).

*4(o)(2)	—	Note Purchase Agreement, dated as of May 4, 2011, among UNS Gas, Inc., UniSource Energy Services, Inc., and a group of purchasers. (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.1).
*4(p)	—	Note Purchase and Guaranty Agreement dated August 5, 2008, among UNS Electric, Inc., UniSource Energy Services, Inc., and certain institutional investors. (Form 10-Q for the quarter ended June 30, 2008, File Nos. 1-5924 and 1-13739 — Exhibit 4).
*4(q)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UNS Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.1).
*4(q)(2)	—	Second Amended and Restated Pledge Agreement, dated as of November 9, 2010, among UNS Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.2).
*4(q)(3)	—	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among UNS Energy Corporation, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 10-K for the year ended December 31, 2011, File No. 1-13739, Exhibit 4(s)(2)).
*4(r)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among Tucson Electric Power Company, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.3).
*4(r)(2)	—	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among Tucson Electric Power Company, Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 10-K for the year ended December 31, 2011, File No. 1-13739, Exhibit 4(o)(2)).
*4(s)(1)	—	Second Amended and Restated Credit Agreement, dated as of November 9, 2010, among UNS Electric, Inc., UNS Gas, Inc., UniSource Energy Services, Inc., Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 8-K dated November 15, 2010, File No. 1-13739, Exhibit 4.4).

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*4(s)(2)	—	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of November 18, 2011, among UNS Electric, Inc., UNS Gas, Inc., UniSource Energy Services, Inc., Union Bank, N.A., as Administrative Agent, and a group of lenders. (Form 10-K for the year ended December 31, 2011, File No. 1-13739, Exhibit 4(t)(2)).
*4(t)(1)	—	Reimbursement Agreement, dated as of December 14, 2010, among TEP, as Borrower, the financial institutions from time to time, parties thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank. (Form 8-K dated December 17, 2010, File No. 1-13739, Exhibit 4(a)).
4(t)(2)	—	Amendment No. 1 to Reimbursement Agreement, dated as of February 11, 2014 among TEP, as Borrower, the financial institutions from time to time, parties thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and as Issuing Bank.

*4(u)(1)	—	Credit Agreement, dated as of August 10, 2011, among UNS Electric, Inc., UniSource Energy Services, Inc., and Union Bank, N.A., as Administrative Agent (Form 8-K dated August 12, 2011, File 1-13739 — Exhibit 4.2).
*10(a)(1)	—	Lease Agreements, dated as of December 1, 1984, between Valencia and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(1)).
*10(a)(2)	—	Guaranty and Agreements, dated as of December 1, 1984, between TEP and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(2)).
*10(a)(3)	—	General Indemnity Agreements, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors; General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc. as Owner Participants; United States Trust Company of New York, as Owner Trustee; Teachers Insurance and Annuity Association of America as Loan Participant; and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(3)).
*10(a)(4)	—	Tax Indemnity Agreements, dated as of December 1, 1984, between General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J.C. Penney Company, Inc., each as Beneficiary under a separate Trust Agreement dated December 1, 1984, with United States Trust of New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia, Lessee, and TEP, Indemnitors. (Form 10-K for the year ended December 31, 1984, File No. 1-5924 — Exhibit 10(d)(4)).
*10(a)(5)	—	Amendment No. 1, dated December 31, 1984, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(5)).
*10(a)(6)	—	Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(6)).
*10(a)(7)	—	Amendment No. 3 dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(7)).

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*10(a)(8)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(8)).
*10(a)(9)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(9)).
*10(a)(10)	—	Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(10)).
*10(a)(11)	—	Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(11)).
*10(a)(12)	—	Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(12)).
*10(a)(13)	—	Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(13)).
*10(a)(14)	—	Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(14)).
*10(a)(15)	—	Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbell Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar). (Form S-4 Registration No. 33-52860 — Exhibit 10(f)(15)).
*10(a)(16)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(12)).
*10(a)(17)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(13)).

K-155

*10(a)(18)	—	Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(14)).
*10(a)(19)	—	Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(19)).
*10(a)(20)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 —Exhibit 10(f)(20)).
*10(a)(21)	—	Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(21)).
*10(a)(22)	—	Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(22)).
*10(a)(23)	—	Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(15)).
*10(a)(24)	—	Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(16)).
*10(a)(25)	—	Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(25)).
*10(a)(26)	—	Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(26)).

K-156

*10(a)(27)	—	Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732 — Exhibit 10(f)(27)).
*10(b)(1)	—	Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(1)).
*10(b)(2)	—	Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(2)).
*10(b)(3)	—	Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(3)).
*10(b)(4)	—	Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(4)).
*10(b)(5)	—	Lease Supplement No.1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(5)).
*10(b)(6)	—	Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 — Exhibit 10(g)(6)).
*10(b)(7)	—	Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and TEP and San Carlos, jointly and severally, as Lessee. (Form S-1, Registration No. 33-55732 — Exhibit 10(g)(7)).
*10(b)(8)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(8)).

K-157

*10(b)(9)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(9)).
*10(b)(10)	—	Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(10)).
*10(b)(11)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(11)).
*10(b)(12)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(12)).
*10(b)(13)	—	Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(13)).
*10(b)(14)	—	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(a)).
*10(b)(15)	—	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit, LLC as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(b)).
*10(b)(16)	—	Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(c)).
*10(b)(17)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(d)).

K-158

*10(b)(18)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit, LLC as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(e)).
*10(b)(19)	—	Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(f)).
*10(b)(20)	—	Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.1).
*10(b)(21)	—	Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Selco Service Corporation as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.2).
*10(b)(22)	—	Amendment No. 4, dated as of June 1, 2006, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, under a Trust Agreement with Emerson Finance LLC as Owner Participant. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.3).
*10(b)(23)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.4).
*10(b)(24)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement , dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Selco Service Corporation as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.5).
*10(b)(25)	—	Amendment No. 4, dated as of June 1, 2006 to Tax Indemnity Agreement , dated as of December 1, 1985, between TEP and San Carlos, as Lessee, and Emerson Finance LLC as Owner Participant, beneficiary under a Trust Agreement, dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Cotrustee, respectively, together as Lessor. (Form 8-K dated June 12, 2006, File No. 1-5924 – Exhibit 10.6).
*10(c)(1)	—	Participation Agreement, dated as of June 30, 1992, among TEP, as Lessee, various parties thereto, as Owner, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to TEP’s lease of Springerville Unit 1. (Form S-1, Registration No. 33-55732 — Exhibit 10(u)).
*10(c)(2)	—	Lease Agreements, dated as of December 15, 1992, between TEP, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 — Exhibit 10(v)).

K-159

*10(c)(3)	—	Tax Indemnity Agreements, dated as of December 15, 1992, between the various Owner Participants parties thereto and TEP, as Lessee. (Form S-1, Registration No. 33-55732 — Exhibit 10(w)).
*10(d)	—	Amended and Restated UNS Energy 1994 Outside Director Stock Option Plan of UNS Energy. (Form S-8 dated September 9, 2002, File No. 333-99317).
*10(e)	—	UNS Energy 2006 Omnibus Stock and Incentive Plan. (Form S-8 dated January 31, 2007, File No. 333-140353).
*10(f)	—	UNS Energy Corporation 2011 Omnibus Stock and Incentive Plan. (Form 8-K dated May 10, 2011, File 1-13739 – Exhibit 10.1).
10(g)	—	UNS Energy Officer Change in Control Agreement (including a schedule of officers who are covered by the agreement or substantially identical agreements), between UNS Energy and officers of the company.
*10(h)	—	Management and Directors Deferred Compensation Plan II of UNS Energy. (Form S-8 dated December 30, 2008, File No. 333-156491).
*10(i)	—	UNS Energy Corporation Severance Pay Plan, as amended (Form 8-K, dated July 27, 2013, File No. 1-13739 - Exhibit 10(b)).
*10(j)	—	Severance Agreement between Michael J. DeConcini and Tucson Electric Power Company (Form 8-K, dated July 27, 2013, File No. 1-13739 - Exhibit 10(a)).
12(a)	—	Computation of Ratio of Earnings to Fixed Charges – UNS Energy.
12(b)	—	Computation of Ratio of Earnings to Fixed Charges – TEP.
21	—	Subsidiaries of the Registrants.
23(a)	—	Consent of Independent Registered Public Accounting Firm – UNS Energy.

K-160

23(b)	—	Consent of Independent Registered Public Accounting Firm – TEP.
24(a)	—	Power of Attorney – UNS Energy.
24(b)	—	Power of Attorney – TEP.
31(a)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Paul J. Bonavia.
31(b)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Kevin P. Larson.
31(c)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Paul J. Bonavia.
31(d)	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Kevin P. Larson.
**32(a)	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) - UNS Energy.
**32(b)	—	Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) - TEP.
101	—	The following materials from UNS Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, formatted in XBRL (Extensible Business Reporting Language):
		(a)	UNS Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Balance Sheets, (v) Consolidated Statements of Capitalization, (vi) Consolidated Statements of Changes in Stockholders’ Equity; and
		(b)	Notes to Consolidated Financial Statements.

(*) Previously filed as indicated and incorporated herein by reference.

(+) Management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by item 601(b)(10)(iii) of Regulation S-K.

** Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

K-161

EX-2.B2

Exhibit 2(b)(2)

Execution Version

FIRST AMENDMENT

TO

ASSET PURCHASE AND SALE AGREEMENT

THIS FIRST AMENDMENT TO ASSET PURCHASE AND SALE AGREEMENT (this “Amendment”) is made and entered into as of February 14, 2014, by and between GILA RIVER POWER LLC, a limited liability company organized and existing pursuant to the laws of the State of Delaware (“Seller”), and TUCSON ELECTRIC POWER COMPANY (“TEP”), a corporation organized and existing pursuant to the laws of the State of Arizona, and UNS ELECTRIC, INC. (“UNSE”), a corporation organized and existing pursuant to the laws of the State of Arizona (TEP and UNSE are individually a “Buyer” and collectively the “Buyers”). Seller and Buyers are hereinafter referred to individually as a “Party” and collectively as the “Parties.”

WHEREAS, Seller and Buyers are party to that certain Asset Purchase and Sale Agreement dated as of December 23, 2013 (the “Agreement”); and

WHEREAS, Seller and Buyers desire to amend the Agreement as set forth herein.

NOW, THEREFORE, in consideration of the foregoing premises, the mutual covenants and agreements hereinafter set forth, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller and Buyers agree as follows:

Section 1.Defined Terms. Capitalized terms used herein and not otherwise defined have the meaning assigned to such terms in the Agreement.

Section 2.Amendments to Agreement. From and after the date hereof, the Agreement is hereby amended as follows:

(a)Amendment to Section 2.8. Section 2.8 of the Agreement is amended by adding the following new subsection (e) thereto:

“(e)If the Letter of Credit has not been cancelled by Seller and Buyers pursuant to this Section 2.8 and Seller has not received a renewed or replacement Letter of Credit at least ten (10) days prior to the stated expiry date of the then-effective Letter of Credit, Seller may draw on the full available amount of the Letter of Credit after having provided written notice to Buyers of its intent to do so. Amounts drawn in such circumstance shall be deposited by Seller into an escrow account held by the Escrow Agent in trust for the benefit of Seller and Buyers, which shall be distributed only upon either joint instructions signed by Seller and Buyers or a final non-appealable judgment from a court of competent jurisdiction.”

(b)    Amendment to Section 5.1(a). Section 5.1(a) of the Agreement is amended by:

(i)deleting the phrase “January 31, 2014” appearing therein and replacing it with “February 28, 2014”; and

(ii)deleting the phrase “February 15, 2014” appearing therein and replacing it with “February 28, 2014”.

(c)    Amendment to Section 6.9. Section 6.9(d) is hereby renumbered as Section 6. 9(c) to correct a typographical error.

(d)    Amendment to Section 9.4(k). Section 9.4(k) of the Agreement is amended by adding the following parenthetical immediately before the period at the end thereof: “(including, if the Letter of Credit was provided and was not previously drawn pursuant to Section 2.8(e), the original of the Letter of Credit for cancellation)”.

(e)    Amendment to Section 10.1(h). Section 10.1(h) of the Agreement is amended by:

(i)    deleting the phrase “January 31, 2014” appearing therein and replacing it with “February 28, 2014”; and

(ii)    deleting the phrase “February 15, 2014” appearing therein and replacing it with “February 28, 2014”.

Section 3.Representations and Warranties. Each of Seller and Buyers represents and warrants solely with respect to itself that (a) the execution, delivery and performance of this Amendment and the consummation of the transactions contemplated hereby have been duly authorized on its behalf by all requisite action, corporate, limited liability company, or otherwise, (b) it has the full right, power and authority to enter into this Amendment and to carry out the terms of this Amendment, (c) it has duly executed and delivered this Amendment, and (d) this Amendment is a valid and binding obligation of it enforceable in accordance with its terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other Laws of general application now or hereafter in effect relating to creditors’ rights generally and (ii) general principles of equity, regardless of whether enforcement is sought in a Proceeding at law or in equity.

Section 4.Other Provisions Unaffected. All of the terms, covenants and provisions of the Agreement shall continue in full force and effect, unamended and unmodified except as specifically set forth in this Amendment.

Section 5.Effectiveness. This Amendment shall be effective, and shall be binding on the Parties, on the date first above written.

Section 6.Further Assurances. Each Party agrees, at the request of any other Party, at any time and from time to time, to execute and deliver all such further documents, and to take and to forbear from all such action, as may be reasonably necessary or appropriate in order to more effectively carry out the provisions of this Amendment.

Section 7.Governing Law. This Amendment shall be governed in all respects, including validity, interpretation and effect, by the internal Laws of the State of New York without giving effect to any choice or conflict of law provision or rule (whether of the State of New York or any other jurisdiction) that would cause the application of the Laws of any jurisdiction other than the State of New York.

Section 8.Counterparts. This Amendment may be executed in two or more original or electronic counterparts, each which shall be deemed an original, but all of which together shall constitute one and the same instrument.

[Signature pages follow.]

IN WITNESS WHEREOF, the Parties have duly executed this Agreement on the date first above written.

BUYERS:

TUCSON ELECTRIC POWER COMPANY,

an Arizona corporation

By:_____________________

Name: David Hutchens

Title: President

UNS ELECTRIC, INC.,

an Arizona corporation

By:_____________________

Name: David Hutchens

Title: President

SELLER:

GILA RIVER POWER LLC,

a Delaware limited liability company

By:______________________

Name:

Title:

EX-4.T2

Exhibit 4(t)(2)

EXECUTION VERSION

AMENDMENT NO. 1

This AMENDMENT NO. 1 (this “Amendment”), dated as of February 11, 2014, is entered into by and among TUCSON ELECTRIC POWER COMPANY (the “Applicant”), the Banks signatory hereto (the “Banks”) and JPMorgan Chase Bank, N.A., as a Bank, as Issuing Bank (in such capacity, the “Issuing Bank”), and as Administrative Agent (in such capacity, the “Administrative Agent”).

W I T N E S S E T H:

WHEREAS, the Applicant, the Banks, the Issuing Bank and the Administrative Agent have entered into that certain Reimbursement Agreement dated as of December 14, 2010 (as amended, restated, supplemented or otherwise modified from time to time, the “Reimbursement Agreement”), in connection with which the Issuing Bank issued its Letter of Credit No. CPCS-869304 (the “Letter of Credit”); and

WHEREAS, the parties hereto desire to amend the Reimbursement Agreement as set forth below and to extend the Letter of Credit for a period of five years pursuant to Annex K to the Letter of Credit;

NOW THEREFORE, in consideration of the premises herein contained, and for other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto hereby agree as follows:

Section 1.1Defined Terms. Capitalized terms used and not otherwise defined herein shall have the meanings assigned to such terms in the Reimbursement Agreement.

Section 1.2Amendments to the Reimbursement Agreement. Subject to the satisfaction of the conditions precedent set forth in Section 1.4below, the Reimbursement Agreement is hereby amended as follows:

(a)The following new defined terms shall be inserted in proper alphabetical order in Section 1.1 of the Reimbursement Agreement:

“Administrative Questionnaire” means an administrative questionnaire in a form supplied by the Administrative Agent.

“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Applicant or its Subsidiaries from time to time concerning or relating to bribery or corruption.

“Bankruptcy Event” means, with respect to any Person, such Person becomes the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee, administrator, custodian, assignee for the benefit of creditors or similar Person charged with the reorganization or liquidation of its business appointed for it, or, in the good faith

determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment, provided that a Bankruptcy Event shall not result solely by virtue of any ownership interest, or the acquisition of any ownership interest, in such Person by a Governmental Authority or instrumentality thereof, provided, further, that such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority or instrumentality) to reject, repudiate, disavow or disaffirm any contracts or agreements made by such Person.

“Impacted Interest Period” has the meaning assigned to such term in the definition of “LIBO Rate”.

“Interpolated Rate” means, at any time, the rate per annum determined by the Administrative Agent (which determination shall be conclusive and binding absent manifest error) to be equal to the rate that results from interpolating on a linear basis between: (a) the LIBOR Screen Rate for the longest period (for which the LIBOR Screen Rate is available) that is shorter than the Impacted Interest Period and (b) the LIBOR Screen Rate for the shortest period (for which the LIBOR Screen Rate is available) that exceeds the Impacted Interest Period, in each case, at such time.

“LIBOR Screen Rate” has the meaning assigned to such term in the definition of “LIBO Rate”.

“Participant Register” has the meaning assigned to such term in Section 9.6(b).

“Sanctions” means economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by (a) the U.S. government, including those administered by OFAC or the U.S. Department of State or (b) the United Nations Security Council, the European Union or Her Majesty’s Treasury of the United Kingdom.

(b)The definitions of “Anti-Terrorism Laws” and “Index Debt” set forth in Section 1.1 of the Reimbursement Agreement are each hereby deleted in their entirety.

(c)The definition of “Alternate Base Rate” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended to insert the following at the end of the first sentence of such definition:

“; provided that, for the avoidance of doubt, the Adjusted LIBO Rate for any day shall be based on the rate appearing on Reuters Screen LIBOR01 Page (or any successor or substitute of such page) at approximately 11:00 a.m., London time, on such day”

(d)The definition of “Change in Law” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

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“Change in Law” means the occurrence, after the date of this Agreement (or with respect to any Bank, if later, the date on which such Bank becomes a Bank), of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation or application thereof by any Governmental Authority, or (c) the making or issuance of any request, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided, however, that notwithstanding anything herein to the contrary, (i) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines, requirements and directives thereunder, issued in connection therewith or in implementation thereof, and (ii) all requests, rules, guidelines, requirements and directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law” regardless of the date enacted, adopted, issued or implemented.

(e)The definition of “Defaulting Bank” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“Defaulting Bank” means any Bank that (a) has failed, within two (2) Business Days of the date required to be funded or paid, to (i) fund its participation in any LC Disbursement or (ii) pay over to the Administrative Agent any other amount required to be paid by it hereunder, unless, in the case of clause (i), such Bank notifies the Administrative Agent in writing that such failure is the result of such Bank’s good faith determination that a condition precedent to funding (specifically identified and including the particular default, if any) has not been satisfied, (b) has notified the Applicant and the Administrative Agent in writing, or has made a public statement to the effect, that it does not intend or expect to comply with any of its funding obligations under this Agreement (unless such writing or public statement indicates that such position is based on such Bank’s good faith determination that a condition precedent (specifically identified and including the particular default, if any) to funding a LC Disbursement under this Agreement cannot be satisfied) or generally under other agreements in which it commits to extend credit, (c) has failed, within three (3) Business Days after request by the Administrative Agent, acting in good faith, to provide a certification in writing from an authorized officer of such Bank that it will comply with its obligations to fund its participation in outstanding or prospective LC Disbursements under this Agreement, provided that such Bank shall cease to be a Defaulting Bank pursuant to this clause (c) upon the Administrative Agent’s receipt of such certification in form and substance satisfactory to it and the Banks, or (d) has become the subject of a Bankruptcy Event.

(f)The definition of “Disclosure Documents” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“Disclosure Documents” means (i) the Annual Report on Form 10-K of the Applicant for the fiscal year ended December 31, 2012, as filed with the SEC, (ii) the Quarterly Reports on Form 10-Q of the Applicant for the fiscal quarters ended March 31, 2013, June 30, 2013 and September 30, 2013, as filed with the SEC, and (iii) the Current Reports on Form 8-K

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of the Applicant as filed with the SEC on January 22, 2013, February 5, 2013, March 14, 2013, May 20, 2013, June 12, 2013, September 5, 2013, September 16, 2013, October 7, 2013, November 1, 2013, November 14, 2013, December 12, 2013, December 27, 2013, January 13, 2014 and February 3, 2014.

(g)Clause (a) of the definition of “Excluded Taxes” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended (i) to delete each reference to “Lender” therein and to substitute “Bank” therefor, and (ii) to delete each reference to “Borrower” therein and to substitute “Applicant” therefor.

(h)The definition of “Interest Payment Date” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended to insert the following at the end thereof:

“and (c) any date on which a Liquidity Advance is required to be repaid in accordance with the terms of this Agreement and the Letter of Credit”

(i)The definition of “LIBO Rate” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“LIBO Rate” means, for any applicable Interest Period, the London interbank offered rate administered by the British Bankers Association (or any other Person that takes over the administration of such rate) for U.S. dollars for a period equal in length to such Interest Period as displayed on pages LIBOR01 or LIBOR02 of the Reuters screen or, in the event such rate does not appear on either of such Reuters pages, on any successor or substitute page on such screen that displays such rate, or on the appropriate page of such other information service that publishes such rate as shall be selected by the Administrative Agent from time to time in its reasonable discretion (in each case the “LIBOR Screen Rate”) at approximately 11:00 a.m., London time, two (2) Business Days prior to the commencement of such Interest Period; provided that, if the LIBOR Screen Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement; provided, further, that if a LIBOR Screen Rate shall not be available at such time for such Interest Period (the “Impacted Interest Period”), then the LIBO Rate for such Interest Period shall be the Interpolated Rate; provided, that, if any Interpolated Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement. It is understood and agreed that all of the terms and conditions of this definition of “LIBO Rate” shall be subject to Section 2.15.

(j)The definition of “Sanctioned Country” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“Sanctioned Country” means, at any time, a country or territory which is the subject or target of any Sanctions.

(k)The definition of “Sanctioned Person” set forth in Section 1.1 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

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“Sanctioned Person” means, at any time, (a) any Person listed in any Sanctions-related list of designated Persons maintained by OFAC, the U.S. Department of State, the United Nations Security Council, the European Union or any EU member state, (b) any Person operating, organized or resident in a Sanctioned Country or (c) any Person controlled by any such Person.

(l)Clause (c) of Section 2.15 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“(c)    the Administrative Agent shall have received notice from any Bank that any Change in Law makes it unlawful, or any central bank or other Governmental Authority asserts that it is unlawful after the date hereof, for any Bank or its Eurodollar Lending Office to make, fund or maintain Eurodollar Advances hereunder;”

(m)Section 4.4 of the Reimbursement Agreement is hereby amended to delete each reference to “2009” now appearing therein and to substitute “2012” therefor.

(n) Section 4.16 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“Section 4.16    Anti-Corruption Laws and Sanctions. The Applicant has implemented and maintains in effect policies and procedures designed to ensure compliance by the Applicant, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions, and the Applicant, its Subsidiaries and their respective officers and employees and to the knowledge of the Applicant its directors and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects. None of (a) the Applicant, any Subsidiary or to the knowledge of the Applicant or such Subsidiary any of their respective directors, officers or employees, or (b) to the knowledge of the Applicant, any agent of the Applicant or any Subsidiary that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person. Neither the Letter of Credit nor any Liquidity Advance, use of proceeds or other Transactions will violate Anti-Corruption Laws or applicable Sanctions.”

(o)Section 5.1(h) of the Reimbursement Agreement is hereby amended to delete the phrase “Index Debt” now appearing therein and to substitute “Senior Unsecured Debt” therefor.

(p) Section 5.7 of the Reimbursement Agreement is hereby amended to insert the following new sentence at the end thereof:

“The Applicant will maintain in effect and enforce policies and procedures designed to ensure compliance by the Applicant, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions.”

(q)Section 5.8 of the Reimbursement Agreement is hereby amended to insert the following new sentence at the end thereof:

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“The Applicant will not request any Liquidity Advance or the Letter of Credit, and the Applicant shall not use, and shall procure that its Subsidiaries and its or their respective directors, officers, employees and agents shall not use, the proceeds of any Liquidity Advance or the Letter of Credit (i) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (ii) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any Sanctioned Country or (iii) in any manner that would result in the violation of any Sanctions applicable to any party hereto.”

(r)Section 5.13 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“Section 5.13    Patriot Act Compliance. The Applicant will provide, to the extent commercially reasonable, such information and take such actions as are reasonably requested by the Administrative Agent or any Bank in order to assist the Administrative Agent and the Banks in maintaining compliance with the PATRIOT Act.”

(s)Article VIII of the Reimbursement Agreement is hereby amended to insert the following new Section at the end thereof:

“Section 8.8.    Enforcement. The Banks are not partners or co-venturers, and no Bank shall be liable for the acts or omissions of, or (except as otherwise set forth herein in case of the Administrative Agent) authorized to act for, any other Bank. The Administrative Agent shall have the exclusive right on behalf of the Banks to enforce the payment of the principal of and interest on any Liquidity Advance after the date such principal or interest has become due and payable pursuant to the terms of this Agreement.”

(t)Section 9.1(b)(i) of the Reimbursement Agreement is hereby amended (i) to insert the following parenthetical after the phrase “or similar requirement” now appearing in subclause (1) thereof: “(including any compulsory loan requirement, insurance charge or other assessment)”; and (ii) to insert the following after the phrase “any other condition” now appearing in subclause (2) thereof: “, cost or expense (other than Taxes)”.

(u)Section 9.1(b)(ii) of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“(ii)    If any Bank or the Issuing Bank determines that any Change in Law regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Bank’s or the Issuing Bank’s capital or on the capital of such Bank’s or the Issuing Bank’s holding company, if any, as a consequence of this Agreement or any Liquidity Advances made by, or participations in the Letter of Credit held by, such Bank, or the Letter of Credit issued by the Issuing Bank, to a level below that which such Bank or the Issuing Bank or such Bank’s or the Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Bank’s or the Issuing Bank’s policies and the policies of such Bank’s or the Issuing Bank’s holding company with respect to capital

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adequacy and liquidity), then from time to time the Applicant will pay to such Bank or the Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Bank or the Issuing Bank or such Bank’s or the Issuing Bank’s holding company for any such reduction suffered.”

(v)Section 9.5(a) of the Reimbursement Agreement is hereby amended to insert the following after the phrase “gross negligence or willful misconduct” now appearing therein: “, as determined in a final, non-appealable judgment by a court of competent jurisdiction”.

(w)Section 9.6 of the Reimbursement Agreement is hereby amended and restated in its entirety as follows:

“Section 9.6 Participations.

(a)    Any Bank may, without the consent of the Applicant, the Administrative Agent or the Issuing Bank, sell participations to one or more banks or other entities (a “Participant”) in all or a portion of such Bank’s rights and obligations under this Agreement (including all or a portion of its Commitment and the LC Disbursements owing to it); provided that (A) such Bank’s obligations under this Agreement shall remain unchanged, (B) such Bank shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Applicant, the Administrative Agent, the Issuing Bank and the other Banks shall continue to deal solely and directly with such Bank in connection with such Bank’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Bank sells such a participation shall provide that such Bank shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Bank will not, without the consent of the Participant, agree to any amendment, modification or waiver described in Section 9.9(i) that affects such Participant. Subject to clause (b) of this Section 9.6, the Applicant agrees that each Participant shall be entitled to the benefits of Sections 9.1 and 9.15 to the same extent as if it were a Bank and had acquired its interest by assignment pursuant to Section 9.7. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 9.2 as though it were a Bank, provided such Participant agrees to be subject to Section 2.5(b) as though it were a Bank.

(b)    A Participant shall not be entitled to receive any greater payment under Section 9.1 or 9.15 than the applicable Bank would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Applicant’s prior written consent. A Participant that would be a Non-U.S. Bank if it were a Bank shall not be entitled to the benefits of Section 9.15 unless the Applicant is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Applicant, to comply with Section 9.15(e) as though it were a Bank (it being understood that the documentation required under Section 9.15(e) shall be delivered to the applicable Bank). Each Bank that sells a participation shall, acting solely for this purpose as an agent of the Applicant, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each

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Participant’s interest in the obligations under this Agreement (the “Participant Register”); provided that no Bank shall have any obligation to disclose all or any portion of the Participant Register to any Person (including the identity of any Participant or any information relating to a Participant’s interest in the obligations under this Agreement) except to the extent that such disclosure is necessary to establish that such interest is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Bank shall treat each person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary.”

(x)Section 9.13(a) of the Reimbursement Agreement is hereby amended to replace the notice information with respect to the Administrative Agent and the Issuing Bank as follows:

If to JPMorgan, to JPMorgan Chase Bank, N.A.
10 S Dearborn St.
Mail code IL1-0090
Chicago, IL 60603
Facsimile No.: (312) 732-1762
Telephone No.: (312) 732-1838
Email: nancy.r.barwig@jpmorgan.com

Attention:    Nancy Barwig

With a copy to the JPMorgan Chase Bank, N.A.

Administrative Agent: 10 S. Dearborn St.
Mail Code IL1-0874
Chicago, IL 60603Facsimile No.:    (312) 325-3238
Telephone No.: (312) 325-3150
Email: lisa.tverdek@jpmorgan.com
Attention:    Lisa Tverdek

With a copy to the Issuing JPMorgan Chase Bank, N.A.

Bank, Standby Letter of 131 S. Dearborn, 5^th Floor

Credit Unit: Mail Code IL1-0236
Standby Letter of Credit UnitChicago, Il 60603-5506
Facsimile No.: (312) 954-6163
Telephone No.: (800) 634-1969, Option 1

Attention:    Standby Service Unit

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(y)Article IX of the Reimbursement Agreement is hereby amended to insert the following new Section at the end thereof:

“Section 9.23.    Dissemination of Information. Each Bank may disseminate information relating to Applicant, this Agreement or any Credit Document (i) in connection with any assignment or participation (subject to Section 9.20); (ii) upon the order of any court or otherwise to the extent required by statute, rule, regulation or judicial process; (iii) to bank examiners or upon the request or demand of any other administrative, regulatory agency, or authority; or (iv) to any domestic or foreign branch, subsidiary or affiliate, representative office or agent of such Bank and third parties selected by any of the foregoing entities, wherever situated, for confidential use (including in connection with the provision of any service and for data processing, statistical and risk analysis purposes), or in connection with such Bank’s performance, administration or enforcement of this Agreement.”

(z)Annex I of the Reimbursement Agreement (Pricing Grid) is hereby amended and restated in the form of Attachment A to this Amendment.

(aa)Each of the parties hereto hereby acknowledges and agrees that, and directs the Issuing Bank to amend the Letter of Credit to provide that, the Stated Expiration Date is extended to February 11, 2019. Upon the terms, subject to the conditions and relying upon the representations and warranties set forth in this Amendment or incorporated herein by reference, the Issuing Bank agrees to deliver to the Trustee an amendment to the Letter of Credit in the form of Annex K thereto designating February 11, 2019 as the date to which the Stated Expiration Date is extended.

Section 1.3Representations and Warranties. The Applicant represents and warrants to the Administrative Agent and each Bank that:

(a)The representations and warranties of the Applicant set forth in Article Four of the Reimbursement Agreement (other than any representation and warranty with respect to the Mortgage Indenture, Mortgage Bonds, Collateral Mortgage Bonds, the Bond Delivery Agreement or Twelfth Supplemental Indenture) are true, correct and complete in all material respects on the date hereof as if made on and as of the date hereof and there exists no Event of Default or Potential Default on the date hereof, provided that in the case of any representation or warranty in Article Four of the Reimbursement Agreement that expressly relates to facts in existence on an earlier date, the reaffirmation thereof under this Section 1.3(a) shall be made as of such earlier date.

(b)The execution and delivery by the Applicant of this Amendment have been duly authorized by proper corporate proceedings of the Applicant and this Amendment and the Reimbursement Agreement constitute the legal, valid and binding obligation of the Applicant enforceable against the Applicant in accordance with their respective terms, except as such enforcement may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws of general applicability affecting the enforcement of creditors’ rights generally.

Section 1.4Conditions Precedent. This Amendment shall become effective (the “Effective Date”) as of February 11, 2014, upon the receipt by the Administrative Agent of (i) an opinion of each of (a) Todd C. Hixon, General Counsel of the Applicant, and (b) Morgan, Lewis &

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Bockius LLP, outside counsel to the Applicant, (ii) a certificate of the secretary of the Applicant certifying (a) that there have been no changes in the certificate of incorporation of the Applicant since December 14, 2010, (b) resolutions of its Board of Directors authorizing the execution, delivery and performance of the Reimbursement Agreement, as modified by this Amendment, (c) the incumbency and specimen signature of each of its officers authorized to sign this Amendment, and (d) the bylaws of the Applicant, (iii) duly executed copies of this Amendment from each of the Applicant, the Banks, the Issuing Bank and the Administrative Agent, and (iv) the fees payable pursuant to Section 2.6(a) of the Reimbursement Agreement as amended by this Amendment.

Section 1.5Continuing Effectiveness, Etc.

(a)Upon the effectiveness of this Amendment, each reference in the Reimbursement Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” “hereby” or words of like import shall mean and be a reference to the Reimbursement Agreement as modified hereby and each reference to the Reimbursement Agreement in any other document, instrument or agreement executed and/or delivered in connection the Reimbursement Agreement shall mean and be a reference to the Reimbursement Agreement as modified hereby.

(b)Except as specifically modified hereby, the Reimbursement Agreement and the instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect and are hereby ratified and confirmed.

Section 1.6CHOICE OF LAW. THIS AMENDMENT SHALL BE CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

Section 1.7Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

Section 1.8Successors and Assigns. This Amendment shall be binding upon the Applicant, the Issuing Bank, the Banks and the Administrative Agent and their respective successors and assigns, and shall inure to the benefit of the Applicant, the Issuing Bank, the Banks and the Administrative Agent and their respective successors and assigns.

Section 1.9Integration. This Amendment contains the final and complete integration of all prior expressions by the parties hereto with respect to the subject matter hereof and shall constitute the entire agreement among the parties hereto with respect to the subject matter hereof superseding all prior oral or written understandings.

Section 1.10Headings. Section headings in this Amendment are included herein for convenience or reference only and shall not constitute a part of this Amendment for any other purpose.

[signature pages follow]

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed and delivered by their duly authorized officers as of the date hereof.

TUCSON ELECTRIC POWER COMPANY
By:	/s/ Kentton C. Grant
Name: Kentton C. Grant
Title: Vice President and Treasurer

Signature Page to

Amendment No. 1 to

2010 Reimbursement Agreement

JPMORGAN CHASE BANK, N.A., as Administrative Agent, as Issuing Bank and as a Bank
By:	/s/ Nancy R. Barwig
Name: Nancy R. Barwig
Title: Credit Executive

Signature Page to

Amendment No. 1 to

2010 Reimbursement Agreement

ATTACHMENT A

ANNEX I

PRICING GRID

The “Applicable Margin” and the “LC Fee Margin” for any day are the respective annual percentage rates set forth below in the applicable row under the column corresponding to the Status that exists on such day:

	Level 1 ≥A-/A3	Level 2 BBB+/Baa1	Level 3 BBB/Baa2	Level 4   BBB-/Baa3	Level 5 ≤BB+/Ba1
Applicable Margin - Eurodollar Advances	0.75%	1.00%	1.25%	1.50%	2.00%
Applicable Margin -ABR Advances	0.00%	0.00%	0.25%	0.50%	1.00%
LC Fee Margin	0.75%	1.00%	1.25%	1.50%	2.00%

For purposes of this Pricing Grid, the following terms have the following meanings:

“Level 1 Status” exists at any date if, at such date, the Senior Unsecured Debt is rated either A- or higher by S&P or A3 or higher by Moody’s.

“Level 2 Status” exists at any date if, at such date (i) the Senior Unsecured Debt is rated either BBB+ or higher by S&P or Baa1 or higher by Moody’s and (ii) Level 1 Status does not exist.

“Level 3 Status” exists at any date if, at such date (i) the Senior Unsecured Debt is rated either BBB or higher by S&P or Baa2 or higher by Moody’s and (ii) neither Level 1 Status nor Level 2 Status exists.

“Level 4 Status” exists at any date if, at such date (i) the Senior Unsecured Debt is rated either BBB- or higher by S&P or Baa3 or higher by Moody’s and (ii) none of Level 1 Status, Level 2 Status or Level 3 Status exists.

“Level 5 Status” exists at any date if, at such date, no other Status exists.

“Status” refers to the determination of which of Level 1 Status, Level 2 Status, Level 3 Status, Level 4 Status or Level 5 Status exists at any date.

Notwithstanding the foregoing, if the Senior Unsecured Debt is split-rated and the ratings differential is two or more ratings levels, the Status shall be determined assuming that (a) the higher rating is equal to the midpoint of the two ratings (e.g., for a split rating of BBB+/Baa3, BBB is the midpoint and will be deemed to be the higher rating) or (b) if there is no exact midpoint, the higher rating is equal to the higher of the two middle intermediate ratings (e.g., for a split rating of BBB+/Ba1, BBB is the higher of the two middle intermediate ratings and will be deemed to be the higher rating).

If at any time the Senior Unsecured Debt is unrated by both Moody’s and S&P, Level 5 Status shall exist; provided that if the reason that there is no such Moody’s rating or S&P rating results from Moody’s or S&P, as the case may be, ceasing to issue debt ratings generally, then the Applicant and the Administrative Agent may select another nationally-recognized rating agency to substitute for Moody’s or S&P, as applicable, for purposes of this Pricing Schedule (and all references herein to Moody’s or S&P, as applicable, shall refer to such substitute rating agency), and until a substitute nationally-recognized rating agency is so selected the Status shall be determined by reference to the rating most recently in effect prior to such cessation; and provided, further, that if the Senior Unsecured Debt is rated by only one of Moody’s or S&P, the Status shall be determined by reference to the rating of such Rating Agency.

The Applicable Margin and LC Fee Margin shall be increased or decreased in accordance with the foregoing Pricing Grid upon any change in the applicable ratings of the Senior Unsecured Debt. The ratings of the Senior Unsecured Debt in effect at any date are those in effect at the close of business on such date.

EX-10.G

Exhibit 10(g)

UNS ENERGY CORPORATION

OFFICER CHANGE IN CONTROL AGREEMENT

This Officer Change in Control Agreement (the “Agreement”) is made and entered into by and between UNS Energy Corporation (“Company”) and _______________ (“Executive”), effective as of the date set forth below (the “Effective Date”).

RECITALS

A.    The Board of Directors of Company (the “Board”) believes that it is in the best interests of Company and its shareholders to take appropriate steps to ensure the continuity in the management of Company and its Affiliates (as defined in this Agreement), in the event a Change in Control (as defined in this Agreement) occurs.

B.    Executive currently serves as an officer of Company and one or more of its Affiliates.

C.    The Board has determined that Executive is a key employee whose continued service to Company and the applicable Affiliate(s) is critical in the event a Change of Control is being considered or occurs.

D.    In order to ensure that Company retains Executive’s services in the event a Change in Control is being considered or occurs, the Board has decided to offer to Executive the Change in Control Severance Benefits described in this Agreement.

NOW THEREFORE, in consideration of Executive’s continued service to Company and the mutual agreements contained in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which Executive hereby acknowledges, Company and Executive agree as follows:

AGREEMENT

1.TERM OF AGREEMENT.

This Agreement is effective immediately and will continue in effect until December 31, 2010 (the “Initial Term”). This Agreement will be automatically renewed at the end of the Initial Term for additional terms commencing on each January 1, and ending on the next following December 31 (a “Renewal Term”), unless Company provides Executive with written notice of its intent to terminate the Agreement at least 12 months before the end of the Initial Term or the applicable Renewal Term. If a Change in Control occurs during the Initial Term or any Renewal Term, the scheduled expiration date of the Initial Term or Renewal Term, as the case may be, shall be extended for a term ending on the 24‑month anniversary of the Change in Control, at which time this Agreement will expire. The expiration of the term of this Agreement will not reduce or diminish any liabilities that have accrued prior to the expiration.

2.CHANGE IN CONTROL SEVERANCE BENEFITS.

(a)Entitlement to Change in Control Severance Benefits. Executive will be entitled to receive the “Change in Control Severance Benefits” described in this Section 2 if Executive incurs a “Separation from Service” (as defined in Section 3) due to Company’s termination of Executive’s employment without “Cause” (as defined in Section 4) or due to Executive’s termination of employment with Company for “Good Reason” (as defined in Section 5) during the six-month period prior to the occurrence of a “Change in Control” (as defined in Section 7) and if Executive’s Separation from Service is effected in contemplation of such Change in Control. Executive also will be entitled to receive the Change in Control Severance Benefits described in this Section 2 if Executive incurs a Separation from Service due to Company’s termination of Executive’s employment with Company without Cause or due to Executive’s termination of employment with Company for Good Reason during the 24-month period following the occurrence of a Change in Control.

The Change in Control Severance Benefits described in this Section 2 will not be payable if Executive’s employment is terminated for Cause, if Executive voluntarily terminates Executive’s employment without Good Reason, or if Executive’s employment is terminated by reason of Executive’s “Disability” (as defined in Section 6) or Executive’s death. In addition, the Change in Control Severance Benefits will not be payable if Executive’s employment is terminated by Executive or Company for any or no reason more than six-months prior to the occurrence of a Change in Control or more than 24 months following the occurrence of a Change in Control. The Change in Control Severance Benefits also will not be payable if Executive’s employment is terminated within six-months prior to a Change in Control if such termination is effected for reasons other than in contemplation of a Change in Control.

Further, as noted in Section 2(f), a transfer to an Affiliate is not a Separation from Service for purposes of this Agreement.

(b)Change in Control Severance Benefits. If Executive is entitled to receive Change in Control Severance Benefits pursuant to Section 2(a), the Change in Control Severance Benefits provided to Executive pursuant to the terms of this Agreement will consist of the following:

(i)A single lump sum cash payment in an amount equal to [two for CEO] [one and one-half for Pres or SVP] [one for VP] times the greater of (a) Executive’s annualized base salary as of the date of Executive’s Separation from Service or (b) Executive’s annualized base salary in effect immediately prior to any material diminution in Executive’s base salary following the execution of this Agreement.

(ii)A single lump sum cash payment in an amount equal to [two for CEO] [one and one-half for Pres or SVP] [one for VP] times the average payment to which Executive was entitled pursuant to the UniSource Energy Corporation Performance Enhancement Plan or any successor plan (the “Incentive Compensation Plan”) for the three calendar years immediately preceding the calendar year in which Executive’s Separation from Service occurs. If, during each of the three calendar years prior to the year in which Executive’s Separation from Service occurs, Executive was not eligible to (a) participate in the Incentive Compensation Plan or

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(b) receive a payment pursuant to the Incentive Compensation Plan based on Executive’s pay grade level in effect at the time of Executive’s Separation from Service, then Executive’s target payment under the Incentive Compensation Plan for the year of Executive’s Separation from Service will be used to calculate the amount to which Executive is entitled pursuant to this paragraph (ii) in lieu of the average payment for the preceding three years.

(iii)A single lump sum cash payment in an amount equal to a prorated portion (based on the number of calendar days that have elapsed during the calendar year prior to the date of Executive’s Separation from Service) of the payment to which Executive would be entitled under the Incentive Compensation Plan (had Executive’s Separation from Service not occurred) for the calendar year in which Executive’s Separation from Service occurs. The payment due pursuant to this paragraph (iii) will be based on Executive’s target payment under the Incentive Compensation Plan for the year in which Executive’s Separation from Service occurs.

(iv)A single lump sum cash payment in the amount of the payment, if any, to which Executive is entitled under the Incentive Compensation Plan (based on Executive’s actual performance) for the year prior to the year in which the Executive’s Separation from Service occurs, to the extent Executive has not yet received such payment from Company.

(v)The continuation of any health, life, disability or other insurance benefits that Executive was receiving as of Executive’s last day of active employment for a period expiring on the earlier of (a) [24 for CEO] [18 for Pres or SVP] [12 for VP] months following Executive’s Separation from Service or, if Executive’s Separation from Service occurs within six months prior to the occurrence of a Change in Control, for the [24 for CEO] [18 for Pres or SVP] [12 for VP] months following the date on which the Change in Control occurs or (b) the day on which Executive becomes eligible to receive any substantially similar benefits, on a benefit-by-benefit basis, under any plan or program of any successor employer. The continuation of any health, life, disability or other insurance benefits shall run concurrently with Executive’s COBRA continuation coverage for health benefits. Company will satisfy the obligation to provide the health insurance benefits pursuant to this paragraph (v) by either paying for or reimbursing Executive for the employer’s portion of the COBRA premium (and Executive shall cooperate with Company in all respects in securing and maintaining such benefits, including exercising all appropriate COBRA elections and complying with all terms and conditions of such coverage in a manner to minimize the cost). In the event Executive’s right to Company’s continued payment for the employer’s portion of health insurance benefits extends beyond the applicable COBRA coverage period, Company will satisfy the obligation to provide the health insurance benefits by either paying for or reimbursing Executive for the employer’s portion of premiums for health insurance benefits that are comparable to those Executive receives during the COBRA continuation period. Company also will reimburse Executive for the employer’s portion of the cost of comparable coverage for all other insurance benefits that are not subject to the COBRA continuation rules. It will be Executive’s responsibility to procure such benefits and Company will promptly reimburse Executive for the employer’s portion of the premiums for such benefits upon Executive’s submission of an invoice or other acceptable proof of payment. For purposes of this Agreement, the “employer’s portion” is an amount equal to the cost of Company’s corresponding coverage for the applicable benefit for an active employee at Executive’s level at the time of Executive’s Separation from Service.

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Notwithstanding the foregoing, if Executive has elected a health care option pursuant to which Company has agreed to make contributions to Executive’s Health Savings Account, then Company will pay to Executive a single lump sum cash payment in an amount equal to the contributions that Company would have made to Executive’s Health Savings Account during the [12 for VP] [18 for Pres or SVP] [24 for CEO] month benefit continuation period described above had Executive not incurred a Separation from Service.

(c)Timing of Lump Sum Change in Control Severance Benefits. The lump sum Change in Control Severance Benefit payments described in Sections 2(b)(i), (ii), (iii), (iv) and (v) that become payable due to Executive’s Separation from Service within the six-month period prior to a Change in Control will be paid to Executive within 20 days following the later of the (1) date on which the Change in Control occurs or (2) the expiration of the revocation period provided in the release required pursuant to Section 2(d). In the event Executive becomes entitled to the Change in Control Severance Benefit payments described above as a result of Executive’s Separation from Service within the 24-month period following a Change in Control, such payments will be paid to Executive within 20 days following the later of (1) the date of Executive’s Separation from Service or (2) the expiration of the revocation period provided in the release required pursuant to Section 2(d). The payment provisions set forth in this Section 2(c) are subject to the provisions of Section 8(b) (which generally requires a six-month delay in payments to a Specified Employee), if applicable.

(d)Release Agreement.In order to receive the Change in Control Severance Benefits described in this Section 2, Executive must execute (and not revoke) any release reasonably requested by Company of any claims that Executive may have against Company or any Affiliate in connection with Executive’s employment with Company and/or any Affiliate or otherwise. The release shall be provided to Executive within five days following the occurrence of a Change in Control, in the event Executive’s Separation from Service occurs during the six-month period prior to the occurrence of a Change in Control. The release shall be provided to Executive within five days following Executive’s Separation from Service, in the event such Separation from Service occurs during the 24-month period following the occurrence of a Change in Control. If Executive is 40 years of age or older, Executive shall have either 21 or 45 calendar days (with the exact amount of time to be specified by Company in the release) following the date the release is given to Executive to sign and return the release to Company. If Executive is 40 years of age or older, then within seven calendar days after delivery of the release to Company by Executive, Executive shall be entitled to revoke the release by returning the signed copy or counterpart original of the release to Company. The returned release shall include Executive’s written signature in a space provided thereon, indicating his or her decision to revoke the release. The revocation of a previously signed and delivered release pursuant to the above shall be deemed to constitute an irrevocable election by Executive to have declined to receive Change in Control Severance Benefits pursuant to this Agreement. If Executive is younger than 40 years of age, Executive shall have ten calendar days following the date the release is given to Executive to sign and return the release to Company. If Executive is younger than 40 years of age, Executive shall not be entitled to revoke the release.

(e)Compliance with Covenants. Executive’s receipt of the Change in Control Severance Benefits described in this Section 2 also is expressly conditioned upon Executive’s

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continued compliance with the provisions of Section 10 (Intellectual Property) and Section 11 (Restrictive Covenants).

(f)Transfers to Affiliates. In order to receive the Change in Control Severance Benefits, Executive must incur a Separation from Service with Company which, as noted below, generally requires Executive’s Separation from Service with UniSource Energy Corporation and all of its Affiliates. As a result, a transfer to an Affiliate will not be treated as a Separation from Service for purposes of this Agreement. For purposes of determining whether a transfer constitutes Good Reason for Executive’s Separation from Service pursuant to Section 5, a transfer shall be treated the same as a reassignment within Company.

(g)“Affiliate” Defined. For purposes of this Agreement, the term “Affiliate” shall have the meaning assigned in Treas. Reg. § 1.409A-1(h)(3) (which generally requires 50% common ownership).

(h)Employment by Successor. For purposes of this Agreement, employment by a successor of Company or a successor of one of its Affiliates shall be considered to be employment by Company or one of its Affiliates. As a result, if Executive is employed by such a successor following a Change in Control, Executive will not be entitled to receive the Change in Control Severance Benefits provided by this Section 2 unless Executive subsequently incurs a Separation from Service with the successor either without Cause or for Good Reason within 24 months following the Change in Control.

(i)Non-Duplication of Benefits. Except as otherwise provided in Section 2(j), the right to receive any Change in Control Severance Benefits under this Agreement is specifically conditioned upon the Executive either waiving or being ineligible for any and all benefits under any other severance, retention or change in control plan, program or agreement sponsored by Company or any successor.

(j)Severance Plan Benefits. Notwithstanding Section 2(i), if Executive incurs a Separation from Service for which Executive becomes entitled to, and receives, severance benefits pursuant to the UniSource Energy Corporation Severance Pay Plan (the “Severance Plan”) and a Change in Control occurs within six months following such Separation from Service, Executive will be entitled to Change in Control Severance Benefits pursuant to this Agreement. The payments and benefits due to Executive as Change in Control Severance Benefits then will be reduced by the amount of any payment or benefit Executive already has received pursuant to the Severance Plan.

3.SEPARATION FROM SERVICE DEFINED.

For purposes of this Agreement, the term “Separation from Service” means, either (a) termination of Executive’s employment with Company and all Affiliates, or (b) a permanent reduction in the level of bona fide services Executive provides to Company and all Affiliates to an amount that is 20% or less of the average level of bona fide services Executive provided to Company in the immediately preceding 36 months, with the level of bona fide service calculated in accordance with Treas. Reg. § 1.409A-1(h)(1)(ii).

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Solely for purposes of determining whether Executive has a “Separation from Service,” Executive’s employment relationship is treated as continuing while Executive is on military leave, sick leave, or other bona fide leave of absence (if the period of such leave does not exceed six months, or if longer, so long as Executive’s right to reemployment with Company or an Affiliate is provided either by statute or contract). If Executive’s period of leave exceeds six months and Executive’s right to reemployment is not provided either by statute or by contract, the employment relationship is deemed to terminate on the first day immediately following the expiration of such six-month period. Whether a termination of employment has occurred will be determined based on all of the facts and circumstances and in accordance with regulations issued by the United States Treasury Department pursuant to Section 409A of the Code.

4.CAUSE DEFINED.

Company may terminate Executive’s employment at any time for “Cause” upon written notice to Executive specifying the basis for the termination. If Executive incurs a Separation from Service due to Company’s termination of Executive’s employment for “Cause,” Executive shall not be entitled to any Change in Control Severance Benefits pursuant to this Agreement. For purposes of this Agreement, the term “Cause” shall mean the termination of Executive’s employment by Company for one or more of the following reasons:

(a)Executive’s willful failure to perform any of Executive’s duties which continues after Company has given Executive written notice describing Executive’s failure and provided to Executive an opportunity to cure such failure within 30 days (or such longer period as may be specified by the Board) of such written notice; or

(b)Executive’s material violation of Company policy; or

(c)Any act of fraud or dishonesty resulting or intended to result in Executive’s personal enrichment at Company’s or any Affiliate’s expense; or

(d)Executive’s gross misconduct in the performance of Executive’s duties that results in material economic harm to Company or any Affiliate; or

(e)Executive’s conviction of, or plea of guilty or no contest (or its equivalent) to, a felony; or

(f)Executive’s material breach of Executive’s employment agreement with Company, if any.

The existence of Cause shall be determined by the Board, in its discretion.

5.GOOD REASON DEFINED.

Executive may Separate from Service due to Executive’s termination of employment with Company for “Good Reason” if Executive provides Company with notice of such termination as set forth below. For purposes of this Agreement, the term “Good Reason” shall mean and include each of the following (unless Executive has expressly agreed to such event in a signed writing):

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(a)A material, adverse diminution in Executive’s authority, duties, or responsibilities; or

(b)A material change in the geographic location at which Executive must primarily perform services; or

(c)A material diminution in Executive’s base salary provided that such diminution is not a result of a generally applicable reduction in the base salary of all officers of Company in an amount that does not exceed 10%; or

(d)Any action or inaction that constitutes a material breach of this Agreement by Company which, for this purpose, shall include, but not be limited to, Company’s failure to ensure that any successor to Company or to any Affiliate assumes Company’s obligations pursuant to this Agreement.

Notwithstanding any provisions of this Agreement to the contrary, none of the events described in this Section 5 will constitute Good Reason if, within 30 days after Executive provides Company with a written notice specifying the occurrence or existence of the breach or action that Executive believes constitutes Good Reason, Company has fully corrected (or reversed) such breach or action. Executive’s Separation from Service for Good Reason will occur on the day following the expiration of this 30 day “cure period,” (unless Company has fully corrected (or reversed) such breach or action) unless Executive and Company agree to a later date not later than two years following the initial existence of such breach or action. Executive shall be deemed to have waived Executive’s right to terminate for Good Reason with respect to any such breach or action if Executive fails to notify Company in writing of such breach or action within 90 days of the event that gives rise to such breach or action.

6.DISABILITY DEFINED.

For purposes of this Agreement, the term “Disability” means Executive is, by reason of any medically determinable physical or mental impairment that can be expected to (a) result in death or (b) last for a continuous period of not less than 12 months, unable to continue to perform the essential functions of Executive’s job, with or without any accommodation required by law, for six consecutive calendar months or for shorter periods aggregating 125 business days in any 12-month period.

7.CHANGE IN CONTROL DEFINED.

For purposes of this Agreement, “Change in Control” shall mean each occurrence of any of the following:

(a)Any person, or more than one person acting as a group (as determined in accordance with Treas. Reg. § 1.409A-3(i)(5)), acquires (or has acquired during the 12-month period ending on the most recent acquisition by such person or persons) ownership of stock of Company possessing 40% or more of the total voting power of the stock of Company, unless such person is, or shall be, a trustee or other fiduciary holding securities under an employee benefit plan of Company

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or a corporation owned, directly or indirectly, by the stockholders of Company in substantially the same proportion as their ownership of stock of Company;

(b)The closing of a merger or consolidation of Company or its subsidiary, Tucson Electric Power Company (“TEP”), with another entity that is not affiliated with Company immediately before the Change in Control; provided, however, that, in the case of a merger or consolidation involving Company, if the merger or consolidation results in the voting securities of Company outstanding immediately prior thereto continuing to represent, either by remaining outstanding or by being converted into voting securities of the surviving entity, more than 50% of the combined voting power of the voting securities of Company or such surviving entity outstanding immediately after such merger or consolidation, the merger or consolidation will be disregarded; and provided further that, in the case of a merger or consolidation involving TEP, if Company continues to hold more than 50% of the combined voting power of the voting securities of TEP or the surviving entity outstanding immediately after such merger or consolidation, the merger or consolidation will be disregarded;

(c)During any period of 12 consecutive months, excluding any period prior to the execution of this Agreement, the majority of members of Company’s Board is replaced by directors whose appointment or election is not endorsed by a majority of the members of the Board before the date of such appointment or election; or

(d)Company’s execution of an agreement for the sale or disposition by Company of all or substantially all of Company’s assets.

Notwithstanding the foregoing, a Change in Control will not be deemed to have occurred until: (1) any required regulatory approval, including any final non-appealable regulatory order, has been obtained; and (2) the transaction that would otherwise be considered a Change in Control closes. Further, to the extent required by Section 409A of the Code, a transaction will not be considered a Change in Control for purposes of this Section 7 unless the transaction also constitutes a “change in control event” as such term is used in Treas. Reg. § 1.409A-3(i)(5).

8.SECTION 409A COMPLIANCE.

(a)Compliance Strategy; Responsibility for Taxes. Section 409A of the Code imposes an additional 20% tax, plus interest, on payments from “non-qualified deferred compensation plans.” Certain payments under this Agreement could be considered to be payments under a “non-qualified deferred compensation plan.” The additional 20% tax, and interest, does not apply if the payment qualifies for an exception to the requirements of Section 409A of the Code or complies with the requirements of Section 409A of the Code. Company intends that the payments and benefits due pursuant to this Agreement either comply with the requirements of Section 409A of the Code or qualify for an exception to the requirements of Section 409A of the Code. Nevertheless, Company does not guarantee any particular tax effect or treatment of the amounts due under this Agreement. Except for Company’s responsibility to withhold applicable income and employment taxes from compensation paid or provided to Executive, Company will not be

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responsible for the payment of any applicable taxes on compensation paid or provided pursuant to this Agreement.

(b)Delay in Payments. Prior to making any payments due under this Agreement, Company will determine, on the basis of any regulations, rulings or other available guidance, whether the short-term deferral exception, the separation pay exception or any other exception to the requirements of Section 409A of the Code is available. If Executive is a “Specified Employee” (as defined in Treas. Reg. § 1.409A-1(i)), and Company concludes that no exception to the requirements of Section 409A of the Code is available, no payments that are payable to Executive as a result of Executive’s Separation from Service under this Agreement, or under any other arrangement that is aggregated with this Agreement under Section 409A of the Code, shall be made to Executive prior to the first business day following the date which is six months after Executive’s Separation from Service. Any amounts that would have been paid during the six months following Executive’s Separation from Service will be paid on the first business day following the expiration of the six-month period without interest thereon. The provisions of this paragraph apply to all amounts due pursuant to this Agreement, other than amounts that do not constitute a deferral of compensation within the meaning of Treas. Reg. §1.409A-1(b) or other amounts or benefits that are not subject to the requirements of Section 409A of the Code.

(c)Distributions Treated as Made upon a Designated Event. If Company fails to make any payment, either intentionally or unintentionally, within the time period specified in this Agreement, but the payment is made within the same calendar year, such payment will be treated as made within the time period specified in this Agreement pursuant to Treas. Reg. § 1.409A-3(d). In addition, if a payment is not made due to a dispute with respect to such payment, the payment may be delayed in accordance with Treas. Reg. § 1.409A-3(g).

(d)Reimbursements. In order to ensure compliance with the applicable regulations, the amounts reimbursed by Company in one taxable year will not affect the amounts eligible for reimbursement by Company in a different taxable year. All reimbursements must be made no later than December 31 of the calendar year following the calendar year in which the expense was incurred. Executive may not elect to receive cash or any other benefit in lieu of the benefits provided by this Agreement.

(e)Miscellaneous Payment Provisions. Under no circumstances may the time or schedule of any payment made or benefit provided pursuant to this Agreement be accelerated or subject to a further deferral except as otherwise permitted or required pursuant to regulations and other guidance issued pursuant to Section 409A of the Code. Executive does not have any right to make any election regarding the time or form of any payment due under this Agreement. This Agreement shall be operated in compliance with Section 409A of the Code or an exception thereto and each provision of this Agreement shall be interpreted, to the extent possible, to comply with Section 409A of the Code or to qualify for an applicable exception.

9.CAP ON PAYMENTS.

(a)General Rules. The Code places significant tax burdens on Executive and Company if the total payments made to Executive due to a “change in control” (which, for purposes

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of this Section 9, shall have the meaning ascribed to it in Section 280G of the Code and the regulations adopted thereunder) exceed prescribed limits. For example, if Executive’s “Base Period Income” (as defined below) is $100,000, Executive’s limit or “280G Cap” is $299,999. If Executive’s “Basic Payments” exceed the 280G Cap by even $1.00, Executive is subject to an excise tax under Section 4999 of the Code of 20% of all amounts paid to him in excess of $100,000. In other words, if Executive’s 280G Cap is $299,999, Executive will not be subject to an excise tax if Executive receives exactly $299,999. If Executive receives $300,000, Executive will be subject to an excise tax of $40,000 (20% of $200,000). In order to avoid this excise tax and the related adverse tax consequences for Company, by signing this Agreement Executive agrees that Executive’s Basic Payments will not exceed an amount equal to Executive’s 280G Cap unless the exception described in Section 9(e) applies.

(b)Special Definitions. For purposes of this Section 9, the following specialized terms will have the following meanings:

(i)“Base Period Income.” “Base Period Income” is an amount equal to Executive’s “annualized includable compensation” for the “base period” as defined in Sections 280G(d)(1) and (2) of the Code and the regulations adopted thereunder. Generally, Executive’s “annualized includable compensation” is the average of Executive’s annual taxable income from Company for the “base period,” which is the five calendar years prior to the year in which the change in control occurs. These concepts are complicated and technical and all of the rules set forth in the applicable regulations apply for purposes of this Agreement.

(ii)“280G Cap.” “280G Cap” shall mean an amount equal to three times Executive’s “Base Period Income” minus $1.00. This is the maximum amount which Executive may receive without becoming subject to the excise tax imposed by Section 4999 of the Code or which Company may pay without loss of deduction under Section 280G of the Code.

(iii)“Basic Payments.” The “Basic Payments” include any “payments in the nature of compensation” (as defined in Section 280G of the Code and the regulations adopted thereunder), made pursuant to this Agreement or otherwise, to Executive or for Executive’s benefit, the receipt of which is contingent on a change in control and to which Section 280G of the Code applies.

(c)Calculating the 280G Cap. If Company believes that these rules will result in a reduction of the payments to which Executive is entitled under this Agreement, it will so notify Executive as soon as possible. Company will then, at its expense, retain a “Consultant” (which shall be a law firm, a certified public accounting firm and/or a firm of recognized executive compensation consultants working with a law firm or certified public accounting firm) to provide a determination concerning whether Executive’s Basic Payments exceed Executive’s 280G Cap (the “Determination”). Company will select the Consultant.

At a minimum, the Determination required by this Section must set forth the amount of Executive’s Base Period Income, the value of the Basic Payments, the amount, if any, by which Executive’s Basic Payments exceed Executive’s 280G Cap and the amount and present value of any “Excess Parachute Payment.” For purposes of this Section 9(c), the term “Excess Parachute

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Payment” means an amount equal to the excess of any Basic Payment to which Executive is entitled over the Base Period Income allocated to such Basic Payment. Executive shall have the right to review the final calculations used by the Consultant in reaching its conclusions with respect to the Determination.

If the Determination states that the Basic Payments exceed the 280G Cap, Executive’s Basic Payments will be reduced to the extent necessary to eliminate the excess. In making such reduction, Company first will reduce the amount of Executive’s payments under this Agreement and, if necessary, any other payments to which Executive is entitled under any other arrangement that do not constitute “non-qualified deferred compensation” that is subject to Section 409A of the Code. Company will reduce the amount of any Basic Payments payable to Executive that are subject to Section 409A of the Code only to the extent reductions in addition to those described in the preceding sentence are necessary to avoid exceeding the 280G Cap. If reduction of any Basic Payments which are subject to Section 409A of the Code becomes necessary to avoid exceeding the 280G Cap, Company first will reduce the non-equity based Basic Payments on a proportional basis. To the extent additional reductions are necessary to avoid exceeding the 280G Cap, Company then will reduce the equity based Basic Payments on a proportional basis.

If the Consultant selected to provide the Determination so requests, a firm of recognized executive compensation consultants selected by Company (which may, but is not required to be, the Consultant) shall provide an opinion, upon which such Consultant may rely, as to the reasonableness of any item of compensation as reasonable compensation for services rendered before or after the change in control.

If Company believes that Executive’s Basic Payments will exceed the limitations of this Section 9, it will nonetheless make payments to Executive, at the times stated above, in the maximum amount that it believes may be paid without exceeding such limitations. The balance, if any, will then be paid after the opinions called for above have been received.

As a general rule, the Determination shall be binding on Executive and Company. Section 280G and the excise tax rules of Section 4999, however, are complex and somewhat uncertain and, as a result, the Internal Revenue Service may disagree with the Consultant’s conclusions. If the Internal Revenue Service finally and conclusively determines that the 280G Cap is actually lower than calculated by the Consultant, the 280G Cap will be recalculated by the Consultant. Any payment over that revised 280G Cap will then be repaid by Executive to Company. If the Internal Revenue Service finally and conclusively determines that the actual 280G Cap exceeds the amount calculated by the Consultant, Company shall pay Executive any shortage, together with interest thereon, from the date such amount should have been paid to the date of such payment, so that Executive will have received or be entitled to receive the maximum amount to which Executive is entitled under this Agreement. For purposes of this Section 9, the applicable interest rate shall be the prime rate published by the Wall Street Journal on the date the amounts described in the preceding sentence should have been paid to Executive.

Company has the right to challenge any determinations made by the Internal Revenue Service. If Company agrees to indemnify Executive from any taxes, interest and penalties that may be imposed upon Executive (including any taxes, interest and penalties on the amounts paid pursuant

11

to Company’s indemnification agreement), Executive must cooperate fully with Company in connection with any such challenge. Company shall bear all costs associated with the challenge by Company of any determination made by the Internal Revenue Service and Company shall control all such challenges.

Executive must notify Company in writing of any claim or determination by the Internal Revenue Service that, if upheld, would result in the payment of excise taxes. Such notice shall be given as soon as possible but in no event later than 15 days following Executive’s receipt of notice of the Internal Revenue Service’s position.

(d)Effect of Repeal or Inapplicability. In the event that the provisions of Sections 280G and 4999 of the Code are repealed without succession, this Section 9 shall be of no further force or effect. Moreover, if the provisions of Sections 280G and 4999 of the Code do not apply to impose the excise tax to payments under this Agreement, then the provisions of this Section 9 shall not apply.

(e)Exception. The Consultant selected pursuant to this Section 9 will calculate Executive’s “Uncapped Benefit” and Executive’s “Capped Benefit.” The limitations of this Section 9 will not apply if Executive’s “Uncapped Benefit” minus the excise taxes that will be imposed on Executive pursuant to Section 4999 of the Code exceeds Executive’s “Capped Benefit.” For this purpose, Executive’s “Uncapped Benefit” is equal to the Basic Payments to which Executive will be entitled pursuant to this Agreement, or otherwise, without regard to the limitations of this Section 9. Executive’s “Capped Benefit” is the amount to which Executive will be entitled pursuant to Section 9 of this Agreement after the application of the limitations of this Section 9.

10.INTELLECTUAL PROPERTY.

(a)Proprietary Information. Executive and Company hereby acknowledge and agree that in connection with the performance of Executive’s services, Executive shall be provided with or shall otherwise be exposed to or receive certain proprietary information of Company. Such proprietary information may include, but shall not be limited to, information concerning Company’s customers and products, information concerning certain marketing, selling, and pricing strategies of Company, and information concerning methods, manufacturing techniques, and processes used by Company in its operations (all of the foregoing shall be deemed “Proprietary Information” for purposes of this Agreement). Executive hereby agrees that, without the prior written consent of Company, any and all Proprietary Information shall be and shall forever remain the property of Company, and that during Executive’s employment with Company, and at all times thereafter, Executive shall not in any way disclose or reveal the Proprietary Information other than to Company’s executives, officers and other employees and agents in the normal course of Executive’s provision of services hereunder. The term “Proprietary Information” does not include information that (1) becomes generally available to the public other than as a result of a disclosure by Executive contrary to the terms of this Agreement, (2) was available on a non-confidential basis prior to its disclosure, or (3) becomes available on a non-confidential basis from a source other than Executive, provided that such source is not contractually obligated to keep such information confidential.

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(b)Trade Secrets. Executive, prior to and during this Agreement, has had and will have access to and become acquainted with various trade secrets that are owned by Company or by its Affiliates and are regularly used in the operation of their respective businesses and that may give Company or an Affiliate an opportunity to obtain an advantage over competitors who do not know or use such trade secrets. Executive agrees and acknowledges that Executive has been granted access to these valuable trade secrets only by virtue of the confidential relationship created by Executive’s employment and Executive’s prior relationship to, interest in, and fiduciary relationships to Company. Executive shall not disclose any of the aforesaid trade secrets, directly or indirectly, or use them in any way, either during Executive’s employment with Company or at any time thereafter, except as required in the course of employment by Company and for its benefit.

(c)Ownership of Documents. Company shall own all papers, records, books, drawings, documents, manuals, and anything of a similar nature (collectively, the “Documents”) prepared by Executive in connection with Executive’s employment. The Documents shall be the property of Company and are not to be used on other projects except upon Company’s prior written consent. Upon termination of Executive’s employment with Company, Executive shall surrender to Company any and all Documents or other property of whatsoever kind now or hereafter in Executive’s possession, custody, or control that contain or reflect in any manner whatsoever Proprietary Information or information that in any way relates to Company’s business.

(d)Company Defined. For purposes of this Section 10, “Company” shall be interpreted to include Company and all of Company’s Affiliates.

11.RESTRICTIVE COVENANTS.

(a)Covenant Not to Compete. In consideration of Company’s agreements contained herein and the payments to be made by it to Executive pursuant hereto, Executive agrees that during the Restricted Period Executive will not, without prior written consent of Company, consult with, engage in or act as an advisor to another company about activity that is a “Competing Business” of such company in the Restricted Territory, as defined in this Section 11.

(b)Non-Solicitation. Executive recognizes that Company’s customers are valuable and proprietary resources of Company. Accordingly, Executive agrees that during the Restricted Period Executive will not directly or indirectly, through Executive’s own efforts or through the efforts of another person or entity, solicit business in the Restricted Territory for or in connection with any Competing Business from any individual or entity that obtained products or services from Company at any time during Executive’s employment with Company. In addition, during the Restricted Period Executive will not solicit business in the Restricted Territory for or in connection with a Competing Business from any individual or entity that was solicited by Executive on behalf of Company. Further, during the Restricted Period Executive will not solicit employees of Company who would have the skills and knowledge necessary to enable or assist efforts by Executive to engage in a Competing Business.

(c)Competing Business. For purposes of this Section 11, Executive shall be deemed to be engaged in a “Competing Business” if, in any capacity, including proprietor, shareholder, partner, officer, director or employee, Executive engages or participates, directly or

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indirectly, in the operation, ownership or management of the activity of any proprietorship, partnership, company or other business entity which activity is competitive with the then actual business in which Company or its operating subsidiaries and Affiliates are engaged on the date of, or any business contemplated by such entities’ business plans in effect on the date of notice of, Executive’s termination of employment. Nothing in this Section 11(c) is intended to limit Executive’s ability to own equity in a public company constituting less than 1% of the outstanding equity of such company, when Executive is not actively engaged in the management thereof. If requested by Executive, Company shall furnish Executive with a good-faith written description of the business or businesses in which Company is then actively engaged or that is contemplated by Company’s current business plan within 30 days after such request is made, and only those activities so timely described in which Company is, in fact, actively engaged or which are so contemplated may be treated as activities that are directly competitive with Company.

(d)Restricted Period. For purposes of this Section 11, the “Restricted Period” shall include the time during which Executive is employed by Company and a period of one year (or in the event any reviewing court finds this period to be over-broad or unenforceable, for a period of nine months; or in the event any reviewing court finds this period to be over-broad or unenforceable, for a period of six months) following the termination of Executive’s employment with Company for any reason.

(e)Restricted Territory. Executive and Company understand and agree that Company’s business is not geographically restricted and in some respects at least is unrelated to the physical location of Company facilities or the physical location of any Competing Business, due to extensive use of the power grid, Internet, telephones, facsimile transmissions and other means of electronic information and product distribution. Executive and Company further understand and agree that Executive will, in part, work toward expanding Company’s markets and geographic business territories and will be compensated for performing this work on behalf of Company.

Accordingly, Company has a protectable business interest in, and the parties intend the Restricted Territory to encompass, each and every geographical location from which Executive could engage in a Competing Business. If, but only if, this Restricted Territory is held to be invalid on the ground that it is unreasonably broad, the Restricted Territory shall be limited to any geographical location that is within 10 miles of any geographical location in which Company is in fact carrying out its business operations or, pursuant to Company’s business plans, is contemplating conducting business operations on the date of Executive’s termination of employment. If, but only if, this Restricted Territory is held to be invalid on the ground that it is unreasonably broad, the Restricted Territory shall be any location within a 50 mile radius of any Company office in existence or, pursuant to Company’s business plans, intended to be opened at the time of Executive’s termination of employment.

(f)Remedies; Reasonableness. Executive acknowledges and agrees that a breach by Executive of the provisions of this Section 11 will constitute such damage as will be irreparable and the exact amount of which will be impossible to ascertain and for that reason agrees that Company will be entitled to an injunction to be issued by any court of competent jurisdiction restraining and enjoining Executive from violating the provisions of this Section 11. The right to

14

an injunction shall be in addition to and not in lieu of any other remedy available to Company for such breach or threatened breach, including the recovery of damages from Executive.

Executive expressly acknowledges and agrees that: (1) the Restrictive Covenants contained herein are reasonable as to time and geographical area and do not place any unreasonable burden upon Executive, (2) the general public will not be harmed as a result of enforcement of these Restrictive Covenants, and (3) Executive understands and hereby agrees to each and every term and condition of the Restrictive Covenants set forth in this Agreement.

Executive also expressly acknowledges and agrees that Executive’s covenants and agreements in this Section 11 shall survive this Agreement and continue to be binding upon Executive after the expiration or termination of this Agreement, whether by passage of time or otherwise.

(g)Company Not in Default. Company agrees that the restrictions described in this Section 11 apply only so long as Company is continuously not in material default of its obligations to provide payments or employment-type benefits to Executive hereunder or under any other agreement, covenant or obligation.

(h)Company Defined. For purposes of this Section 11, “Company” shall be interpreted to include Company and all of Company’s Affiliates.

12.NO MITIGATION.

The payment of Change in Control Severance Benefits will not be affected by whether Executive seeks or obtains other employment. Executive will have no obligation to seek or obtain other employment and Executive’s Change in Control Severance Benefits will not be impacted by Executive’s failure to “mitigate.” As provided in Section 2(b)(v), however, Company’s obligation to provide continued health, life, disability and other insurance benefits will cease with respect to a particular type of coverage when and if Executive becomes eligible to receive substantially similar coverage with a successor employer.

13.SUCCESSORS.

Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of Company or any Affiliate to expressly assume and agree to perform this Agreement in the same manner and to the same extent that Company or any Affiliate would be required to perform it if no such succession had taken place. Failure of Company to obtain such assumption and agreement prior to the effectiveness of any such succession shall be a material breach of this Agreement.

14.BINDING AGREEMENT; ASSIGNMENT.

This Agreement shall inure to the benefit of and be binding upon Company, its successors and assigns, including, but not limited to, any company, person, or other entity which may acquire all or substantially all of the assets and business of Company or any company with or into which

15

Company may be consolidated or merged, and Executive, Executive’s heirs, executors, administrators, and legal representatives. Nevertheless, the obligations, rights and benefits of Executive hereunder are personal and may not be delegated, assigned or transferred in any manner whatsoever, nor are such obligations, rights or benefits subject to involuntary alienation, assignment or transfer. This Agreement shall be assigned automatically to any entity merging with or acquiring Company or its business.

15.NOTICE.

All notices hereunder shall be in writing and delivered personally or sent by United States registered or certified mail, postage prepaid and return receipt requested:

If to Company, to: UNS Energy Corporation 88 E Broadway Blvd
Tucson, Arizona 85701

If to Executive, to: ______________________________

Either party may change the address to which notices are to be sent to it by giving ten days written notice of such change of address to the other party in the manner above provided for giving notice.

Notices will be considered delivered on personal delivery or on the date of deposit in the United States mail in the manner provided for giving notice by mail.

16.MISCELLANEOUS.

No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Executive and the Chief Executive Officer of Company or his designee. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. Any payments provided for hereunder shall be paid net of any applicable withholding required under federal, state or local law. The obligations of Company that arise prior to the expiration of this Agreement shall survive the expiration of the term of this Agreement.

17.SEVERABILITY.

If any term or provision of this Agreement is declared by a court or tribunal of competent jurisdiction to be invalid or unenforceable for any reason, this Agreement shall remain in full force and effect, and either (a) the invalid or unenforceable provision shall be modified to

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the minimum extent necessary to make it valid and enforceable or (b) if such a modification is not possible or permitted by law, this Agreement shall be interpreted as if such invalid or unenforceable provision were not a part hereof.

18.COUNTERPARTS.

This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

19.ALTERNATIVE DISPUTE RESOLUTION.

(a)The parties agree that any controversy, dispute or claim arising out of or relating to the Agreement or breach thereof, including without limitation Executive’s employment with or separation of employment from Company, compensatory and punitive damages, and to the extent allowable by law, all claims that Company or any of its representatives engaged in conduct prohibited on any basis under any federal, state, or local statute, including federal or state discrimination statutes or public policy (collectively the “Dispute”), shall be resolved in accordance with the procedures described in this Section, which shall be the sole and exclusive procedures for resolution of any Dispute. The parties shall bear their own attorneys’ fees and costs, unless provided otherwise by an arbitration award, and share equally the cost thereof of all Dispute Resolution procedures described in the Section.

(a)The parties shall initially try in good faith to settle the Dispute through non-binding mediation. A party seeking mediation shall make a written request for mediation by certified mail, return receipt requested, setting forth with reasonable specificity the basis for the Dispute and the relief requested. A neutral third party mediator shall be agreed upon by the parties. If, within 14 days after a party makes a written request for mediation or within any longer period mutually agreed upon by the parties, the parties have not agreed upon the identity of the mediator and the procedure for mediation, the mediation shall be held in Tucson, Arizona, and administered by the American Arbitration Association (“AAA”) under its Employment Arbitration and Mediation Procedures formally known as the National Rules for Resolution of Employment Disputes (“Rules”) currently in effect. Unless otherwise agreed, the parties shall select a mediator as provided by the Rules. A good faith attempt at mediation shall be a condition precedent to the commencement of arbitration, but is not a condition precedent to any court action for injunctive or other interim relief pending the outcome of these Dispute Resolution procedures.

(b)If the parties are unable to resolve the dispute by mediation in a timely manner (which, in any case, shall not exceed 60 days from the first notice of mediation or such longer period mutually agreed upon by the parties), the Dispute shall be resolved by final, binding and conclusive arbitration with a sole arbitrator in Tucson, Arizona. The parties shall initiate arbitration by filing a written notice of intention to arbitrate at any office of the AAA. The selection of the arbitrator and the arbitration shall proceed pursuant to the Rules and judgment upon the award rendered by the arbitrator may be entered in any court having jurisdiction thereof.

(c)The arbitrator shall award Executive his attorneys’ fees and costs if Executive prevails on at least one material issue in the Dispute, including the attorneys’ fees Executive incurs

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in connection with any appeal or the enforcement of any award. “Attorneys’ fees and costs” mean all reasonable pre-award expenses, administrative fees, travel expenses, out-of-pocket expenses such as copying and telephone costs, witness fees and attorneys’ fees. Any award of attorneys’ fees and costs to Executive shall be paid by Company within 60 days following the award of such fees and costs by the arbitrator, but in no event later than December 31 of the calendar year following the year of the conclusion of the arbitration.

A party may apply to the arbitrator for injunctive or other equitable relief until the arbitration award is rendered or the matter is otherwise resolved. A party may, without waiving the Dispute Resolution procedures under the Agreement, seek from any court having jurisdiction any interim or provisional relief, including a temporary restraining order, an injunction both preliminary and final, and any other appropriate equitable relief, that is necessary to protect the rights or property of that party, pending the final decision of the arbitrator on all issues related to the injunctive relief.

20.PAYMENT OBLIGATIONS ABSOLUTE.

Company’s obligation to pay Executive the compensation and to make the arrangements in accordance with the provisions herein shall be absolute and unconditional and shall not be affected by any circumstances. All amounts payable by Company in accordance with this Agreement shall be paid without notice or demand. If Company has paid Executive more than the amount to which Executive is entitled under this Agreement, Company shall have the right to recover all or any part of such overpayment from Executive or from whomsoever has received such amount.

21.ENTIRE AGREEMENT.

This Agreement sets forth the entire agreement between Executive and Company concerning the subject matter discussed in this Agreement and supersedes all prior agreements, promises, covenants, arrangements, communications, representations or warranties, whether written or oral, by any officer, employee or representative of Company. Any prior agreements or understandings with respect to the subject matter set forth in the aforementioned agreements are hereby terminated and canceled.

22.STATUTORY REFERENCES.

All references to sections of the Code shall be deemed also to refer to any successor provisions to such sections. All references to sections of the final regulations issued pursuant to Section 409A shall be deemed also to refer to any successor provisions of such regulations or rulings or other guidance that clarify such regulations.

23.DEFINITIONS.

A number of terms have been defined throughout this Agreement. These defined terms are identified by the capitalization of the first letter of each word or the first letter of each substantive word of a phrase. Whenever these terms are capitalized they shall be given the defined meaning.

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24.PARTIES.

This Agreement is an agreement between Executive and Company. In certain cases, though, obligations imposed upon Company may be satisfied by an Affiliate of Company. Any payment made or action taken by an Affiliate of Company shall be considered to be a payment made or action taken by Company for purposes of determining whether Company has satisfied its obligations under this Agreement.

25.NO RIGHTS IN ANY PROPERTY OF COMPANY.

The undertakings of Company constitute merely the unsecured promise of Company to make payments as provided for herein. No property of Company shall, by reason of this Agreement, be held in trust for Executive, Executive’s spouse or any other person, and neither Executive nor Executive’s spouse or any other person shall have, by reason of this Agreement, any rights, title or interest of any kind in any property of Company.

26.NOT AN EMPLOYMENT AGREEMENT.

Nothing in this Agreement shall be construed as an offer or commitment by Company to continue Executive’s employment with Company for any period of time.

27.CONSTRUCTION.

This Agreement is the result of negotiation between Company and Executive and both have had the opportunity to have this Agreement reviewed by their legal counsel and other advisors. Accordingly, this Agreement shall not be construed for or against Company or Executive, regardless of which party drafted the provision at issue. The language in all parts of this Agreement shall in all cases be construed as a whole according to its fair meaning and not strictly for or against either party. The Section headings contained in this Agreement are for reference purposes only and will not affect the meaning or interpretation of this Agreement in any way. Whenever the words “include,” “includes,” or “including” are used in the Agreement, they shall be deemed to be followed by the words “without limitation.”

28.GOVERNING LAW.

This Agreement shall be governed in all respects by the laws of the State of Arizona, excluding the conflicts of law principles, and except as preempted by or governed solely by Federal law.

29.AMENDMENTS.

This Agreement may be amended at any time by a written agreement executed by Company and Executive. No amendment that will result in a violation of Section 409A of the Code, or any other provision of applicable law, may be made to this Agreement and any such amendment shall be void ab initio.

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IN WITNESS WHEREOF, Company and Executive have executed this Agreement on this ____ day of ____________ 20__.

UNS ENERGY CORPORATION

By:

Its:

EXECUTIVE

___________________________________________

20

Schedule of Officers who are Covered by this Agreement

or Substantially Identical Agreements

Paul J. Bonavia, Chief Executive Officer.

David G. Hutchens, President and Chief Operating Officer.

Kevin P. Larson, Senior Vice President, Chief Financial Officer and Treasurer

Phillip J. Dion, Senior Vice President, Public Policy and Customer Solutions

Kentton C. Grant, Vice President, Finance and Rates

Todd C. Hixon, Vice President and General Counsel

Karen G. Kissinger, Vice President, Controller and Chief Compliance Officer

Mark Mansfield, Vice President, Energy Resources

Frank P. Marino, Vice President and Controller

Thomas A. McKenna, Vice President, Energy Delivery

Catherine E. Ries, Vice President, Human Resources and Information Technology

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EX-12.A

Exhibit 12a

UNS Energy Corporation

Computation of Ratio of Earnings to Fixed Charges

	12 Months Ended
	December 31,		December 31,		December 31,		December 31,		December 31,
	2013		2012		2011		2010		2009
	Thousands of Dollars
Net Income	$	127,478	$	90,919	$	109,975	$	112,984	$	105,901
Add:
Income Tax Expense	58,427		55,727		66,951		76,921		63,232
Interest Expense, net(1)	95,117		108,303		116,873		116,624		112,982
Estimated Interest Portion of Rental Expense	959		691		926		240		345
Losses from Equity Investees	—		7		—		5,570		1,834
Total Earnings before Taxes and Fixed Charges	$	281,981	$	255,647	$	294,725	$	312,339	$	284,294
Fixed Charges:
Interest Expense (before deducting capitalized interest)(2)	$	100,844	$	110,456	$	120,626	$	119,211	$	115,284
Estimated Interest Portion of Rental Expense	959		691		926		240		345
Total Fixed Charges	$	101,803	$	111,147	$	121,552	$	119,451	$	115,629
Ratio of Earnings to Fixed Charges	2.770		2.300		2.425		2.615		2.459

⁽¹⁾  The ratios of earnings to fixed charges for the fiscal years ended 2012, 2011, 2010, and 2009 have been revised to exclude capitalized interest from the calculation of Earnings before Taxes and Fixed Charges. Capitalized interest was not material to the calculation of Earnings before Taxes and Fixed Charges or the Ratio of Earnings to Fixed Charges in prior periods.

⁽²⁾  Excludes recognition of Allowance for Borrowed Funds Used During Construction and Loss on Extinguishment of Debt.

EX-12.B

Exhibit 12b

Tucson Electric Power Company

Computation of Ratio of Earnings to Fixed Charges

	12 Months Ended
	December 31,		December 31,		December 31,		December 31,		December 31,
	2013		2012		2011		2010		2009
	Thousands of Dollars
Net Income	$	101,342	$	65,470	$	85,334	$	108,260	$	90,688
Add:
Income Tax Expense	47,986		39,109		52,000		59,936		54,220
Interest Expense, net(1)	80,793		91,295		93,786		93,465		89,715
Estimated Interest Portion of Rental Expense	842		611		795		72		106
(Income) from Equity Investees	—		—		—		—		—
Total Earnings before Taxes and Fixed Charges	$	230,963	$	196,485	$	231,915	$	261,733	$	234,729
Fixed Charges:
Interest Expense (before deducting capitalized interest)(2)	$	85,591	$	93,077	$	95,859	$	95,345	$	91,467
Estimated Interest Portion of Rental Expense	842		611		795		72		106
Total Fixed Charges	$	86,433	$	93,688	$	96,654	$	95,417	$	91,573
Ratio of Earnings to Fixed Charges	2.672		2.097		2.399		2.743		2.563

⁽¹⁾  The ratios of earnings to fixed charges for the fiscal years ended 2012, 2011, 2010, and 2009 have been revised to exclude capitalized interest from the calculation of Earnings before Taxes and Fixed Charges. Capitalized interest was not material to the calculation of Earnings before Taxes and Fixed Charges or the Ratio of Earnings to Fixed Charges in prior periods.

⁽²⁾  Excludes recognition of Allowance for Borrowed Funds Used During Construction.

EX-21

Exhibit 21
UNS Energy Corporation Subsidiaries
Subsidiary	State or Other Jurisdiction of Incorporation or Organization
Tucson Electric Power Company (TEP)	Arizona
TEP Subsidiaries:
San Carlos Resources Inc.	Arizona
Escavada Company	Arizona
UniSource Energy Services, Inc. (UES)	Arizona
UES Subsidiaries:
UNS Electric, Inc.	Arizona
UNS Gas, Inc.	Arizona

EX-23.A

Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S‑8 (Nos. 333-43765, 333-99317, 333-140353, 333-156491 and 333-175001) and on Form S-3 (No. 333-181305) of UNS Energy Corporation of our report dated February 25, 2014 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

February 25, 2014

EX-23.B

Exhibit 23(b)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-181305-01) of Tucson Electric Power Company of our report dated February 25, 2014 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Phoenix, Arizona

February 25, 2014

EX-24.A

Exhibit 24(a)

Power of Attorney

KNOW ALL MEN BY THESE PRESENTS, that the undersigned Principal Executive Officer, Principal Financial Officer, Principal Accounting Officer, officers and/or directors of UNS Energy Corporation, an Arizona corporation, which corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 2013, under the Securities Exchange Act of 1934, as amended, does each for himself and not for one another, hereby constitute and appoint Kevin P. Larson, Todd C. Hixon, and Frank P. Marino and each of them, his true and lawful attorneys, in his name, place and stead, to sign his name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said attorneys, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and each of the undersigned for himself hereby ratifies and confirms all that said attorneys, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 25th of February 2014.

/s/ Paul J. Bonavia Paul J. Bonavia Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer)	/s/ Daniel W.L. Fessler Daniel W.L. Fessler, Director
/s/ Kevin P. Larson Kevin P. Larson Senior Vice President and Chief Financial Officer (Principal Financial Officer)	/s/ Louise L. Francesconi Louise L. Francesconi, Director
/s/ Frank P. Marino Frank P. Marino Vice President and Controller (Principal Accounting Officer)	/s/ David G. Hutchens David G. Hutchens, Director
/s/ Lawrence J. Aldrich Lawrence J. Aldrich, Director	/s/ Ramiro G. Peru Ramiro G. Peru, Director
/s/ Barbara M. Baumann Barbara M. Baumann, Director	/s/ Gregory A. Pivirotto Gregory A. Pivirotto, Director
/s/ Larry W. Bickle Larry W. Bickle, Director	/s/ Joaquin Ruiz Joaquin Ruiz, Director
/s/ Robert A. Elliott Robert A. Elliott, Director

EX-24.B

Exhibit 24(b)

Power of Attorney

KNOW ALL MEN BY THESE PRESENTS, that the undersigned Principal Executive Officer, Principal Financial Officer, Principal Accounting Officer, officers and/or directors of Tucson Electric Power Company, an Arizona corporation, which corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 2013, under the Securities Exchange Act of 1934, as amended, does each for himself and not for one another, hereby constitute and appoint Kevin P. Larson, Todd C. Hixon, and Frank P. Marino and each of them, his true and lawful attorneys, in his name, place and stead, to sign his name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said attorneys, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and each of the undersigned for himself hereby ratifies and confirms all that said attorneys, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 25th day of February, 2014.

  /s/ Paul J. Bonavia

Paul J. Bonavia

Chief Executive Officer

and Chairman of the Board of

Directors

(Principal Executive Officer)

/s/ Kevin P. Larson

Kevin P. Larson

Senior Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

/s/ Frank P. Marino

Frank P. Marino

Vice President and Controller

(Principal Accounting Officer)

/s/ David G. Hutchens

David G. Hutchens

Director

EX-31.A

Exhibit 31(a)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Paul J. Bonavia, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2013, of UNS Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 25, 2014	/s/ Paul J. Bonavia
		Paul J. Bonavia
		Chairman and Chief Executive Officer
		(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Kevin P. Larson, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2013, of UNS Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 25, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

EX-31.C

Exhibit 31(c)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Paul J. Bonavia, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2013, of Tucson Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 25, 2014	/s/ Paul J. Bonavia
		Paul J. Bonavia
		Chairman and Chief Executive Officer
		(Principal Executive Officer)

EX-31.D

Exhibit 31(d)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Kevin P. Larson, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2013, of Tucson Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 25, 2014	/s/ Kevin P. Larson
		Kevin P. Larson
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32.A

Exhibit 32(a)

UNS ENERGY CORPORATION

_________________________________________________________

STATEMENTS OF CORPORATE OFFICERS

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

_________________________________________________________

Each of the undersigned, Paul J. Bonavia, Chairman of the Board and Chief Executive Officer of UNS Energy Corporation (the “Company”), and Kevin P. Larson, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 25, 2014

/s/ Paul J. Bonavia

Paul J. Bonavia

Chairman of the Board and

Chief Executive Officer

(Principal Executive Officer)

UNS Energy Corporation

/s/ Kevin P. Larson

Kevin P. Larson

Senior Vice President,

Chief Financial Officer and Treasurer

(Principal Financial Officer)

UNS Energy Corporation

EX-32.B

Exhibit 32(b)

TUCSON ELECTRIC POWER COMPANY

 _________________________________________________________

STATEMENTS OF CORPORATE OFFICERS

(Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

 _________________________________________________________

Each of the undersigned, Paul J. Bonavia, Chairman of the Board and Chief Executive Officer of Tucson Electric Power Company (the “Company”), and Kevin P. Larson, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 25, 2014

/s/ Paul J. Bonavia

Paul J. Bonavia

Chairman of the Board and

Chief Executive Officer

(Principal Executive Officer)

Tucson Electric Power Company

/s/ Kevin P. Larson

Kevin P. Larson

Senior Vice President and

Chief Financial Officer

(Principal Financial Officer)

Tucson Electric Power Company

XML

SHARE-BASED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule of Share-based Compensation, Stock Options, Activity

See summary of stock option activity in the table below:

	2013				2012				2011
Stock Options	Shares (000s)		Weighted Average Exercise Price		Shares (000s)		Weighted Average Exercise Price		Shares (000s)		Weighted Average Exercise Price
Outstanding, Beginning of Year	409		$	29.09	581		$	29.11	921		$	27.96
Exercised	(127	)	30.12		(132	)	26.54		(319	)	25.60
Forfeited/Expired	—		—		(40	)	37.88		(21	)	31.92
Outstanding, End of Year	282		28.63		409		29.09		581		29.11
Exercisable, End of Year	282		$	28.63	409		$	29.09	508		$	29.53
Aggregate Intrinsic Value of Options Exercised ($000s)			$	2,897			$	1,878			$	3,690

See summary of stock options in the tables below:

	December 31, 2013
Aggregate Intrinsic Value for Options Outstanding ($000s)	$	8,795
Aggregate Intrinsic Value for Options Exercisable ($000s)	$	8,795
Weighted Average Remaining Contractual Term of Outstanding Options	4.1 years
Weighted Average Remaining Contractual Term of Exercisable Options	4.1 years

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number  of Shares (000s)	Weighted Average Remaining Contractual Term	Weighted Average Exercise Price		Number  of Shares (000s)	Weighted Average Exercise Price
$26.11—$37.88	282	4.1 years	$	28.63	282	$	28.63

Schedule of Share-based Compensation, Restricted Stock Units Award Activity

See summary of restricted stock units awarded in the table below:

	Non-Employee Directors			Management Employees
Award Year	Restricted Stock Units	Grant Date Fair Value		Restricted Stock Units	Grant Date Fair Value
2013	8,870	$	48.99	21,560	$	46.23
2012	15,303	35.94		—	—
2011	14,655	37.53		—	—

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

See summary of performance shares awarded in the table below:

		Grant Date Fair Value
Award Year	Performance Shares	TSR-Based Award		CNI-Based Award
2013	43,120	$	45.54	$	46.23
2012	80,140	32.71		36.40
2011	80,440	33.73		36.58

Schedule of Nonvested Share Activity

See summary of restricted stock units and performance shares current year activity in the table below:

	Restricted Stock Units				Performance Shares
	Shares (000s)		Weighted Average Grant  Date Fair Value		Shares (000s)		Weighted Average Grant  Date Fair Value
Non-vested, Beginning of Year	15		$	35.94	145		$	34.83
Granted	31		47.04		52		44.94
Vested	(16	)	36.27		(52	)	35.35
Forfeited	(2	)	46.23		(32	)	37.57
Non-vested, End of Year	28		47.12		113		38.45

Schedule of Fair Value of Vested Restricted Stock Units and Performance Shares

The total fair value of restricted stock units and performance shares vested were as follows:

	Restricted Stock Units						Performance Shares
	2013		2012		2011		2013		2012		2011
	Thousands of Dollars
Total Fair Value of Shares Vested	$	574	$	550	$	495	$	2,387	$	2,377	$	1,069

XML

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Dec. 31, 2013 GWh	Dec. 31, 2012 GWh
Power Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	1,583	2,228
Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	33,371,000,000	17,851,000,000
TUCSON ELECTRIC POWER COMPANY | Power Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	779	820
TUCSON ELECTRIC POWER COMPANY | Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes	9,615,000,000	7,958,000,000

XML

BUSINESS SEGMENTS (Reporting) (Details)	12 Months Ended
	Dec. 31, 2013 Segment
Segment Reporting [Abstract]
Number of Reportable Segments	3

XML

PENDING MERGER WITH FORTIS INC. (Details) (Fortis Inc, USD $)	Dec. 11, 2013
Fortis Inc
Business Acquisition [Line Items]
Share price	$ 60.25

XML

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Commitments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	$ 234
2015	163
2016	141
2017	135
2018	108
Thereafter	956
Total	1,737
Fuel [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	103
2015	83
2016	80
2017	75
2018	49
Thereafter	345
Total	735
Purchased Power [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	75
2015	17
2016	0
2017	0
2018	0
Thereafter	0
Total	92
Transmission Facilities [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	7
2015	13
2016	12
2017	12
2018	11
Thereafter	27
Total	82
Renewable Energy Power Purchase Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	36
2015	37
2016	37
2017	37
2018	37
Thereafter	485
Total	669
RES Performance Based Incentives Minimum Commitment [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	9
2015	9
2016	9
2017	9
2018	9
Thereafter	85
Total	130
Operating Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	4
2015	4
2016	3
2017	2
2018	2
Thereafter	14
Total	29
TUCSON ELECTRIC POWER COMPANY
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	148
2015	116
2016	111
2017	109
2018	83
Thereafter	813
Total	1,380
TUCSON ELECTRIC POWER COMPANY | Fuel [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	77
2015	63
2016	64
2017	62
2018	36
Thereafter	285
Total	587
TUCSON ELECTRIC POWER COMPANY | Purchased Power [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	27
2015	5
2016	0
2017	0
2018	0
Thereafter	0
Total	32
TUCSON ELECTRIC POWER COMPANY | Transmission Facilities [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	3
2015	6
2016	6
2017	6
2018	6
Thereafter	21
Total	48
TUCSON ELECTRIC POWER COMPANY | Renewable Energy Power Purchase Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	30
2015	31
2016	31
2017	31
2018	31
Thereafter	410
Total	564
TUCSON ELECTRIC POWER COMPANY | RES Performance Based Incentives Minimum Commitment [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	8
2015	8
2016	8
2017	8
2018	8
Thereafter	83
Total	123
TUCSON ELECTRIC POWER COMPANY | Operating Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2014	3
2015	3
2016	2
2017	2
2018	2
Thereafter	14
Total	$ 26

XML

BUSINESS SEGMENTS (Reconciliation of Income Statement Items from Segments to Consolidation) (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended										12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	$ 350,161		$ 437,041	$ 365,217	$ 332,141	$ 348,273		$ 434,108	$ 363,998	$ 315,387	$ 1,484,560		$ 1,461,766		$ 1,478,702
Operating Revenues-Intersegment											0	[1]	0	[1]	0	[1]
Depreciation and Amortization											177,172		177,087		164,815
Interest Income											534		1,106		4,568
Interest Expense											93,375		105,352		112,358
Income Tax Expense											58,427		55,727		66,951
Net Income	13,525		67,990	34,618	11,345	7,506		50,664	26,273	6,476	127,478		90,919		109,975
Capital Expenditures											(325,886)		(307,277)		(374,122)
Assets	4,273,069					4,140,429					4,273,069		4,140,429
Reconciling Adjustments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues											(2,000)		(1,000)		1,000
Operating Revenues-Intersegment											(39,000)	[1]	(40,000)	[1]	(42,000)	[1]
Depreciation and Amortization											0		0		(1,000)
Interest Income											0		0		0
Interest Expense											0		0		0
Income Tax Expense											0		0		(2,000)
Net Income											0		0		(3,000)
Capital Expenditures											0		0		121,000
Assets	(1,192,000)					(1,122,000)					(1,192,000)		(1,122,000)
TUCSON ELECTRIC POWER COMPANY | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues											1,180,000		1,145,000		1,141,000
Operating Revenues-Intersegment											17,000	[1]	17,000	[1]	15,000	[1]
Depreciation and Amortization											149,000		150,000		140,000
Interest Income											0		0		4,000
Interest Expense											79,000		88,000		89,000
Income Tax Expense											48,000		39,000		52,000
Net Income											101,000		65,000		85,000
Capital Expenditures											(253,000)		(253,000)		(352,000)
Assets	3,556,000					3,461,000					3,556,000		3,461,000
UNS Electric | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues											174,000		189,000		188,000
Operating Revenues-Intersegment											2,000	[1]	1,000	[1]	2,000	[1]
Depreciation and Amortization											19,000		18,000		17,000
Interest Income											1,000		0		0
Interest Expense											7,000		8,000		7,000
Income Tax Expense											7,000		11,000		11,000
Net Income											12,000		17,000		18,000
Capital Expenditures											(56,000)		(38,000)		(96,000)
Assets	404,000					370,000					404,000		370,000
UNS Gas | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues											131,000		129,000		149,000
Operating Revenues-Intersegment											3,000	[1]	4,000	[1]	2,000	[1]
Depreciation and Amortization											9,000		9,000		8,000
Interest Income											0		0		0
Interest Expense											6,000		6,000		7,000
Income Tax Expense											7,000		6,000		7,000
Net Income											11,000		9,000		10,000
Capital Expenditures											(17,000)		(16,000)		(13,000)
Assets	311,000					310,000					311,000		310,000
Other | Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues											2,000	[2]	0	[2]	0	[2]
Operating Revenues-Intersegment											17,000	[1],[2]	18,000	[1],[2]	23,000	[1],[2]
Depreciation and Amortization											0	[2]	0	[2]	1,000	[2]
Interest Income											0	[2]	1,000	[2]	1,000	[2]
Interest Expense											1,000	[2]	3,000	[2]	9,000	[2]
Income Tax Expense											(4,000)	[2]	0	[2]	(1,000)	[2]
Net Income											3,000	[2]	0	[2]	0	[2]
Capital Expenditures											0	[2]	0	[2]	(34,000)	[2]
Assets	$ 1,194,000	[2]				$ 1,121,000	[2]				$ 1,194,000	[2]	$ 1,121,000	[2]

[1] Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

[2] Other includes the UNS Energy and UES holding companies, Millennium, and UED.

XML

INCOME TAXES (Balance Sheets Display Net Deferred Income Tax Liability) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Deferred Income Taxes - Current Assets	$ 60	$ 34
Deferred Tax Liabilities, Gross, Noncurrent	(482)	(365)
Deferred Tax Liabilities, Net	(422)	(331)
TUCSON ELECTRIC POWER COMPANY
Income Taxes [Line Items]
Deferred Income Taxes - Current Assets	64	37
Deferred Tax Liabilities, Gross, Noncurrent	(421)	(319)
Deferred Tax Liabilities, Net	$ (357)	$ (282)

XML

UNS ENERGY EARNINGS PER SHARE - Effects of Dilutive Common Stock on Weighted-Average Number of Shares (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Numerator:
Net Income	$ 13,525	$ 67,990	$ 34,618	$ 11,345	$ 7,506	$ 50,664	$ 26,273	$ 6,476	$ 127,478		$ 90,919		$ 109,975
Interest on Convertible Debt, Net of Tax									0	[1]	1,100	[1]	4,390	[1]
Adjusted Net Income Available for Diluted Common Stock Outstanding									$ 127,478		$ 92,019		$ 114,365
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued									41,446		40,212		36,780
Fully Vested Deferred Stock Units									172		150		129
Participating Securities									0		0		53
Total Weighted Average Shares of Common Stock Outstanding and Participating Securities - Basic									41,618		40,362		36,962
Effect of Dilutive Securities:
Convertible Senior Notes									0	[1]	1,062	[1]	4,281	[1]
Options and Stock Issuable Under Share-Based Compensation Plans									357		331		366
Total Shares - Diluted									41,975		41,755		41,609

[1] In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY
Long-term Contract for Purchase of Electric Power [Line Items]
Average AFUDC Rate on Regulated Construction Expenditures	7.38%	7.22%	6.72%
UNS Electric
Long-term Contract for Purchase of Electric Power [Line Items]
Average AFUDC Rate on Regulated Construction Expenditures	8.07%	7.89%	8.18%
UNS Gas
Long-term Contract for Purchase of Electric Power [Line Items]
Average AFUDC Rate on Regulated Construction Expenditures	7.89%	7.95%	8.32%

XML

BUSINESS SEGMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Reconciling Adjustments of Income Statement Items in Consolidation

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

	Reportable Segments
	TEP			UNS Electric			UNS Gas			Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
2013
Income Statement
Operating Revenues-External	$	1,180		$	174		$	131		$	2		$	(2	)	$	1,485
Operating Revenues-Intersegment (1)	17			2			3			17			(39		)	—
Depreciation and Amortization	149			19			9			—			—			177
Interest Income	—			1			—			—			—			1
Interest Expense	79			7			6			1			—			93
Income Tax Expense	48			7			7			(4		)	—			58
Net Income	101			12			11			3			—			127
Cash Flow Statement
Capital Expenditures	(253		)	(56		)	(17		)	—			—			(326		)
Balance Sheet
Total Assets	3,556			404			311			1,194			(1,192		)	4,273

	Reportable Segments
	TEP			UNS Electric			UNS Gas			Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
2012
Income Statement
Operating Revenues-External	$	1,145		$	189		$	129		$	—		$	(1	)	$	1,462
Operating Revenues-Intersegment (1)	17			1			4			18			(40		)	—
Depreciation and Amortization	150			18			9			—			—			177
Interest Income	—			—			—			1			—			1
Interest Expense	88			8			6			3			—			105
Income Tax Expense	39			11			6			—			—			56
Net Income	65			17			9			—			—			91
Cash Flow Statement
Capital Expenditures	(253		)	(38		)	(16		)	—			—			(307		)
Balance Sheet
Total Assets	3,461			370			310			1,121			(1,122		)	4,140
2011
Income Statement
Operating Revenues-External	$	1,141		$	188		$	149		$	—		$	1		$	1,479
Operating Revenue-Intersegment (1)	15			2			2			23			(42		)	—
Depreciation and Amortization	140			17			8			1			(1		)	165
Interest Income	4			—			—			1			—			5
Interest Expense	89			7			7			9			—			112
Income Tax Expense	52			11			7			(1		)	(2		)	67
Net Income	85			18			10			—			(3		)	110
Cash Flow Statement
Capital Expenditures	(352		)	(96		)	(13		)	(34		)	121			(374		)

⁽¹⁾  Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

⁽²⁾  Other includes the UNS Energy and UES holding companies, Millennium, and UED.

XML

INCOME TAXES (Summary of Tax Carryforwards) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Income Tax Contingency [Line Items]
Capital Loss	$ 7
Investment Tax Credits	6
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Net Operating Loss Carryforward	266
State Tax Jurisdiction [Member]
Income Tax Contingency [Line Items]
Net Operating Loss Carryforward	30
Tax Credits	5
AMT Credit [Member]
Income Tax Contingency [Line Items]
Tax Credits	43
TUCSON ELECTRIC POWER COMPANY
Income Tax Contingency [Line Items]
Capital Loss	0
Investment Tax Credits	6
TUCSON ELECTRIC POWER COMPANY | Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Net Operating Loss Carryforward	286
TUCSON ELECTRIC POWER COMPANY | State Tax Jurisdiction [Member]
Income Tax Contingency [Line Items]
Net Operating Loss Carryforward	99
Tax Credits	6
TUCSON ELECTRIC POWER COMPANY | AMT Credit [Member]
Income Tax Contingency [Line Items]
Tax Credits	$ 24

XML

QUARTERLY FINANCIAL DATA - Summary of Quarterly Financial Data (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information [Line Items]
Operating Revenue	$ 350,161	$ 437,041	$ 365,217	$ 332,141	$ 348,273	$ 434,108	$ 363,998	$ 315,387	$ 1,484,560	$ 1,461,766	$ 1,478,702
Operating Income	41,033	129,765	60,803	39,895	42,918	106,409	68,065	34,403	271,496	251,795	281,707
Net Income (Loss)	13,525	67,990	34,618	11,345	7,506	50,664	26,273	6,476	127,478	90,919	109,975
Basic EPS	$ 0.32	$ 1.63	$ 0.83	$ 0.27	$ 0.18	$ 1.22	$ 0.65	$ 0.17	$ 3.06	$ 2.25	$ 2.98
Diluted EPS	$ 0.32	$ 1.62	$ 0.83	$ 0.27	$ 0.18	$ 1.21	$ 0.64	$ 0.17	$ 3.04	$ 2.20	$ 2.75
TUCSON ELECTRIC POWER COMPANY
Quarterly Financial Information [Line Items]
Operating Revenue	273,437	371,239	304,263	247,751	271,353	366,910	299,419	223,978	1,196,690	1,161,660	1,156,386
Operating Income	31,014	123,177	53,433	22,747	30,299	94,079	58,211	17,898	230,371	200,487	229,408
Net Income (Loss)	$ 4,910	$ 64,167	$ 30,787	$ 1,478	$ 452	$ 44,569	$ 21,910	$ (1,461)	$ 101,342	$ 65,470	$ 85,334

XML

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Environmental Matters) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Navajo [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	$ 1,000,000
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1,000,000
Estimated Capital Expenditure for Selective Catalytic Reduction	42,000,000	[1]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	0	[1]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	1,000,000	[1]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	0	[1]
Better Than BART Agreement Year by which to Shut Down One Unit	2020
Better than BART Agreement, Year by which SCR Technology to be Installed	2030
Better than BART Agreement, Year by which Coal Fired Operation will Cease	2044
Estimated Capital Expenditure Related to Installation of Baghouses	43,000,000
Estimated Future Annual Operating Costs For Mercury Emmission Control Equipment and Baghouses	1,000,000
San Juan Unit Two [Member]
Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	1,000,000
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	1,000,000
Estimated Capital Expenditure for Selective Catalytic Reduction	35,000,000	[2]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	0	[2]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	2,000,000	[2]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	0	[2]
Jointly Owned Utility Plant, Proportionate Ownership Share	7.00%
Springerville [Member]
Commitments And Contingencies [Line Items]
Estimated Future Capital Cost For Mercury Emission Control Equipment	5,000,000
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment	3,000,000
San Juan [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	35,000,000	[3]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	6,000,000	[3]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	1,000,000	[3]
Jointly Owned Utility Plant, Proportionate Ownership Share	20.00%
Book Value of Company Share Of Generating Units	113,000,000
San Juan [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	180,000,000
San Juan [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	200,000,000
Sundt [Member]
Commitments And Contingencies [Line Items]
Estimated Capital Expenditure for Selective Catalytic Reduction	0	[2]
Estimated Capital Expenditure for Selective Non Catalytic Reduction	12,000,000	[2]
Estimated Future Change in Operating Cost for Selective Catalytic Reduction	0	[2]
Sundt [Member] | Minimum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	5,000,000	[2]
Sundt [Member] | Maximum [Member]
Commitments And Contingencies [Line Items]
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction	6,000,000	[2]
TUCSON ELECTRIC POWER COMPANY
Commitments And Contingencies [Line Items]
Environmental compliance costs capitalized in construction costs	5,000,000		2,000,000	8,000,000
Environmental Remediation Expense	8,000,000		15,000,000	12,000,000
Expected environmental expenses	5,000,000
TUCSON ELECTRIC POWER COMPANY | Sundt [Member]
Commitments And Contingencies [Line Items]
Book Value of Company Share Of Generating Units	27,000,000
TUCSON ELECTRIC POWER COMPANY | One Year In Future [Member]
Commitments And Contingencies [Line Items]
Expected environmental compliance costs to be capitalized in construction costs	12,000,000
TUCSON ELECTRIC POWER COMPANY | Two Years In Future [Member] [Member]
Commitments And Contingencies [Line Items]
Expected environmental compliance costs to be capitalized in construction costs	$ 36,000,000

[1] The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.

[2] On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.

[3] The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

XML

EMPLOYEE BENEFIT PLANS (Changes in Plan Assets and Benefit Obligations Recognized) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Amortization of Prior Service (Cost) Credit	$ (1,488,000)
Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Prior Service Cost (Credit)	(1,000,000)	0	(1,000,000)
Current Year Actuarial (Gain) Loss	(7,000,000)	(13,000,000)
Amortization of Actuarial (Gain) Loss	(1,000,000)	0	0
Other Retiree Benefits [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Prior Service Cost (Credit)	0	0	(2,000,000)
Current Year Actuarial (Gain) Loss	(6,000,000)	2,000,000	0
Amortization of Actuarial (Gain) Loss	1,000,000	0	0
Amortization of Prior Service (Cost) Credit	1,000,000	0	1,000,000
Total Recognized (Gain) Loss	(6,000,000)	2,000,000	(1,000,000)
Amortization of estimated net loss in 2014	1,000,000
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Prior Service Cost (Credit)	0	0	0
Current Year Actuarial (Gain) Loss	(77,000,000)	(133,000,000)
Amortization of Actuarial (Gain) Loss	(9,000,000)	(7,000,000)	(6,000,000)
Pension Benefits [Member] | Regulatory Asset [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	(46,000,000)	30,000,000	25,000,000
Amortization of Actuarial (Gain) Loss	8,000,000	7,000,000	5,000,000
Total Recognized (Gain) Loss	(54,000,000)	23,000,000	20,000,000
Estimated gain (loss) that will be amortized in the net periodic benefit cost in 2014	4,000,000
Amortization of estimated net loss in 2014	1,000,000
Pension Benefits [Member] | Accumulated Other Comprehensive Loss [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	(1,000,000)	1,000,000	(2,000,000)
Amortization of Actuarial (Gain) Loss	0	0	0
Total Recognized (Gain) Loss	(1,000,000)	1,000,000	(2,000,000)
Amortization of estimated net loss in 2014	$ 1,000,000

XML

UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]
Capitalized Computer Software, Gross	$ 40	$ 36
Amortization of computer software costs	14	13	10
TUCSON ELECTRIC POWER COMPANY
Public Utility, Property, Plant and Equipment [Line Items]
Capitalized Computer Software, Gross	39	35
Amortization of computer software costs	$ 14	$ 13	$ 10

XML

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Schedule of Fair Value Measurements of Financial Assets and Liabilities) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Assets
Cash Equivalent	$ 14	[1]	$ 20	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	7	[3]	7	[3]
Total Assets	45		53
Liabilities
Liabilities	(15)		(27)
Net Total Assets (Liability)	30		26
Energy Contracts [Member]
Liabilities
Derivative Liability	(7)	[3]	(15)	[3]
Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Interest Rate Swap [Member]
Liabilities
Derivative Liability	(7)	[4]	(10)	[4]
TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	1	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	2	[3]	3	[3]
Total Assets	26		30
Liabilities
Liabilities	(10)		(15)
Net Total Assets (Liability)	16		15
TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(2)	[3]	(3)	[3]
TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(7)	[4]	(10)	[4]
Level 1 [Member]
Assets
Cash Equivalent	14	[1]	20	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	0	[3]
Total Assets	16		27
Liabilities
Liabilities	0		0
Net Total Assets (Liability)	16		27
Level 1 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	1	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	0	[3]	0	[3]
Total Assets	2		8
Liabilities
Liabilities	0		0
Net Total Assets (Liability)	2		8
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 1 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 2 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	3	[3]	2	[3]
Total Assets	25		21
Liabilities
Liabilities	(9)		(17)
Net Total Assets (Liability)	16		4
Level 2 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	(2)	[3]	(7)	[3]
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(7)	[4]	(10)	[4]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	1	[3]	1	[3]
Total Assets	23		20
Liabilities
Liabilities	(7)		(13)
Net Total Assets (Liability)	16		7
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	0	[3]	(3)	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3]	0	[3]
Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(7)	[4]	(10)	[4]
Level 3 [Member]
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	4	[3]	5	[3]
Total Assets	4		5
Liabilities
Derivative Liability	6
Liabilities	(6)		(10)
Net Total Assets (Liability)	(2)		(5)
Level 3 [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	(5)	[3]	(8)	[3]
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Level 3 [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	0	[1]
Restricted Cash	0	[1]	0	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2]	0	[2]
Energy Contracts	1	[3]	2	[3]
Total Assets	1		2
Liabilities
Liabilities	(3)		(2)
Net Total Assets (Liability)	(2)		0
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(2)	[3]	0	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4]	0	[4]
Netting [Member]
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	(5)	[3],[5]	(5)	[3],[5]
Total Assets	(5)	[5]	(5)	[5]
Liabilities
Liabilities	5	[5]	5	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	5	[3],[5]	5	[3],[5]
Netting [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4],[5]	0	[4],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1],[5]	0	[1],[5]
Restricted Cash	0	[1],[5]	0	[1],[5]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	0	[2],[5]	0	[2],[5]
Energy Contracts	(1)	[3],[5]	(1)	[3],[5]
Total Assets	(1)	[5]	(1)	[5]
Liabilities
Liabilities	1	[5]	1	[5]
Net Total Assets (Liability)	0	[5]	0	[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	1	[3],[5]	1	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	0	[3],[5]	0	[3],[5]
Netting [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	0	[4],[5]	0	[4],[5]
Net Fair Value [Member]
Assets
Cash Equivalent	14	[1]	20	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	2	[3]	2	[3]
Total Assets	40		48
Liabilities
Liabilities	(10)		(22)
Net Total Assets (Liability)	30		26
Net Fair Value [Member] | Energy Contracts [Member]
Liabilities
Derivative Liability	(2)	[3]	(10)	[3]
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Net Fair Value [Member] | Interest Rate Swap [Member]
Liabilities
Derivative Liability	(7)	[4]	(10)	[4]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY
Assets
Cash Equivalent	0	[1]	1	[1]
Restricted Cash	2	[1]	7	[1]
Rabbi Trust Investments to Support the Deferred Compensation and SERP	22	[2]	19	[2]
Energy Contracts	1	[3]	2	[3]
Total Assets	25		29
Liabilities
Liabilities	(9)		(14)
Net Total Assets (Liability)	16		15
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Energy Contracts Cash Flow Hedge [Member]
Liabilities
Derivative Liability	(1)	[3]	(2)	[3]
Net Fair Value [Member] | TUCSON ELECTRIC POWER COMPANY | Interest Rate Swap [Member]
Liabilities
Derivative Liability	$ (7)	[4]	$ (10)	[4]

[1] Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

[2] Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

[3] Energy Contracts include gas swap agreements (Level 2), power options (Level 2 or Level 3), gas options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.

[4] Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

[5] All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

XML

INCOME TAXES (Income Tax Expense Included in Income Statements) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current Tax Expense (Benefit)
Federal	$ (11,000,000)	$ (2,000,000)	$ (7,000,000)
State	(2,000,000)	(2,000,000)	(2,000,000)
Total	(13,000,000)	(4,000,000)	(9,000,000)
Deferred Tax Expense (Benefit)
Federal	61,000,000	51,000,000	64,000,000
Investment Tax Credit	(1,000,000)	0	(1,000,000)
State	11,000,000	9,000,000	13,000,000
Total	71,000,000	60,000,000	76,000,000
Income Tax Expense (Benefit)	58,427,000	55,727,000	66,951,000
TUCSON ELECTRIC POWER COMPANY
Current Tax Expense (Benefit)
Federal	(8,000,000)	(4,000,000)	(5,000,000)
State	(2,000,000)	(2,000,000)	(2,000,000)
Total	(10,000,000)	(6,000,000)	(7,000,000)
Deferred Tax Expense (Benefit)
Federal	47,000,000	38,000,000	50,000,000
Investment Tax Credit	(1,000,000)	0	(1,000,000)
State	12,000,000	7,000,000	10,000,000
Total	58,000,000	45,000,000	59,000,000
Income Tax Expense (Benefit)	$ 47,986,000	$ 39,109,000	$ 52,000,000

XML

EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	$ 77	$ 133
Prior Service Cost (Benefit)	0	1
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	7	13
Prior Service Cost (Benefit)	$ (3)	$ (3)

XML

INCOME TAXES (Additional Information) (Detail) (USD $)	1 Months Ended	12 Months Ended
	Feb. 28, 2013	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Unregulated investment loss		$ (7,000,000)	$ (7,000,000)
Deferred Tax Asset Valuation Allowance		7,000,000	7,000,000
Proceeds and Excess Tax Benefit from Share-based Compensation		4,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate			1,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		0	1,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		0
Unrecognized Tax Benefits, Interest on Income Taxes Expense		1,000,000	0
Reductions Based on Settlements with Tax Authorities	(28,000,000)	(28,000,000)	(4,000,000)
Change In Deferred Tax Liabilities And Deferred Tax Assets Related To Tangible Property		4,000,000
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards		266,000,000
TUCSON ELECTRIC POWER COMPANY
Income Taxes [Line Items]
Deferred Tax Asset Valuation Allowance		2,000,000	0
Reductions Based on Settlements with Tax Authorities	(22,000,000)	(22,000,000)	(4,000,000)
TUCSON ELECTRIC POWER COMPANY | Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards		$ 286,000,000

XML

EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Detail) (Pension Benefits [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]
Accumulated Benefit Obligation at End of Year	$ 30	$ 334
Fair Value of Plan Assets at End of Year	$ 16	$ 289

XML

INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Gross Deferred Income Tax Assets
Capital Lease Obligations	$ 127	$ 141
Net Operating Loss Carryforwards	94	72
Customer Advances and Contributions in Aid of Construction	33	34
Alternative Minimum Tax Credit	43	43
Accrued Postretirement Benefits	23	23
Renewable Energy Credit Up-Front Incentive Payments	0	26
Emission Allowance Inventory	10	10
Deferred Tax Assets Unregulated Investment Losses	7	9
Other	50	44
Gross Deferred Income Tax Assets	387	402
Deferred Tax Assets Valuation Allowance	(7)	(7)
Gross Deferred Income Tax Liabilities
Plant - Net	(708)	(648)
Capital Lease Assets - Net	(47)	(34)
Pensions	(21)	(23)
PPFAC	(5)	(6)
Other	(21)	(15)
Deferred Tax Liabilities, Gross	(802)	(726)
Deferred Tax Liabilities, Net	(422)	(331)
TUCSON ELECTRIC POWER COMPANY
Gross Deferred Income Tax Assets
Capital Lease Obligations	127	141
Net Operating Loss Carryforwards	104	85
Customer Advances and Contributions in Aid of Construction	19	19
Alternative Minimum Tax Credit	24	24
Accrued Postretirement Benefits	23	23
Renewable Energy Credit Up-Front Incentive Payments	0	20
Emission Allowance Inventory	10	10
Deferred Tax Assets Unregulated Investment Losses	0	0
Other	44	43
Gross Deferred Income Tax Assets	351	365
Deferred Tax Assets Valuation Allowance	(2)	0
Gross Deferred Income Tax Liabilities
Plant - Net	(615)	(571)
Capital Lease Assets - Net	(47)	(34)
Pensions	(22)	(24)
PPFAC	(2)	(3)
Other	(20)	(15)
Deferred Tax Liabilities, Gross	(706)	(647)
Deferred Tax Liabilities, Net	$ (357)	$ (282)

XML

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Commitments Additional Information) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrecorded Unconditional Purchase Obligation [Line Items]
Operating Leases, Rent Expense		$ 3	$ 3	$ 3
TUCSON ELECTRIC POWER COMPANY
Unrecorded Unconditional Purchase Obligation [Line Items]
Duration of Power Purchase Agreement, In Years	20 years
Output Purchase Requirement From Renewable Energy Facility		100.00%
Operating Leases, Rent Expense		$ 2	$ 2	$ 2
UNS Electric
Unrecorded Unconditional Purchase Obligation [Line Items]
Duration of Power Purchase Agreement, In Years	20 years
Output Purchase Requirement From Renewable Energy Facility		100.00%

XML

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity.

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	14		$	14	$	—		$	—		$	—		$	14
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	7			—		3			4			(5		)	2
Total Assets	45			16		25			4			(5		)	40
Liabilities
Energy Contracts - Regulatory Recovery(3)	(7		)	—		(2		)	(5		)	5			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(15		)	—		(9		)	(6		)	5			(10		)
Net Total Assets (Liabilities)	$	30		$	16	$	16		$	(2	)	$	—		$	30

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery(3)	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	2			—		1			1			(1		)	1
Total Assets	26			2		23			1			(1		)	25
Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)	—		—			(2		)	1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(10		)	—		(7		)	(3		)	1			(9		)
Net Total Assets (Liabilities)	$	16		$	2	$	16		$	(2	)	$	—		$	16

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1		$	1	$	—		$	—		$	—		$	1
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	30			8		20			2			(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(3		)	—			1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(15		)	—		(13		)	(2		)	1			(14		)
Net Total Assets (Liabilities)	$	15		$	8	$	7		$	—		$	—		$	15

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

⁽³⁾  Energy Contracts include gas swap agreements (Level 2), power options (Level 2 or Level 3), gas options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.

(4) Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

DERIVATIVE INSTRUMENTS

We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.

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

Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.

We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. Beginning in the third quarter of 2013, the fair value of our power options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented.

We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.

Our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our contracts monthly.

Cash Flow Hedges

The interest rate swap agreements expire through January 2020. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 16. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $4 million.

Financial Impact of Energy Contracts

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:

	UNS Energy								TEP
	Years Ended December 31,
	2013			2012			2011		2013		2012			2011
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	(9	)	$	(21	)	$	2	$	—	$	(6	)	$	2

Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At December 31, 2013, UNS Energy and TEP have energy contracts that will settle through the fourth quarter of 2016.

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	December 31, 2013	December 31, 2012	December 31, 2013	December 31, 2012
Power Contracts GWh	1,583	2,228	779	820
Gas Contracts GBtu	33,371	17,851	9,615	7,958

Level 3 Fair Value Measurements

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:

		Fair Value at
		December 31, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	1	$	(4	)	Market price per MWh	$	26.54		-	$	51.75
Option Contracts(2)	Option model	3		(2		)	Market Price per MMbtu	$	3.87		-	$	4.32
							Gas Volatility	25.05		%	-	35.07		%
Level 3 Energy Contracts		$	4	$	(6	)

⁽¹⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

⁽²⁾  TEP comprises less than $1 million of the option contract assets.

Our exposure to risk resulting from changes in the unobservable inputs identified above is mitigated as we report the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statement.

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(1		)	(2		)
Settlements	4			—
Balances at December 31, 2013	$	(2	)	$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	(1	)

	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(5		)	1
Settlements	10			(1		)
Balances at December 31, 2012	$	(5	)	$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

CREDIT RISK

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.

We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Electric, or UNS Gas; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.

We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.

Material adverse changes could trigger credit risk-related contingent features. At December 31, 2013, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features was $21 million for UNS Energy and $5 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $21 million for UNS Energy and $5 million for TEP.

FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE

The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:

• The carrying amounts of our current assets, current liabilities, including current maturities of long-term debt, and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.

• For Investment in Lease Debt, we calculated the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporated the impact of counterparty credit risk using market credit default swap data. TEP's Investment in Lease Debt matured in January 2013.

• For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.

• For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:

		December 31, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		25		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,507		1,521		1,498		1,583
TEP	Level 2	1,223		1,214		1,223		1,271

XML

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended	1 Months Ended				12 Months Ended			1 Months Ended		12 Months Ended
	Jun. 30, 2013 UNS Gas	Dec. 31, 2013 UNS Gas	Oct. 31, 2013 UNS Gas Before November 1, 2013 [Member]	Oct. 31, 2013 UNS Gas From November 1, 2013 through April 30, 2014 [Member]	Oct. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 UNS Electric	Oct. 31, 2013 UNS Electric	Dec. 31, 2013 UNS Electric	Dec. 31, 2012 UNS Electric	Dec. 31, 2013 Minimum [Member] UNS Gas	Dec. 31, 2012 Minimum [Member] UNS Gas	Dec. 31, 2013 Maximum [Member] UNS Gas	Dec. 31, 2012 Maximum [Member] UNS Gas
Schedule of Regulatory Cost Recovery Mechanisms [Line Items]
Increase (Decrease) of PPFAC												0.83
Deferral balance										$ 10		$ 10
PPFAC balance over-collected										14		14
Factor automatically adjusts restricted from rising or falling in twelve month period		0.15
Gas Is Required To Request Approval Of Surcredit When Pga Bank Balance Exceeds		10
Purchased Gas Adjustor Credit			0.045	0.10
Customer refund liability, current		10
Purchased gas adjustor rate														0.4504	0.5202	0.5280	0.6501
Approved Investment Cost By ACC To Invest In Owned Solar Projects					40						7
Proposed Collections From Customers For Renewable Energy Programs					34						6
Amount receivable as return on investment							2.0	2.0	1.0			0.5	0.5
Approved energy efficiency budget	$ 2					$ 21				$ 5
Retail revenue cap on environmental compliance adjustor						0.25%
Cap on increase in lost fixed cost recovery rate						1.00%

XML

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule of Fair Value Measurements of Financial Assets and Liabilities

These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	14		$	14	$	—		$	—		$	—		$	14
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	7			—		3			4			(5		)	2
Total Assets	45			16		25			4			(5		)	40
Liabilities
Energy Contracts - Regulatory Recovery(3)	(7		)	—		(2		)	(5		)	5			(2		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(15		)	—		(9		)	(6		)	5			(10		)
Net Total Assets (Liabilities)	$	30		$	16	$	16		$	(2	)	$	—		$	30

	UNS Energy
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	20		$	20	$	—		$	—		$	—		$	20
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	7			—		2			5			(5		)	2
Total Assets	53			27		21			5			(5		)	48
Liabilities
Energy Contracts - Regulatory Recovery(3)	(15		)	—		(7		)	(8		)	5			(10		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(27		)	—		(17		)	(10		)	5			(22		)
Net Total Assets (Liabilities)	$	26		$	27	$	4		$	(5	)	$	—		$	26

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2013
	Millions of Dollars
Assets
Cash Equivalents(1)	$	—		$	—	$	—		$	—		$	—		$	—
Restricted Cash(1)	2			2		—			—			—			2
Rabbi Trust Investments(2)	22			—		22			—			—			22
Energy Contracts - Regulatory Recovery(3)	2			—		1			1			(1		)	1
Total Assets	26			2		23			1			(1		)	25
Liabilities
Energy Contracts - Regulatory Recovery(3)	(2		)	—		—			(2		)	1			(1		)
Energy Contracts - Cash Flow Hedge(3)	(1		)	—		—			(1		)	—			(1		)
Interest Rate Swaps(4)	(7		)	—		(7		)	—			—			(7		)
Total Liabilities	(10		)	—		(7		)	(3		)	1			(9		)
Net Total Assets (Liabilities)	$	16		$	2	$	16		$	(2	)	$	—		$	16

	TEP
	Total			Level 1		Level 2			Level 3			Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)			Net Amount
	December 31, 2012
	Millions of Dollars
Assets
Cash Equivalents(1)	$	1		$	1	$	—		$	—		$	—		$	1
Restricted Cash(1)	7			7		—			—			—			7
Rabbi Trust Investments(2)	19			—		19			—			—			19
Energy Contracts - Regulatory Recovery(3)	3			—		1			2			(1		)	2
Total Assets	30			8		20			2			(1		)	29
Liabilities
Energy Contracts - Regulatory Recovery(3)	(3		)	—		(3		)	—			1			(2		)
Energy Contracts - Cash Flow Hedge(3)	(2		)	—		—			(2		)	—			(2		)
Interest Rate Swaps(4)	(10		)	—		(10		)	—			—			(10		)
Total Liabilities	(15		)	—		(13		)	(2		)	1			(14		)
Net Total Assets (Liabilities)	$	15		$	8	$	7		$	—		$	—		$	15

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.

⁽²⁾  Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.

⁽³⁾  Energy Contracts include gas swap agreements (Level 2), power options (Level 2 or Level 3), gas options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.

(4) Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets.

⁽⁵⁾  All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.

Financial Impact of Energy Contracts

We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:

	UNS Energy								TEP
	Years Ended December 31,
	2013			2012			2011		2013		2012			2011
	Millions of Dollars
Increase (Decrease) to Regulatory Assets/Liabilities	$	(9	)	$	(21	)	$	2	$	—	$	(6	)	$	2

Derivative Volumes

The volumes associated with our energy contracts were as follows:

	UNS Energy		TEP
	December 31, 2013	December 31, 2012	December 31, 2013	December 31, 2012
Power Contracts GWh	1,583	2,228	779	820
Gas Contracts GBtu	33,371	17,851	9,615	7,958

Quantitative Information Regarding Unobservable Inputs

The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements:

		Fair Value at
		December 31, 2013						Range of
	Valuation Approach	Assets		Liabilities			Unobservable Inputs	Unobservable Input
		Millions of Dollars
Forward Contracts(1)	Market approach	$	1	$	(4	)	Market price per MWh	$	26.54		-	$	51.75
Option Contracts(2)	Option model	3		(2		)	Market Price per MMbtu	$	3.87		-	$	4.32
							Gas Volatility	25.05		%	-	35.07		%
Level 3 Energy Contracts		$	4	$	(6	)

⁽¹⁾  TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

⁽²⁾  TEP comprises less than $1 million of the option contract assets.

Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities

.

The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:

	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2012	$	(5	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(1		)	(2		)
Settlements	4			—
Balances at December 31, 2013	$	(2	)	$	(2	)
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	(1	)

	UNS Energy			TEP
	Millions of Dollars
Balances at December 31, 2011	$	(10	)	$	—
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities – Derivative Instruments	(5		)	1
Settlements	10			(1		)
Balances at December 31, 2012	$	(5	)	$	—
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period	$	(1	)	$	—

Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments

The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:

		December 31, 2013				December 31, 2012
	Fair Value Hierarchy	Carrying Value		Fair Value		Carrying Value		Fair Value
		Millions of Dollars
Assets:
TEP Investment in Lease Debt	Level 2	$	—	$	—	$	9	$	9
TEP Investment in Lease Equity	Level 3	36		25		36		23
Liabilities:
Long-Term Debt
UNS Energy	Level 2	1,507		1,521		1,498		1,583
TEP	Level 2	1,223		1,214		1,223		1,271

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INCOME TAXES (Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Detail) (USD $)	1 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]
Statutory tax rate		35.00%
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 65,000,000	$ 51,000,000	$ 62,000,000
State Income Tax Expense, Net of Federal Deduction		8,000,000	7,000,000	8,000,000
Federal/State Tax Credits		(2,000,000)	(1,000,000)	(3,000,000)
Allowance for Funds Used During Construction Income Tax Difference		(2,000,000)	(1,000,000)	(1,000,000)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		0	0	0
Investment Tax Credit Basis Difference	(11,039,000)		0	0
Other		0	0	1,000,000
Income Tax Expense (Benefit)		58,427,000	55,727,000	66,951,000
TUCSON ELECTRIC POWER COMPANY
Income Taxes [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		52,000,000	37,000,000	48,000,000
State Income Tax Expense, Net of Federal Deduction		7,000,000	5,000,000	6,000,000
Federal/State Tax Credits		(2,000,000)	(1,000,000)	(2,000,000)
Allowance for Funds Used During Construction Income Tax Difference		(1,000,000)	(1,000,000)	(1,000,000)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		2,000,000	0	0
Investment Tax Credit Basis Difference		(10,751,000)	0	0
Other		1,000,000	(1,000,000)	1,000,000
Income Tax Expense (Benefit)		$ 47,986,000	$ 39,109,000	$ 52,000,000

XML

EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Detail)	12 Months Ended
	Dec. 31, 2013
TUCSON ELECTRIC POWER COMPANY
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
TUCSON ELECTRIC POWER COMPANY | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	41.00%
TUCSON ELECTRIC POWER COMPANY | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	24.00%
TUCSON ELECTRIC POWER COMPANY | Non-United States Developed
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	15.00%
TUCSON ELECTRIC POWER COMPANY | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	8.00%
TUCSON ELECTRIC POWER COMPANY | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
TUCSON ELECTRIC POWER COMPANY | Non-United States Emerging
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
TUCSON ELECTRIC POWER COMPANY | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	2.00%
TUCSON ELECTRIC POWER COMPANY | Cash/Treasury Bills
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
UNS Gas and UNS Electric [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
UNS Gas and UNS Electric [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	42.00%
UNS Gas and UNS Electric [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	24.00%
UNS Gas and UNS Electric [Member] | Non-United States Developed
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	14.00%
UNS Gas and UNS Electric [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	10.00%
UNS Gas and UNS Electric [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
UNS Gas and UNS Electric [Member] | Non-United States Emerging
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
UNS Gas and UNS Electric [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
UNS Gas and UNS Electric [Member] | Cash/Treasury Bills
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
VEBA Trust [Member]
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	100.00%
VEBA Trust [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	38.00%
VEBA Trust [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	39.00%
VEBA Trust [Member] | Non-United States Developed
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	7.00%
VEBA Trust [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
VEBA Trust [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	5.00%
VEBA Trust [Member] | Non-United States Emerging
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	9.00%
VEBA Trust [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	0.00%
VEBA Trust [Member] | Cash/Treasury Bills
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets	2.00%

XML

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:

	UNS Energy									TEP
	Years Ended December 31,
	2013			2012			2011			2013			2012			2011
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	65		$	51		$	62		$	52		$	37		$	48
State Income Tax Expense, Net of Federal Deduction	8			7			8			7			5			6
Federal/State Tax Credits	(2		)	(1		)	(3		)	(2		)	(1		)	(2		)
Allowance for Equity Funds Used During Construction	(2		)	(1		)	(1		)	(1		)	(1		)	(1		)
Deferred Tax Asset Valuation Allowance	—			—			—			2			—			—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—			—			(11		)	—			—
Other	—			—			1			1			(1		)	1
Total Federal and State Income Tax Expense	$	58		$	56		$	67		$	48		$	39		$	52

Schedule Of Income Tax Reconciliation Table

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

	UNS Energy									TEP
	Years Ended December 31,
	2013			2012			2011			2013			2012			2011
	Millions of Dollars
Current Tax Expense (Benefit):
Federal	$	(11	)	$	(2	)	$	(7	)	$	(8	)	$	(4	)	$	(5	)
State	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total Current Tax Expense (Benefit)	(13		)	(4		)	(9		)	(10		)	(6		)	(7		)
Deferred Tax Expense (Benefit):
Federal	61			51			64			47			38			50
Federal Investment Tax Credits	(1		)	—			(1		)	(1		)	—			(1		)
State	11			9			13			12			7			10
Total Deferred Tax Expense (Benefit)	71			60			76			58			45			59
Total Federal and State Income Tax Expense	$	58		$	56		$	67		$	48		$	39		$	52

Schedule of Deferred Tax Assets and Liabilities

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

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Gross Deferred Income Tax Assets:
Capital Lease Obligations	$	127		$	141		$	127		$	141
Net Operating Loss Carryforwards	94			72			104			85
Customer Advances and Contributions in Aid of Construction	33			34			19			19
Alternative Minimum Tax Credit	43			43			24			24
Accrued Postretirement Benefits	23			23			23			23
Renewable Energy Credit Up-Front Incentive Payments	—			26			—			20
Emission Allowance Inventory	10			10			10			10
Unregulated Investment Losses	7			9			—			—
Other	50			44			44			43
Total Gross Deferred Income Tax Assets	387			402			351			365
Deferred Tax Assets Valuation Allowance	(7		)	(7		)	(2		)	—
Gross Deferred Income Tax Liabilities:
Plant – Net	(708		)	(648		)	(615		)	(571		)
Capital Lease Assets – Net	(47		)	(34		)	(47		)	(34		)
Pensions	(21		)	(23		)	(22		)	(24		)
PPFAC	(5		)	(6		)	(2		)	(3		)
Other	(21		)	(15		)	(20		)	(15		)
Total Gross Deferred Income Tax Liabilities	(802		)	(726		)	(706		)	(647		)
Net Deferred Income Tax Liabilities	$	(422	)	$	(331	)	$	(357	)	$	(282	)

Summary of Deferred Tax Liability Not Recognized

The net deferred income tax liability on the balance sheet is as follows:

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Deferred Income Taxes – Current Assets	$	60		$	34		$	64		$	37
Deferred Income Taxes – Noncurrent Liabilities	(482		)	(365		)	(421		)	(319		)
Net Deferred Income Tax Liability	$	(422	)	$	(331	)	$	(357	)	$	(282	)

Summary Of Details Of Tax Carryforwards Table

As of December 31, 2013, UNS Energy and TEP had the following carryforward amounts:

	UNS Energy			TEP
	Amount		Expiring Year	Amount		Expiring Year
	Millions of Dollars			Millions of Dollars
Capital Loss	$	7	2015	$	—	N/A
Federal Net Operating Loss	266		2031-33	286		2031-33
State Net Operating Loss	30		2032-33	99		2016-33
State Credits	5		2016-18	6		2016-18
Alternative Minimum Tax Credit	43		None	24		None
Investment Tax Credits	6		2032-33	6		2032-33

Summary of Income Tax Contingencies

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Unrecognized Tax Benefits, Beginning of Year	$	30		$	29		$	23		$	24
Additions Based on Tax Positions Taken in the Current Year	2			5			1			3
Reductions of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(4		)	(22		)	(4		)
Unrecognized Tax Benefits, End of Year	$	4		$	30		$	2		$	23

XML

REGULATORY MATTERS (Regulatory Assets and Liabilities) (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets—Current	$ 52,763		$ 51,619
Regulatory Assets—Noncurrent	150,584		191,077
Regulatory Liabilities - Current	(53,935)		(43,516)
Regulatory Liability, Noncurrent	(302,482)		(279,111)
UNS Energy
Regulatory Assets And Liabilities [Line Items]
Property Tax Deferrals Current	20,000	[1]	18,000	[1]
Derivative Instruments Regulatory Assets Current	1,000		11,000
Mine Fire Cost Deferral	10,000	[2]
PPFAC	14,000	[2]	15,000	[2]
DSM and LFCR Regulatory Assets Current	3,000	[2]
DSM			5,000	[2]
Other Current Regulatory Assets	5,000	[3]	3,000	[3]
Regulatory Assets—Current	53,000		52,000
Pension And Other Postretirement Benefits Noncurrent	80,000		139,000
Income Taxes Recoverable through Future Revenues	25,000	[4]	10,000	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	25,000	[5]	22,000	[5]
Tucson to Nogales Transmission Line	5,000	[6]	5,000	[6]
Other Regulatory Assets Noncurrent	16,000	[3]	15,000	[3]
Regulatory Assets—Noncurrent	151,000		191,000
PGA	(15,000)		(17,000)
RES	(31,000)		(23,000)
Other Current Regulatory Liabilities Current	(8,000)		(4,000)
Regulatory Liabilities - Current	(54,000)		(44,000)
Net Cost of Removal for Interim Retirements	(292,000)	[7]	(267,000)	[7]
Income Taxes Payable through Future Rates	(6,000)		(6,000)
Deferred Investment Tax Credit	(4,000)	[8]	(5,000)	[8]
Other Regulatory Liabilities			1,000
Regulatory Liability, Noncurrent	(302,000)		(279,000)
Total Net Regulatory Assets (Liabilities)	(152,000)		(80,000)
TUCSON ELECTRIC POWER COMPANY
Regulatory Assets And Liabilities [Line Items]
Property Tax Deferrals Current	20,000	[1]	18,000	[1]
Derivative Instruments Regulatory Assets Current	1,000		2,000
Mine Fire Cost Deferral	10,000	[2]
PPFAC	4,000	[2]	7,000	[2]
DSM and LFCR Regulatory Assets Current	3,000	[2]
DSM			5,000	[2]
Other Current Regulatory Assets	5,000	[3]	2,000	[3]
Regulatory Assets—Current	42,555		34,345
Pension And Other Postretirement Benefits Noncurrent	75,000		130,000
Income Taxes Recoverable through Future Revenues	22,000	[4]	8,000	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	25,000	[5]	22,000	[5]
Tucson to Nogales Transmission Line	5,000	[6]	5,000	[6]
Other Regulatory Assets Noncurrent	14,000	[3]	13,000	[3]
Regulatory Assets—Noncurrent	141,030		178,330
PGA	0		0
RES	(22,000)		(19,000)
Other Current Regulatory Liabilities Current	(2,000)		(2,000)
Regulatory Liabilities - Current	(23,701)		(20,822)
Net Cost of Removal for Interim Retirements	(254,000)	[7]	(231,000)	[7]
Income Taxes Payable through Future Rates	(5,000)		(5,000)
Deferred Investment Tax Credit	(4,000)	[8]	(5,000)	[8]
Other Regulatory Liabilities			0
Regulatory Liability, Noncurrent	(263,270)		(241,189)
Total Net Regulatory Assets (Liabilities)	(103,386)		(50,000)
UNS Electric
Regulatory Assets And Liabilities [Line Items]
Property Tax Deferrals Current	0	[1]	0	[1]
Derivative Instruments Regulatory Assets Current	0		6,000
Mine Fire Cost Deferral	0	[2]
PPFAC	10,000	[2]	8,000	[2]
DSM and LFCR Regulatory Assets Current	0	[2]
DSM			0	[2]
Other Current Regulatory Assets	0	[3]	0	[3]
Regulatory Assets—Current	10,000		14,000
Pension And Other Postretirement Benefits Noncurrent	3,000		5,000
Income Taxes Recoverable through Future Revenues	3,000	[4]	2,000	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	0	[5]	0	[5]
Tucson to Nogales Transmission Line	0	[6]	0	[6]
Other Regulatory Assets Noncurrent	2,000	[3]	1,000	[3]
Regulatory Assets—Noncurrent	8,000		8,000
PGA	0		0
RES	(9,000)		(4,000)
Other Current Regulatory Liabilities Current	(6,000)		(1,000)
Regulatory Liabilities - Current	(15,000)		(5,000)
Net Cost of Removal for Interim Retirements	(12,000)	[7]	(11,000)	[7]
Income Taxes Payable through Future Rates	0		0
Deferred Investment Tax Credit	0	[8]	0	[8]
Other Regulatory Liabilities			1,000
Regulatory Liability, Noncurrent	(12,000)		(12,000)
Total Net Regulatory Assets (Liabilities)	(9,000)		5,000
UNS Gas
Regulatory Assets And Liabilities [Line Items]
Property Tax Deferrals Current	0	[1]	0	[1]
Derivative Instruments Regulatory Assets Current	0		3,000
Mine Fire Cost Deferral	0	[2]
PPFAC	0	[2]	0	[2]
DSM and LFCR Regulatory Assets Current	0	[2]
DSM			0	[2]
Other Current Regulatory Assets	0	[3]	1,000	[3]
Regulatory Assets—Current	0		4,000
Pension And Other Postretirement Benefits Noncurrent	2,000		4,000
Income Taxes Recoverable through Future Revenues	0	[4]	0	[4]
PPFAC—Final Mine Reclamation and Retiree Health Care Costs	0	[5]	0	[5]
Tucson to Nogales Transmission Line	0	[6]	0	[6]
Other Regulatory Assets Noncurrent	0	[3]	1,000	[3]
Regulatory Assets—Noncurrent	2,000		5,000
PGA	(15,000)		(17,000)
RES	0		0
Other Current Regulatory Liabilities Current	0		(1,000)
Regulatory Liabilities - Current	(15,000)		(18,000)
Net Cost of Removal for Interim Retirements	(26,000)	[7]	(25,000)	[7]
Income Taxes Payable through Future Rates	(1,000)		(1,000)
Deferred Investment Tax Credit	0	[8]	0	[8]
Other Regulatory Liabilities			0
Regulatory Liability, Noncurrent	(27,000)		(26,000)
Total Net Regulatory Assets (Liabilities)	$ (40,000)		$ (35,000)

[1] Property Tax is recovered over approximately a six-month period as costs are paid, rather than as costs are accrued.

[2] See Cost Recovery Mechanisms discussion above.

[3] TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).

[4] Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.

[5] Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.

[6] TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.

[7] Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.

[8] The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Effect of Fixing Interest Rates on Amortizing Principal Balances of Swaps) (Detail) (Springerville Common Facilities Lease Debt [Member], TUCSON ELECTRIC POWER COMPANY, USD $)	Dec. 31, 2013
Derivative Instruments And Hedging Activities [Line Items]
Derivative basis spread	1.75%
Interest Rate Swap One [Member]
Derivative Instruments And Hedging Activities [Line Items]
Derivative amount of hedged item	$ 33,000,000
Fixed rate of interest related to interest rate swap	5.77%
Derivative basis spread	1.75%
Interest Rate Swap Two [Member]
Derivative Instruments And Hedging Activities [Line Items]
Derivative amount of hedged item	16,000,000
Fixed rate of interest related to interest rate swap	3.18%
Derivative basis spread	1.75%
Interest Rate Swap Three [Member]
Derivative Instruments And Hedging Activities [Line Items]
Derivative amount of hedged item	$ 6,000,000
Fixed rate of interest related to interest rate swap	3.32%
Derivative basis spread	1.75%

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Financial Impact of Energy Contracts) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Increase (Decrease) to Regulatory Assets/Liabilities	$ (9)	$ (21)	$ 2
TUCSON ELECTRIC POWER COMPANY
Derivative Instruments, Gain (Loss) [Line Items]
Increase (Decrease) to Regulatory Assets/Liabilities	$ 0	$ (6)	$ 2

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UTILITY PLANT AND JOINTLY-OWNED FACILITES (TEP's Interests in Jointly-Owned Generating Stations and Transmission Systems) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$ 1,084
Construction Work in Progress	52
Accumulated Depreciation	607
Net Book Value	529
San Juan Units 1 and 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	50.00%
Plant in Service	448
Construction Work in Progress	6
Accumulated Depreciation	230
Net Book Value	224
Navajo Units 1, 2, and 3 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	7.50%
Plant in Service	152
Construction Work in Progress	1
Accumulated Depreciation	110
Net Book Value	43
Four Corners Units 4 and 5 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	7.00%
Plant in Service	101
Construction Work in Progress	2
Accumulated Depreciation	75
Net Book Value	28
Luna Energy Facility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of ownership in generating station	33.30%
Plant in Service	53
Construction Work in Progress	0
Accumulated Depreciation	2
Net Book Value	51
Transmission Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	330
Construction Work in Progress	43
Accumulated Depreciation	190
Net Book Value	$ 183

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY
Public Utility, Property, Plant and Equipment [Line Items]
Average annual depreciation rate	3.16%	3.22%	3.14%
UNS Electric
Public Utility, Property, Plant and Equipment [Line Items]
Average annual depreciation rate	3.94%	3.99%	4.02%
UNS Gas
Public Utility, Property, Plant and Equipment [Line Items]
Average annual depreciation rate	2.63%	2.69%	2.84%

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CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $) Share data in Thousands, unless otherwise specified	Total USD ($)	TUCSON ELECTRIC POWER COMPANY USD ($)	Common Shares Outstanding [Member]	Common Stock [Member] USD ($)	Common Stock [Member] TUCSON ELECTRIC POWER COMPANY USD ($)	Capital Stock Expense [Member] TUCSON ELECTRIC POWER COMPANY USD ($)	Retained Earnings [Member] USD ($)	Retained Earnings [Member] TUCSON ELECTRIC POWER COMPANY USD ($)	Accumulated Other Comprehensive Loss [Member] USD ($)	Accumulated Other Comprehensive Loss [Member] TUCSON ELECTRIC POWER COMPANY USD ($)
Balances at Dec. 31, 2010	$ 830,756,000	$ 709,884,000		$ 715,687,000	$ 858,971,000	$ (6,357,000)	$ 124,838,000	$ (132,961,000)	$ (9,769,000)	$ (9,769,000)
Balances, shares at Dec. 31, 2010			36,542
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	109,975,000	85,334,000					109,975,000	85,334,000
Other Comprehensive Loss, net of tax	(315,000)	(275,000)							(315,000)	(275,000)
Dividends Paid to UNS Energy		0
Dividends Declared	(62,158,000)						(62,158,000)
Shares Issued for Stock Options, shares	319		319
Shares Issued for Stock Options	8,176,000			8,176,000
Shares Issued Under Performance Share Awards, shares			57
Shares Issued Under Performance Share Awards	0			0
Share-based Compensation	2,040,000			2,040,000
Payments of Dividends		30,000,000			30,000,000
Balances at Dec. 31, 2011	888,474,000	824,943,000		725,903,000	888,971,000	(6,357,000)	172,655,000	(47,627,000)	(10,084,000)	(10,044,000)
Balances, shares at Dec. 31, 2011			36,918
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	6,476,000	(1,461,000)
Balances at Mar. 31, 2012
Balances at Dec. 31, 2011	888,474,000	824,943,000		725,903,000		(6,357,000)	172,655,000	(47,627,000)	(10,084,000)	(10,044,000)
Balances, shares at Dec. 31, 2011			36,918
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	90,919,000	65,470,000					90,919,000	65,470,000
Other Comprehensive Loss, net of tax	294,000	514,000							294,000	514,000
Dividends Paid to UNS Energy		(30,000,000)						(30,000,000)
Dividends Declared	(70,457,000)						(70,457,000)
Shares Issued on Conversion of Notes and Related Tax Effect, shares			4,262
Shares Issued on Conversion of Notes and Related Tax Effect	149,805,000			149,805,000
Shares Issued for Stock Options, shares	132		133
Shares Issued for Stock Options	3,511,000			3,511,000
Shares Issued Under Performance Share Awards, shares			31
Shares Issued Under Performance Share Awards	0			0
Share-based Compensation	2,919,000			2,919,000
Balances at Dec. 31, 2012	1,065,465,000	860,927,000		882,138,000	888,971,000	(6,357,000)	193,117,000	(12,157,000)	(9,790,000)	(9,530,000)
Balances, shares at Dec. 31, 2012			41,344
Balances at Sep. 30, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	7,506,000	452,000
Balances at Dec. 31, 2012	1,065,465,000	860,927,000			888,971,000	(6,357,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	11,345,000	1,478,000
Balances at Mar. 31, 2013
Balances at Dec. 31, 2012	1,065,465,000	860,927,000		882,138,000	888,971,000	(6,357,000)	193,117,000	(12,157,000)	(9,790,000)	(9,530,000)
Balances, shares at Dec. 31, 2012			41,344
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	127,478,000	101,342,000					127,478,000	101,342,000
Other Comprehensive Loss, net of tax	3,741,000	3,654,000							3,741,000	3,654,000
Dividends Paid to UNS Energy		(40,000,000)						(40,000,000)
Dividends Declared	(73,063,000)						(73,063,000)
Shares Issued under Dividend Reinvestment Plan, shares			10
Shares Issued under Dividend Reinvestment Plan	464,000			464,000
Shares Issued for Stock Options, shares	127		127
Shares Issued for Stock Options	3,831,000			3,831,000
Shares Issued Under Performance Share Awards, shares			57
Shares Issued Under Performance Share Awards	0			0
Share-based Compensation	2,868,000			2,868,000
Balances at Dec. 31, 2013	1,130,784,000	925,923,000		889,301,000	888,971,000	(6,357,000)	247,532,000	49,185,000	(6,049,000)	(5,876,000)
Balances, shares at Dec. 31, 2013			41,538
Balances at Sep. 30, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	13,525,000	4,910,000
Balances at Dec. 31, 2013	$ 1,130,784,000	$ 925,923,000			$ 888,971,000	$ (6,357,000)

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Liabilities:
Long-Term Debt	$ 1,507,070,000	$ 1,498,442,000
TUCSON ELECTRIC POWER COMPANY
Liabilities:
Long-Term Debt	1,223,070,000
Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-Term Debt	1,507,000,000	1,498,000,000
Carrying Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Debt	0	9,000,000
Liabilities:
Long-Term Debt	1,223,000,000	1,223,000,000
Carrying Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Equity	36,000,000	36,000,000
Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-Term Debt	1,521,000,000	1,583,000,000
Fair Value [Member] | Level 2 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Debt	0	9,000,000
Liabilities:
Long-Term Debt	1,214,000,000	1,271,000,000
Fair Value [Member] | Level 3 [Member] | TUCSON ELECTRIC POWER COMPANY
Assets:
TEP Investment in Lease Equity	$ 25,000,000	$ 23,000,000

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UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Asset Retirement Obligations) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]
Liabilities Incurred	$ 8,064,000	[1]	$ 789,000	[1]	$ 7,638,000	[1]
UNS Energy
Public Utility, Property, Plant and Equipment [Line Items]
Beginning Balance	14,000,000		13,000,000
Liabilities Incurred	1,000,000		0
Accretion Expense	1,000,000		1,000,000
Revision to Estimated Cash Flows	7,000,000	[2]	0	[2]
Ending Balance	23,000,000		14,000,000
UNS Electric
Public Utility, Property, Plant and Equipment [Line Items]
Ending Balance	$ 1,000,000		$ 1,000,000

[1] The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

[2] Primarily related to changes in expected retirement dates of generating facilities.

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CHANGES IN ACCUMULATIVE OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables)

12 Months Ended

Dec. 31, 2013

Statement of Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The realized changes in AOCI by component are as follows:

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Year Ended December 31, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(1,377	)	$	(1,166	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(2,429		)	(2,429		)	Interest Expense Capital Leases
Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
Tax Benefit	1,801			1,718
Realized Losses on Cash Flow Hedges, Net of Taxes	(2,752		)	(2,624		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(1,488		)	(1,488		)	Other Expense
Tax Benefit	572			572
Amortization, Net of Taxes	(916		)	(916		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(3,668	)	$	(3,540	)

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SCHEDULE II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

SCHEDUEL II- VALUATION & QUALIFYING ACCOUNTS

Schedule II—Valuation and Qualifying Accounts – UNS Energy

Allowance for Doubtful Accounts (1)	Beginning Balance		Additions- Charged  to Income		Deductions		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	7	$	2	$	2	$	7
2012	16		4		13		7
2011	13		5		2		16

Other Reserves (2)	Beginning Balance		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	9	$	6
2012	6		9
2011	4		6

Schedule II—Valuation and Qualifying Accounts—TEP

Allowance for Doubtful Accounts (1)	Beginning Balance		Additions- Charged  to Income		Deductions		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	5	$	2	$	2	$	5
2012	14		3		12		5
2011	11		4		1		14

Other Reserves (2)	Beginning Balance		Ending Balance
	Millions of Dollars
Year Ended December 31,
2013	$	8	$	4
2012	4		8
2011	3		4

⁽¹⁾  TEP, UNS Electric, and UNS Gas record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.

⁽²⁾  As the Other reserves are not individually significant, additions and deductions need not be disclosed. Principally reserves for sales tax audits, litigation matters, and damages billable to third parties.

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QUARTERLY FINANCIAL DATA

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

QUARTERLY FINANCIAL DATA

QUARTERLY FINANCIAL DATA (UNAUDITED)

Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility businesses are seasonal in nature. Peak sales periods for TEP and UNS Electric generally occur during the summer while UNS Gas’ sales generally peak during the winter. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

	UNS Energy
	First		Second		Third		Fourth
	Thousands of Dollars (Except Per Share Amounts)
2013
Operating Revenue	$	332,141	$	365,217	$	437,041	$	350,161
Operating Income	39,895		60,803		129,765		41,033
Net Income	11,345		34,618		67,990		13,525
Basic EPS	0.27		0.83		1.63		0.32
Diluted EPS	0.27		0.83		1.62		0.32
2012
Operating Revenue	$	315,387	$	363,998	$	434,108	$	348,273
Operating Income (1)	34,403		68,065		106,409		42,918
Net Income	6,476		26,273		50,664		7,506
Basic EPS	0.17		0.65		1.22		0.18
Diluted EPS	0.17		0.64		1.21		0.18

EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.

	TEP
	First			Second		Third		Fourth
	Thousands of Dollars
2013
Operating Revenue	$	247,751		$	304,263	$	371,239	$	273,437
Operating Income	22,747			53,433		123,177		31,014
Net Income	1,478			30,787		64,167		4,910
2012
Operating Revenue	$	223,978		$	299,419	$	366,910	$	271,353
Operating Income (1)	17,898			58,211		94,079		30,299
Net Income (Loss)	(1,461		)	21,910		44,569		452

⁽¹⁾Immaterial variances from quarterly amounts previously reported result from line item reclassifications.

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SHARE-BASED COMPENSATION PLANS (Restricted Stock Units) (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Director [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Granted, Shares	8,870	15,303	14,655
Grant Date Fair Value	$ 48.99	$ 35.94	$ 37.53
Management [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Granted, Shares	21,560
Grant Date Fair Value	$ 46.23

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UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Plant in Service:
Total Plant in Service	$ 5,192,122,000		$ 5,005,768,000
Utility Plant under Capital Leases	638,000,000	[1]	583,000,000	[1]
Electricity Generation Plant, Non-Nuclear [Member]
Plant in Service:
Total Plant in Service	1,974,000,000		1,932,000,000
Electric Transmission Plant [Member]
Plant in Service:
Total Plant in Service	912,000,000		842,000,000
Electric Distribution Plant [Member]
Plant in Service:
Total Plant in Service	1,529,000,000		1,495,000,000
Gas Distribution Plant [Member]
Plant in Service:
Total Plant in Service	252,000,000		240,000,000
Gas Transmission Plant [Member]
Plant in Service:
Total Plant in Service	18,000,000		18,000,000
General Plant [Member]
Plant in Service:
Total Plant in Service	356,000,000		347,000,000
Software Costs [Member]
Plant in Service:
Total Plant in Service	142,000,000	[2],[3]	124,000,000	[2],[3]
Intangible Plant [Member]
Plant in Service:
Total Plant in Service	5,000,000		5,000,000
Electric Plant Held for Future Use [Member]
Plant in Service:
Total Plant in Service	4,000,000		3,000,000
TUCSON ELECTRIC POWER COMPANY
Plant in Service:
Total Plant in Service	4,467,667,000		4,348,041,000
Utility Plant under Capital Leases	638,000,000	[1]	583,000,000	[1]
TUCSON ELECTRIC POWER COMPANY | Electricity Generation Plant, Non-Nuclear [Member]
Plant in Service:
Total Plant in Service	1,889,000,000		1,847,000,000
TUCSON ELECTRIC POWER COMPANY | Electric Transmission Plant [Member]
Plant in Service:
Total Plant in Service	825,000,000		796,000,000
TUCSON ELECTRIC POWER COMPANY | Electric Distribution Plant [Member]
Plant in Service:
Total Plant in Service	1,298,000,000		1,271,000,000
TUCSON ELECTRIC POWER COMPANY | Gas Distribution Plant [Member]
Plant in Service:
Total Plant in Service	0		0
TUCSON ELECTRIC POWER COMPANY | Gas Transmission Plant [Member]
Plant in Service:
Total Plant in Service	0		0
TUCSON ELECTRIC POWER COMPANY | General Plant [Member]
Plant in Service:
Total Plant in Service	312,000,000		309,000,000
TUCSON ELECTRIC POWER COMPANY | Software Costs [Member]
Plant in Service:
Total Plant in Service	141,000,000	[2],[3]	123,000,000	[2],[3]
TUCSON ELECTRIC POWER COMPANY | Intangible Plant [Member]
Plant in Service:
Total Plant in Service	0		0
TUCSON ELECTRIC POWER COMPANY | Electric Plant Held for Future Use [Member]
Plant in Service:
Total Plant in Service	$ 3,000,000		$ 2,000,000

[1] In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.

[2] Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.

[3] The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.

XML

QUARTERLY FINANCIAL DATA (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule of Quarterly Financial Information

comparisons among quarters of a year may not represent overall trends and changes in operations.

	UNS Energy
	First		Second		Third		Fourth
	Thousands of Dollars (Except Per Share Amounts)
2013
Operating Revenue	$	332,141	$	365,217	$	437,041	$	350,161
Operating Income	39,895		60,803		129,765		41,033
Net Income	11,345		34,618		67,990		13,525
Basic EPS	0.27		0.83		1.63		0.32
Diluted EPS	0.27		0.83		1.62		0.32
2012
Operating Revenue	$	315,387	$	363,998	$	434,108	$	348,273
Operating Income (1)	34,403		68,065		106,409		42,918
Net Income	6,476		26,273		50,664		7,506
Basic EPS	0.17		0.65		1.22		0.18
Diluted EPS	0.17		0.64		1.21		0.18

EPS is computed independently for each of the quarters presented. Therefore, the sum of the quarterly EPS amounts may not equal the total for the year.

	TEP
	First			Second		Third		Fourth
	Thousands of Dollars
2013
Operating Revenue	$	247,751		$	304,263	$	371,239	$	273,437
Operating Income	22,747			53,433		123,177		31,014
Net Income	1,478			30,787		64,167		4,910
2012
Operating Revenue	$	223,978		$	299,419	$	366,910	$	271,353
Operating Income (1)	17,898			58,211		94,079		30,299
Net Income (Loss)	(1,461		)	21,910		44,569		452

⁽¹⁾Immaterial variances from quarterly amounts previously reported result from line item reclassifications.

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Nature of Operations

NATURE OF OPERATIONS

UNS Energy Corporation (UNS Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of December 31, 2013. TEP generates, transmits and distributes electricity to approximately 413,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).

UES wholly-owns two regulated utilities: UNS Electric, Inc. (UNS Electric) and UNS Gas, Inc. (UNS Gas). UNS Electric is a regulated utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.

UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2013.

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

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

Basis Of Presentation

BASIS OF PRESENTATION

UNS Energy's consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 3. The consolidated financial statements include the accounts of UNS Energy and all of its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated if recovery from ratepayers is probable. See Note 4. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income.

Use of Accounting Estimates

USE OF ACCOUNTING ESTIMATES

Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect:

• Assets and liabilities on our balance sheets at the dates of the financial statements;

• Our disclosures about contingent assets and liabilities at the dates of the financial statements; and

• Our revenues and expenses in our income statements during the periods presented.

Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.

Accounting for Regulated Operations

ACCOUNTING FOR REGULATED OPERATIONS

We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through FERC-approved transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future billing reductions.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 3.

TEP, UNS Electric, and UNS Gas apply regulatory accounting as the following conditions exist:

• An independent regulator sets rates;

• The regulator sets the rates to recover the specific enterprise’s costs of providing service; and

• Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.

Recently Adopted Accounting Pronouncements

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2013, we adopted authoritative guidance that:

• Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 15.

• Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 16.

Cash and Cash Equivalents

CASH AND CASH EQUIVALENTS

We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.

Restricted Cash

RESTRICTED CASH

Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets

Utility Plant

UTILITY PLANT

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

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

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

AFUDC and Capitalized Interest

AFUDC and Capitalized Interest

AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.

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

	2013		2012		2011
TEP	7.38	%	7.22	%	6.72	%
UNS Electric	8.07	%	7.89	%	8.18	%
UNS Gas	7.89	%	7.95	%	8.32	%

UNS Energy did not capitalize interest related to non-regulated construction activity in 2013 or 2012. UNS Energy capitalized interest on non-regulated construction activity at a rate of 3.30% for 2011.

Depreciation

Depreciation

We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 and Note 5. The Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC)

TEP Utility Plant Under Capital Leases

TEP Utility Plant Under Capital Leases

TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense—Capital Leases. The lease terms are described in Note 6.

Computer Software Costs

Computer Software Costs

We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.

Investments in Lease Debt and Equity

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 15. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to the equity holders.

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

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

TEP and UNS Electric have identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense, and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.

Depreciation rates for all of our utilities also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.

Evaluation of Assets for Impairment

EVALUATION OF ASSETS FOR IMPAIRMENT

We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.

Deferred Financing Costs

DEFERRED FINANCING COSTS

We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.

We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.

Operating Revenues

OPERATING REVENUES

We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity and gas sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.

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

TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned.

The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) associated with energy sales that no longer occur due to EE Standards and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.

Allowance for Doubtful Accounts

ALLOWANCE FOR DOUBTFUL ACCOUNTS

We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions.

Inventory

INVENTORY

We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.

Recovery Of Fuel And Purchased Energy Costs

FUEL AND PURCHASED ENERGY COST RECOVERY MECHANISMS

TEP and UNS Electric Purchased Power and Fuel Adjustment Clause

TEP and UNS Electric recover actual fuel, purchased power and transmission costs incurred to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts the PPFAC rate at which TEP and UNS Electric recover these costs. The difference between costs recovered through rates and actual fuel, purchased power and transmission costs prudently incurred to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 3.

UNS Gas Purchased Gas Adjustor

UNS Gas recovers actual gas costs incurred through a Purchased Gas Adjustor (PGA) mechanism that adjusts monthly. Gas cost over-recoveries are deferred as regulatory liabilities and under-recoveries are deferred as regulatory assets. See Note 3.

Renewable Energy Credits

RENEWABLE ENERGY and ENERGY EFFICIENCY PROGRAMS

The ACC’s Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The 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. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates.

TEP, UNS Electric, and UNS Gas are required to implement cost-effective Demand-Side Management (DSM) programs to comply with the ACC’s Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail kWh savings equal to22% by 2020. The Gas EE Standards require increasing annual targeted retail therm sales equal to 6% by 2020.

Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP and UNS Electric recognize RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. Similarly, UNS Gas recognizes DSM surcharge revenue in Gas Retail Sales.

RENEWABLE ENERGY CREDITS

The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP or UNS Electric purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC.

When RECs are purchased, TEP and UNS Electric record the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount. See Note 3.

Income Taxes

INCOME TAXES

Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized.

Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.  Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.

Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 3.

We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and are deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises.

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.

Taxes Other Than Income Taxes

TAXES OTHER THAN INCOME TAXES

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

Derivative Instruments

DERIVATIVE INSTRUMENTS

We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.

Cash Flow Hedges

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. UNS Electric uses a cash flow hedge to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP and UNS Electric account for cash flow hedges as follows:

• The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and

• When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.

We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.

Energy Contracts - Regulatory Recovery

TEP, UNS Electric and UNS Gas are authorized to recover the prudent costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC or PGA mechanism.

Master Netting Agreements

We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.

Normal Purchases and Normal Sales

We enter into forward energy purchase and sales contracts, including call options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.

Pension and Other Retiree Benefits

PENSION AND OTHER RETIREE BENEFITS

We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees.

We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees.

Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.

Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 10.

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

AFUDC Rates

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

	2013		2012		2011
TEP	7.38	%	7.22	%	6.72	%
UNS Electric	8.07	%	7.89	%	8.18	%
UNS Gas	7.89	%	7.95	%	8.32	%

Summary Of Average Annual Depreciation Rates For All Utility Plants

Below are the summarized average annual depreciation rates for all utility plant:

	2013		2012		2011
TEP	3.16	%	3.22	%	3.14	%
UNS Electric	3.94	%	3.99	%	4.02	%
UNS Gas	2.63	%	2.69	%	2.84	%

XML

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	75,000,000	75,000,000
Shares Outstanding, common stock	41,538,343	41,343,851
Shares Authorized, preferred stock	1,000,000	1,000,000
Shares Outstanding, preferred stock	0	0
Par Value, preferred stock	$ 0	$ 0
TUCSON ELECTRIC POWER COMPANY
Common Stock, Shares Authorized	75,000,000	75,000,000
Shares Outstanding, common stock	32,139,434	32,139,434

XML

REGULATORY MATTERS (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Summary of PPFAC Rates

The tables below summarize TEP’s and UNS Electric’s PPFAC rates:

	TEP
	2013		2012
	July - December	January - June	April - December	January - March
	Cents per kWh
PPFAC Rate	0.14	0.77	0.77	0.53
Competition Transition Charge (1)	—	—	—	(0.53	)
Net TEP PPFAC Rate	0.14	0.77	0.77	—

⁽¹⁾  TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.

	UNS Electric
	2013						2012
	September - December		June - August		January - May		June - December		January - May
	Cents per kWh
PPFAC Rate	(0.40	)	(0.92	)	(1.44	)	(1.44	)	(0.88	)

Regulatory Assets and Liabilities

The following tables summarize regulatory assets and liabilities:

	December 31, 2013
	TEP			UNS Electric			UNS Gas			UNS Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	20		$	—		$	—		$	20
Derivative Instruments (Note 15)	1			—			—			1
San Juan Mine Fire Cost Deferral (2)	10			—			—			10
PPFAC (2)	4			10			—			14
DSM and LFCR (2)	3			—			—			3
Other Current Regulatory Assets (3)	5			—			—			5
Total Regulatory Assets—Current	43			10			—			53
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	75			3			2			80
Income Taxes Recoverable through Future Revenues (4)	22			3			—			25
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	25			—			—			25
Discontinued Nogales Transmission Project (6)	5			—			—			5
Other Regulatory Assets (3)	14			2			—			16
Total Regulatory Assets—Noncurrent	141			8			2			151
Regulatory Liabilities—Current
PGA (2)	—			—			(15		)	(15		)
RES (2)	(22		)	(9		)	—			(31		)
Other Current Regulatory Liabilities	(2		)	(6		)	—			(8		)
Total Regulatory Liabilities—Current	(24		)	(15		)	(15		)	(54		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(254		)	(12		)	(26		)	(292		)
Income Taxes Payable through Future Rates	(5		)	—			(1		)	(6		)
Deferred Investment Tax Credit (8)	(4		)	—			—			(4		)
Total Regulatory Liabilities—Noncurrent	(263		)	(12		)	(27		)	(302		)
Total Net Regulatory Assets (Liabilities)	$	(103	)	$	(9	)	$	(40	)	$	(152	)

	December 31, 2012
	TEP			UNS Electric			UNS Gas			UNS Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	18		$	—		$	—		$	18
Derivative Instruments (Note 15)	2			6			3			11
PPFAC (2)	7			8			—			15
DSM (2)	5			—			—			5
Other Current Regulatory Assets (3)	2			—			1			3
Total Regulatory Assets—Current	34			14			4			52
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	130			5			4			139
Income Taxes Recoverable through Future Revenues (4)	8			2			—			10
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	22			—			—			22
Discontinued Nogales Transmission Project (6)	5			—			—			5
Other Regulatory Assets (3)	13			1			1			15
Total Regulatory Assets—Noncurrent	178			8			5			191
Regulatory Liabilities—Current
PGA (2)	—			—			(17		)	(17		)
RES (2)	(19		)	(4		)	—			(23		)
Other Current Regulatory Liabilities	(2		)	(1		)	(1		)	(4		)
Total Regulatory Liabilities—Current	(21		)	(5		)	(18		)	(44		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(231		)	(11		)	(25		)	(267		)
Income Taxes Payable through Future Rates	(5		)	—			(1		)	(6		)
Deferred Investment Tax Credit (8)	(5		)	—			—			(5		)
Other Regulatory Liabilities	—			(1		)	—			(1		)
Total Regulatory Liabilities—Noncurrent	(241		)	(12		)	(26		)	(279		)
Total Net Regulatory Assets (Liabilities)	$	(50	)	$	5		$	(35	)	$	(80	)

Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets below. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets.

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

⁽²⁾  See Cost Recovery Mechanisms discussion above.

⁽³⁾  TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).

⁽⁴⁾  Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.

⁽⁵⁾  Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.

⁽⁶⁾  TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.

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

⁽⁷⁾  Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.

⁽⁸⁾  The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

XML

EMPLOYEE BENEFIT PLANS (Pension and Other Retiree Benefit Related Amounts) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	$ 75	$ 129
Accrued Benefit Liability Included in Accrued Employee Expenses	(1)	(1)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(28)	(90)
Accumulated Other Comprehensive Loss (related to SERP)	2	4
Net Amount Recognized	48	42
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Pension Asset Included in Other Regulatory Assets	4	10
Accrued Benefit Liability Included in Accrued Employee Expenses	(2)	(2)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(63)	(69)
Accumulated Other Comprehensive Loss (related to SERP)	0	0
Net Amount Recognized	(61)	(61)
UNS Gas and UNS Electric [Member] | Pension Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Accrued pension benefit liability	5	9
UNS Gas and UNS Electric [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Accrued pension benefit liability	$ 1	$ 1

XML

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning balance		$ (5)	$ (10)
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities - Derivative Instruments		(1)	(5)
Settlements		4	10
Ending balance		(2)	(5)
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period		(1)	(1)
Transfered amount out of Level 3	0.5
TUCSON ELECTRIC POWER COMPANY
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Beginning balance		0	0
Realized/Unrealized Gains/(Losses) Recorded to:
Net Regulatory Assets/Liabilities - Derivative Instruments		(2)	1
Settlements		0	(1)
Ending balance		(2)	0
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period		$ (1)	$ 0

XML

UNS ENERGY EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Effects of Dilutive Common Stock on Weighted-Average Number of Shares

The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:

	Years Ended December 31,
	2013		2012		2011
	Thousands of Dollars
Numerator:
Net Income	$	127,478	$	90,919	$	109,975
Income from Assumed Conversion of Convertible Senior Notes (1)	—		1,100		4,390
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	127,478	$	92,019	$	114,365
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,446		40,212		36,780
Fully Vested Deferred Stock Units	172		150		129
Participating Securities	—		—		53
Total Weighted Average Common Stock Outstanding and Participating Securities—Basic	41,618		40,362		36,962
Effect of Dilutive Securities:
Convertible Senior Notes (1)	—		1,062		4,281
Options and Stock Issuable Under Share-Based Compensation Plans	357		331		366
Total Weighted Average Common Stock Outstanding —Diluted	41,975		41,755		41,609

⁽¹⁾ In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

Number of Stock Options to Purchase Shares of Common Stock Excluded from Computation of Diluted Earning Per Share

We excluded the following outstanding stock options, with an exercise price above market, and contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive:

	Years Ended December 31,
	2013	2012	2011
	Thousands of Shares
Stock Options	—	50	153
Restricted Stock Units	6	—	—
Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	50	153

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REGULATORY MATTERS (Regulatory Assets and Liabilities Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013
Regulatory Assets [Line Items]
Property Tax Recovery Period	6 months
TUCSON ELECTRIC POWER COMPANY
Regulatory Assets [Line Items]
Recovery Period Of Reacquired Debt	2032
Recovery Period Of Coal Contract Amendment	2017
Recovery Period for Rate Case Costs	3 years
Recovery Other Assets	2014
Minimum [Member] | TUCSON ELECTRIC POWER COMPANY
Regulatory Assets [Line Items]
Expected Life Of Mines	14 years
Maximum [Member] | TUCSON ELECTRIC POWER COMPANY
Regulatory Assets [Line Items]
Expected Life Of Mines	20 years

XML

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (TEP Contingencies) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
San Juan [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in Generating Units 1 & 2		50.00%
Percentage of ownership in generating station		20.00%
Four Corner [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		7.00%
Tucson to Nogales [Member]
Commitments And Contingencies [Line Items]
Transmission line from Tucson to Nogales		60
Transmission Line, in KV		345
TUCSON ELECTRIC POWER COMPANY
Commitments And Contingencies [Line Items]
TEP's share of reclamation costs at expiration dates of the coal supply agreements		$ 44
TEP's recorded obligations for final mine reclamation costs	16	18
TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]
Commitments And Contingencies [Line Items]
TEP accrued an estimated loss related to Four Corners Generating Station		1
TUCSON ELECTRIC POWER COMPANY | Tucson to Nogales [Member]
Commitments And Contingencies [Line Items]
Asset Impairment Charges	5
Regulatory Assets		5
Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member] | TUCSON ELECTRIC POWER COMPANY | San Juan [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		5
Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member] | TUCSON ELECTRIC POWER COMPANY | San Juan [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		1
Assessment for Coal Severance Tax, Coal Supplier [Member] | TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		30
Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member] | TUCSON ELECTRIC POWER COMPANY | Four Corner [Member]
Commitments And Contingencies [Line Items]
Estimate of Possible Loss Contingency		$ 1

XML

CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues
Electric Retail Sales	$ 1,102,769	$ 1,087,279	$ 1,085,822
Electric Wholesale Sales	135,160	125,414	132,346
Gas Retail Sales	125,478	123,133	145,053
Other Revenue	121,153	125,940	115,481
Total Operating Revenues	1,484,560	1,461,766	1,478,702
Operating Expenses
Fuel	332,279	327,832	324,520
Purchased Energy	252,532	224,696	276,610
Transmission and Other PPFAC Recoverable Costs	23,012	14,540	7,334
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(16,313)	32,246	(4,932)
Total Fuel and Purchased Energy	591,510	599,314	603,532
Operations and Maintenance	389,699	383,689	379,220
Depreciation	149,615	141,303	133,832
Amortization	27,557	35,784	30,983
Taxes Other Than Income Taxes	54,683	49,881	49,428
Total Operating Expenses	1,213,064	1,209,971	1,196,995
Operating Income	271,496	251,795	281,707
Other Income (Deductions)
Interest Income	534	1,106	4,568
Other Income	7,880	4,928	7,958
Other Expense	(3,463)	(7,723)	(5,278)
Appreciation in Fair Value of Investments	2,833	1,892	329
Total Other Income (Deductions)	7,784	203	7,577
Interest Expense [Abstract]
Long-Term Debt	71,180	71,909	73,217
Capital Leases	25,140	33,613	40,359
Other Interest Expense	538	1,983	2,535
Interest Capitalized	(3,483)	(2,153)	(3,753)
Interest Expense	93,375	105,352	112,358
Income Before Income Taxes	185,905	146,646	176,926
Income Tax Expense (Benefit)	58,427	55,727	66,951
Net Income	127,478	90,919	109,975
Weighted-Average Shares of Common Stock Outstanding (000)
Basic (in shares)	41,618	40,362	36,962
Diluted (in shares)	41,975	41,755	41,609
Earnings Per Share
Basic (in dollars per share)	$ 3.06	$ 2.25	$ 2.98
Diluted (in dollars per share)	$ 3.04	$ 2.20	$ 2.75
Dividends Declared Per Share (usd per share)	$ 1.74	$ 1.72	$ 1.68
TUCSON ELECTRIC POWER COMPANY
Operating Revenues
Electric Retail Sales	934,357	915,879	903,930
Electric Wholesale Sales	132,500	111,194	129,861
Other Revenue	129,833	134,587	122,595
Total Operating Revenues	1,196,690	1,161,660	1,156,386
Operating Expenses
Fuel	325,903	318,901	318,268
Purchased Energy	112,452	80,137	105,766
Transmission and Other PPFAC Recoverable Costs	12,233	5,722	(1,435)
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment	(12,458)	31,113	(6,165)
Total Fuel and Purchased Energy	438,130	435,873	416,434
Operations and Maintenance	335,321	334,553	330,801
Depreciation	118,076	110,931	104,894
Amortization	31,294	39,493	34,650
Taxes Other Than Income Taxes	43,498	40,323	40,199
Total Operating Expenses	966,319	961,173	926,978
Operating Income	230,371	200,487	229,408
Other Income (Deductions)
Interest Income	120	136	3,567
Other Income	5,770	3,953	5,364
Other Expense	(10,715)	(13,574)	(12,064)
Appreciation in Fair Value of Investments	2,833	1,892	329
Total Other Income (Deductions)	(1,992)	(7,593)	(2,804)
Interest Expense [Abstract]
Long-Term Debt	56,378	55,038	49,858
Capital Leases	25,140	33,613	40,358
Other Interest Expense	87	1,446	1,127
Interest Capitalized	(2,554)	(1,782)	(2,073)
Interest Expense	79,051	88,315	89,270
Income Before Income Taxes	149,328	104,579	137,334
Income Tax Expense (Benefit)	47,986	39,109	52,000
Net Income	$ 101,342	$ 65,470	$ 85,334

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended			12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY sqmi	Dec. 31, 2013 UNS Electric	Dec. 31, 2013 UNS Gas	Dec. 31, 2013 Millennium Energy Holdings [Member]	Dec. 31, 2013 Springerville Unit 1 [Member]	Dec. 31, 2013 Springerville Common Facilities [Member]
Nature Of Business And Summary Of Significant Accounting Policies [Line Items]
Percentage of TEP owned by UNS Energy		100.00%
Percentage Of Subsidiary In Companys Asset				83.00%
Retail customers				413,000	93,000	150,000
Area in which subsidiary generates transmits and distributes electricity to retail electric customers				1,155
Investments In Unregulated Businesses As Percentage Of Companys Assets							1.00%
Restricted Cash and Cash Equivalents, Noncurrent		$ 2	$ 7
Capitalized interest	3.30%
Equity Method Investment, Ownership Percentage								14.00%	7.00%

XML

EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Pension Assets) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Actual Return on Plan Assets:
Fair Value Ending Balance	$ 323	$ 289
Level 3 [Member]
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	19	15
Actual Return on Plan Assets:
Assets Held at Reporting Date	2	3
Purchases, Sales, and Settlements	0	1
Fair Value Ending Balance	21	19
Private Equity | Level 3 [Member]
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	6	4
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	1
Purchases, Sales, and Settlements	0	1
Fair Value Ending Balance	7	6
Real Estate | Level 3 [Member]
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items]
Fair Value Beginning Balance	13	11
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	2
Purchases, Sales, and Settlements	0	0
Fair Value Ending Balance	$ 14	$ 13

XML

FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Quantitative Information Regarding Unobservable Inputs) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	$ 7	[1]	$ 7	[1]
Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	4	[1]	5	[1]
Derivative Liability	(6)
Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	1	[2]
Derivative Liability	(4)	[2]
Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	3	[3]
Derivative Liability	(2)	[3]
Minimum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh/MMbtu	26.54
Minimum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh/MMbtu	3.87
Gas Volatility	25.05%
Maximum [Member] | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh/MMbtu	51.75
Maximum [Member] | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price per MWh/MMbtu	4.32
Gas Volatility	35.07%
TUCSON ELECTRIC POWER COMPANY
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	2	[1]	3	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	1	[1]	2	[1]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	1
Derivative Liability	(3)	[2]
TUCSON ELECTRIC POWER COMPANY | Level 3 [Member] | Valuation Technique Option Model [Member] | Options Held [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Assets	$ 1

[1] Energy Contracts include gas swap agreements (Level 2), power options (Level 2 or Level 3), gas options (Level 3), forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below.

[2] TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities.

[3] TEP comprises less than $1 million of the option contract assets.

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Utility Plant
Plant in Service	$ 5,192,122	$ 5,005,768
Utility Plant Under Capital Leases	637,957	582,669
Construction Work in Progress	201,959	128,621
Total Utility Plant	6,032,038	5,717,058
Less Accumulated Depreciation and Amortization	(1,982,524)	(1,921,733)
Less Accumulated Amortization of Capital Lease Assets	(514,677)	(494,962)
Total Utility Plant—Net	3,534,837	3,300,363
Investments And Other Property
Investments in Lease Equity	36,194	36,339
Other	34,971	36,537
Total Investments and Other Property	71,165	72,876
Current Assets
Cash and Cash Equivalents	74,878	123,918
Accounts Receivable—Customer	104,596	93,742
Unbilled Accounts Receivable	52,403	53,568
Allowance for Doubtful Accounts	(6,833)	(6,545)
Materials and Supplies	88,085	93,322
Deferred Income Taxes—Current	59,681	34,260
Fuel Inventory	44,317	62,019
Regulatory Assets—Current	52,763	51,619
Derivative Instruments	5,629	3,165
Investments in Lease Debt	0	9,118
Other	15,354	33,567
Total Current Assets	490,873	551,753
Regulatory and Other Assets
Regulatory Assets—Noncurrent	150,584	191,077
Derivative Instruments	1,180	3,801
Other Assets	24,430	20,559
Total Regulatory and Other Assets	176,194	215,437
Total Assets	4,273,069	4,140,429
Capitalization
Common Stock Equity	1,130,784	1,065,465
Capital Lease Obligations	149,767	262,138
Long-Term Debt	1,507,070	1,498,442
Long-term Debt	1,507,070	1,498,442
Total Capitalization	2,787,621	2,826,045
Current Liabilities
Current Obligations Under Capital Leases	167,659	90,583
Borrowings Under Revolving Credit Facilities	22,000	0
Accounts Payable—Trade	117,503	107,740
Regulatory Liabilities—Current	53,935	43,516
Accrued Taxes Other than Income Taxes	43,880	41,939
Customer Deposits	30,671	34,048
Accrued Employee Expenses	28,148	24,094
Accrued Interest	27,786	31,950
Derivative Instruments	7,534	14,742
Other	17,775	10,517
Total Current Liabilities	516,891	399,129
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	481,662	364,756
Regulatory Liabilities—Noncurrent	302,482	279,111
Pension and Other Retiree Benefits	90,923	159,401
Derivative Instruments	7,100	12,709
Other	86,390	99,278
Total Deferred Credits and Other Liabilities	968,557	915,255
Commitments, Contingencies, and Environmental Matters
Total Capitalization and Other Liabilities	4,273,069	4,140,429
TUCSON ELECTRIC POWER COMPANY
Utility Plant
Plant in Service	4,467,667	4,348,041
Utility Plant Under Capital Leases	637,957	582,669
Construction Work in Progress	180,485	98,460
Total Utility Plant	5,286,109	5,029,170
Less Accumulated Depreciation and Amortization	(1,826,977)	(1,783,787)
Less Accumulated Amortization of Capital Lease Assets	(514,677)	(494,962)
Total Utility Plant—Net	2,944,455	2,750,421
Investments And Other Property
Investments in Lease Equity	36,194	36,339
Other	33,488	35,091
Total Investments and Other Property	69,682	71,430
Current Assets
Cash and Cash Equivalents	25,335	79,743
Accounts Receivable—Customer	80,211	71,813
Unbilled Accounts Receivable	34,369	33,782
Allowance for Doubtful Accounts	(4,825)	(4,598)
Accounts Receivable - Due from Affiliates	6,064	5,720
Materials and Supplies	75,200	80,377
Deferred Income Taxes—Current	63,497	37,212
Fuel Inventory	44,027	61,737
Regulatory Assets—Current	42,555	34,345
Derivative Instruments	2,137	2,230
Investments in Lease Debt	0	9,118
Other	12,923	32,163
Total Current Assets	381,493	443,642
Regulatory and Other Assets
Regulatory Assets—Noncurrent	141,030	178,330
Derivative Instruments	167	1,354
Other Assets	19,233	15,869
Total Regulatory and Other Assets	160,430	195,553
Total Assets	3,556,060	3,461,046
Capitalization
Common Stock Equity	925,923	860,927
Capital Lease Obligations	149,767	262,138
Long-Term Debt	1,223,070
Long-term Debt	1,223,070	1,223,442
Total Capitalization	2,298,760	2,346,507
Current Liabilities
Current Obligations Under Capital Leases	167,659	90,583
Accounts Payable—Trade	88,556	82,122
Regulatory Liabilities—Current	23,701	20,822
Accounts Payable—Due to Affiliates	9,153	3,134
Accrued Taxes Other than Income Taxes	34,485	33,060
Customer Deposits	21,354	24,846
Accrued Employee Expenses	24,454	20,715
Accrued Interest	22,785	26,965
Derivative Instruments	5,531	4,899
Other	9,244	7,085
Total Current Liabilities	406,922	314,231
Deferred Credits and Other Liabilities
Deferred Income Taxes—Noncurrent	420,878	319,216
Regulatory Liabilities—Noncurrent	263,270	241,189
Pension and Other Retiree Benefits	84,936	149,718
Derivative Instruments	5,161	10,565
Other	76,133	79,620
Total Deferred Credits and Other Liabilities	850,378	800,308
Commitments, Contingencies, and Environmental Matters
Total Capitalization and Other Liabilities	$ 3,556,060	$ 3,461,046

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EMPLOYEE BENEFIT PLANS (Pension Plan Asset Allocations) (Detail)	Dec. 31, 2013	Dec. 31, 2012
TUCSON ELECTRIC POWER COMPANY
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	100.00%	100.00%
TUCSON ELECTRIC POWER COMPANY | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	50.00%	50.00%
TUCSON ELECTRIC POWER COMPANY | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	40.00%	41.00%
TUCSON ELECTRIC POWER COMPANY | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	7.00%	7.00%
TUCSON ELECTRIC POWER COMPANY | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	3.00%	2.00%
UNS Gas and UNS Electric [Member]
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	100.00%	100.00%
UNS Gas and UNS Electric [Member] | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	50.00%	56.00%
UNS Gas and UNS Electric [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	40.00%	33.00%
UNS Gas and UNS Electric [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	10.00%	11.00%
UNS Gas and UNS Electric [Member] | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation	0.00%	0.00%

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UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service) (Detail)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY
Public Utility, Property, Plant and Equipment [Line Items]
Generation Plant	22 years
Transmission Plant	32 years
Distribution Plant	35 years
General Plant	11 years
Depreciation Rate	3.16%		3.22%	3.14%
TUCSON ELECTRIC POWER COMPANY | Electric Generation Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	3.31%	[1]
TUCSON ELECTRIC POWER COMPANY | Electric Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	1.48%	[2]
TUCSON ELECTRIC POWER COMPANY | Electric Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.08%	[1]
TUCSON ELECTRIC POWER COMPANY | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	5.48%	[3]
UNS Electric
Public Utility, Property, Plant and Equipment [Line Items]
Generation Plant	36 years
Transmission Plant	19 years
Distribution Plant	15 years
General Plant	7 years
Depreciation Rate	3.94%		3.99%	4.02%
UNS Electric | Electric Generation Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.56%	[2]
UNS Electric | Electric Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	3.36%	[2]
UNS Electric | Electric Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	3.97%	[2]
UNS Electric | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	8.01%	[2]
UNS Gas
Public Utility, Property, Plant and Equipment [Line Items]
Generation Plant	41 years
Transmission Plant	54 years
General Plant	7 years
Depreciation Rate	2.63%		2.69%	2.84%
UNS Gas | Electric Generation Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	2.37%	[2]
UNS Gas | Gas Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	1.54%	[2]
UNS Gas | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Rate	4.38%	[2]

[1] In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.

[2] The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.

[3] Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.

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SHARE-BASED COMPENSATION PLANS (Summary of Stock Option Activity) (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Shares
Outstanding, Beginning balance	409	581	921
Exercised, Shares	(127)	(132)	(319)
Forfeited/Expired, Shares	0	(40)	(21)
Outstanding, Ending balance	282	409	581
Exercisable, End of Year, Shares	282	409	508
Weighted Average Exercise Price
Outstanding, Beginning balance	$ 29.09	$ 29.11	$ 27.96
Exercised	$ 30.12	$ 26.54	$ 25.60
Forfeited/Expired	$ 0.00	$ 37.88	$ 31.92
Outstanding, Ending balance	$ 28.63	$ 29.09	$ 29.11
Exercisable, End of Year	$ 28.63	$ 29.09	$ 29.53
Aggregate Intrinsic Value of Options Exercised ($000s)	$ 2,897	$ 1,878	$ 3,690
Aggregate Intrinsic Value for Options Outstanding ($000s)	8,795
Aggregate Intrinsic Value for Options Exercisable ($000s)	$ 8,795
Weighted Average Remaining Contractual Term of Outstanding Options	4 years 1 month 6 days
Weighted Average Remaining Contractual Term of Exercisable Options	4 years 1 month 6 days
$26.11 - $37.88 [Member]
Shares
Outstanding, Ending balance	282
Exercisable, End of Year, Shares	282
Weighted Average Exercise Price
Outstanding, Ending balance	$ 28.63
Exercisable, End of Year	$ 28.63
Weighted Average Remaining Contractual Term of Outstanding Options	4 years 1 month 6 days

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Interest Rates on TEP's Variable Rate

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

	Years Ended December 31,
	2013	2012	2011
Interest Rates on Bonds:
Average Interest Rate	0.10%	0.17%	0.18%
Range of Average Weekly Rates	0.06% - 0.25%	0.06% - 0.26%	0.05% - 0.34%

Effect Of Fixing Interest Rates On Amortizing Principal Balances Of Swaps

The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

Lease Debt Outstanding at December 31, 2013	Fixed Rate		LIBOR Spread
Swap 1 - Notional Amount $33 million - Effective Date June 2006	5.77	%	1.75	%
Swap 2 - Notional Amount $16 million - Effective Date May 2009	3.18	%	1.75	%
Swap 3 - Notional Amount $6 million - Effective Date May 2009	3.32	%	1.75	%

TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 15.

Maturities of Long-term Debt

Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:

	TEP Long-Term Debt Maturities (1)		TEP Capital Lease Obligations			TEP Total			UNS Electric		UNS Gas		UNS Energy Parent Company		Total
	Millions of Dollars
2014	$	—	$	214		$	214		$	—	$	—	$	—	$	214
2015	—		69			69			80		50		—		199
2016	78		17			95			—		—		54		149
2017	—		18			18			—		—		—		18
2018	100		11			111			—		—		—		111
Total 2014 – 2018	178		329			507			80		50		54		691
Thereafter	1,046		30			1,076			50		50		—		1,176
Less: Imputed Interest	—		(42		)	(42		)	—		—		—		(42		)
Total	$	1,224	$	317		$	1,541		$	130	$	100	$	54	$	1,825

⁽¹⁾  $115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (TEP Capital Lease) (Details) (USD $)	12 Months Ended						1 Months Ended			12 Months Ended		12 Months Ended			1 Months Ended				1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY	Oct. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Unit One Lease [Member] MW	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Unit One Lease [Member] MW	Aug. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Unit One Lease [Member] MW	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Coal Handling Facilities Lease [Member]	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Common Facilities [Member] lease	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Common Facility Lease Part One [Member]	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Springerville Common Facility Lease Part Two [Member]	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY Springerville Common Facilities Lease Debt [Member]	Jan. 31, 2013 Springerville Unit One Lease Debt [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Springerville Unit One Lease Debt [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 Springerville Unit One Lease Debt [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Springerville Common Facilities Lease Debt [Member] TUCSON ELECTRIC POWER COMPANY	Jan. 31, 2014 Subsequent Event [Member]
Debt Instrument [Line Items]
Increase in Capital Lease Obligation							$ 55,000,000
Repayments of Long-term Capital Lease Obligations	99,621,000	89,452,000	74,381,000	99,621,000	89,452,000	74,343,000													80,000,000
Equity method investment, aggregate cost																36,000,000	36,000,000
Derivative basis spread														1.75%				1.75%
Lease arrangement, purchase price per kW								478
Generating capacity in jointly owned facility, in MWs								387
Percentage of interest committed to purchase							0.106		0.248
Generating capacity purchased, in MWs							41	192	96
Lease arrangement, fair market value purchase price							20,000,000		46,000,000
Percentage of interest owned after close of purchases							0.495
Increase in utility plant under capital lease							55,000,000
Fixed price to acquire leased interest in facilities										120,000,000		38,000,000	68,000,000
Proceeds from collection of lease receivables															$ 9,000,000
Lease renewal period										6 years	2 years
Additional renewal period										5 years
Number of operating lease											2

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UNS ENERGY EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

UNS ENERGY EARNINGS PER SHARE

UNS ENERGY EARNINGS PER SHARE

We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options, share-based compensation awards, or UNS Energy's Convertible Senior Notes were exercised or converted into Common Stock. We excluded anti-dilutive stock options and contingently issuable shares from the calculation of diluted EPS. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the notes were converted to Common Stock.

The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:

	Years Ended December 31,
	2013		2012		2011
	Thousands of Dollars
Numerator:
Net Income	$	127,478	$	90,919	$	109,975
Income from Assumed Conversion of Convertible Senior Notes (1)	—		1,100		4,390
Adjusted Net Income Available for Diluted Common Stock Outstanding	$	127,478	$	92,019	$	114,365
	Thousands of Shares
Denominator:
Weighted Average Shares of Common Stock Outstanding:
Common Shares Issued	41,446		40,212		36,780
Fully Vested Deferred Stock Units	172		150		129
Participating Securities	—		—		53
Total Weighted Average Common Stock Outstanding and Participating Securities—Basic	41,618		40,362		36,962
Effect of Dilutive Securities:
Convertible Senior Notes (1)	—		1,062		4,281
Options and Stock Issuable Under Share-Based Compensation Plans	357		331		366
Total Weighted Average Common Stock Outstanding —Diluted	41,975		41,755		41,609

⁽¹⁾ In 2012, the Convertible Senior Notes were converted to Common Stock or redeemed for cash.

We excluded the following outstanding stock options, with an exercise price above market, and contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive:

	Years Ended December 31,
	2013	2012	2011
	Thousands of Shares
Stock Options	—	50	153
Restricted Stock Units	6	—	—
Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	50	153

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COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Unrecorded Unconditional Purchase Obligations Disclosure

At December 31, 2013, UNS Energy and TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases. UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas:

	UNS Energy Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	103	$	83	$	80	$	75	$	49	$	345	$	735
Purchased Power	75		17		—		—		—		—		92
Transmission	7		13		12		12		11		27		82
Renewable Power Purchase Agreements	36		37		37		37		37		485		669
RES Performance-Based Incentives	9		9		9		9		9		85		130
Operating Leases	4		4		3		2		2		14		29
Total Purchase Commitments	$	234	$	163	$	141	$	135	$	108	$	956	$	1,737

At December 31, 2013, TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases:

	TEP Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	77	$	63	$	64	$	62	$	36	$	285	$	587
Purchased Power	27		5		—		—		—		—		32
Transmission	3		6		6		6		6		21		48
Renewable Power Purchase Agreements	30		31		31		31		31		410		564
RES Performance-Based Incentives	8		8		8		8		8		83		123
Operating Leases	3		3		2		2		2		14		26
Total Purchase Commitments	$	148	$	116	$	111	$	109	$	83	$	813	$	1,380

Schedule of Environmental Loss Contingencies by Site

TEP's estimated potential costs involved in meeting these rules are:

Estimated Potential Emissions Control Costs:	Navajo (1)		San Juan (2)	Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital - SCR	$	42	$ 180-200	$	35	$	—
Capital - SNCR	—		35	—		12
Annual O&M - SCR	1		6	2		—
Annual O&M - SNCR	—		1	—		5-6

⁽¹⁾ The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾ The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

⁽³⁾ On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾ In January 2014, the EPA issued a proposal that would require TEP to either (i) install SNCR by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is expected to issue a final BART determination by July 2014. At December 31, 2013, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATs) rule, additional emission control equipment will be required by 2015. The estimated costs include:

Estimated Emissions Control Costs:	Navajo		Four Corners		Springerville
	Millions of Dollars
Capital Expenditures - Mercury Emissions Control	$	1	$	1	$	5
Annual O&M Expenses	1		1		3

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EMPLOYEE BENEFIT PLANS (Benefit Payments by Defined Pension Plans and Retiree Plan) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2014	$ 15
2015	16
2016	17
2017	18
2018	20
Years 2019-2023	114
Other Retiree Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2014	5
2015	5
2016	5
2017	5
2018	5
Years 2019-2023	$ 29

XML

SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:

	UNS Energy
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Net Income	$	127,478		$	90,919		$	109,975
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense	149,615			141,303			133,832
Amortization Expense	27,557			35,784			30,983
Depreciation and Amortization Recorded to Fuel and O&M Expense	7,288			6,622			6,140
Amortization of Deferred Debt-Related Costs included in Interest Expense	3,050			3,000			3,985
Provision for Retail Customer Bad Debts	2,263			2,767			2,072
Use of Renewable Energy Credits for Compliance	17,706			5,935			5,695
Deferred Income Taxes	83,501			60,264			75,515
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—			—
Pension and Retiree Expense	22,783			21,856			21,202
Pension and Retiree Funding	(29,161		)	(29,058		)	(28,775		)
Share-Based Compensation Expense	3,399			2,573			2,599
Allowance for Equity Funds Used During Construction	(6,190		)	(3,464		)	(4,496		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(16,313		)	32,246			(4,932		)
PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
Competition Transition Charge Revenue Refunded	—			—			(35,958		)
Partial Write-off of Tucson to Nogales Transmission Line	—			4,668			—
Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,338		)	3,369			2,743
Materials and Fuel Inventory	16,197			(39,429		)	(20,864		)
Accounts Payable	3,223			595			8,792
Income Taxes	(15,868		)	(11,557		)	(2,739		)
Interest Accrued	4,875			6,922			14,344
Taxes Other Than Income Taxes	1,941			(58		)	2,857
Current Regulatory Liabilities	11,124			(684		)	2,644
Other	20,421			11,486			19,097
Net Cash Flows – Operating Activities	$	420,512		$	348,109		$	337,320

	TEP
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Net Income	$	101,342		$	65,470		$	85,334
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	118,076			110,931			104,894
Amortization Expense	31,294			39,493			34,650
Depreciation and Amortization Recorded to Fuel and O&M Expense	6,219			5,384			4,509
Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,452			2,227			2,378
Provision for Retail Customer Bad Debts	1,678			1,871			1,447
Use of RECs for Compliance	15,990			5,071			5,190
Deferred Income Taxes	69,950			45,232			59,309
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—			—
Pension and Retiree Expense	19,878			19,289			18,816
Pension and Retiree Funding	(27,636		)	(25,899		)	(25,878		)
Share-Based Compensation Expense	2,709			2,029			2,027
Allowance for Equity Funds Used During Construction	(4,526		)	(2,840		)	(3,842		)
Increase (Decrease) to Reflect PPFAC Recovery	(12,458		)	31,113			(6,165		)
PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
Competition Transition Charge Revenue Refunded	—			—			(35,958		)
Partial Write-off of Tucson to Nogales Transmission Line	—			4,484			—
Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,041		)	(871		)	4,809
Materials and Fuel Inventory	16,145			(38,384		)	(19,789		)
Accounts Payable	334			1,115			14,561
Income Taxes	(10,790		)	(11,421		)	(5,582		)
Interest Accrued	4,859			8,055			14,268
Taxes Other Than Income Taxes	1,425			905			2,282
Current Regulatory Liabilities	3,331			(3,040		)	303
Other	19,711			5,655			18,122
Net Cash Flows – Operating Activities	$	346,191		$	267,919		$	268,294

NON-CASH TRANSACTIONS

In 2013, the following non-cash transactions occurred:

• TEP recorded an increase of $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in December 2014 and January 2015. See Note 6.

• In November 2013, TEP issued $100 million of tax-exempt bonds and the proceeds were deposited with the trustee to redeem debt in December 2013. TEP had no cash receipts or payments as a result of this transaction. See Note 6.

• In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. See Note 6.

In 2012, the following non-cash transactions occurred:

• UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Shares. See Note 6; and

• TEP redeemed $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. See Note 6.

Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
	2013		2012		2011
	Thousands of Dollars
(Decrease)/Increase to Utility Plant Accruals(1)	$	4,995	$	4,813	$	(2,741	)
Net Cost of Removal of Interim Retirements(2)	25,182		35,983		31,626
Capital Lease Obligations(3)	9,039		11,967		15,162
Asset Retirement Obligations(4)	8,064		789		7,638

⁽¹⁾  The non-cash additions to Utility Plant represent accruals for capital expenditures.

⁽²⁾  The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.

⁽³⁾  The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.

⁽⁴⁾  The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) (USD $) In Thousands, unless otherwise specified											12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 UNS Gas	Dec. 31, 2013 UNS ELECTRIC, INC.	Dec. 31, 2013 UNS Energy	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Capital Lease Obligations [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Long-term Debt [Member] TUCSON ELECTRIC POWER COMPANY		Dec. 31, 2013 Variable Rate Bonds [Member] Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY
Schedule Of Maturities Of Long Term Debt [Line Items]
Term of debt instruments											5 years
2014	$ 214		$ 0	$ 0	$ 0	$ 214		$ 214	$ 0	[1]
2015	199		50	80	0	69		69	0	[1]
2016	149		0	0	54	95		17	78	[1]
2017	18		0	0	0	18		18	0	[1]
2018	111		0	0	0	111		11	100	[1]
Total 2014 - 2018	691		50	80	54	507		329	178	[1]
Thereafter	1,176		50	50	0	1,076		30	1,046	[1]
Less: Imputed Interest	(42)		0	0	0	(42)		(42)	0	[1]
Long-term Debt and Capital Lease Obligations	1,825					1,541
Total	$ 1,507,070	$ 1,498,442	$ 100	$ 130	$ 54	$ 1,223,070	$ 1,223,442	$ 317	$ 1,224	[1]

[1] $115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

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SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) (USD $)	12 Months Ended								1 Months Ended	12 Months Ended		1 Months Ended			12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2013 UNS Energy	Dec. 31, 2012 UNS Energy	Oct. 31, 2013 Springerville Unit One Lease [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 Convertible Debt [Member] UNS Energy	Dec. 31, 2005 Convertible Debt [Member] UNS Energy	Apr. 30, 2013 Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2012 Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY	Mar. 31, 2012 Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY	Mar. 31, 2013 Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY	Sep. 30, 2012 Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY	Nov. 30, 2013 Variable Rate Bonds [Member] Unsecured Debt [Member] TUCSON ELECTRIC POWER COMPANY
Document Fiscal Year Focus	2013
Increase in Capital Lease Obligation									$ 55,000,000
Debt instrument, face amount											150,000,000		16,000,000	177,000,000		91,000,000	150,000,000	100,000,000
Debt extinguishment												91,000,000	16,000,000	184,000,000	193,000,000
Converted Notes principal										147,000,000
(Decrease)/Increase to Utility Plant Accruals	4,995,000	[1]	4,813,000	[1]	(2,741,000)	[1]
Net Cost Of Removal Of Interim Retirements	25,182,000	[2]	35,983,000	[2]	31,626,000	[2]
Change In Capital Lease Obligations	9,039,000	[3]	11,967,000	[3]	15,162,000	[3]
Asset Retirement Obligations	$ 8,064,000	[4]	$ 789,000	[4]	$ 7,638,000	[4]	$ 1,000,000	$ 0

[1] The non-cash additions to Utility Plant represent accruals for capital expenditures.

[2] The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.

[3] The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.

[4] The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	75,000,000	75,000,000
Common Stock, Shares, Outstanding	41,538,343	41,343,851
COMMON STOCK EQUITY
Common Stock-No Par Value	$ 889,301	$ 882,138
Accumulated Deficit	247,532	193,117
Accumulated Other Comprehensive Loss	(6,049)	(9,790)
Total Common Stock Equity	1,130,784	1,065,465
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding	0	0
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	317,426	352,721
Less Current Maturities	(167,659)	(90,583)
Total Long-Term Capital Lease Obligations	149,767	262,138
LONG-TERM DEBT
Long-term Debt	1,507,070	1,498,442
Total Capitalization	2,787,621	2,826,045
Springerville Unit 1 [Member]
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	192,871	196,843
Springerville Coal Handling Facilities [Member]
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	27,878	48,038
Springerville Common Facilities [Member]
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	96,677	107,840
Parent [Member] | Line of Credit [Member]
LONG-TERM DEBT
Long-term Debt	54,000	45,000
TUCSON ELECTRIC POWER COMPANY
Common Stock, Shares Authorized	75,000,000	75,000,000
Common Stock, Shares, Outstanding	32,139,434	32,139,434
COMMON STOCK EQUITY
Common Stock-No Par Value	888,971	888,971
Capital Stock Expense	(6,357)	(6,357)
Accumulated Deficit	49,185	(12,157)
Accumulated Other Comprehensive Loss	(5,876)	(9,530)
Total Common Stock Equity	925,923	860,927
PREFERRED STOCK
No Par Value, 1,000,000 Shares Authorized, None Outstanding	0	0
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	317,426	352,721
Less Current Maturities	(167,659)	(90,583)
Total Long-Term Capital Lease Obligations	149,767	262,138
LONG-TERM DEBT
Long-term Debt	1,223,070	1,223,442
Total Capitalization	2,298,760	2,346,507
TUCSON ELECTRIC POWER COMPANY | Springerville Unit 1 [Member]
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	192,871	196,843
TUCSON ELECTRIC POWER COMPANY | Springerville Coal Handling Facilities [Member]
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	27,878	48,038
TUCSON ELECTRIC POWER COMPANY | Springerville Common Facilities [Member]
CAPITAL LEASE OBLIGATIONS
Capital Lease Obligations	96,677	107,840
UNS ELECTRIC, INC.
LONG-TERM DEBT
Long-term Debt	130
Unsecured Fixed Rate Bonds [Member] | TUCSON ELECTRIC POWER COMPANY
LONG-TERM DEBT
Long-term Debt	1,008,268	1,008,142
Variable Rate Tax-Exempt Bonds [Member] | TUCSON ELECTRIC POWER COMPANY
LONG-TERM DEBT
Long-term Debt	214,802	215,300
Unsecured Debt [Member] | TUCSON ELECTRIC POWER COMPANY
LONG-TERM DEBT
Long-term Debt	1,008,268	1,008,142
Unsecured Debt [Member] | UNS Gas and UNS Electric [Member]
LONG-TERM DEBT
Long-term Debt	200,000	200,000
Uns Electric Term Loan [Member] | UNS ELECTRIC, INC.
LONG-TERM DEBT
Long-term Debt	$ 30,000	$ 30,000
Minimum [Member] | Unsecured Debt [Member] | TUCSON ELECTRIC POWER COMPANY
LONG-TERM DEBT
Fixed interest rate of Long-Term Debt	3.85%
Minimum [Member] | Unsecured Debt [Member] | UNS Gas and UNS Electric [Member]
LONG-TERM DEBT
Fixed interest rate of Long-Term Debt	5.39%
Maximum [Member] | Unsecured Debt [Member] | TUCSON ELECTRIC POWER COMPANY
LONG-TERM DEBT
Fixed interest rate of Long-Term Debt	5.75%
Maximum [Member] | Unsecured Debt [Member] | UNS Gas and UNS Electric [Member]
LONG-TERM DEBT
Fixed interest rate of Long-Term Debt	7.10%

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	$ 1,208,967,000	$ 1,197,390,000	$ 1,163,537,000
Cash Receipts from Electric Wholesale Sales	160,947,000	149,722,000	183,151,000
Cash Receipts from Gas Retail Sales	138,775,000	141,590,000	159,529,000
Cash Receipts from Operating Springerville Units 3 & 4	114,258,000	107,927,000	104,754,000
Cash Receipts from Gas Wholesale Sales	3,740,000	5,233,000	12,404,000
Interest Received	517,000	2,947,000	6,334,000
Income Tax Refunds Received	11,000	1,821,000	4,672,000
Performance Deposits Received	0	200,000	7,050,000
Other Cash Receipts	35,142,000	24,105,000	23,937,000
Fuel Costs Paid	(285,812,000)	(321,355,000)	(277,386,000)
Purchased Energy Costs Paid	(280,920,000)	(250,231,000)	(328,713,000)
Payment of Operations and Maintenance Costs	(260,453,000)	(291,512,000)	(295,662,000)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(182,488,000)	(187,257,000)	(179,766,000)
Wages Paid, Net of Amounts Capitalized	(131,710,000)	(127,176,000)	(122,370,000)
Interest Paid, Net of Amounts Capitalized	(66,610,000)	(69,478,000)	(68,027,000)
Capital Lease Interest Paid	(22,553,000)	(28,788,000)	(32,103,000)
Income Taxes Paid	(316,000)	0	(700,000)
Performance Deposits Paid	0	(200,000)	(4,550,000)
Wholesale Gas Costs Paid	0	0	(11,822,000)
Other Cash Payments	(10,983,000)	(6,829,000)	(6,949,000)
Net Cash Flows—Operating Activities	420,512,000	348,109,000	337,320,000
Cash Flows from Investing Activities
Capital Expenditures	(325,886,000)	(307,277,000)	(374,122,000)
Purchase of Intangibles—Renewable Energy Credits	(26,948,000)	(10,317,000)	(5,992,000)
Return of Investments in Springerville Lease Debt	9,104,000	19,278,000	38,353,000
Change in Restricted Cash	4,134,000	(1,445,000)	0
Proceeds from Note Receivable	0	15,000,000	0
Other, net	5,786,000	21,862,000	14,673,000
Net Cash Flows—Investing Activities	(333,810,000)	(262,899,000)	(327,088,000)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	139,000,000	359,000,000	391,000,000
Repayments of Borrowings Under Revolving Credit Facilities	(108,000,000)	(381,000,000)	(351,000,000)
Payments of Capital Lease Obligations	(99,621,000)	(89,452,000)	(74,381,000)
Common Stock Dividends Paid	(72,234,000)	(69,648,000)	(61,904,000)
Proceeds from Stock Options Exercised	3,831,000	3,570,000	8,115,000
Proceeds from Common Stock Issuance	464,000	0	0
Proceeds from Issuance of Long-Term Debt	0	149,513,000	340,285,000
Repayments of Long-Term Debt	0	(9,341,000)	(252,125,000)
Equity Investment from UNS Energy	0	0	30,000,000
Other, net	818,000	(324,000)	(1,431,000)
Net Cash Provided by (Used in) Financing Activities	(135,742,000)	(37,682,000)	(1,441,000)
Cash and Cash Equivalents, Period Increase (Decrease)	(49,040,000)	47,528,000	8,791,000
Cash and Cash Equivalents, Beginning of Period	123,918,000	76,390,000	67,599,000
Cash and Cash Equivalents, End of Period	74,878,000	123,918,000	76,390,000
TUCSON ELECTRIC POWER COMPANY
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales	1,020,903,000	1,006,926,000	963,247,000
Cash Receipts from Electric Wholesale Sales	146,880,000	124,594,000	152,618,000
Cash Receipts from Operating Springerville Units 3 & 4	114,258,000	107,927,000	104,754,000
Reimbursement of Affiliate Charges	23,468,000	20,926,000	18,448,000
Cash Receipts from Gas Wholesale Sales	3,271,000	4,652,000	11,825,000
Interest Received	509,000	2,025,000	5,367,000
Income Tax Refunds Received	77,000	493,000	7,492,000
Other Cash Receipts	25,079,000	18,850,000	19,611,000
Fuel Costs Paid	(280,639,000)	(313,742,000)	(271,975,000)
Payment of Operations and Maintenance Costs	(253,054,000)	(282,752,000)	(287,615,000)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized	(144,849,000)	(147,859,000)	(139,728,000)
Purchased Power Costs Paid	(115,008,000)	(81,328,000)	(117,224,000)
Wages Paid, Net of Amounts Capitalized	(110,995,000)	(104,955,000)	(100,942,000)
Interest Paid, Net of Amounts Capitalized	(52,589,000)	(52,125,000)	(45,433,000)
Capital Lease Interest Paid	(22,553,000)	(28,786,000)	(32,103,000)
Income Taxes Paid	0	(1,796,000)	(2,346,000)
Wholesale Gas Costs Paid	0	0	(11,822,000)
Other Cash Payments	(8,567,000)	(5,131,000)	(5,880,000)
Net Cash Flows—Operating Activities	346,191,000	267,919,000	268,294,000
Cash Flows from Investing Activities
Capital Expenditures	(252,848,000)	(252,782,000)	(351,890,000)
Purchase of Intangibles—Renewable Energy Credits	(23,280,000)	(8,889,000)	(5,111,000)
Return of Investments in Springerville Lease Debt	9,104,000	19,278,000	38,353,000
Change in Restricted Cash	4,134,000	(1,445,000)	0
Other, net	3,228,000	15,957,000	6,637,000
Net Cash Flows—Investing Activities	(259,662,000)	(227,881,000)	(312,011,000)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	78,000,000	189,000,000	220,000,000
Repayments of Borrowings Under Revolving Credit Facilities	(78,000,000)	(199,000,000)	(210,000,000)
Payments of Capital Lease Obligations	(99,621,000)	(89,452,000)	(74,343,000)
Dividends Paid to UNS Energy	(40,000,000)	(30,000,000)	0
Proceeds from Issuance of Long-Term Debt	0	149,513,000	260,285,000
Repayments of Long-Term Debt	0	(6,535,000)	(172,460,000)
Equity Investment from UNS Energy	0	0	30,000,000
Other, net	(1,316,000)	(1,539,000)	(2,030,000)
Net Cash Provided by (Used in) Financing Activities	(140,937,000)	11,987,000	51,452,000
Cash and Cash Equivalents, Period Increase (Decrease)	(54,408,000)	52,025,000	7,735,000
Cash and Cash Equivalents, Beginning of Period	79,743,000	27,718,000	19,983,000
Cash and Cash Equivalents, End of Period	$ 25,335,000	$ 79,743,000	$ 27,718,000

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COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS

COMMITMENTS

At December 31, 2013, UNS Energy and TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases. UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas:

	UNS Energy Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	103	$	83	$	80	$	75	$	49	$	345	$	735
Purchased Power	75		17		—		—		—		—		92
Transmission	7		13		12		12		11		27		82
Renewable Power Purchase Agreements	36		37		37		37		37		485		669
RES Performance-Based Incentives	9		9		9		9		9		85		130
Operating Leases	4		4		3		2		2		14		29
Total Purchase Commitments	$	234	$	163	$	141	$	135	$	108	$	956	$	1,737

At December 31, 2013, TEP had the following firm, non-cancelable, minimum purchase obligations and operating leases:

	TEP Purchase Commitments
	2014		2015		2016		2017		2018		Thereafter		Total
	Millions of Dollars
Fuel, Including Transportation	$	77	$	63	$	64	$	62	$	36	$	285	$	587
Purchased Power	27		5		—		—		—		—		32
Transmission	3		6		6		6		6		21		48
Renewable Power Purchase Agreements	30		31		31		31		31		410		564
RES Performance-Based Incentives	8		8		8		8		8		83		123
Operating Leases	3		3		2		2		2		14		26
Total Purchase Commitments	$	148	$	116	$	111	$	109	$	83	$	813	$	1,380

Fuel

TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more than the minimum purchase obligations to meet its fuel requirements. TEP's fuel costs are recoverable from customers through the PPFAC.

UNS Gas purchases gas from various supplies at market prices. However, UNS Gas' risk of loss due to increased costs is mitigated through the use of the PGA, which provides for the pass-through of actual commodity costs to customers. UNS Gas' forward gas purchase agreements expire through 2016. Certain of these contracts are at a fixed price per Million British Thermal Units (MMbtu) and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected marked prices as of December 31, 2013. UNS Gas has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2016 and 2023.

Purchased Power and Transmission

TEP and UNS Electric have agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire in 2014 and 2015. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2013.

TEP has agreements with other utilities to provide transmission services. These contracts expire in various years between 2018 and 2028. UNS Electric imports the power it purchases over the Western Area Power Administration's (WAPA) transmission lines. UNS Electric's transmission capacity agreements with WAPA provide for annual rate adjustments and expire in 2016.

TEP's and UNS Electric's purchased power and transmission costs are recoverable from customers through their respective PPFAC mechanisms.

Renewable Power Purchase Agreements and RES Performance-Based Incentives

TEP and UNS Electric have entered into 20 year Renewable Power Purchase Agreements (PPAs) which require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. TEP has entered into additional long-term renewable PPAs to comply with RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 3.

TEP and UNS Electric have entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 3.

Operating Leases

Our operating lease expense is primarily for rail cars, office facilities, land easements, and rights of way with varying terms, provisions, and expiration dates. UNS Energy's operating lease expense totaled $3 million in each of 2013, 2012, and 2011, and TEP's operating lease expense totaled $2 million in each of 2013, 2012, and 2011.

TEP CONTINGENCIES

Potential Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility; see Note 8.

Claim Related to San Juan Generating Station

San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.

Claims Related to Four Corners Generating Station

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The joint participants have applied to have the matter stayed until March 17, 2014 in furtherance of settlement talks.

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.

In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. The coal supplier and Four Corners’ operating agent intend to contest the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. TEP cannot predict the outcome or timing of resolution of this claim.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $18 million at December 31, 2013 and $16 million at December 31, 2012.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows us to pass through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

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. 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 Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. See Note 3. 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.

Performance Guarantees

The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. TEP's joint participation agreements expire in 2016 through 2046.

UNS ELECTRIC CONTINGENCIES

Potential Purchase of Gas-Fired Generation Facility

In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 8.

ENVIRONMENTAL MATTERS

Environmental Regulation

The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $5 million in 2013, $2 million in 2012, and $8 million in 2011 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $12 million in 2014 and $36 million in 2015. In addition, TEP recorded O&M expenses of $8 million in 2013, $15 million in 2012, and $12 million in 2011. TEP expects environmental O&M expenses to be $5 million in each of 2014 and 2015.

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.

Hazardous Air Pollutant Requirements

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATs) rule, additional emission control equipment will be required by 2015. The estimated costs include:

Estimated Emissions Control Costs:	Navajo		Four Corners		Springerville
	Millions of Dollars
Capital Expenditures - Mercury Emissions Control	$	1	$	1	$	5
Annual O&M Expenses	1		1		3

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

Regional Haze Rules

The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility 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. 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.

In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install SCRs. Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.

TEP's estimated potential costs involved in meeting these rules are:

Estimated Potential Emissions Control Costs:	Navajo (1)		San Juan (2)	Four Corners (3)		Sundt (4)
	Millions of Dollars
Capital - SCR	$	42	$ 180-200	$	35	$	—
Capital - SNCR	—		35	—		12
Annual O&M - SCR	1		6	2		—
Annual O&M - SNCR	—		1	—		5-6

⁽¹⁾ The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR installation (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. The additional capital cost of baghouses approximates $43 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾ The Federal Implementation Plan (FIP) requires SCR; as part of a proposal for an alternative, PNM, the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 & 3 by December 31, 2017 and install SNCRs on Units 1 & 4 by January 2016 or later. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At December 31, 2013, the net book value of TEP's share in San Juan Unit 2 was $113 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit.

⁽³⁾ On December 30, 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen the alternative BART compliance strategy; APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾ In January 2014, the EPA issued a proposal that would require TEP to either (i) install SNCR by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is expected to issue a final BART determination by July 2014. At December 31, 2013, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.

BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the plant was built after the BART-applicable dates.

XML

SHARE-BASED COMPENSATION PLANS (Additional Information) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation expense, net of amounts capitalized	$ 3,000,000	$ 3,000,000	$ 3,000,000
Tax deduction realized from exercise of share-based payment arrangements	0	500,000	0
Total unrecognized compensation expense on non-vested share-based compensation	3,000,000
Number of shares awarded but not yet issued under share based compensation arrangements	500,000
TUCSON ELECTRIC POWER COMPANY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation expense, net of amounts capitalized		$ 2,000,000	$ 2,000,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares that vested during the period	16,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares that vested during the period	52,000
Omnibus Stock And Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grants under the 2011 Plan	1,200,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock shares issued	57,253	31,058	56,705
Dividend Equivalents [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares that vested during the period	8,521

XML

EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Line Items]
Effect of one percentage point increase on service and interest cost components	$ 1
Effect of one percentage point decrease on service and interest cost components	(1)
Effect on Retiree Benefit Obligation, One-Percentage-Point Increase	6
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease	$ (5)

XML

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Rate of Compensation Increase	3.00%	3.00%
Expected Return on Plan Assets	7.00%	7.00%	7.00%
Pension Benefits [Member] | Minimum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	4.10%	4.90%	5.50%
Rate of Compensation Increase			3.00%
Pension Benefits [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	4.30%	5.00%	5.60%
Rate of Compensation Increase			5.00%
Other Retiree Benefits [Member]
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount Rate	3.80%	4.70%	5.20%
Expected Return on Plan Assets	7.00%	7.00%	5.10%

XML

SCHEDULE II - Valuation and Qualifying Accounts (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended							12 Months Ended
	Dec. 31, 2013 Allowance for Doubtful Accounts [Member]	Dec. 31, 2012 Allowance for Doubtful Accounts [Member]	Dec. 31, 2011 Allowance for Doubtful Accounts [Member]	Dec. 31, 2013 Other Valuation Allowance [Member]	Dec. 31, 2012 Other Valuation Allowance [Member]	Dec. 31, 2011 Other Valuation Allowance [Member]	Dec. 31, 2010 Other Valuation Allowance [Member]	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Allowance for Doubtful Accounts [Member]		Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY Allowance for Doubtful Accounts [Member]		Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY Allowance for Doubtful Accounts [Member]		Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Other Valuation Allowance [Member]		Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY Other Valuation Allowance [Member]		Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY Other Valuation Allowance [Member]		Dec. 31, 2010 TUCSON ELECTRIC POWER COMPANY Other Valuation Allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance	$ 7	$ 16	$ 13	$ 6	$ 9	$ 6	$ 4	$ 5	[1]	$ 14	[1]	$ 11	[1]	$ 4	[2]	$ 8	[2]	$ 4	[2]	$ 3	[2]
Additions-Charged to Income	2	4	5					2	[1]	3	[1]	4	[1]
Deductions	2	13	2					2	[1]	12	[1]	1	[1]
Ending Balance	$ 7	$ 7	$ 16	$ 6	$ 9	$ 6	$ 4	$ 5	[1]	$ 5	[1]	$ 14	[1]	$ 4	[2]	$ 8	[2]	$ 4	[2]	$ 3	[2]

[1] TEP, UNS Electric, and UNS Gas record additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances.

[2] As the Other reserves are not individually significant, additions and deductions need not be disclosed. Principally reserves for sales tax audits, litigation matters, and damages billable to third parties.

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Trading Symbol	UNS
Entity Registrant Name	UNS Energy Corp
Entity Central Index Key	0000941138
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filer	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		41,633,535
Entity Public Float			$ 1,855,552,035
TUCSON ELECTRIC POWER COMPANY
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filer	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		32,139,434

XML

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY

12 Months Ended

Dec. 31, 2013

Potential Purchase of Gas-Fired Generation Facility [Abstract]

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY

POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY

On December 23, 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Generating Station Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to regulatory approvals and other closing conditions. In December 2013, UNS Electric filed an application for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3.

TEP expects to provide a letter of credit in March 2014 for $15 million to satisfy a condition of the purchase agreement. The seller of Gila River Unit 3 would be entitled to draw upon the letter of credit and apply such amount as liquidated damages if it has validly terminated the Purchase Agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the letter of credit would be canceled.

XML

INCOME TAXES (Uncertain Tax Positions) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Feb. 28, 2013	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning of Year		$ 30	$ 29
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions		2	5
Reductions Based on Settlements with Tax Authorities	(28)	(28)	(4)
Unrecognized Tax Benefits, End of Year		4	30
TUCSON ELECTRIC POWER COMPANY
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning of Year		23	24
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions		1	3
Reductions Based on Settlements with Tax Authorities	(22)	(22)	(4)
Unrecognized Tax Benefits, End of Year		$ 2	$ 23

XML

EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Detail)	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Rate of Compensation Increase	3.00%	3.00%
Pension Benefits [Member] | Minimum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	5.00%	4.10%
Pension Benefits [Member] | Maximum [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	5.20%	4.30%
Other Retiree Benefits [Member]
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	4.70%	3.80%

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Income	$ 127,478	$ 90,919	$ 109,975
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit	2,825	1,134	(1,473)
SERP Benefit Amortization, net of income tax (expense) benefit	916	(840)	1,158
Total Other Comprehensive Income (Loss), Net of Tax	3,741	294	(315)
Total Comprehensive Income	131,219	91,213	109,660
TUCSON ELECTRIC POWER COMPANY
Net Income	101,342	65,470	85,334
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit	2,738	1,354	(1,433)
SERP Benefit Amortization, net of income tax (expense) benefit	916	(840)	1,158
Total Other Comprehensive Income (Loss), Net of Tax	3,654	514	(275)
Total Comprehensive Income	$ 104,996	$ 65,984	$ 85,059

XML

PENDING MERGER WITH FORTIS INC.

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

PENDING MERGER WITH FORTIS INC.

PENDING MERGER WITH FORTIS

On December 11, 2013, UNS Energy announced that it had entered into an agreement and plan of merger, subject to shareholder and required regulatory approvals, to be acquired by Fortis for $60.25 per share of Common Stock in cash. Following the merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Board of Directors of each of UNS Energy and Fortis Parent have approved the merger.

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

UNS Energy Corporation (UNS Energy) is a utility services holding company engaged, through its subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of Tucson Electric Power Company (TEP), UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).

TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 83% of UNS Energy’s total assets as of December 31, 2013. TEP generates, transmits and distributes electricity to approximately 413,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agriculture Improvement and Power District (SRP).

UES wholly-owns two regulated utilities: UNS Electric, Inc. (UNS Electric) and UNS Gas, Inc. (UNS Gas). UNS Electric is a regulated utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.

UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of December 31, 2013.

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

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

See Note 2 for information regarding a pending merger with Fortis, Inc.

BASIS OF PRESENTATION

UNS Energy's consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 3. The consolidated financial statements include the accounts of UNS Energy and all of its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. Intercompany profits on transactions between regulated entities are not eliminated if recovery from ratepayers is probable. See Note 4. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income. See Note 5.

USE OF ACCOUNTING ESTIMATES

Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect:

• Assets and liabilities on our balance sheets at the dates of the financial statements;

• Our disclosures about contingent assets and liabilities at the dates of the financial statements; and

• Our revenues and expenses in our income statements during the periods presented.

Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates.

ACCOUNTING FOR REGULATED OPERATIONS

We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through FERC-approved transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future billing reductions.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 3.

TEP, UNS Electric, and UNS Gas apply regulatory accounting as the following conditions exist:

• An independent regulator sets rates;

• The regulator sets the rates to recover the specific enterprise’s costs of providing service; and

• Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers.

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

In 2013, we adopted authoritative guidance that:

• Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 15.

• Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 16.

CASH AND CASH EQUIVALENTS

We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.

RESTRICTED CASH

Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets. Restricted cash was $2 million at December 31, 2013 and $7 million at December 31, 2012.

UTILITY PLANT

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

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

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

AFUDC and Capitalized Interest

AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statements. The capitalized cost for equity funds is recorded as Other Income in the income statements.

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

	2013		2012		2011
TEP	7.38	%	7.22	%	6.72	%
UNS Electric	8.07	%	7.89	%	8.18	%
UNS Gas	7.89	%	7.95	%	8.32	%

UNS Energy did not capitalize interest related to non-regulated construction activity in 2013 or 2012. UNS Energy capitalized interest on non-regulated construction activity at a rate of 3.30% for 2011.

Depreciation

We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 and Note 5. The Arizona Corporation Commission (ACC) approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant:

	2013		2012		2011
TEP	3.16	%	3.22	%	3.14	%
UNS Electric	3.94	%	3.99	%	4.02	%
UNS Gas	2.63	%	2.69	%	2.84	%

TEP Utility Plant Under Capital Leases

TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 5) and Interest Expense—Capital Leases. The lease terms are described in Note 6.

Computer Software Costs

We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense.

INVESTMENTS IN LEASE DEBT AND EQUITY

TEP held an investment in lease debt relating to Springerville Unit 1 through its maturity date in January 2013 and recorded this investment at amortized cost and recognized interest income. TEP holds a 14% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 15. These investments do not reduce the capital lease obligations reflected on the balance sheet because there is no legal right of offset. TEP makes lease payments to a trustee who then distributes the payments to the equity holders.

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

ASSET RETIREMENT OBLIGATIONS

TEP and UNS Electric have identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP and UNS Electric incurred AROs related to their photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense, and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.

Depreciation rates for all of our utilities also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.

EVALUATION OF ASSETS FOR IMPAIRMENT

We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.

DEFERRED FINANCING COSTS

We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.

We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt.

OPERATING REVENUES

We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity and gas sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.

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

TEP recognizes monthly management fees in Other Revenues as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned.

The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) associated with energy sales that no longer occur due to EE Standards and distributed generation. We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.

ALLOWANCE FOR DOUBTFUL ACCOUNTS

We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions.

INVENTORY

We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.

FUEL AND PURCHASED ENERGY COST RECOVERY MECHANISMS

TEP and UNS Electric Purchased Power and Fuel Adjustment Clause

TEP and UNS Electric recover actual fuel, purchased power and transmission costs incurred to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts the PPFAC rate at which TEP and UNS Electric recover these costs. The difference between costs recovered through rates and actual fuel, purchased power and transmission costs prudently incurred to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 3.

UNS Gas Purchased Gas Adjustor

UNS Gas recovers actual gas costs incurred through a Purchased Gas Adjustor (PGA) mechanism that adjusts monthly. Gas cost over-recoveries are deferred as regulatory liabilities and under-recoveries are deferred as regulatory assets. See Note 3.

RENEWABLE ENERGY and ENERGY EFFICIENCY PROGRAMS

The ACC’s Renewable Energy Standard (RES) requires TEP and UNS Electric to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The 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. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates.

TEP, UNS Electric, and UNS Gas are required to implement cost-effective Demand-Side Management (DSM) programs to comply with the ACC’s Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail kWh savings equal to22% by 2020. The Gas EE Standards require increasing annual targeted retail therm sales equal to 6% by 2020.

Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP and UNS Electric recognize RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. Similarly, UNS Gas recognizes DSM surcharge revenue in Gas Retail Sales.

RENEWABLE ENERGY CREDITS

The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP or UNS Electric purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC.

When RECs are purchased, TEP and UNS Electric record the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP and UNS Electric recognize Purchased Power expense and Other Revenues in an equal amount. See Note 3.

INCOME TAXES

Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized.

Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.  Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense.

Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due us from ratepayers as these tax benefits reverse. See Note 3.

We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and are deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises.

Consolidated income tax liabilities are allocated to subsidiaries based on their taxable income as reported in the consolidated tax return.

TAXES OTHER THAN INCOME TAXES

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

DERIVATIVE INSTRUMENTS

We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.

Cash Flow Hedges

TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. UNS Electric uses a cash flow hedge to effectively convert the interest rate on the UNS Electric term loan from a variable rate to a fixed rate. TEP and UNS Electric account for cash flow hedges as follows:

• The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and

• When TEP and UNS Electric determine a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP and UNS Electric recognize the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.

We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items.

Energy Contracts - Regulatory Recovery

TEP, UNS Electric and UNS Gas are authorized to recover the prudent costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC or PGA mechanism.

Master Netting Agreements

We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.

Normal Purchases and Normal Sales

We enter into forward energy purchase and sales contracts, including call options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis.

Commodity Trading

We did not engage in trading of derivative financial instruments.

PENSION AND OTHER RETIREE BENEFITS

We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees.

We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees.

Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.

Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 10.

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS’ EQUITY

DIVIDEND LIMITATIONS

UNS Energy

UNS Energy’s ability to pay cash dividends on Common Stock outstanding depends, in part, upon cash flows from our subsidiaries: TEP, UES, Millennium, and UED, as well as compliance with various debt covenant requirements. UNS Energy and each of its subsidiaries were in compliance with debt covenants at December 31, 2013; therefore, TEP and the other subsidiaries were not restricted from paying dividends.

The merger agreement with Fortis allows UNS Energy's Board of Directors to authorize quarterly dividends of up to $0.48 per share until the merger is completed, including a pro rata dividend determined by the number of days from the last declared record date to the date the merger is completed.

In February 2014, UNS Energy declared a first quarter dividend to shareholders of $0.48 per share of UNS Energy Common Stock. The dividend, totaling approximately $20 million, will be paid on March 25, 2014, to common shareholders of record as of March 13, 2014.

In the first half of 2012, $147 million of the Convertible Senior Notes outstanding were converted into approximately 4.3 million shares of UNS Energy Common Stock increasing common stock equity by $147 million.

TEP

TEP paid dividends to UNS Energy of $40 million in 2013 and $30 million in 2012. TEP paid no dividends to UNS Energy in 2011.

UNS Energy made no capital contributions to TEP in 2013 or 2012, and made capital contributions to TEP of $30 million in 2011.

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INCOME TAXES

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

INCOME TAXES

INCOME TAXES

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:

	UNS Energy									TEP
	Years Ended December 31,
	2013			2012			2011			2013			2012			2011
	Millions of Dollars
Federal Income Tax Expense at Statutory Rate	$	65		$	51		$	62		$	52		$	37		$	48
State Income Tax Expense, Net of Federal Deduction	8			7			8			7			5			6
Federal/State Tax Credits	(2		)	(1		)	(3		)	(2		)	(1		)	(2		)
Allowance for Equity Funds Used During Construction	(2		)	(1		)	(1		)	(1		)	(1		)	(1		)
Deferred Tax Asset Valuation Allowance	—			—			—			2			—			—
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11		)	—			—			(11		)	—			—
Other	—			—			1			1			(1		)	1
Total Federal and State Income Tax Expense	$	58		$	56		$	67		$	48		$	39		$	52

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.

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

	UNS Energy									TEP
	Years Ended December 31,
	2013			2012			2011			2013			2012			2011
	Millions of Dollars
Current Tax Expense (Benefit):
Federal	$	(11	)	$	(2	)	$	(7	)	$	(8	)	$	(4	)	$	(5	)
State	(2		)	(2		)	(2		)	(2		)	(2		)	(2		)
Total Current Tax Expense (Benefit)	(13		)	(4		)	(9		)	(10		)	(6		)	(7		)
Deferred Tax Expense (Benefit):
Federal	61			51			64			47			38			50
Federal Investment Tax Credits	(1		)	—			(1		)	(1		)	—			(1		)
State	11			9			13			12			7			10
Total Deferred Tax Expense (Benefit)	71			60			76			58			45			59
Total Federal and State Income Tax Expense	$	58		$	56		$	67		$	48		$	39		$	52

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

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Gross Deferred Income Tax Assets:
Capital Lease Obligations	$	127		$	141		$	127		$	141
Net Operating Loss Carryforwards	94			72			104			85
Customer Advances and Contributions in Aid of Construction	33			34			19			19
Alternative Minimum Tax Credit	43			43			24			24
Accrued Postretirement Benefits	23			23			23			23
Renewable Energy Credit Up-Front Incentive Payments	—			26			—			20
Emission Allowance Inventory	10			10			10			10
Unregulated Investment Losses	7			9			—			—
Other	50			44			44			43
Total Gross Deferred Income Tax Assets	387			402			351			365
Deferred Tax Assets Valuation Allowance	(7		)	(7		)	(2		)	—
Gross Deferred Income Tax Liabilities:
Plant – Net	(708		)	(648		)	(615		)	(571		)
Capital Lease Assets – Net	(47		)	(34		)	(47		)	(34		)
Pensions	(21		)	(23		)	(22		)	(24		)
PPFAC	(5		)	(6		)	(2		)	(3		)
Other	(21		)	(15		)	(20		)	(15		)
Total Gross Deferred Income Tax Liabilities	(802		)	(726		)	(706		)	(647		)
Net Deferred Income Tax Liabilities	$	(422	)	$	(331	)	$	(357	)	$	(282	)

The net deferred income tax liability on the balance sheet is as follows:

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Deferred Income Taxes – Current Assets	$	60		$	34		$	64		$	37
Deferred Income Taxes – Noncurrent Liabilities	(482		)	(365		)	(421		)	(319		)
Net Deferred Income Tax Liability	$	(422	)	$	(331	)	$	(357	)	$	(282	)

The unregulated investment loss deferred tax asset includes $7 million of capital loss at December 31, 2013 and December 31, 2012. The deferred tax asset can only be used if the company has capital gains to offset the losses. Management believes that it is more likely than not that the company will not be able to generate future capital gains. As a result, UNS Energy recorded a $7 million valuation allowance against the deferred tax asset as of December 31, 2013, and December 31, 2012. Management believes that based on its historical pattern of taxable income, UNS Energy will produce sufficient income in the future to realize all other deferred income tax assets. TEP has recorded a $2 million valuation allowance against state tax credit carryforward deferred tax assets at December 31, 2013. Management believes TEP will not produce sufficient taxable income to use all state tax credits before they expire.

Income Tax Position

As of December 31, 2013, UNS Energy and TEP had the following carryforward amounts:

	UNS Energy			TEP
	Amount		Expiring Year	Amount		Expiring Year
	Millions of Dollars			Millions of Dollars
Capital Loss	$	7	2015	$	—	N/A
Federal Net Operating Loss	266		2031-33	286		2031-33
State Net Operating Loss	30		2032-33	99		2016-33
State Credits	5		2016-18	6		2016-18
Alternative Minimum Tax Credit	43		None	24		None
Investment Tax Credits	6		2032-33	6		2032-33

If the pending Merger is approved there would be an annual limitation on the amount of carryforwards that can be utilized.

Excess Tax Benefit Realized from Share-Based Compensation Plans

UNS Energy records excess tax benefits as an increase to Common Stock when tax deductions for share-based compensation exceed the expense recorded in the financial statements and they result in a reduction to income taxes payable. As of December 31, 2013, UNS Energy had $4 million of excess tax benefits that were not recorded in Common Stock. The excess benefits will be recorded in Common Stock when the Federal net operating loss carryforwards of $266 million are used.

Uncertain Tax Positions

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	UNS Energy						TEP
	December 31,						December 31,
	2013			2012			2013			2012
	Millions of Dollars
Unrecognized Tax Benefits, Beginning of Year	$	30		$	29		$	23		$	24
Additions Based on Tax Positions Taken in the Current Year	2			5			1			3
Reductions of Positions from Prior Year Based on Tax Authority Ruling	(28		)	(4		)	(22		)	(4		)
Unrecognized Tax Benefits, End of Year	$	4		$	30		$	2		$	23

Unrecognized tax benefits, if recognized, would not reduce income tax expense at December 31, 2013. Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million at December 31, 2012 for both UNS Energy and TEP.

UNS Energy and TEP recognized a $1 million reduction to interest expense in 2013 and no reduction in 2012. UNS Energy and TEP had no interest payable balance at December 31, 2013 and $1 million at December 31, 2012. We have no penalties accrued in the years presented.

In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources.  These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation.  As a result of the IRS ruling in the first quarter of 2013, UNS Energy reduced unrecognized tax benefits by $28 million, and TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.

UNS Energy and TEP have been audited by the IRS through tax year 2010 and the IRS has provided notice of intent to audit the 2011 tax returns. UNS Energy and TEP are not currently under audit by any state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of ongoing IRS audits, but we are unable to determine the amount of change.

Tangible Property Regulations

In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. The adoption of these regulations by UNS Energy and TEP resulted in a $4 million increase to plant-related deferred tax liabilities and net operating loss deferred tax assets at December 31, 2013.

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EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Projected Benefit Obligation
Interest Cost		$ 15
Service Cost	3
Change in Plan Assets
Fair Value Beginning Balance	289
Fair Value Ending Balance	323	289
Pension Benefits [Member]
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	380	319
Actuarial (Gain) Loss	(38)	51
Interest Cost	15	16	15
Service Cost	13	10	10
Benefits Paid	(18)	(15)
Projected Benefit Obligation at End of Year	352	380	319
Change in Plan Assets
Fair Value Beginning Balance	289	245
Actual Return on Plan Assets	29	36
Benefits Paid	(18)	(15)
Employer Contributions	23	23
Fair Value Ending Balance	323	289	245
Funded Status at End of Year	(29)	(91)
Other Retiree Benefits [Member]
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	78	73
Actuarial (Gain) Loss	(5)	3
Interest Cost	3	3	4
Service Cost	4	3	3
Benefits Paid	(4)	(4)
Projected Benefit Obligation at End of Year	75	78	73
Change in Plan Assets
Fair Value Beginning Balance	7	5
Actual Return on Plan Assets	1	1
Benefits Paid	(4)	(4)
Employer Contributions	6	5
Fair Value Ending Balance	10	7	5
Funded Status at End of Year	(65)	(71)
TUCSON ELECTRIC POWER COMPANY | Pension Benefits [Member]
Change in Plan Assets
Employer Contributions	22	20
TUCSON ELECTRIC POWER COMPANY | Other Retiree Benefits [Member]
Change in Plan Assets
Employer Contributions	$ 6	$ 5

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UTILITY PLANT AND JOINTLY-OWNED FACILITIES

12 Months Ended

Dec. 31, 2013

Regulatory Operations [Abstract]

UTILITY PLANT AND JOINTLY-OWNED FACILITES

UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

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

	UNS Energy				TEP
	December 31,				December 31,
	2013		2012		2013		2012
	Millions of Dollars
Plant in Service:
Electric Generation Plant	$	1,974	$	1,932	$	1,889	$	1,847
Electric Transmission Plant	912		842		825		796
Electric Distribution Plant	1,529		1,495		1,298		1,271
Gas Distribution Plant	252		240		—		—
Gas Transmission Plant	18		18		—		—
General Plant	356		347		312		309
Intangible Plant - Software Costs (1) (2)	142		124		141		123
Intangible Plant - Other	5		5		—		—
Electric Plant Held for Future Use	4		3		3		2
Total Plant in Service	$	5,192	$	5,006	$	4,468	$	4,348
Utility Plant under Capital Leases(3)	$	638	$	583	$	638	$	583

⁽¹⁾  Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.

⁽²⁾  The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.

⁽³⁾  In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.

TEP Utility Plant under Capital Leases

All TEP utility plant under capital leases is used in TEP’s generation operations and amortized over the primary lease term. See Note 6. At December 31, 2013, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:

	Years Ended December 31,
	2013		2012		2011
	Millions of Dollars
Lease Expense:
Interest Expense – Included in:
Capital Leases	25		$	34	$	40
Operating Expenses – Fuel	2		3		4
Other Expense	—		—		1
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel	5		4		3
Operating Expenses – Amortization	15		14		14
Total Lease Expense	$	47	$	55	$	62

Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2013, were as follows:

	TEP
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant (1)	3.31%	22
Electric Transmission Plant	1.48%	32
Electric Distribution Plant (1)	2.08%	35
General Plant (1)	5.48%	11
Intangible Plant (2)	Various	Various

	UNS Electric
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant	2.56%	36
Electric Transmission Plant	3.36%	19
Electric Distribution Plant	3.97%	15
General Plant	8.01%	7
Intangible Plant (3)	Various	Various

	UNS Gas
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Gas Generation Plant	2.37%	41
Gas Transmission Plant	1.54%	54
General Plant	4.38%	7
Intangible Plant (4)	Various	Various

⁽¹⁾ In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.

⁽²⁾  The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life based on either the average lives of 3 to 5 years for smaller application software or remaining lives ranging from 5 to 19 years for large enterprise software.

⁽³⁾  UNS Electric's intangible plant primarily represents capitalized interconnection costs, which are amortized based on either an average life of 23 years or a remaining life of 35 years.

⁽⁴⁾  UNS Gas' intangible plant consists of miscellaneous intangible assets, which are amortized over an average life of either 15 or 25 years.

⁽⁵⁾  The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.

JOINTLY-OWNED FACILITIES

At December 31, 2013, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:

	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Net Book Value
		Millions of Dollars
San Juan Units 1 and 2	50.0%	$	448	$	6	$	230	$	224
Navajo Units 1, 2, and 3	7.5%	152		1		110		43
Four Corners Units 4 and 5	7.0%	101		2		75		28
Luna Energy Facility	33.3%	53		—		2		51
Transmission Facilities	Various	330		43		190		183
Total		$	1,084	$	52	$	607	$	529

TEP is responsible for its share of operating costs for the above facilities as well as providing financing. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.

ASSET RETIREMENT OBLIGATIONS

The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:

	UNS Energy
	December 31,
	2013		2012
	Millions of Dollars
Beginning Balance	$	14	$	13
Liabilities Incurred	1		—
Accretion Expense or Regulatory Deferral	1		1
Revisions to the Present Value of Estimated Cash Flows (1)	7		—
Ending Balance	$	23	$	14

⁽¹⁾ Primarily related to changes in expected retirement dates of generating facilities.

The table above primarily reflects TEP's ARO obligations. UNS Electric's ARO obligations were less than $1 million at December 31, 2013 and 2012.

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UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2013
Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	23 years
Minimum [Member] | Computer Software, Intangible Asset [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	3 years
Minimum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	5 years
Minimum [Member] | Other Intangible Assets [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	15 years
Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	35 years
Maximum [Member] | Computer Software, Intangible Asset [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	5 years
Maximum [Member] | Application Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	19 years
Maximum [Member] | Other Intangible Assets [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Asset, Useful Life	25 years

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Dec. 31, 2013
Cash Flow Hedges [Abstract]
Estimated loss expected to be reclassified to earnings within the next twelve months	$ 4

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REGULATORY MATTERS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP, UNS Electric, and UNS Gas. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and the pending merger. The FERC regulates terms and prices of transmission services and wholesale electricity sales, and the pending merger.

2013 TEP RATE ORDER

In June 2013, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012 which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.

The provisions of the 2013 TEP Rate Order include, but are not limited to:

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

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

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

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

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

• a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11 million annually; and

• an agreement by TEP to seek recovery of costs related to the discontinued Nogales transmission project from the FERC before seeking rate recovery from the ACC.

The 2013 TEP Rate Order also includes the following cost recovery mechanisms:

• a new Purchased Power and Fuel Adjustment Clause (PPFAC) credit of 0.1388 cents per kWh effective July 1, 2013. The credit reflects the following:

◦ a reduction in the PPFAC bank balance, recorded in June 2013, as an increase to fuel expense, of $3 million related to prior sulfur credits; and

◦ a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory asset to defer coal costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final settlement with the San Juan operator related to insurance proceeds.

• a modification of the PPFAC mechanism to include recovery of generation-related lime costs offset by sulfur credits.

• a Lost Fixed Cost Recovery mechanism (LFCR) to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation. In the fourth quarter of 2013, TEP recorded revenues of $2 million related to unrecovered non-fuel costs incurred during 2013.

• an Environmental Compliance Adjustor (ECA) mechanism to recover certain capital carrying costs to comply with government-mandated environmental regulations between rate cases. The ECA rate is capped at 0.025 cents per kWh, which approximates 0.25% of TEP's total retail revenues, and will be charged to customers beginning in May 2014 for any qualifying costs incurred between August 2013 and December 2013.

• an energy efficiency provision which includes a 2013 calendar year budget of approximately $21 million to fund programs that support the ACC's Electric Energy Efficiency Standards, as well as a $2 million performance incentive.

2013 UNS ELECTRIC RATE ORDER

In December 2013, the ACC issued the 2013 UNS Electric Rate Order that resolved the rate case filed by UNS Electric in December 2012 which was based on a test year ended June 30, 2012. The 2013 UNS Electric Rate Order approved new rates effective January 1, 2014.

The provisions of the 2013 UNS Electric Rate Order include, but are not limited to:

• an increase in non-fuel retail Base Rates of approximately $3 million;

• an OCRB of approximately $213 million and a FVRB of approximately $283 million;

• a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;

• a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and

• a capital structure of 52.6% equity and 47.4% long-term debt.

The 2013 UNS Electric Rate Order also includes the following cost recovery mechanisms:

• a LFCR mechanism to recover certain non-fuel costs related to kWh sales lost due to energy efficiency programs and distributed generation; and

• a Transmission Cost Adjustor (TCA), which will allow more timely recovery of transmission costs associated with serving retail customers.

2012 UNS GAS RATE ORDER

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

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

COST RECOVERY MECHANISMS

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

Purchased Power and Fuel Adjustment Clause

TEP's PPFAC rate is adjusted annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period unless suspended by the ACC.

TEP's PPFAC rate includes: 1) a forward component, under which TEP recovers or refunds differences between a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between prudently incurred actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.

Prior to the 2013 UNS Electric Rate Order, UNS Electric’s PPFAC rate was adjusted annually each June 1^st, effective for the subsequent 12-month period. As a result of the 2013 UNS Electric Rate Order, effective January 1, 2014, UNS Electric's PPFAC rate reflects a weighted 12-month rolling average of actual fuel and purchased power costs incurred by UNS Electric. The PPFAC rate adjusts monthly, but it is restricted from changing by more than 0.83 percent from the preceding month's rate. If the PPFAC deferral balance reflects an over-collection of $10 million or more on a billed-to-customer basis, UNS Electric must file for a PPFAC rate adjustment. At December 31, 2013, the PPFAC bank balance was over-collected by $14 million on a billed-to-customer basis.

The tables below summarize TEP’s and UNS Electric’s PPFAC rates:

	TEP
	2013		2012
	July - December	January - June	April - December	January - March
	Cents per kWh
PPFAC Rate	0.14	0.77	0.77	0.53
Competition Transition Charge (1)	—	—	—	(0.53	)
Net TEP PPFAC Rate	0.14	0.77	0.77	—

⁽¹⁾  TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.

	UNS Electric
	2013						2012
	September - December		June - August		January - May		June - December		January - May
	Cents per kWh
PPFAC Rate	(0.40	)	(0.92	)	(1.44	)	(1.44	)	(0.88	)

UNS Gas Purchased Gas Adjustor

The PGA mechanism allows UNS Gas to adjust Retail Rates to recover fluctuations in natural gas costs. UNS Gas records deferrals for recovery or refund to the extent actual natural gas costs vary from the PGA rate. The PGA rate reflects a weighted, rolling average of the gas costs incurred by UNS Gas over the preceding 12 months. The PGA rate automatically adjusts monthly, but it is restricted from rising or falling more than 15 cents per therm in a twelve-month period. UNS Gas is required to request an additional surcredit if deferral balances reflect $10 million or more on a billed-to-customer basis.

In October 2013, the ACC approved an increase to the existing PGA credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At December 31, 2013 and December 31, 2012, the PGA bank balance was over-collected by $10 million on a billed-to-customer basis.

The PGA rate ranged from 0.4504 to 0.5280 cents per therm in 2013, and ranged from 0.5202 to 0.6501 cents per therm in 2012.

Renewable Energy Standards

TEP and UNS Electric are required to expand their use of renewable energy in order to meet the ACC’s RES. TEP and UNS Electric, through a customer surcharge, recover costs associated with meeting the RES. These costs include the purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates.

In October 2013, the ACC approved TEP's 2014 RES plan and authorized a total 2014 RES budget of $40 million with $34 million to be collected through the 2014 RES funding mechanism. TEP earned returns on solar investments of $2 million in each of 2013 and 2012 and $1 million in 2011.

In October 2013, the ACC approved UNS Electric's 2014 RES plan and authorized a total 2014 RES budget of $7 million with $6 million to be collected through the 2014 RES funding mechanism.  UNS Electric earned returns on solar investments of less than $0.5 million in 2013 and 2012. No return was earned in 2011.

Energy Efficiency Standards

TEP, UNS Electric, and UNS Gas are required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs.

In December 2013, the ACC approved UNS Electric’s 2013-2014 energy efficiency implementation plan that included a 2014 calendar year budget of approximately $5 million to fund programs that support the ACC’s Electric EE Standards as well as a performance incentive.

In June 2013, the ACC approved the UNS Gas 2011-2012 energy efficiency implementation plan with certain modifications. The approval included an annual energy efficiency budget of approximately $2 million and a waiver of the Gas EE Standards through 2013.

Lost Fixed Cost Recovery Mechanism

The LFCR is a mechanism to recover certain non-fuel costs that would go unrecovered due to lost sales as a result of implementing ACC approved EE Standards and distributed generation targets.

In April 2012, the ACC authorized a LFCR mechanism that enables UNS Gas to recover non-purchased energy related costs that would go unrecovered due to lost therm sales as a result of implementing the Gas EE Standards.

In June 2013, the ACC authorized a LFCR mechanism for TEP subject to a year-over-year cap of 1% of TEP's total retail revenues. TEP expects the LFCR rate which will recover 2013 costs, to be effective on July 1, 2014, upon review by the ACC of verified lost kWh sales.

In December 2013, as part of the 2013 UNS Electric Rate Order, the ACC authorized a LFCR for UNS Electric, to be effective on July 1, 2014.

REGULATORY ASSETS AND LIABILITIES

The following tables summarize regulatory assets and liabilities:

	December 31, 2013
	TEP			UNS Electric			UNS Gas			UNS Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	20		$	—		$	—		$	20
Derivative Instruments (Note 15)	1			—			—			1
San Juan Mine Fire Cost Deferral (2)	10			—			—			10
PPFAC (2)	4			10			—			14
DSM and LFCR (2)	3			—			—			3
Other Current Regulatory Assets (3)	5			—			—			5
Total Regulatory Assets—Current	43			10			—			53
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	75			3			2			80
Income Taxes Recoverable through Future Revenues (4)	22			3			—			25
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	25			—			—			25
Discontinued Nogales Transmission Project (6)	5			—			—			5
Other Regulatory Assets (3)	14			2			—			16
Total Regulatory Assets—Noncurrent	141			8			2			151
Regulatory Liabilities—Current
PGA (2)	—			—			(15		)	(15		)
RES (2)	(22		)	(9		)	—			(31		)
Other Current Regulatory Liabilities	(2		)	(6		)	—			(8		)
Total Regulatory Liabilities—Current	(24		)	(15		)	(15		)	(54		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(254		)	(12		)	(26		)	(292		)
Income Taxes Payable through Future Rates	(5		)	—			(1		)	(6		)
Deferred Investment Tax Credit (8)	(4		)	—			—			(4		)
Total Regulatory Liabilities—Noncurrent	(263		)	(12		)	(27		)	(302		)
Total Net Regulatory Assets (Liabilities)	$	(103	)	$	(9	)	$	(40	)	$	(152	)

	December 31, 2012
	TEP			UNS Electric			UNS Gas			UNS Energy
	Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals (1)	$	18		$	—		$	—		$	18
Derivative Instruments (Note 15)	2			6			3			11
PPFAC (2)	7			8			—			15
DSM (2)	5			—			—			5
Other Current Regulatory Assets (3)	2			—			1			3
Total Regulatory Assets—Current	34			14			4			52
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 10)	130			5			4			139
Income Taxes Recoverable through Future Revenues (4)	8			2			—			10
PPFAC—Final Mine Reclamation and Retiree Health Care Costs (5)	22			—			—			22
Discontinued Nogales Transmission Project (6)	5			—			—			5
Other Regulatory Assets (3)	13			1			1			15
Total Regulatory Assets—Noncurrent	178			8			5			191
Regulatory Liabilities—Current
PGA (2)	—			—			(17		)	(17		)
RES (2)	(19		)	(4		)	—			(23		)
Other Current Regulatory Liabilities	(2		)	(1		)	(1		)	(4		)
Total Regulatory Liabilities—Current	(21		)	(5		)	(18		)	(44		)
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements (7)	(231		)	(11		)	(25		)	(267		)
Income Taxes Payable through Future Rates	(5		)	—			(1		)	(6		)
Deferred Investment Tax Credit (8)	(5		)	—			—			(5		)
Other Regulatory Liabilities	—			(1		)	—			(1		)
Total Regulatory Liabilities—Noncurrent	(241		)	(12		)	(26		)	(279		)
Total Net Regulatory Assets (Liabilities)	$	(50	)	$	5		$	(35	)	$	(80	)

Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. We describe regulatory assets below. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets.

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

⁽²⁾  See Cost Recovery Mechanisms discussion above.

⁽³⁾  TEP’s other regulatory assets include unamortized loss on reacquired debt (recovery through 2032), coal contract amendment (recovery through 2017), rate case costs (recovery over three years), environmental compliance costs, Springerville Unit 1 lease deferrals and other assets (recovery through 2014).

⁽⁴⁾  Income Taxes Recoverable through Future Revenues are amortized over the life of the assets.

⁽⁵⁾  Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.

⁽⁶⁾  TEP and UNS Electric will request recovery from FERC for the prudent costs incurred to develop a high-voltage transmission line from Tucson to Nogales. TEP and UNS Electric are not going to proceed with the project. See Note 7.

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

⁽⁷⁾  Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.

⁽⁸⁾  The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.

IMPACTS OF REGULATORY ACCOUNTING

If we determine that we no longer meet the criteria for continued application of regulatory accounting, we would be required to write off our regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on our financial statements.

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BUSINESS SEGMENTS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

BUSINESS SEGMENTS

BUSINESS SEGMENTS

We have three reportable segments regularly reviewed by our chief operating decision makers to evaluate performance and make operating decisions.

(1) TEP, a regulated electric utility and our largest subsidiary

(2) UNS Electric, a regulated electric utility

(3) UNS Gas, a regulated gas distribution utility

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

	Reportable Segments
	TEP			UNS Electric			UNS Gas			Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
2013
Income Statement
Operating Revenues-External	$	1,180		$	174		$	131		$	2		$	(2	)	$	1,485
Operating Revenues-Intersegment (1)	17			2			3			17			(39		)	—
Depreciation and Amortization	149			19			9			—			—			177
Interest Income	—			1			—			—			—			1
Interest Expense	79			7			6			1			—			93
Income Tax Expense	48			7			7			(4		)	—			58
Net Income	101			12			11			3			—			127
Cash Flow Statement
Capital Expenditures	(253		)	(56		)	(17		)	—			—			(326		)
Balance Sheet
Total Assets	3,556			404			311			1,194			(1,192		)	4,273

	Reportable Segments
	TEP			UNS Electric			UNS Gas			Other (2)			Reconciling Adjustments			UNS Energy
	Millions of Dollars
2012
Income Statement
Operating Revenues-External	$	1,145		$	189		$	129		$	—		$	(1	)	$	1,462
Operating Revenues-Intersegment (1)	17			1			4			18			(40		)	—
Depreciation and Amortization	150			18			9			—			—			177
Interest Income	—			—			—			1			—			1
Interest Expense	88			8			6			3			—			105
Income Tax Expense	39			11			6			—			—			56
Net Income	65			17			9			—			—			91
Cash Flow Statement
Capital Expenditures	(253		)	(38		)	(16		)	—			—			(307		)
Balance Sheet
Total Assets	3,461			370			310			1,121			(1,122		)	4,140
2011
Income Statement
Operating Revenues-External	$	1,141		$	188		$	149		$	—		$	1		$	1,479
Operating Revenue-Intersegment (1)	15			2			2			23			(42		)	—
Depreciation and Amortization	140			17			8			1			(1		)	165
Interest Income	4			—			—			1			—			5
Interest Expense	89			7			7			9			—			112
Income Tax Expense	52			11			7			(1		)	(2		)	67
Net Income	85			18			10			—			(3		)	110
Cash Flow Statement
Capital Expenditures	(352		)	(96		)	(13		)	(34		)	121			(374		)

⁽¹⁾  Operating Revenues – Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges charges (primarily meter reading services) provided to the utilities by an unregulated affiliate.

⁽²⁾  Other includes the UNS Energy and UES holding companies, Millennium, and UED.

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS

Long-term debt matures more than one year from the date of the financial statements. We summarize UNS Energy’s and TEP’s long-term debt in the statements of capitalization.

UNS ENERGY CONVERTIBLE SENIOR NOTES

In 2005, UNS Energy issued $150 million of 4.50% Convertible Senior Notes due in 2035. In 2012, UNS Energy converted approximately $147 million of the Convertible Senior Notes into approximately 4.3 million shares of Common Stock and redeemed $3 million for cash.

TEP DEBT ISSUANCES AND REDEMPTIONS

Unsecured Tax-Exempt Variable Rate Bonds

In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate Industrial Development Revenue Bonds (IDRBs), due April 2032. The lender resets the interest rate monthly based on a percentage of an index rate equal to one-month LIBOR plus a bank margin rate; the rate at December 31, 2013 was 0.948% per annum. These bonds are multi-modal bonds, and the initial term is set at five years through November 2018, at which time the bonds will be subject to mandatory tender for purchase. Proceeds were deposited with a trustee to redeem $100 million variable rate bonds in December 2013.

Secured Tax-Exempt Variable Rate Bonds and Interest Rate Swap

Certain of TEP's tax-exempt, variable rate bonds are secured by Letter of Credits (LOCs) issued under the TEP Credit Agreement and TEP Reimbursement Agreement, see below.

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

	Years Ended December 31,
	2013	2012	2011
Interest Rates on Bonds:
Average Interest Rate	0.10%	0.17%	0.18%
Range of Average Weekly Rates	0.06% - 0.25%	0.06% - 0.26%	0.05% - 0.34%

In August 2009, TEP entered into an interest rate swap that had the effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014.

Unsecured Tax-Exempt Fixed Rate Bonds

In March 2013, TEP issued approximately $91 million aggregate principal amount of Pima County, Arizona, unsecured tax-exempt Industrial Development Bonds (IDBs). The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 1, 2023. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013.

In June 2012, TEP issued approximately $16 million of Pima County, Arizona, unsecured tax-exempt IDBs. The bonds bear interest at a fixed rate of 4.5%, mature in June 2030, and may be redeemed at par on or after June 1, 2022. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $16 million of unsecured, tax-exempt bonds with interest rates of 5.85% and 5.875%, and maturity dates ranging from 2026 to 2033.

In March 2012, TEP issued $177 million of Apache County, Arizona, unsecured, tax-exempt pollution control bonds. The bonds bear interest at a fixed rate of 4.5%, mature in March 2030, and may be redeemed at par on or after March 1, 2022. The proceeds from the sale of the bonds, together with $7 million of principal and $1 million for accrued interest provided by TEP, were deposited with a trustee to retire $184 million of unsecured tax-exempt bonds with interest rates of 5.85% and 5.875% and maturity dates ranging from 2026 to 2033.

Unsecured Fixed Rate Notes

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

TEP MORTGAGE INDENTURE

Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP canceled $423 million in mortgage bonds and discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.

UNS ENERGY CREDIT AGREEMENT

The UNS Energy Credit Agreement consists of a $125 million revolving credit facility and revolving LOC facility and expires in November 2016. UNS Energy’s obligations under the agreement are secured by a pledge of the capital stock of Millennium, UES, and UED.

UNS Energy had $54 million of outstanding borrowings at December 31, 2013 and $45 million of outstanding borrowings at December 31, 2012, under its revolving credit facility. The weighted average interest rate on the revolver was 1.66% at December 31, 2013 and 1.96% at December 31, 2012. We report the revolver borrowings in Long-Term Debt on the balance sheet as UNS Energy has the ability and the intent to have outstanding borrowings for the next twelve months. As of February 14, 2014, outstanding borrowings under the UNS Energy Credit Agreement totaled $52 million.

Interest rates and fees under the UNS Energy Credit Agreement are based on a pricing grid tied to UNS Energy’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.25% for Eurodollar loans or Alternate Base Rate plus 0.25% for Alternate Base Rate loans.

TEP CREDIT AGREEMENT

The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility, and a $82 million LOC facility to support tax-exempt bonds, and expires in November 2016. In December 2013, TEP reduced its letter of credit facility from $186 million to $82 million, following the refinancing of $100 million of variable rate bonds and the cancellation of $104 million of LOCs supporting those bonds.

Interest rates and fees under the TEP Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million LOC facility is 1.125%.

TEP had no borrowings and $1 million outstanding in LOCs issued under its revolving credit facility at December 31, 2013 and December 31, 2012. The revolving loan balance was included in Current Liabilities on UNS Energy’s and TEP’s balance sheets. The outstanding LOCs are off-balance sheet obligations of TEP. As of February 14, 2014, TEP had $90 million in borrowings and $1 million outstanding in LOCs under its revolving credit facility.

2010 TEP REIMBURSEMENT AGREEMENT

A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010. In February 2014, TEP amended the agreement to extend the LOC expiration date from 2014 to 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 1.00% per annum.

UNS ELECTRIC/UNS GAS CREDIT AGREEMENT

The UNS Electric/UNS Gas Credit Agreement consists of a $100 million revolving credit and revolving LOC facility, and expires in November 2016. The maximum borrowings outstanding at any one time for UNS Gas or UNS Electric under the agreement may not exceed $70 million. UNS Electric and UNS Gas each are liable for only their own individual borrowings under the UNS Electric/UNS Gas Credit Agreement. UES guarantees the obligations of both UNS Electric and UNS Gas. The UNS Electric/UNS Gas Credit Agreement may be used to issue LOCs, as well as for revolver borrowings. UNS Electric and UNS Gas issue LOCs, which are off-balance sheet obligations, to support power and gas purchases and hedges.

Interest rates and fees under the UNS Electric/UNS Gas Credit Agreement are based on a pricing grid tied to their credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans.

UNS Electric had $22 million in borrowings and less than $0.5 million in outstanding LOCs under the UNS Electric/UNS Gas Credit Agreement as of December 31, 2013. The revolving loan balance was included in Current Liabilities on UNS Energy’s balance sheet. UNS Electric had no borrowings outstanding and less than $0.5 million LOCs under UNS Electric/UNS Gas Credit Agreement as of December 31, 2012. The oustanding LOCs balances are not shown on the balance sheet. As of February 14, 2014, UNS Electric had $25 million in borrowings and less than $0.5 million in outstanding LOCs under the UNS Electric/UNS Gas Credit Agreement.

UNS ELECTRIC TERM LOAN CREDIT AGREEMENT AND INTEREST RATE SWAP

In August 2011, UNS Electric entered into a four-year $30 million variable rate term loan credit agreement. The interest rate currently in effect is three-month LIBOR plus 1.125%. At the same time, UNS Electric entered into a fixed-for-floating interest rate swap in which UNS Electric will pay a fixed rate of 0.97% and receive a three-month LIBOR rate on a $30 million notional amount over a four years period ending August 2015. The UNS Electric term loan credit agreement, included in Long-Term Debt on the balance sheet, is guaranteed by UES.

COVENANT COMPLIANCE

Our credit agreements, the 2010 TEP Reimbursement Agreement, and certain of our long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. The UNS Energy Credit Agreement also requires UNS Energy to meet a minimum cash flow to interest coverage ratio, and each of our credit agreements stipulate a maximum leverage ratio. UNS Energy and its subsidiaries may pay dividends so long as we maintain compliance with our credit agreements.

At December 31, 2013, we were in compliance with the terms of our long-term debt, credit agreements, and the 2010 TEP Reimbursement Agreement. No amounts of net income were subject to dividend restrictions.

TEP CAPITAL LEASE OBLIGATIONS

In January 2014, through scheduled lease payments, TEP reduced its capital lease obligations by $80 million.

Springerville Unit 1 Capital Lease Purchase Commitments

The Springerville Unit 1 Leases have an initial term to January 2015, and include a fair market value purchase option at the end of the initial lease term. In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a capacity rating of 387 MW.

In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value, upon the expiration of the lease term in January 2015.

In October 2013, TEP elected to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014.

Upon close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of capacity. Due to TEP's purchase commitments, TEP and UNS Energy recorded an increase of approximately $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets.

Springerville Coal Handling and Common Facilities Leases

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

The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. Instead of extending the leases, TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of the common facilities are $38 million in 2017 and $68 million in 2021.

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

Lease Debt and Equity

Investments in Springerville Lease Debt and Equity

In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2013 and December 31, 2012.

Interest Rate Swaps—Springerville Common Facilities Lease Debt

TEP’s interest rate swaps hedge the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month London Interbank Offered Rate (LIBOR) plus a spread. The applicable spread was 1.75% at December 31, 2013 and December 31, 2012.

The swaps have the effect of fixing the interest rates on the amortizing principal balances as follows:

Lease Debt Outstanding at December 31, 2013	Fixed Rate		LIBOR Spread
Swap 1 - Notional Amount $33 million - Effective Date June 2006	5.77	%	1.75	%
Swap 2 - Notional Amount $16 million - Effective Date May 2009	3.18	%	1.75	%
Swap 3 - Notional Amount $6 million - Effective Date May 2009	3.32	%	1.75	%

TEP recorded these interest rate swaps as a cash flow hedge for financial reporting purposes. See Note 15.

DEBT MATURITIES

Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:

	TEP Long-Term Debt Maturities (1)		TEP Capital Lease Obligations			TEP Total			UNS Electric		UNS Gas		UNS Energy Parent Company		Total
	Millions of Dollars
2014	$	—	$	214		$	214		$	—	$	—	$	—	$	214
2015	—		69			69			80		50		—		199
2016	78		17			95			—		—		54		149
2017	—		18			18			—		—		—		18
2018	100		11			111			—		—		—		111
Total 2014 – 2018	178		329			507			80		50		54		691
Thereafter	1,046		30			1,076			50		50		—		1,176
Less: Imputed Interest	—		(42		)	(42		)	—		—		—		(42		)
Total	$	1,224	$	317		$	1,541		$	130	$	100	$	54	$	1,825

⁽¹⁾  $115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to TEP’s Credit Agreement, which expires in November 2016, and TEP’s Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the TEP Credit Agreement. TEP's 2013 tax-exempt variable rate IDBs, which mature in 2032, are subject to mandatory tender for purchase after the current five-year term and are therefore reflected as maturing in 2018. The repayment of TEP Unsecured Notes is not reduced by the approximately $1 million discount.

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Credit agreements) (Details) (USD $)		12 Months Ended			12 Months Ended								12 Months Ended
	Dec. 31, 2010 TUCSON ELECTRIC POWER COMPANY Letter of Credit [Member]	Dec. 31, 2013 UNS Gas and UNS Electric [Member] Line of Credit [Member]	Dec. 31, 2013 Parent [Member] Line of Credit [Member]	Feb. 25, 2014 Subsequent Event [Member] TUCSON ELECTRIC POWER COMPANY Letter of Credit [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] UNS Gas and UNS Electric [Member] Line of Credit [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] Parent [Member] Line of Credit [Member]	Dec. 31, 2012 Revolving Credit Facility [Member] Parent [Member] Line of Credit [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] UNS ELECTRIC, INC. Line of Credit [Member]	Feb. 14, 2014 Revolving Credit Facility [Member] Subsequent Event [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Feb. 25, 2014 Revolving Credit Facility [Member] Subsequent Event [Member] Parent [Member] Line of Credit [Member]	Feb. 14, 2014 Revolving Credit Facility [Member] Subsequent Event [Member] UNS ELECTRIC, INC. Line of Credit [Member]	Dec. 31, 2013 Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Nov. 30, 2013 Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Dec. 31, 2012 Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Dec. 31, 2013 Letter of Credit [Member] UNS ELECTRIC, INC. Line of Credit [Member]	Dec. 31, 2012 Letter of Credit [Member] UNS ELECTRIC, INC. Line of Credit [Member]	Feb. 14, 2014 Letter of Credit [Member] Subsequent Event [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Feb. 14, 2014 Letter of Credit [Member] Subsequent Event [Member] UNS ELECTRIC, INC. Line of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility borrowing capacity		$ 100,000,000	$ 125,000,000		$ 200,000,000									$ 186,000,000
Letters of credit outstanding													82,000,000
Outstanding borrowings under the company credit agreement	37,000,000				0		54,000,000	45,000,000	22,000,000	90,000,000	52,000,000	25,000,000	1,000,000		1,000,000	500,000	500,000	1,000,000	500,000
Average interest rate							1.70%	2.00%
Interest rate spread on LIBOR borrowing					1.125%	1.125%	1.25%						1.125%
Interest rate in addition to alternate base rate for alternate base rate loans					0.125%	0.125%	0.25%
Maximum borrowings outstanding limit		70,000,000
Letter of credit cancelled													$ 104,000,000
Commitment fee percentage				1.00%

XML

EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified					12 Months Ended			12 Months Ended				12 Months Ended			12 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 UNS Gas and UNS Electric [Member]	Dec. 31, 2012 UNS Gas and UNS Electric [Member]	Dec. 31, 2013 Pension Benefits [Member]	Dec. 31, 2012 Pension Benefits [Member]	Dec. 31, 2011 Pension Benefits [Member]	Dec. 31, 2013 Pension Benefits [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 Pension Benefits [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Pension Benefits [Member] UNS Gas and UNS Electric [Member]	Dec. 31, 2012 Pension Benefits [Member] UNS Gas and UNS Electric [Member]	Dec. 31, 2013 Other Retiree Benefits [Member]	Dec. 31, 2012 Other Retiree Benefits [Member]	Dec. 31, 2011 Other Retiree Benefits [Member]	Dec. 31, 2013 Other Retiree Benefits [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 Other Retiree Benefits [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Other Retiree Benefits [Member] UNS Gas and UNS Electric [Member]	Dec. 31, 2014 Scenario, Forecast [Member] Pension Benefits [Member]	Dec. 31, 2014 Scenario, Forecast [Member] Pension Benefits [Member] TUCSON ELECTRIC POWER COMPANY
Funded Status And Amount Recognized In Balance Sheet And Statement Of Operations [Line items]
Pension plan contributions					$ 23	$ 23		$ 22	$ 20			$ 6	$ 5		$ 6	$ 5
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year																		10	9
Pension benefit obligations					352	380	319			21	23	75	78	73			1
Defined Benefit Plan, Fair Value of Plan Assets	$ 323	$ 289	$ 16	$ 14	$ 323	$ 289	$ 245					$ 10	$ 7	$ 5

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Interest Rates on TEP's Variable Rate IDBs) (Detail) (TUCSON ELECTRIC POWER COMPANY, Variable Rate Demand Obligation [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
TUCSON ELECTRIC POWER COMPANY | Variable Rate Demand Obligation [Member]
Schedule of Interest Rate [Line Items]
Average Interest Rate	0.10%	0.17%	0.18%
Range of Average weekly interest rate, minimum	0.06%	0.06%	0.05%
Average Weekly Interest Rate Range Maximum	0.25%	0.26%	0.34%

XML

SHARE-BASED COMPENSATION PLANS (Summary of Performance and Restricted Share Awards) (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 574	$ 550	$ 495
Non-vested, beginning balance	15,000
Granted, Shares	31,000
Number of shares that vested during the period	16,000
Forfeited, Shares	(2,000)
Non-vested, ending balance	28,000	15,000
Non-vested, beginning balance	$ 35.94
Granted	$ 47.04
Vested	$ 36.27
Forfeited	$ 46.23
Non-vested, ending balance	$ 47.12	$ 35.94
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 2,387	$ 2,377	$ 1,069
Non-vested, beginning balance	145,000
Granted, Shares	52,000
Number of shares that vested during the period	52,000
Forfeited, Shares	(32,000)
Non-vested, ending balance	113,000	145,000
Non-vested, beginning balance	$ 34.83
Granted	$ 44.94
Vested	$ 35.35
Forfeited	$ 37.57
Non-vested, ending balance	$ 38.45	$ 34.83

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Detail) (USD $)	12 Months Ended						1 Months Ended			12 Months Ended				12 Months Ended			1 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY	Apr. 30, 2013 TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Jun. 30, 2012 TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Mar. 31, 2012 TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Mar. 31, 2013 TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Sep. 30, 2012 TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY Springerville Common Facilities Lease Debt [Member]	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY Variable Rate Demand Obligation [Member]	Dec. 31, 2010 TUCSON ELECTRIC POWER COMPANY Variable Rate Demand Obligation [Member]	Aug. 31, 2009 TUCSON ELECTRIC POWER COMPANY Variable Rate Demand Obligation [Member]	Aug. 31, 2011 UNS ELECTRIC, INC. Uns Electric Term Loan [Member]	Dec. 31, 2012 Parent [Member] Convertible Debt [Member]	Dec. 31, 2005 Parent [Member] Convertible Debt [Member]	Sep. 30, 2012 Revolving Credit Facility [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Dec. 31, 2013 Revolving Credit Facility [Member] Parent [Member] Line of Credit [Member]	Dec. 31, 2013 Letter of Credit [Member] TUCSON ELECTRIC POWER COMPANY Line of Credit [Member]	Jun. 30, 2012 Minimum [Member] TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Mar. 31, 2012 Minimum [Member] TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Jun. 30, 2012 Maximum [Member] TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Mar. 31, 2012 Maximum [Member] TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Oct. 31, 2013 Collateralized Mortgage Backed Securities [Member] TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 Variable Rate Bonds [Member] TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]	Nov. 30, 2013 Variable Rate Bonds [Member] TUCSON ELECTRIC POWER COMPANY Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, face amount								$ 16,000,000	$ 177,000,000		$ 91,000,000	$ 150,000,000		$ 115,000,000	$ 37,000,000		$ 30,000,000		$ 150,000,000											$ 100,000,000
Fixed interest rate of long-term debt							6.375%	4.50%	4.50%		4.00%	3.85%							4.50%					5.85%	5.85%	5.875%	5.875%
Repayments of convertible debt																		3,000,000
Amount of 1992 mortgage bonds used to secure letter of credit facilities																												423,000,000
Derivative amount of hedged item																50,000,000
Fixed rate of interest related to interest rate swap																2.40%	0.97%
Derivative basis spread													1.75%
Repayment of outstanding credit facility	108,000,000	381,000,000	351,000,000	78,000,000	199,000,000	210,000,000														72,000,000
Repayments of long-term debt	0	9,341,000	252,125,000	0	6,535,000	172,460,000			7,000,000
Debt extinguishment							91,000,000	16,000,000	184,000,000	193,000,000				100,000,000
Accrued interest portion on debt repayment									1,000,000
Effective interest rate																													0.948%
Term of debt																	4 years												5 years
Debt instrument																	$ 30,000,000
Interest rate spread on LIBOR borrowing																	1.125%				1.125%	1.25%	1.125%

XML

EMPLOYEE BENEFIT PLANS (Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]
Health Care Cost Trend Rate Assumed for Next Year	6.70%	6.90%
Ultimate Health Care Cost Trend Rate Assumed	4.50%	4.50%
Year that the Rate Reaches the Ultimate Trend Rate	2027	2027

XML

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Operations [Abstract]

Public Utility Property, Plant, and Equipment

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

	UNS Energy				TEP
	December 31,				December 31,
	2013		2012		2013		2012
	Millions of Dollars
Plant in Service:
Electric Generation Plant	$	1,974	$	1,932	$	1,889	$	1,847
Electric Transmission Plant	912		842		825		796
Electric Distribution Plant	1,529		1,495		1,298		1,271
Gas Distribution Plant	252		240		—		—
Gas Transmission Plant	18		18		—		—
General Plant	356		347		312		309
Intangible Plant - Software Costs (1) (2)	142		124		141		123
Intangible Plant - Other	5		5		—		—
Electric Plant Held for Future Use	4		3		3		2
Total Plant in Service	$	5,192	$	5,006	$	4,468	$	4,348
Utility Plant under Capital Leases(3)	$	638	$	583	$	638	$	583

⁽¹⁾  Unamortized computer software costs were $40 million for UNS Energy and $39 million for TEP as of December 31, 2013, and $36 million for UNS Energy and $35 million for TEP as of December 31, 2012.

⁽²⁾  The amortization of computer software costs in UNS Energy’s and TEP's income statements was $14 million in 2013, $13 million in 2012, and $10 million in 2011.

⁽³⁾  In 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 6.

Amount Of Lease Expense Incurred Related Capital Leases

The following table shows the amount of lease expense incurred for TEP’s generation-related capital leases:

	Years Ended December 31,
	2013		2012		2011
	Millions of Dollars
Lease Expense:
Interest Expense – Included in:
Capital Leases	25		$	34	$	40
Operating Expenses – Fuel	2		3		4
Other Expense	—		—		1
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel	5		4		3
Operating Expenses – Amortization	15		14		14
Total Lease Expense	$	47	$	55	$	62

Depreciable Lives Of Utility Plant In Service

Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2013, were as follows:

	TEP
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant (1)	3.31%	22
Electric Transmission Plant	1.48%	32
Electric Distribution Plant (1)	2.08%	35
General Plant (1)	5.48%	11
Intangible Plant (2)	Various	Various

	UNS Electric
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant	2.56%	36
Electric Transmission Plant	3.36%	19
Electric Distribution Plant	3.97%	15
General Plant	8.01%	7
Intangible Plant (3)	Various	Various

	UNS Gas
	December 31, 2013
	Annual Depreciation Rate (5)	Average Remaining Life in Years
Major Class of Utility Plant in Service:
Gas Generation Plant	2.37%	41
Gas Transmission Plant	1.54%	54
General Plant	4.38%	7
Intangible Plant (4)	Various	Various

⁽¹⁾ In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 3.

⁽²⁾  The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life based on either the average lives of 3 to 5 years for smaller application software or remaining lives ranging from 5 to 19 years for large enterprise software.

⁽³⁾  UNS Electric's intangible plant primarily represents capitalized interconnection costs, which are amortized based on either an average life of 23 years or a remaining life of 35 years.

⁽⁴⁾  UNS Gas' intangible plant consists of miscellaneous intangible assets, which are amortized over an average life of either 15 or 25 years.

⁽⁵⁾  The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant.

Schedule of Jointly Owned Utility Plants

At December 31, 2013, TEP’s interests in jointly-owned generating stations and transmission systems were as follows:

	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Net Book Value
		Millions of Dollars
San Juan Units 1 and 2	50.0%	$	448	$	6	$	230	$	224
Navajo Units 1, 2, and 3	7.5%	152		1		110		43
Four Corners Units 4 and 5	7.0%	101		2		75		28
Luna Energy Facility	33.3%	53		—		2		51
Transmission Facilities	Various	330		43		190		183
Total		$	1,084	$	52	$	607	$	529

Schedule of Asset Retirement Obligations

The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:

	UNS Energy
	December 31,
	2013		2012
	Millions of Dollars
Beginning Balance	$	14	$	13
Liabilities Incurred	1		—
Accretion Expense or Regulatory Deferral	1		1
Revisions to the Present Value of Estimated Cash Flows (1)	7		—
Ending Balance	$	23	$	14

⁽¹⁾ Primarily related to changes in expected retirement dates of generating facilities.

The table above primarily reflects TEP's ARO obligations. UNS Electric's ARO obligations were less than $1 million at December 31, 2013 and 2012.

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REGULATORY MATTERS (Summary of PPFAC Rates) (Detail)	3 Months Ended	6 Months Ended		9 Months Ended	3 Months Ended	6 Months Ended		9 Months Ended	3 Months Ended		6 Months Ended				9 Months Ended		3 Months Ended	4 Months Ended	5 Months Ended		7 Months Ended
	Mar. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Mar. 31, 2012 TUCSON ELECTRIC POWER COMPANY PPFAC [Member]	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY PPFAC [Member]	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY PPFAC [Member]	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY PPFAC [Member]	Mar. 31, 2012 TUCSON ELECTRIC POWER COMPANY CTC [Member]		Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY CTC [Member]		Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY CTC [Member]		Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY CTC [Member]		Aug. 31, 2013 UNS Electric	Dec. 31, 2013 UNS Electric	May 31, 2013 UNS Electric	May 31, 2012 UNS Electric	Dec. 31, 2012 UNS Electric
Schedule of Regulatory Matters Summary Of PPFAC Rates [Table] [Line Items]
PPFAC Rates	0.0000	0.0014	0.0077	0.0077	0.0053	0.0014	0.0077	0.0077	(0.0053)	[1]	0.0000	[1]	0.0000	[1]	0.0000	[1]	(0.0092)	(0.0040)	(0.0144)	(0.0088)	(0.0144)

[1] TEP's PPFAC became effective January 1, 2009. However, TEP was initially required to refund amounts to customers through the PPFAC mechanism that were over collected under the Competition Transition Charge (CTC) in place from 1999 through 2008. As a result, the authorized net PPFAC charge was set at zero until all over collected CTC revenue was fully refunded to customers (November 2011). TEP then continued deferring PPFAC eligible costs but was not authorized to bill customers until a new PPFAC rate was approved by the ACC in April 2012.

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SHARE-BASED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

SHARE-BASED COMPENSATION PLANS

SHARE-BASED COMPENSATION PLANS

Under the UNS Energy 2011 Omnibus Stock and Incentive Plan (2011 Plan), the Compensation Committee of the UNS Energy Board of Directors (Compensation Committee) may issue various types of share-based compensation, including stock options, restricted stock units, and performance shares. The total number of shares which may be awarded under the 2011 Plan cannot exceed 1.2 million shares.

STOCK OPTIONS

Stock options are granted with an exercise price equal to the fair market value of the stock on the date of grant, vest over three years, become exercisable in one-third increments on each anniversary date of the grant, and expire on the tenth anniversary of the grant. We recognize compensation expense on a straight-line basis over the service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement-eligible officers, we recognize compensation expense immediately. No stock options were granted by the Compensation Committee in 2013, 2012, or 2011.

See summary of stock option activity in the table below:

	2013				2012				2011
Stock Options	Shares (000s)		Weighted Average Exercise Price		Shares (000s)		Weighted Average Exercise Price		Shares (000s)		Weighted Average Exercise Price
Outstanding, Beginning of Year	409		$	29.09	581		$	29.11	921		$	27.96
Exercised	(127	)	30.12		(132	)	26.54		(319	)	25.60
Forfeited/Expired	—		—		(40	)	37.88		(21	)	31.92
Outstanding, End of Year	282		28.63		409		29.09		581		29.11
Exercisable, End of Year	282		$	28.63	409		$	29.09	508		$	29.53
Aggregate Intrinsic Value of Options Exercised ($000s)			$	2,897			$	1,878			$	3,690

See summary of stock options in the tables below:

	December 31, 2013
Aggregate Intrinsic Value for Options Outstanding ($000s)	$	8,795
Aggregate Intrinsic Value for Options Exercisable ($000s)	$	8,795
Weighted Average Remaining Contractual Term of Outstanding Options	4.1 years
Weighted Average Remaining Contractual Term of Exercisable Options	4.1 years

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number  of Shares (000s)	Weighted Average Remaining Contractual Term	Weighted Average Exercise Price		Number  of Shares (000s)	Weighted Average Exercise Price
$26.11—$37.88	282	4.1 years	$	28.63	282	$	28.63

RESTRICTED STOCK UNITS AND PERFORMANCE SHARES

Restricted Stock Units

In 2013, 2012, and 2011, the Compensation Committee granted restricted stock units to non-employee directors. We recognize compensation expense equal to the fair valuin the tablee on the grant date over the one-year vesting period. The grant date fair value was calculated by reducing the grant date share price by the present value of the dividends expected to be paid on the shares during the vesting period. Fully vested but undistributed non-employee director stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. We issue Common Stock for the vested stock units in the January following the year the person is no longer a director.

In 2013, the Compensation Committee granted restricted stock units to certain management employees. The restricted stock units vest on the third anniversary of grant and are distributed in shares of Common Stock upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. The grant date fair value was the closing Common Stock market price on the date of grant. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.

See summary of restricted stock units awarded in the table below:

	Non-Employee Directors			Management Employees
Award Year	Restricted Stock Units	Grant Date Fair Value		Restricted Stock Units	Grant Date Fair Value
2013	8,870	$	48.99	21,560	$	46.23
2012	15,303	35.94		—	—
2011	14,655	37.53		—	—

Performance Shares

In 2013, 2012, and 2011, the Compensation Committee granted performance share awards to certain management employees. Half of the performance share awards will be paid out in Common Stock based on UNS Energy’s compound annualized Total Shareholder Return (TSR) relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period. The grant date fair values of these awards were derived based on a Monte Carlo simulation. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half will be paid out in Common Stock based on cumulative net income (CNI) for the three-year performance period. The grant date fair values of these awards were the closing Common Stock market prices on the dates of grant. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.

The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.

See summary of performance shares awarded in the table below:

		Grant Date Fair Value
Award Year	Performance Shares	TSR-Based Award		CNI-Based Award
2013	43,120	$	45.54	$	46.23
2012	80,140	32.71		36.40
2011	80,440	33.73		36.58

At December 31, 2013, upon completion of the three-year performance period, 68,158 shares were earned and vested based on goal attainment at 150% of target for the awards based on TSR and 57.8% of target for the awards based on CNI; 28,682 shares were unearned and forfeited. The vested performance shares also earned 8,521 in dividend equivalent shares.

See summary of restricted stock units and performance shares current year activity in the table below:

	Restricted Stock Units				Performance Shares
	Shares (000s)		Weighted Average Grant  Date Fair Value		Shares (000s)		Weighted Average Grant  Date Fair Value
Non-vested, Beginning of Year	15		$	35.94	145		$	34.83
Granted	31		47.04		52		44.94
Vested	(16	)	36.27		(52	)	35.35
Forfeited	(2	)	46.23		(32	)	37.57
Non-vested, End of Year	28		47.12		113		38.45

The total fair value of restricted stock units and performance shares vested were as follows:

	Restricted Stock Units						Performance Shares
	2013		2012		2011		2013		2012		2011
	Thousands of Dollars
Total Fair Value of Shares Vested	$	574	$	550	$	495	$	2,387	$	2,377	$	1,069

Common Stock shares totaling 57,253 in 2013, 31,058 in 2012, and 56,705 in 2011 were issued with no additional increase in equity as the expense was previously recognized over the vesting period.

SHARE-BASED COMPENSATION EXPENSE

In 2013, UNS Energy and TEP recorded share-based compensation expense of $3 million. In 2012 and 2011, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. No share-based compensation was capitalized as part of the cost of an asset. UNS Energy did not realize a tax deduction from the exercise of share-based payment arrangements in 2013 or 2011. In 2012, the actual tax deduction realized from the exercise of share-based payment arrangements totaled less than $0.5 million.

At December 31, 2013, the total unrecognized compensation cost related to non-vested share-based compensation was $3 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016. At December 31, 2013, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.

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FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Derivative [Line Items]
Fair value of derivative instruments	$ (21)
Additional collateral if credit-risk contingent features are triggered	21
TUCSON ELECTRIC POWER COMPANY
Derivative [Line Items]
Fair value of derivative instruments	5
Additional collateral if credit-risk contingent features are triggered	$ (5)

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

12 Months Ended

Dec. 31, 2013

Statement of Comprehensive Income [Abstract]

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT

The realized changes in AOCI by component are as follows:

Details About Accumulated Other Comprehensive Income Components	Amount Reclassified from Other Comprehensive Income						Affected Line Item in the Income Statement
	UNS Energy			TEP
	Year Ended December 31, 2013
	Thousands of Dollars
Realized Losses on Cash Flow Hedges
Interest Rate Swaps - Debt	$	(1,377	)	$	(1,166	)	Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases	(2,429		)	(2,429		)	Interest Expense Capital Leases
Commodity Contracts	(747		)	(747		)	Purchased Energy/Purchased Power
Tax Benefit	1,801			1,718
Realized Losses on Cash Flow Hedges, Net of Taxes	(2,752		)	(2,624		)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(1,488		)	(1,488		)	Other Expense
Tax Benefit	572			572
Amortization, Net of Taxes	(916		)	(916		)
Total Reclassifications from Other Comprehensive Income for the Period	$	(3,668	)	$	(3,540	)

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EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Pension Plan Assets) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 323	$ 289
Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	21	19	15
Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	14	13	11
Level 3 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7	6	4
Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	10	7	5
Fair Value Measurements of Pension Assets [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1	1
Fair Value Measurements of Pension Assets [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	80	71
Fair Value Measurements of Pension Assets [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	17	15
Fair Value Measurements of Pension Assets [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	65	59
Fair Value Measurements of Pension Assets [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	130	116
Fair Value Measurements of Pension Assets [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	23	21
Fair Value Measurements of Pension Assets [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7	6
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1	1
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	1	1
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 1 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	301	269
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	80	71
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	17	15
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	65	59
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	130	116
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	9	8
Fair Value Measurements of Pension Assets [Member] | Level 2 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	21	19
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	14	13
Fair Value Measurements of Pension Assets [Member] | Level 3 [Member] | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	7	6
Uns Gas And Uns Electric [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	16	14
Uns Gas And Uns Electric [Member] | Level 2 [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	16	14
VEBA Trust [Member] | Other Retiree Benefits [Member]
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	10	7
VEBA Trust [Member] | Other Retiree Benefits [Member] | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	4	3
VEBA Trust [Member] | Other Retiree Benefits [Member] | VEBA Trust Asset - Equities
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 6	$ 4

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REGULATORY MATTERS (Rate Order) (Details) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended			1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2013 UNS Electric	Jun. 30, 2013 UNS Gas	Apr. 30, 2012 UNS Gas	Jun. 30, 2013 Before July 1, 2013 [Member] TUCSON ELECTRIC POWER COMPANY	Jun. 30, 2013 After June 30, 2013 [Member] [Member] TUCSON ELECTRIC POWER COMPANY
Schedule of Regulatory Orders [Line Items]
Base rate increase approved				$ 76,000,000				$ 3,000,000		$ 2,700,000
Original cost rate base				1,500,000,000				213,000,000		183,000,000
Fair value of rate base				2,300,000,000				283,000,000
Approved rate of return on equity				10.00%				9.50%
Approved long term cost of debt				5.18%				5.97%
Approved short-term cost of debt				1.42%
Approved weighted average cost of capital				7.26%				7.83%
Approved equity portion of capital structure				43.50%				52.60%
Approved long term debt portion of capital structure				56.00%				47.40%
Approved short-term debt portion of capital structure				0.50%
Approved rate of return on the fair value increment of rate base				0.68%				0.50%		1.00%
Fair value increment of rate base				800,000,000				70,000,000		70,000,000
Change in composite rate											3.32%	3.00%
Expected change in annual depreciation				11,000,000
PPFAC credit				0.1388
PPFAC Reduction - TEP Rate Order	3,000,000	0	0	3,000,000	3,000,000	0	0
Deferred costs related to San Juan Mine Fire				10,000,000
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism				2,000,000
Environmental compliance adjustor capped rate				0.025
Retail revenue cap on environmental compliance adjustor				0.25%
Approved energy efficiency budget				21,000,000				5,000,000	2,000,000
Performance Incentive Included in Efficiency Budget				$ 2,000,000
Percentage increase in base rates approved by regulator										1.80%
Authorized rate of return										8.30%

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UNS ENERGY EARNINGS PER SHARE - Number of Stock Options to Purchase Shares of Common Stock Excluded from Computation of Diluted Earning Per Share (Detail) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	50	153
Stock Options [Member]
Anti-Dilutive Shares Excluded from the Diluted EPS Computation	0	50	153
Restricted Stock Units (RSUs) [Member]
Anti-Dilutive Shares Excluded from the Diluted EPS Computation	6	0	0

XML

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:

	UNS Energy
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Net Income	$	127,478		$	90,919		$	109,975
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities
Depreciation Expense	149,615			141,303			133,832
Amortization Expense	27,557			35,784			30,983
Depreciation and Amortization Recorded to Fuel and O&M Expense	7,288			6,622			6,140
Amortization of Deferred Debt-Related Costs included in Interest Expense	3,050			3,000			3,985
Provision for Retail Customer Bad Debts	2,263			2,767			2,072
Use of Renewable Energy Credits for Compliance	17,706			5,935			5,695
Deferred Income Taxes	83,501			60,264			75,515
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(11,039		)	—			—
Pension and Retiree Expense	22,783			21,856			21,202
Pension and Retiree Funding	(29,161		)	(29,058		)	(28,775		)
Share-Based Compensation Expense	3,399			2,573			2,599
Allowance for Equity Funds Used During Construction	(6,190		)	(3,464		)	(4,496		)
Increase (Decrease) to Reflect PPFAC/PGA Recovery	(16,313		)	32,246			(4,932		)
PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
Competition Transition Charge Revenue Refunded	—			—			(35,958		)
Partial Write-off of Tucson to Nogales Transmission Line	—			4,668			—
Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,338		)	3,369			2,743
Materials and Fuel Inventory	16,197			(39,429		)	(20,864		)
Accounts Payable	3,223			595			8,792
Income Taxes	(15,868		)	(11,557		)	(2,739		)
Interest Accrued	4,875			6,922			14,344
Taxes Other Than Income Taxes	1,941			(58		)	2,857
Current Regulatory Liabilities	11,124			(684		)	2,644
Other	20,421			11,486			19,097
Net Cash Flows – Operating Activities	$	420,512		$	348,109		$	337,320

	TEP
	Years Ended December 31,
	2013			2012			2011
	Thousands of Dollars
Net Income	$	101,342		$	65,470		$	85,334
Adjustments to Reconcile Net Income
To Net Cash Flows from Operating Activities
Depreciation Expense	118,076			110,931			104,894
Amortization Expense	31,294			39,493			34,650
Depreciation and Amortization Recorded to Fuel and O&M Expense	6,219			5,384			4,509
Amortization of Deferred Debt-Related Costs Included in Interest Expense	2,452			2,227			2,378
Provision for Retail Customer Bad Debts	1,678			1,871			1,447
Use of RECs for Compliance	15,990			5,071			5,190
Deferred Income Taxes	69,950			45,232			59,309
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset	(10,751		)	—			—
Pension and Retiree Expense	19,878			19,289			18,816
Pension and Retiree Funding	(27,636		)	(25,899		)	(25,878		)
Share-Based Compensation Expense	2,709			2,029			2,027
Allowance for Equity Funds Used During Construction	(4,526		)	(2,840		)	(3,842		)
Increase (Decrease) to Reflect PPFAC Recovery	(12,458		)	31,113			(6,165		)
PPFAC Reduction - 2013 TEP Rate Order	3,000			—			—
Competition Transition Charge Revenue Refunded	—			—			(35,958		)
Partial Write-off of Tucson to Nogales Transmission Line	—			4,484			—
Liquidated Damages for Springerville Unit 3 Outage	—			2,050			—
Gain on Settlement of El Paso Electric Dispute	—			—			(7,391		)
Changes in Assets and Liabilities which Provided (Used)
Cash Exclusive of Changes Shown Separately
Accounts Receivable	(6,041		)	(871		)	4,809
Materials and Fuel Inventory	16,145			(38,384		)	(19,789		)
Accounts Payable	334			1,115			14,561
Income Taxes	(10,790		)	(11,421		)	(5,582		)
Interest Accrued	4,859			8,055			14,268
Taxes Other Than Income Taxes	1,425			905			2,282
Current Regulatory Liabilities	3,331			(3,040		)	303
Other	19,711			5,655			18,122
Net Cash Flows – Operating Activities	$	346,191		$	267,919		$	268,294

Supplemental Noncash Investing And Financing Activities Table

Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
	2013		2012		2011
	Thousands of Dollars
(Decrease)/Increase to Utility Plant Accruals(1)	$	4,995	$	4,813	$	(2,741	)
Net Cost of Removal of Interim Retirements(2)	25,182		35,983		31,626
Capital Lease Obligations(3)	9,039		11,967		15,162
Asset Retirement Obligations(4)	8,064		789		7,638

⁽¹⁾  The non-cash additions to Utility Plant represent accruals for capital expenditures.

⁽²⁾  The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings.

⁽³⁾  The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments.

⁽⁴⁾  The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations.

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SUPPLEMENTAL CASH FLOW INFORMATION (Reconciliation of Net Income to Net Cash Flows from Operating Activities) (Detail) (USD $) In Thousands, unless otherwise specified	1 Months Ended	3 Months Ended								12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Line Items]
Net Income		$ 13,525	$ 67,990	$ 34,618	$ 11,345	$ 7,506	$ 50,664	$ 26,273	$ 6,476	$ 127,478	$ 90,919	$ 109,975
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities
Depreciation Expense										149,615	141,303	133,832
Amortization Expense										27,557	35,784	30,983
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense										7,288	6,622	6,140
Amortization of Deferred Debt-Related Costs Included in Interest Expense										3,050	3,000	3,985
Provision for Retail Customer Bad Debts										2,263	2,767	2,072
Use of RECs for Compliance										17,706	5,935	5,695
Deferred Income Taxes										83,501	60,264	75,515
Investment Tax Credit Basis Adjustment	(11,039)										0	0
Pension and Postretirement Expense										22,783	21,856	21,202
Pension and Postretirement Funding										(29,161)	(29,058)	(28,775)
Share-Based Compensation Expense										3,399	2,573	2,599
Allowance for Equity Funds Used During Construction										(6,190)	(3,464)	(4,496)
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment										(16,313)	32,246	(4,932)
PPFAC Reduction - TEP Rate Order										3,000	0	0
Competition Transition Charge Revenue Refunded										0	0	(35,958)
Partial Write-off of Tucson to Nogales Transmission Line										0	4,668	0
Liquidated Damages for Springerville Unit 3 Outage										0	2,050	0
Gain on Settlement of El Paso Electric Dispute										0	0	(7,391)
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately
Accounts Receivable										(6,338)	3,369	2,743
Materials and Fuel Inventory										16,197	(39,429)	(20,864)
Accounts Payable										3,223	595	8,792
Income Taxes										(15,868)	(11,557)	(2,739)
Interest Accrued										4,875	6,922	14,344
Taxes Other Than Income Taxes										1,941	(58)	2,857
Increase (Decrease) in Regulatory Liabilities										11,124	(684)	2,644
Other										20,421	11,486	19,097
Net Cash Flows—Operating Activities										420,512	348,109	337,320
TUCSON ELECTRIC POWER COMPANY
Supplemental Cash Flow Information [Line Items]
Net Income		4,910	64,167	30,787	1,478	452	44,569	21,910	(1,461)	101,342	65,470	85,334
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities
Depreciation Expense										118,076	110,931	104,894
Amortization Expense										31,294	39,493	34,650
Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense										6,219	5,384	4,509
Amortization of Deferred Debt-Related Costs Included in Interest Expense										2,452	2,227	2,378
Provision for Retail Customer Bad Debts										1,678	1,871	1,447
Use of RECs for Compliance										15,990	5,071	5,190
Deferred Income Taxes										69,950	45,232	59,309
Investment Tax Credit Basis Adjustment										(10,751)	0	0
Pension and Postretirement Expense										19,878	19,289	18,816
Pension and Postretirement Funding										(27,636)	(25,899)	(25,878)
Share-Based Compensation Expense										2,709	2,029	2,027
Allowance for Equity Funds Used During Construction										(4,526)	(2,840)	(3,842)
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment										(12,458)	31,113	(6,165)
PPFAC Reduction - TEP Rate Order	3,000									3,000	0	0
Competition Transition Charge Revenue Refunded										0	0	(35,958)
Partial Write-off of Tucson to Nogales Transmission Line										0	4,484	0
Liquidated Damages for Springerville Unit 3 Outage										0	2,050	0
Gain on Settlement of El Paso Electric Dispute										0	0	(7,391)
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately
Accounts Receivable										(6,041)	(871)	4,809
Materials and Fuel Inventory										16,145	(38,384)	(19,789)
Accounts Payable										334	1,115	14,561
Income Taxes										(10,790)	(11,421)	(5,582)
Interest Accrued										4,859	8,055	14,268
Taxes Other Than Income Taxes										1,425	905	2,282
Increase (Decrease) in Regulatory Liabilities										3,331	(3,040)	303
Other										19,711	5,655	18,122
Net Cash Flows—Operating Activities										$ 346,191	$ 267,919	$ 268,294

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	$ (1,850)	$ (743)	$ 964
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	(572)	608	(804)
TUCSON ELECTRIC POWER COMPANY
Income Tax on Net Changes in Fair Value of Cash Flow Hedges	(1,793)	(887)	941
Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income	$ (572)	$ 608	$ (804)

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EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3
Interest Cost		15
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	13	10	10
Interest Cost	15	16	15
Expected Return on Plan Assets	(20)	(17)	(16)
Prior Service Cost Amortization	0	0	0
Amortization of Actuarial (Gain) Loss	9	7	6
Net Periodic Benefit Plan Cost	17	16	15
Other Retiree Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	3	3
Interest Cost	3	3	4
Expected Return on Plan Assets	(1)	0	0
Prior Service Cost Amortization	(1)	0	(1)
Amortization of Actuarial (Gain) Loss	1	0	0
Net Periodic Benefit Plan Cost	$ 6	$ 6	$ 6

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CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	75,000,000	75,000,000
TUCSON ELECTRIC POWER COMPANY
Common Stock, Shares Authorized	75,000,000	75,000,000

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UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for TEP's Generation-Related Capital Leases) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest Expense - Included in:
Interest Expense	$ 25,140,000	$ 33,613,000	$ 40,358,000
Total Lease Expense	47,000,000	55,000,000	62,000,000
Operating Expenses - Fuel
Interest Expense - Included in:
Interest Expense	2,000,000	3,000,000	4,000,000
Amortization of Capital Lease Assets	5,000,000	4,000,000	3,000,000
Other Expense [Member]
Interest Expense - Included in:
Interest Expense	0	0	1,000,000
Operating Expenses - Amortization [Member]
Interest Expense - Included in:
Amortization of Capital Lease Assets	$ 15,000,000	$ 14,000,000	$ 14,000,000

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EMPLOYEE BENEFIT PLANS (Additional Information) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentage of net periodic benefit cost that was capitalized	21.00%
Level 3 [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Index value percentage of real estate assets	85.00%	87.00%
Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan contributions	$ 6	$ 5
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan contributions	23	23
Defined Benefit Plan, Accumulated Benefit Obligation	314	334
TUCSON ELECTRIC POWER COMPANY
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Matching 401(k) contributions made	5	5	5
TUCSON ELECTRIC POWER COMPANY | Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan contributions	6	5
TUCSON ELECTRIC POWER COMPANY | Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan contributions	22	20
UNS Gas and UNS Electric [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Expected annual benefit payment for 2014-2018	7
Expected annual benefit payment for 2019-2023	9
Matching 401(k) contributions made	1	1	1
Other Retiree Benefits [Member] | TUCSON ELECTRIC POWER COMPANY
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Effect of plan amendment on obligation		1
Pension Benefits [Member] | TUCSON ELECTRIC POWER COMPANY
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Effect of plan amendment on obligation		1
Effect of Plan Amendment on Future Payments		5
VEBA Trust [Member] | TUCSON ELECTRIC POWER COMPANY | Other Retiree Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan contributions	$ 3	$ 3	$ 2

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STOCKHOLDERS' EQUITY (Additional Information) (Detail) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	12 Months Ended							1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2011 TUCSON ELECTRIC POWER COMPANY	Dec. 31, 2012 Convertible Debt [Member] UNS Energy	Feb. 25, 2014 Subsequent Event [Member]
Class of Stock [Line Items]
Dividends declared (usd per share)	$ 1.74	$ 1.72	$ 1.68					$ 0.48
Dividend payable								$ 20,000,000
Converted notes principal							147,000,000
UNS Energy common stock							4,300
Dividends paid to UNS energy				40,000,000	30,000,000	0
Equity investment from parent	$ 0	$ 0	$ 30,000,000	$ 0	$ 0	$ 30,000,000

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DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Parenthetical) (Detail) (TUCSON ELECTRIC POWER COMPANY, USD $)	Dec. 31, 2013 Variable Rate Demand Obligation [Member]	Dec. 31, 2010 Variable Rate Demand Obligation [Member]	Dec. 31, 2013 Unsecured Debt [Member]	Mar. 31, 2013 Unsecured Debt [Member]	Sep. 30, 2012 Unsecured Debt [Member]	Jun. 30, 2012 Unsecured Debt [Member]	Mar. 31, 2012 Unsecured Debt [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Debt instrument, face amount	$ 115,000,000	$ 37,000,000		$ 91,000,000	$ 150,000,000	$ 16,000,000	$ 177,000,000
Debt discount			$ 1,000,000

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RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board (FASB) issued guidance for the recognition, measurement, and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors. This guidance will be effective in the first quarter of 2014. We do not expect the adoption of this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair value and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.

The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such change to be material. In addition, we do not expect any material changes in the presentations of our other financial statements.

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Gains and Losses on Cash Flow Hedges
Tax Benefit	$ 1,801
Realized Losses on Cash Flow Hedges, Net of Taxes	(2,752)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(1,488)
Tax (Expense) Benefit	572	(608)	804
Amortization, Net of Taxes	(916)	840	(1,158)
Total Reclassification from Other Comprehensive Income for the Period	(3,668)
TUCSON ELECTRIC POWER COMPANY
Gains and Losses on Cash Flow Hedges
Tax Benefit	1,718
Realized Losses on Cash Flow Hedges, Net of Taxes	(2,624)
Amortization of SERP and Defined Benefit Plans
Prior Service Costs	(1,488)
Tax (Expense) Benefit	572	(608)	804
Amortization, Net of Taxes	(916)	840	(1,158)
Total Reclassification from Other Comprehensive Income for the Period	(3,540)
Interest Rate Contract Long Term Debt [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(1,377)
Interest Rate Contract Long Term Debt [Member] | TUCSON ELECTRIC POWER COMPANY
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(1,166)
Interest Rate contract Capital Leases [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(2,429)
Interest Rate contract Capital Leases [Member] | TUCSON ELECTRIC POWER COMPANY
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(2,429)
Commodity Contract [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(747)
Commodity Contract [Member] | TUCSON ELECTRIC POWER COMPANY
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	$ (747)

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POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY Additional Information (Details) (Entegra, Gila River Generating Station Unit 3, USD $) In Millions, unless otherwise specified	Feb. 25, 2014	Dec. 23, 2013 MW
Unusual or Infrequent Item [Line Items]
Potential Purchase of Gas-Fired Generation Facility		$ 219
Generating capacity of plant in MW		550
TUCSON ELECTRIC POWER COMPANY
Unusual or Infrequent Item [Line Items]
Potential Purchase of Gas-Fired Generation Facility		164
Generating capacity of plant in MW		413
Percentage of ownership in Generating Unit		75.00%
Letters Of Credit Potential Amount	15
UNS ELECTRIC, INC.
Unusual or Infrequent Item [Line Items]
Potential Purchase of Gas-Fired Generation Facility		$ 55
Generating capacity of plant in MW		137
Percentage of ownership in Generating Unit		25.00%

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule of Amounts Recognized in Balance Sheet

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

	Pension Benefits						Other  Retiree Benefits
	Years Ended December 31,
	2013			2012			2013			2012
	Millions of Dollars
Regulatory Pension Asset Included in Other Regulatory Assets	$	75		$	129		$	4		$	10
Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)	(1		)	(2		)	(2		)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(28		)	(90		)	(63		)	(69		)
Accumulated Other Comprehensive Loss (related to SERP)	2			4			—			—
Net Amount Recognized	$	48		$	42		$	(61	)	$	(61	)

The table above includes accrued pension benefit liabilities for UNS Electric and UNS Gas of approximately $5 million at December 31, 2013 and $9 million at December 31, 2012. The table also includes an other retiree benefit liability of $1 million for UNS Electric and UNS Gas for each period presented.

Schedule of Changes in Projected Benefit Obligations

We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2013 and December 31, 2012. The table below includes TEP’s, UNS Electric’s, and UNS Gas’ plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below:

	Pension Benefits						Other  Retiree Benefits
	Years Ended December 31,
	2013			2012			2013			2012
	Millions of Dollars
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	380		$	319		$	78		$	73
Actuarial (Gain) Loss	(38		)	51			(5		)	3
Interest Cost	15			15			3			3
Service Cost	13			10			3			3
Benefits Paid	(18		)	(15		)	(4		)	(4		)
Projected Benefit Obligation at End of Year	352			380			75			78
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year	289			245			7			5
Actual Return on Plan Assets	29			36			1			1
Benefits Paid	(18		)	(15		)	(4		)	(4		)
Employer Contributions (1)	23			23			6			5
Fair Value of Plan Assets at End of Year	323			289			10			7
Funded Status at End of Year	$	(29	)	$	(91	)	$	(65	)	$	(71	)

⁽¹⁾  TEP made $22 million in pension contributions and $6 million in other retiree benefits contributions in 2013 and $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012. In 2014, UNS Energy expects to contribute $10 million to the pension plans, including $9 million in contributions by TEP.

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

• Pension benefit obligations of $21 million at December 31, 2013 and $23 million at December 31, 2012;

• Plan assets of $16 million at December 31, 2013 and $14 million at December 31, 2012; and

• A retiree benefit obligation of $1 million at December 31, 2013 and December 31, 2012.

Schedule of Net Periodic Benefit Cost Not yet Recognized

The following table provides the components of UNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:

	Pension Benefits				Other  Retiree Benefits
	Years Ended December 31,
	2013		2012		2013			2012
	Millions of Dollars
Net Loss	$	77	$	133	$	7		$	13
Prior Service Cost (Benefit)	—		1		(3		)	(3		)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets

The accumulated benefit obligation aggregated for all pension plans is $314 million at December 31, 2013 and $334 million at December 31, 2012.

Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
	December 31,
	2013	2012
	Millions of Dollars
Accumulated Benefit Obligation at End of Year	30	334
Fair Value of Plan Assets at End of Year	16	289

At December 31, 2012, all four UNS Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets. Due to 2013 contributions, returns on plan assets, and the favorable impact of the increase in the discount rate on the accumulated benefit obligations, only the SERP, which is unfunded, and the UES plan have accumulated benefit obligations in excess of plan assets at December 31, 2013.

Components of Net Periodic Benefit Cost

UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:

	Pension Benefits									Other Retiree Benefits
	Years Ended December 31,
	2013			2012			2011			2013			2012		2011
	Millions of Dollars
Service Cost	$	13		$	10		$	10		$	4		$	3	$	3
Interest Cost	15			16			15			3			3		4
Expected Return on Plan Assets	(20		)	(17		)	(16		)	(1		)	—		—
Prior Service Cost Amortization	—			—			—			(1		)	—		(1		)
Actuarial Loss Amortization	9			7			6			1			—		—
Net Periodic Benefit Cost	$	17		$	16		$	15		$	6		$	6	$	6

Approximately 21% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:

	Pension Benefits
	2013						2012					2011
	Regulatory Asset			AOCI			Regulatory Asset			AOCI		Regulatory Asset			AOCI
	Millions of Dollars
Current Year Actuarial (Gain) Loss	$	(46	)	$	(1	)	$	30		$	1	$	25		$	(2	)
Amortization of Actuarial Gain (Loss)	(8		)	—			(7		)	—		(5		)	—
Total Recognized (Gain) Loss	$	(54	)	$	(1	)	$	23		$	1	$	20		$	(2	)

	Other Retiree Benefits
	2013			2012		2011
	Regulatory Asset			Regulatory Asset		Regulatory Asset
	Millions of Dollars
Prior Service Cost (Credit)	$	—		$	—	$	(2	)
Current Year Actuarial (Gain) Loss	(6		)	2		—
Amortization of Actuarial (Gain) Loss	(1		)	—		—
Amortization of Prior Service (Cost) Credit	1			—		1
Total Recognized (Gain) Loss	$	(6	)	$	2	$	(1	)

For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $4 million estimated net loss and less than $1 million prior service cost from other regulatory assets and less than $1 million prior service cost from AOCI into net periodic benefit cost in 2014. The estimated prior service benefit for the other retiree benefit plan that will be amortized from other regulatory assets into net periodic benefit cost in 2014 is less than $1.0 million.

Schedule Of Weighted Average Assumptions Used To Determine Benefit Obligations At Year End Table

	Pension Benefits		Other Retiree Benefits
	2013	2012	2013	2012
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	5.0% - 5.2%	4.1%-4.3%	4.7%	3.8%
Rate of Compensation Increase	3.0%	3.0%	N/A	N/A

Schedule Of Weighted Average Assumptions Used To Determine Net Periodic Benefit Cost Table

	Pension Benefits			Other Retiree Benefits
	2013	2012	2011	2013	2012	2011
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate	4.1%-4.3%	4.9% - 5.0%	5.5% - 5.6%	3.8%	4.7%	5.2%
Rate of Compensation Increase	3.0%	3.0%	3.0% - 5.0%	N/A	N/A	N/A
Expected Return on Plan Assets	7.0%	7.0%	7.0%	7.0%	7.0%	5.1%

Schedule of Health Care Cost Trend Rates

The assumed health care cost trend rates follow:

	December 31,
	2013	2012
Health Care Cost Trend Rate Assumed for Next Year	6.7%	6.9%
Ultimate Health Care Cost Trend Rate Assumed	4.5%	4.5%
Year that the Rate Reaches the Ultimate Trend Rate	2027	2027

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2013, amounts:

	One-Percentage- Point Increase		One-Percentage- Point Decrease
	Millions of Dollars
Effect on Total Service and Interest Cost Components	$	1	$	(1	)
Effect on Retiree Benefit Obligation	6		(5		)

Schedule of Allocation of Plan Assets

The current target allocation percentages for the major asset categories of the plan as of December 31, 2013 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.

	TEP Plan	UNS Electric and UNS Gas Plan	VEBA Trust
Fixed Income	41%	42%	38%
United States Large Cap	24%	24%	39%
Non-United States Developed	15%	14%	7%
Real Estate	8%	10%	—%
United States Small Cap	5%	5%	5%
Non-United States Emerging	5%	5%	9%
Private Equity	2%	—%	—%
Cash/Treasury Bills	—%	—%	2%
Total	100%	100%	100%

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

	TEP Plan Assets				UNS Electric and UNS Gas Plan Assets
	2013		2012		2013		2012
Asset Category
Equity Securities	50	%	50	%	50	%	56	%
Fixed Income Securities	40		41	%	40		33
Real Estate	7		7	%	10		11
Other	3		2	%	—		—
Total	100	%	100	%	100	%	100	%

FV Measurements of Pension Plan Assets by FV Hierarchy

The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:

	Fair Value Measurements of Pension Assets December 31, 2013
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap	—		80		—		80
United States Small Cap	—		17		—		17
Non-United States	—		65		—		65
Fixed Income	—		130		—		130
Real Estate	—		9		14		23
Private Equity	—		—		7		7
Total	$	1	$	301	$	21	$	323
	Fair Value Measurements of Pension Assets December 31, 2012
	Level 1		Level 2		Level 3		Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap	—		71		—		71
United States Small Cap	—		15		—		15
Non-United States	—		59		—		59
Fixed Income	—		116		—		116
Real Estate	—		8		13		21
Private Equity	—		—		6		6
Total	$	1	$	269	$	19	$	289

Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.

Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.

Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 85% of real estate assets tracked by the index in 2013 and comprising 87% in 2012.

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

The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UNS Electric and UNS Gas pension plan of $16 million at December 31, 2013 and $14 million at December 31, 2012.

The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.

Schedule of Changes in Fair Value of Plan Assets

The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.

	Year Ended December 31, 2013
	Private Equity		Real Estate		Total
	Millions of Dollars
Beginning Balance at January 1, 2013	$	6	$	13	$	19
Actual Return on Plan Assets:
Assets Held at Reporting Date	1		1		2
Purchases, Sales, and Settlements	—		—		—
Ending Balance at December 31, 2013	$	7	$	14	$	21

	Year Ended December 31, 2012
	Private Equity		Real Estate		Total
	Millions of Dollars
Beginning Balance at January 1, 2012	$	4	$	11	$	15
Actual Return on Plan Assets:
Assets Held at Reporting Date	1		2		3
Purchases, Sales, and Settlements	1		—		1
Ending Balance at December 31, 2012	$	6	$	13	$	19

Schedule of Expected Benefit Payments

ESTIMATED FUTURE BENEFIT PAYMENTS

TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate.

	2014		2015		2016		2017		2018		2019-2023
	Millions of Dollars
Pension Benefits	$	15	$	16	$	17	$	18	$	20	$	114
Other Retiree Benefits	5		5		5		5		5		29

One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million.

UNS Electric and UNS Gas expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $7 million in 2014 through 2018, and $9 million in 2019 through 2023

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

We sponsor three noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.

We also maintain a Supplemental Executive Retirement Plan (SERP) for executive management.

OTHER RETIREE BENEFIT PLANS

TEP provides limited health care and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. UNS Electric and UNS Gas provide retiree medical benefits for current retirees. UNS Electric's and UNS Gas' active employees are not eligible for retiree medical benefits.

TEP funds its other retiree benefits for classified employees through a Voluntary Employee Beneficiary Association (VEBA). TEP contributed $3 million in each of 2013 and 2012 and $2 million in 2011 to the VEBA. Other retiree benefits for unclassified employees are self funded.

TEP’s other retiree benefit plan was amended in 2012 to increase the participant contributions for classified employees who retire after February 1, 2014. The effect on the benefit obligation was less than $1 million.

REGULATORY RECOVERY

We record changes in our non-SERP pension plans and other retiree benefit plan, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income since SERP expense is not currently recoverable in rates.

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

	Pension Benefits						Other  Retiree Benefits
	Years Ended December 31,
	2013			2012			2013			2012
	Millions of Dollars
Regulatory Pension Asset Included in Other Regulatory Assets	$	75		$	129		$	4		$	10
Accrued Benefit Liability Included in Accrued Employee Expenses	(1		)	(1		)	(2		)	(2		)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits	(28		)	(90		)	(63		)	(69		)
Accumulated Other Comprehensive Loss (related to SERP)	2			4			—			—
Net Amount Recognized	$	48		$	42		$	(61	)	$	(61	)

The table above includes accrued pension benefit liabilities for UNS Electric and UNS Gas of approximately $5 million at December 31, 2013 and $9 million at December 31, 2012. The table also includes an other retiree benefit liability of $1 million for UNS Electric and UNS Gas for each period presented.

OBLIGATIONS AND FUNDED STATUS

We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2013 and December 31, 2012. The table below includes TEP’s, UNS Electric’s, and UNS Gas’ plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below:

	Pension Benefits						Other  Retiree Benefits
	Years Ended December 31,
	2013			2012			2013			2012
	Millions of Dollars
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year	$	380		$	319		$	78		$	73
Actuarial (Gain) Loss	(38		)	51			(5		)	3
Interest Cost	15			15			3			3
Service Cost	13			10			3			3
Benefits Paid	(18		)	(15		)	(4		)	(4		)
Projected Benefit Obligation at End of Year	352			380			75			78
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year	289			245			7			5
Actual Return on Plan Assets	29			36			1			1
Benefits Paid	(18		)	(15		)	(4		)	(4		)
Employer Contributions (1)	23			23			6			5
Fair Value of Plan Assets at End of Year	323			289			10			7
Funded Status at End of Year	$	(29	)	$	(91	)	$	(65	)	$	(71	)

⁽¹⁾  TEP made $22 million in pension contributions and $6 million in other retiree benefits contributions in 2013 and $20 million in pension contributions and $5 million of other retiree benefits contributions in 2012. In 2014, UNS Energy expects to contribute $10 million to the pension plans, including $9 million in contributions by TEP.

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

• Pension benefit obligations of $21 million at December 31, 2013 and $23 million at December 31, 2012;

• Plan assets of $16 million at December 31, 2013 and $14 million at December 31, 2012; and

• A retiree benefit obligation of $1 million at December 31, 2013 and December 31, 2012.

The following table provides the components of UNS Energy’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:

	Pension Benefits				Other  Retiree Benefits
	Years Ended December 31,
	2013		2012		2013			2012
	Millions of Dollars
Net Loss	$	77	$	133	$	7		$	13
Prior Service Cost (Benefit)	—		1		(3		)	(3		)

The accumulated benefit obligation aggregated for all pension plans is $314 million at December 31, 2013 and $334 million at December 31, 2012.

Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
	December 31,
	2013	2012
	Millions of Dollars
Accumulated Benefit Obligation at End of Year	30	334
Fair Value of Plan Assets at End of Year	16	289

At December 31, 2012, all four UNS Energy defined benefit pension plans had accumulated benefit obligations in excess of plan assets. Due to 2013 contributions, returns on plan assets, and the favorable impact of the increase in the discount rate on the accumulated benefit obligations, only the SERP, which is unfunded, and the UES plan have accumulated benefit obligations in excess of plan assets at December 31, 2013.

UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:

	Pension Benefits									Other Retiree Benefits
	Years Ended December 31,
	2013			2012			2011			2013			2012		2011
	Millions of Dollars
Service Cost	$	13		$	10		$	10		$	4		$	3	$	3
Interest Cost	15			16			15			3			3		4
Expected Return on Plan Assets	(20		)	(17		)	(16		)	(1		)	—		—
Prior Service Cost Amortization	—			—			—			(1		)	—		(1		)
Actuarial Loss Amortization	9			7			6			1			—		—
Net Periodic Benefit Cost	$	17		$	16		$	15		$	6		$	6	$	6

Approximately 21% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income.

The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows:

	Pension Benefits
	2013						2012					2011
	Regulatory Asset			AOCI			Regulatory Asset			AOCI		Regulatory Asset			AOCI
	Millions of Dollars
Current Year Actuarial (Gain) Loss	$	(46	)	$	(1	)	$	30		$	1	$	25		$	(2	)
Amortization of Actuarial Gain (Loss)	(8		)	—			(7		)	—		(5		)	—
Total Recognized (Gain) Loss	$	(54	)	$	(1	)	$	23		$	1	$	20		$	(2	)

	Other Retiree Benefits
	2013			2012		2011
	Regulatory Asset			Regulatory Asset		Regulatory Asset
	Millions of Dollars
Prior Service Cost (Credit)	$	—		$	—	$	(2	)
Current Year Actuarial (Gain) Loss	(6		)	2		—
Amortization of Actuarial (Gain) Loss	(1		)	—		—
Amortization of Prior Service (Cost) Credit	1			—		1
Total Recognized (Gain) Loss	$	(6	)	$	2	$	(1	)

For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $4 million estimated net loss and less than $1 million prior service cost from other regulatory assets and less than $1 million prior service cost from AOCI into net periodic benefit cost in 2014. The estimated prior service benefit for the other retiree benefit plan that will be amortized from other regulatory assets into net periodic benefit cost in 2014 is less than $1.0 million.

	Pension Benefits		Other Retiree Benefits
	2013	2012	2013	2012
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31,
Discount Rate	5.0% - 5.2%	4.1%-4.3%	4.7%	3.8%
Rate of Compensation Increase	3.0%	3.0%	N/A	N/A

	Pension Benefits			Other Retiree Benefits
	2013	2012	2011	2013	2012	2011
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,
Discount Rate	4.1%-4.3%	4.9% - 5.0%	5.5% - 5.6%	3.8%	4.7%	5.2%
Rate of Compensation Increase	3.0%	3.0%	3.0% - 5.0%	N/A	N/A	N/A
Expected Return on Plan Assets	7.0%	7.0%	7.0%	7.0%	7.0%	5.1%

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

We use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25^th percentile to the 75^th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward looking return expectations only. The above method is used for all asset classes.

Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. The assumed health care cost trend rates follow:

	December 31,
	2013	2012
Health Care Cost Trend Rate Assumed for Next Year	6.7%	6.9%
Ultimate Health Care Cost Trend Rate Assumed	4.5%	4.5%
Year that the Rate Reaches the Ultimate Trend Rate	2027	2027

Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2013, amounts:

	One-Percentage- Point Increase		One-Percentage- Point Decrease
	Millions of Dollars
Effect on Total Service and Interest Cost Components	$	1	$	(1	)
Effect on Retiree Benefit Obligation	6		(5		)

PENSION PLAN AND OTHER RETIREE BENEFIT ASSETS

Pension Assets

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

	TEP Plan Assets				UNS Electric and UNS Gas Plan Assets
	2013		2012		2013		2012
Asset Category
Equity Securities	50	%	50	%	50	%	56	%
Fixed Income Securities	40		41	%	40		33
Real Estate	7		7	%	10		11
Other	3		2	%	—		—
Total	100	%	100	%	100	%	100	%

The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy:

	Fair Value Measurements of Pension Assets December 31, 2013
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap	—		80		—		80
United States Small Cap	—		17		—		17
Non-United States	—		65		—		65
Fixed Income	—		130		—		130
Real Estate	—		9		14		23
Private Equity	—		—		7		7
Total	$	1	$	301	$	21	$	323
	Fair Value Measurements of Pension Assets December 31, 2012
	Level 1		Level 2		Level 3		Total
	Millions of Dollars
Asset Category
Cash Equivalents	$	1	$	—	$	—	$	1
Equity Securities:
United States Large Cap	—		71		—		71
United States Small Cap	—		15		—		15
Non-United States	—		59		—		59
Fixed Income	—		116		—		116
Real Estate	—		8		13		21
Private Equity	—		—		6		6
Total	$	1	$	269	$	19	$	289

Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.

Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.

Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 85% of real estate assets tracked by the index in 2013 and comprising 87% in 2012.

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

The tables above reflecting the fair value measurements of pension plan assets include Level 2 assets for the UNS Electric and UNS Gas pension plan of $16 million at December 31, 2013 and $14 million at December 31, 2012.

The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.

	Year Ended December 31, 2013
	Private Equity		Real Estate		Total
	Millions of Dollars
Beginning Balance at January 1, 2013	$	6	$	13	$	19
Actual Return on Plan Assets:
Assets Held at Reporting Date	1		1		2
Purchases, Sales, and Settlements	—		—		—
Ending Balance at December 31, 2013	$	7	$	14	$	21

	Year Ended December 31, 2012
	Private Equity		Real Estate		Total
	Millions of Dollars
Beginning Balance at January 1, 2012	$	4	$	11	$	15
Actual Return on Plan Assets:
Assets Held at Reporting Date	1		2		3
Purchases, Sales, and Settlements	1		—		1
Ending Balance at December 31, 2012	$	6	$	13	$	19

UNS Electric and UNS Gas have no pension assets classified as Level 3 in the fair value hierarchy.

Pension Plan Investments

Investment Goals

Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. We consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.

Risk Management

We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: plan status, plan sponsor financial status and profitability, plan features, and workforce characteristics. We have determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.

Relationship between Plan Assets and Benefit Obligations

The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation.

Target Allocation Percentages

The current target allocation percentages for the major asset categories of the plan as of December 31, 2013 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.

	TEP Plan	UNS Electric and UNS Gas Plan	VEBA Trust
Fixed Income	41%	42%	38%
United States Large Cap	24%	24%	39%
Non-United States Developed	15%	14%	7%
Real Estate	8%	10%	—%
United States Small Cap	5%	5%	5%
Non-United States Emerging	5%	5%	9%
Private Equity	2%	—%	—%
Cash/Treasury Bills	—%	—%	2%
Total	100%	100%	100%

Pension Fund Descriptions

For each type of asset category selected by the Pension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds.

Other Retiree Benefit Assets

As of December 31, 2013, the fair value of VEBA trust assets was $10 million, of which $4 million were fixed income investments and $6 million were equities. As of December 31, 2012, the fair value of VEBA trust assets was $7 million, of which $3 million were fixed income investments and $4 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust.

ESTIMATED FUTURE BENEFIT PAYMENTS

TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate.

	2014		2015		2016		2017		2018		2019-2023
	Millions of Dollars
Pension Benefits	$	15	$	16	$	17	$	18	$	20	$	114
Other Retiree Benefits	5		5		5		5		5		29

One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million.

UNS Electric and UNS Gas expect annual benefit payments, made by the defined benefit pension and retiree plans, to be approximately $7 million in 2014 through 2018, and $9 million in 2019 through 2023.

DEFINED CONTRIBUTION PLAN

We offer a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account which may include a UNS Energy stock fund. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in each of 2013, 2012, and 2011. UNS Electric and UNS Gas made matching contributions of less than $1 million in each of 2013, 2012, and 2011.

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SHARE-BASED COMPENSATION PLANS (Summary of Performance Shares Awarded and Grant Date Fair Value) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Shares	52,000
Grant Date Fair Value	$ 44.94
Performance period description	three-year
Number of shares that vested during the period	52,000
Performance Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Shares	43,120	80,140	80,440
Market Condition Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant Date Fair Value	$ 45.54	$ 32.71	$ 33.73
Vesting based on goal attainment	57.80%
Performance Condition [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant Date Fair Value	$ 46.23	$ 36.40	$ 36.58
Vesting based on goal attainment	150.00%
Performance Period Ending in Current Year [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares that vested during the period	68,158
Number of shares unearned and forfeited	28,682
Dividend Equivalents [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares that vested during the period	8,521