UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20142017
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                    . 
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specifiedin its charter)
Arizona
(State or other jurisdiction of
incorporation or organization)
 
86-0062700
(I.R.S. Employer Identification No.)
88 East Broadway Boulevard, Tucson, AZ 85701
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act:Common Stock, No Par Value (Title of Class)
Common Stock, without par value
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes o No x
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). Yes o No x
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 Securities Exchange Act of 1934 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. Yes x No o
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).
Yes x No ox
No  ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company”company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filero
¨
Accelerated Filero
¨
Non-Accelerated Filerx
Non-accelerated Filerx
Smaller Reporting Companyo
¨
Emerging Growth Companyo
(do not check if a smaller reporting company)




If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o¨
No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates: None
As of 01/30/15,February 14, 2018, Tucson Electric Power Company had 32,139,434 shares of common stock, no par value, outstanding, all of which were held by UNS Energy Corporation.

Corporation, an indirect wholly owned subsidiary of Fortis Inc.
Documents incorporated by reference: None
Tucson Electric Power meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is, therefore, filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.



ii




Table of Contents
PART I
  
  
PART II
  

iii




  
PART III

iii




  
  
PART IV
  


iv







DEFINITIONS
The abbreviations and acronyms used in the 20142017 Form 10-K are defined below:
2010 Credit AgreementThe 2010 Credit Agreement consists of a $200 million revolving credit and LOC facility together with an $82 million LOC facility to support tax-exempt bonds
2010 Reimbursement Agreement Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2013 Covenants AgreementA Lender Rate Mode Covenants Agreement between TEP and the purchaser of $100 million of unsecured tax-exempt bonds that were issued on behalf of TEP in November 2013 and sold in a private placement
2013 TEP2017 Rate Order A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013
2014 Credit AgreementThe 2014 Credit Agreement consists of a $130 million term loan commitment and a $70 million revolving credit commitmenton February 27, 2017
ACC Arizona Corporation Commission
APS Arizona Public Service Company
BART Best Available Retrofit Technology
Base O&MBBtu A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business
Base RatesThe portion of TEP’s Retail Rates attributed to generation, transmission, distribution, and customer costs. Base Rates exclude authorized charges designed to recover specific costs that are passed through to customers including fuel and purchased energy costs, energy efficiency program costs, certain environmental compliance costs, and a portion of renewable energy costs
BtuBillion British thermal unit(s)
Cooling Degree DaysAn 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
DG Distributed Generation
DSM Demand Side Management
ECAEnvironmental Compliance Adjustor
EE Standards Energy Efficiency Standards
EPAEnvironmental Protection Agency
EPNGEl Paso Natural Gas Company, LLC.
FERC Federal Energy Regulatory Commission
Fortis Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners Four Corners Generating Station
GAAP Generally Accepted Accounting Principles in the United States of America
GBtuGila River Billion British thermal unitsGila River Generating Station
GWh Gigawatt-hour(s)
Gila River Unit 3Unit 3 of the Gila River Generating Station
Heating Degree DaysAn 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(s)
kWh Kilowatt-hour(s)
LFCR Lost Fixed Cost Recovery Mechanism
LOC LetterLetter(s) of Credit
MergerLuna The acquisition of UNS Energy in 2014 pursuant to the Agreement and Plan of Merger between UNS Energy and FortisUS Inc.Luna Generating Station
MMBtu Million British thermal units
MW Megawatt(s)
MWh Megawatt-hour(s)
Navajo Navajo Generating Station
NBVNet Book Value
PNM Public Service Company of New Mexico

v




PPA Power Purchase Agreement
PPFAC Purchased Power and Fuel Adjustment Clause
ppbPV Parts per billionPhotovoltaic
REC Renewable Energy Credit
Regional Haze Rules Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
RES Renewable Energy Standard
Retail Rates Rates designed to allow a regulated utility recovery of its cost of providing services and an opportunity to recover its reasonable operating and capital costs and earn a reasonable return on its utility plant in serviceinvestment
RICEReciprocating Internal Combustion Engine
San Juan San Juan Generating Station
SCR Selective Catalytic Reduction
SESSouthwest Energy Solutions, Inc.
SJCC San Juan Coal Company
SNCR Selective Non-Catalytic Reduction

v







Springerville Springerville Generating Station
Springerville Coal Handling FacilitiesCoal handling facilities at Springerville used by all four Springerville units
Springerville Coal Handling Facilities LeasesLeases for coal handling facilities at Springerville used in common by all four Springerville units
Springerville Common FacilitiesFacilities at Springerville used in common by all four Springerville units
Springerville Common Facilities LeasesLeveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities
Springerville Unit 1Unit 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 2Unit 2 of the Springerville Generating Station
Springerville Unit 3Unit 3 of the Springerville Generating Station
Springerville Unit 4Unit 4 of the Springerville Generating Station
SRP Salt River Project Agricultural Improvement and Power District
Sundt H. Wilson Sundt Generating Station
Sundt Unit 4TCJA Unit 4 ofOn December 22, 2017, the H. Wilson Sundt Generating StationTax Cuts and Jobs Act was signed into law enacting significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017
TEP Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Third-Party Owners Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
TSATransmission Service Agreement
Tri-State Tri-State Generation and Transmission Association, Inc.
UESUniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy Corporation, and the intermediate holding company established to own the operating companies UNS Electric, Inc. and UNS Gas, Inc.
UNS Electric UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy affiliatesAffiliates Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy


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FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Tucson Electric Power (TEP)Company (TEP or the Company) is 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 TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial 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, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, 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 TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.report, except as may otherwise be required by the federal securities laws.
Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed therein. We express our estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, 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: Part I, Item 1A. Risk Factors; Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and other parts of this report. These factors include: state and federal regulatory and legislative decisions and actions;actions, including changes in tax policies; changes in, and compliance with, environmental laws regulations,and regulatory decisions and policies that could increase operating and capital costs, reduce generating facility output or accelerate generatinggeneration facility retirements; regional economic and market conditions which could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets and bank markets; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other retireepostretirement benefit plan assets and the related contribution requirements and expense;expenses; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in O&Moperations and maintenance expense; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and distributed generation initiatives; changes to long-term contracts; the cost of fuel and power supplies; the ability to obtain coal from our suppliers; cyber attackscyber-attacks, data breaches, or other challenges to our information security;security, including our operations and technology systems; the performance of TEP's generating plants.generation facilities; and the impact of the Tax Cuts and Jobs Act on our financial condition and results of operations, including the assumptions we made relating thereto.


vii







PART I

ITEM 1. BUSINESS

GENERAL
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson Electric Power Company (TEP)metropolitan area for 125 years. TEP was incorporated in the State of Arizona in 1963. TEP is a vertically integrated, regulated electric utility that generates, transmitscompany serving approximately 422,000 retail customers. TEP’s service territory covers 1,155 square miles and distributes electricity.includes a population of over one million people in Pima County, as well as parts of Cochise County. TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP also sells electricity, transmission, and ancillary services to other utilities, municipalities, and powerenergy marketing entities located primarily in the western United States. companies on a wholesale basis. TEP is subject to comprehensive state and federal regulation. The regulated electric utility operation is TEP's only segment.
TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. In 2014, UNS Energy iswas acquired by Fortis Inc. (Fortis) and became an indirect wholly owned subsidiary of Fortis Inc. (Fortis) which is a leader in the largest investor-ownedNorth American electric and gas utility business.
Regulated Utility Operations
TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for coal, natural gas, wind, and electricsolar generation resources to provide electricity. This electricity, together with electricity purchased on the wholesale market, is delivered over transmission lines which are part of the Western Interconnection, a regional grid in the United States. The electricity is then transformed to lower voltages and delivered to customers through TEP's distribution utility holding company in Canada.system.
FORTIS ACQUISITION OF UNS ENERGY
UNS Energy,TEP operates under a certificate of public convenience and necessity as regulated by the parent of TEP, was acquired by Fortis for $60.25 per share of UNS Energy common stock in cash effective August 15, 2014.
The Arizona Corporation Commission'sCommission (ACC) approval of the Merger was subject, under which TEP is obligated to certain stipulations, including, but not limited to, the following:
TEP will provide credits on retail customers' bills totaling approximately $19 million over five years: $6 million in year one and $3 million annually in years two through five. The monthly bill credits will be applied each year from October through March effective October 1, 2014;
Dividends paid from TEP to UNS Energy cannot exceed 60 percent of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reaches 50 percent of total capital; and
Fortis making an equity investment of at least $220 million to UNS Energy and its regulated subsidiaries, including TEP. Fortis exceeded the investment requirement by contributing $287 million to UNS Energy through December 31, 2014. UNS Energy then contributed a total of $225 million to TEP through December 31, 2014.
As a result of the Merger being completed, TEP recorded approximately $15 million in 2014 as its allocated share of merger-related expenses, in addition to the customer bill credits discussed above. Merger-related expenses include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards.
SERVICE AREA AND CUSTOMERS
TEP’s service territory covers 1,155 square miles withelectricity service to approximately 415,000customers within its service territory. The ACC establishes rates that are designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates).
Customers
Electricity sold to retail electricand wholesale customers by class of customer and includes a populationthe average number of approximately one million people inretail customers over the greater Tucson metropolitan area in Pima County,last three years were as well as partsfollows:
(sales in GWh)2017 2016 2015
Electric Sales           
Residential3,786 28% 3,724
 29% 3,724
 28%
Commercial2,192 17% 2,139
 17% 2,124
 15%
Industrial, non-Mining1,939 15% 2,006
 16% 2,063
 15%
Industrial, Mining991 8% 997
 8% 1,109
 8%
Other18 % 30
 % 33
 %
Total Retail Sales by Customer Class8,926 68% 8,896
 70% 9,053
 66%
Wholesale Sales, Long-Term587 4% 463
 4% 750
 5%
Wholesale Sales, Short-Term3,630 28% 3,308
 26% 3,928
 29%
Total Electric Sales13,143 100% 12,667
 100% 13,731
 100%
            
Average Number of Retail Customers           
Residential381,399 90% 378,991
 90% 376,439
��90%
Commercial38,564 9% 38,403
 9% 38,253
 9%
Industrial, non-Mining520 % 580
 % 588
 %
Industrial, Mining4 % 4
 % 4
 %
Other1,879 1% 1,866
 1% 1,857
 1%
Total Retail Customers422,366 100% 419,844
 100% 417,141
 100%

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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,healthcare, 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 efficientenergy-efficient products, and opportunities for customers to generate their own electricity.customer-sited Distributed Generation (DG).
Customer Base
The table below shows the percentage distribution of TEP’s energy sales by major customer class over the last three years. In 2015, the retail energy consumption by customer class is expected to be similar to the historical distribution.
 2014 2013 2012
Residential41% 42% 41%
Commercial24% 23% 24%
Non-mining Industrial23% 23% 23%
Mining12% 12% 12%

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Local, regional, and national economic factors can impact the growth in the number of customers in TEP’s service territory. In 2014, 2013, and 2012,each of the past five years, TEP’s average number of retail customers increased by less than 1% in each year.
We expect. TEP expects the number of TEP’s retail customers to increase at a rate of approximately 1% in 2015 and 20162018 based on the estimated population growth in ourits service territory.
TwoTEP’s retail sales volume in 2017 was 8,926 gigawatt-hours (GWh), which is a decrease of 3.8% from 2013 levels. During the past five years, mining load reductions and state requirements to reduce retail sales through energy efficiency and DG have resulted in lower sales volumes.
TEP’s largestmining customers make up 11% of total retail customers are in the copper mining industry.sales. TEP’s kilowatt-hour (kWh)GWh sales to mining customers depend on a variety of factors including the market price of copper, thecommodity prices, electricity rate paid by mining customers,prices, and the mines’ potential development of their own electric generationself-generating resources. TEP’s kWhGWh sales to mining customers increaseddecreased by 5.4%8% from 2013 levels as a result of the decline in 2014.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations, Salescommodity prices requiring the mines to Mining Customers.
Retail Sales Volumes
TEP’s retail sales volumescurtail production starting in 2014 were approximately 9,165 Gigawatt-hours (GWh). These volumes were 1.3% below 2010 levels. During2016. TEP cannot predict future commodity prices or the past four years, economic conditions and state requirements for Energy Efficiency (EE) and Distributed Generation (DG)impact they will have negatively affected retail electricity sales.on mining production.
Wholesale SalesCustomers
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 generatinggeneration 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:types:
Long-Term Wholesale Sales
Long-termContracts for long-term wholesale sales contracts cover periods of more than one year.year or greater. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers. In 2014, TEP’s two primary long-term contracts were with Salt River Project Agriculture Improvement and Power District (SRP) and the Navajo Tribal Utility Authority (NTUA). The SRP contract expires in May 2016 and the NTUA contract expires in December 2022.
In December 2014, TEP entered into two additionalTEP’s long-term wholesale sales contracts that began in January 2015. The first long-term sales contract is with TRICO Electric Cooperative and expires in December 2024. The second long-term sales contract is with Shell Energy North America and expiresexpired in December 2017. The execution of these two additionalTEP's primary long-term wholesale sale contracts are presented in the table below:
Contracts Expire
CounterpartyDecember 31,
Navajo Tribal Utility Authority2022
TRICO Electric Cooperative2024
Navopache Electric Cooperative2041
Short-Term Wholesale Sales
Certain contracts for short-term wholesale sales contracts use near-term capacity acquired with TEP’s purchasecover periods of Gila River Unit 3 discussed below.
See Item 7. Management’s Discussionless than one year and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations, Long-Term Wholesale Sales.
Short-Term Sales
Forward contracts commitobligate TEP to sell a specified amount of capacity or energypower at a specified price over a given period of time, typically for one-month, three-month, or one-year periods.fixed price. TEP also engages in short-term sales by selling energypower in the daily or hourly markets at fluctuating spot market prices and making other non-firm energypower sales. AllThe majority of our revenues from short-term wholesale sales offset fuel and purchased power costs and are passed through to TEP’s retail customers.customers offsetting fuel and purchased power costs. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. See Rates
Competition
Retail Customers
TEP is the primary electric service provider to retail customers within its service territory and Regulation, below.operates under a certificate of public convenience and necessity as regulated by the ACC.

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GENERATING AND OTHER RESOURCESWholesale Customers
The Federal Energy Regulatory Commission (FERC) regulates rates for wholesale power sales and transmission services. TEP engages in long-term wholesale sales to optimize its generation resources. As a result of its wholesale power activity, TEP competes with other utilities, power marketers, and independent power producers in the wholesale markets.
Generation Facilities
As of January 1, 2015, following completion of the purchase of a 24.8% leased interest in Springerville Unit 1 and expiration of the Springerville Unit 1 leases,December 31, 2017, TEP owned 2,448 MW2,531 megawatts (MW) of nominal generatinggeneration capacity, as set forth in the following table. Nominal capacity is based on unit design net output.output and measured in alternating current (AC) except for the solar generation which is measured in direct current (DC).
 Unit   Date Resource Capacity Operating TEP’s Share
Generating SourceNo. Location In Service Type MW Agent % MW
Springerville Station(1)
1 Springerville, AZ 1985 Coal 387
 TEP 49.5
 192
Springerville Station2 Springerville, AZ 1990 Coal 390
 TEP 100.0
 390
San Juan Station1 Farmington, NM 1976 Coal 340
 PNM 50.0
 170
San Juan Station2 Farmington, NM 1973 Coal 340
 PNM 50.0
 170
Navajo Station1 Page, AZ 1974 Coal 750
 SRP 7.5
 56
Navajo Station2 Page, AZ 1975 Coal 750
 SRP 7.5
 56
Navajo Station3 Page, AZ 1976 Coal 750
 SRP 7.5
 56
Four Corners Station4 Farmington, NM 1969 Coal 785
 APS 7.0
 55
Four Corners Station5 Farmington, NM 1970 Coal 785
 APS 7.0
 55
Gila River Power Station3 Gila Bend, AZ 2003 Gas 550
 Ethos Energy 75.0
 413
Luna Generating Station1 Deming, NM 2006 Gas 555
 PNM 33.3
 185
Sundt Station1 Tucson, AZ 1958 Gas/Oil 81
 TEP 100.0
 81
Sundt Station2 Tucson, AZ 1960 Gas/Oil 81
 TEP 100.0
 81
Sundt Station3 Tucson, AZ 1962 Gas/Oil 104
 TEP 100.0
 104
Sundt Station (2)
4 Tucson, AZ 1967 Coal 120
 TEP 100.0
 120
Sundt Internal Combustion Turbines  Tucson, AZ 1972-1973 Gas/Oil 50
 TEP 100.0
 50
DeMoss Petrie  Tucson, AZ 2001 Gas 75
 TEP 100.0
 75
North Loop  Tucson, AZ 2001 Gas 94
 TEP 100.0
 94
Springerville Solar Station  Springerville, AZ 2002-2014 Solar 16
 TEP 100.0
 16
Tucson Solar Projects  Tucson, AZ 2010-2014 Solar 12
 TEP 100.0
 12
Ft. Huachuca Project  Ft. Huachuca, AZ 2014 Solar 17
 TEP 100.0
 17
Total TEP Capacity (3)
              2,448
  Unit   Date Resource Capacity Operating TEP’s Share
Generation Source No. Location In Service Type MW Agent % MW
Springerville 1 Springerville, AZ 1985 Coal 387 TEP 100 387
Springerville (1)
 2 Springerville, AZ 1990 Coal 406 TEP 100 406
San Juan 1 Farmington, NM 1976 Coal 340 PNM 50.0 170
Navajo (2)
 1 Page, AZ 1974 Coal 750 SRP 7.5 56
Navajo (2)
 2 Page, AZ 1975 Coal 750 SRP 7.5 56
Navajo (2)
 3 Page, AZ 1976 Coal 750 SRP 7.5 56
Four Corners 4 Farmington, NM 1969 Coal 785 APS 7.0 55
Four Corners 5 Farmington, NM 1970 Coal 785 APS 7.0 55
Gila River 3 Gila Bend, AZ 2003 Gas 550 Ethos Energy 75.0 413
Luna 1 Deming, NM 2006 Gas 555 PNM 33.3 185
Sundt (3)
 1 Tucson, AZ 1958 Gas/Oil 81 TEP 100 81
Sundt (3)
 2 Tucson, AZ 1960 Gas/Oil 81 TEP 100 81
Sundt 3 Tucson, AZ 1962 Gas 104 TEP 100 104
Sundt 4 Tucson, AZ 1967 Gas 156 TEP 100 156
Sundt Internal Combustion Turbines   Tucson, AZ 1972-1973 Gas/Oil 50 TEP 100 50
DeMoss Petrie   Tucson, AZ 2001 Gas 75 TEP 100 75
North Loop   Tucson, AZ 2001 Gas 94 TEP 100 94
Springerville   Springerville, AZ 2002-2014 Solar 16 TEP 100 16
Tucson   Tucson, AZ 2010-2014 Solar 13 TEP 100 13
Ft. Huachuca   Ft. Huachuca, AZ 2014-2017 Solar 22 TEP 100 22
Total TEP Capacity (4)
               2,531
(1) 
At December 31, 2014, TEPSpringerville Generating Station (Springerville) Unit 2 is owned 96 MWby San Carlos Resources, Inc., a wholly-owned subsidiary of capacity at Springerville Unit 1 and continued to lease the remaining 291 MW of capacity. In January 2015, TEP purchased 96 MW of capacity bringing the total owned capacity to 192 MW. TEP's lease of the remaining 195 MW expired in January 2015. See Note 5 of Notes to Consolidated Financial Statements.TEP.
(2) 
Sundt Station Unit 4 can be operated on either coal or natural gas. The table above reflectsTEP, along with the nominal generating capacity assumingother participants at the unit is fueledNavajo Generating Facility (Navajo), plan to discontinue operations of Navajo Units 1-3 by coal. If the Unit burns natural gas, it has a nominal capacityend of 156 MW.2019.
(3) 
Excludes 932 MWTEP plans to discontinue operations of additional resources, which consistSundt Units 1 & 2 by the end of certain2020.
(4)
On December 20, 2017, San Juan Generating Station (San Juan) Unit 2 was removed from service. TEP's 50% share of San Juan Unit 2's nominal capacity purchases and interruptible retail load.was 170 MW.
Springerville Generating Station
TEP's other interests in Springerville Unit 1
TEP leased Unit 1 of the Springerville Generating Station and aninclude: (i) undivided one-half interestinterests in certain common facilities at Springerville (Springerville Common Facilities (collectivelyFacilities) made up of 67.8% of ownership interest and 32.2% of leased interest, that includes assets such as, but not limited to: administration building, roads, and well fields used to serve all four units at Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that were accounted for as capital leases. The leases expired in January 2015cannot be proportioned to each unit; and included fair market value renewal and purchase options. As of January 1, TEP owns 49.5% of Unit 1 and a one-quarter(ii) an 82.95% ownership interest in the common facilities.Springerville Coal Handling Facilities.
In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 megawatts (MW) of capacity. During 2013, TEP agreed to purchase leased interests of 35.4% or 137 MW of Springerville Unit 1, for an aggregate purchase price of approximately $65 million. TEP completed the purchase of a 10.6% leased interest, representing 41 MW of capacity in December 2014 and a 24.8% leased interest, representing 96 MW of capacity, in January 2015. The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, continues to be owned by third parties, i.e.

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Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). With the expiration of the leases in January 2015, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $1.5 million per month, and their share of capital expenditures, which are approximately $7 million in 2015.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations, Springerville Unit 1.
Springerville Unit 2
Unit 2 of the Springerville Generating Station (Springerville Unit 2) is owned by San Carlos Resources, Inc. (San Carlos), a wholly-owned subsidiary of TEP.
Springerville Common Facilities Leases
TheAs of December 31, 2017, TEP holds two leveraged lease arrangements relatingrelated to ana 32.2% undivided one-half interest in certain Springerville Common Facilities (Springerville Common Facilities Leases), whichFacilities. The lease arrangements are scheduled to expire in 2017January 2021 and 2021, have fair market value renewal options as well as fixed-price purchase options. The fixed prices to acquire the leased interests in the Springerville Common Facilities are $38 million in 2017 andoptions totaling $68 million in 2021.million.
Springerville Coal Handling Facilities Lease
In 1984, TEP sold and leased back the Springerville Coal Handling Facilities. Since entering into the lease, TEP purchased a 13% ownership interest in the Springerville Coal Handling Facilities. 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. In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Upon TEP’s purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million and Tri-State Generation and Transmission Association, Inc. (Tri-State) is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities.
See Note 56 of Notes to Consolidated Financial Statements and in Part II, Item 7. Management’s Discussion and Analysis8 of Financial Condition and Results of Operations, Liquidity and Capital Resources, Contractual Obligations.
Sundt Generating Station
The H. Wilson Sundt Generating Station (Sundt) andthis Form 10-K for additional information regarding 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.
Gila River Generating Station Unit 3
On December 10, 2014, TEP and UNS Electric, Inc. (UNS Electric), an affiliated subsidiary of UNS Energy, acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW) for $164 million, and UNS Electric purchased the remaining 25% undivided interest. See Item 7. Management's Discussion and Analysis of Financial Condition and Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 7 of Notes to Consolidated Financial Statements.
The purchase of Gila River Unit 3 is intended to replace the expired coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, and is consistent with TEP's strategy to diversify its generation fuel mix. See Environmental Matters, Regional Haze Rules, San Juan, below.
Renewable Energy Resources
Owned Resources
As of December 31, 2014, TEP owned 45 MW of photovoltaic (PV) solar generating capacity. The Springerville solar system, which is located near the Springerville Generating Station, has a total capacity of 16 MW, including 10 MW of capacity

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completed in December 2014. In December 2014, TEP also completed a solar project providing 17 MW of capacity at Ft. Huachuca, Arizona. TEP’s remaining 12 MW of PV solar generating capacity is located in the Tucson area.
Power Purchase Agreements
In order to meet the ACC’s renewable energy requirements, TEP has power purchase agreements (PPAs) for 145 MW of capacity from solar resources, 90 MW of capacity from wind resources and 4 MW of capacity from a landfill gas generation plant. At December 31, 2014, approximately 124 MW of contracted solar resources and 50 MW of contracted wind resources were operational. The remaining resources are expected to be developed over the next several years. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future period. See Rates and Regulation, Renewable Energy Standard and Tariff, below.
Power Purchases
TEP purchases power from other utilities and power marketers. TEP may enter into contracts: (a) to purchase energy under long-term contracts to serve retail load and long-term wholesale contracts, (b) to purchase capacity or energy during periods of planned outages or for peak summer load conditions, and (c) to purchase energy for resale to certain wholesale customers under load and resource management agreements.
TEP typically uses generation from its gas-fired units, supplemented by power purchases, to meet the summer peak demands of its retail customers. Some of these power purchases are price-indexed to natural gas. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure with fixed price contracts for a maximum of three years. TEP also purchases energy in the daily and hourly markets to meet higher than anticipated demands, to cover unplanned generation outages, or when doing so is more economical than generating its own energy.
TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as plant outages and system disturbances, and reduce the amount of reserves TEP is required to carry.capital leases.
Springerville Units 3 and 4
Springerville Units 3 and 4 are each approximately 400 MW coal-fired generatinggeneration facilities that are operated but not owned by TEP. These facilities are located at the same site as Springerville Units 1 and 2. The ownerslessee of Springerville UnitsUnit 3 and 4 compensatecompensates TEP for operating the facilities and paypays an allocated portion of the fixed costs related to the Springerville Common Facilities and Springerville Coal Handling Facilities. The owner of Springerville Unit 4 owns 17.05% of the Springerville Coal Handling Facilities and pays TEP for a portion of the fixed costs allocated for the common facilities.
Renewable Energy Resources
The ACC’s Renewable Energy Standard (RES) requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. TEP plans to meet these requirements through a combination of utility-owned resources, Power Purchase Agreements (PPAs), and customer-sited DG. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K and Item 7. Management’s DiscussionRates and AnalysisRegulations below for additional information regarding RES.
Owned Renewable Resources
As of Financial ConditionDecember 31, 2017, TEP owned 51 MW of photovoltaic (PV) solar generation capacity measured in DC. The solar generation facilities are located on properties held under land easements and Resultsleases.
Renewable Power Purchase Agreements
As of Operations, Factors Affecting Results of Operations, Springerville Units 3December 31, 2017, TEP had renewable PPAs for 198 MW measured in DC from solar resources, 80 MW measured in AC from wind resources and 4 MW measured in AC associated with the purchase of landfill gas. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date.
Purchased Power
TEP purchases power from other utilities and power marketers. TEP may enter into contracts to purchase: (i) power under long-term contracts to serve retail load and long-term wholesale contracts; (ii) capacity or power during periods of planned outages or for peak summer load conditions; and (iii) power for resale to certain wholesale customers under load and resource management agreements. See Note 7 of Notes to Consolidated Financial Statements related to the commitment amount of purchased power in Part II, Item 8 of this Form 10-K.
TEP typically uses its generation, supplemented by purchased power, to meet the summer peak demands of its retail customers. Due to its increasing natural gas and purchased power usage, TEP hedges a portion of its total energy price exposure with forward priced contracts. Certain of these contracts are at a fixed price per megawatt-hour (MWh) and others are indexed to natural gas prices. TEP also purchases power in the daily and hourly.markets to meet higher than anticipated demands, to cover generation outages, or when doing so is more economical than generating its own power.
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 facility outages and system disturbances, and reduce the amount of reserves TEP is required to carry.

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Peak Demand and Future Resources
Peak Demand and Resources
Peak Demand2014 2013 2012 2011 2010
 MW
Retail Customers2,218
 2,230
 2,290
 2,334
 2,333
Firm Sales to Other Utilities673
 484
 286
 322
 340
Coincident Peak Demand (A)2,891
 2,714
 2,576
 2,656
 2,673
Total Generating Resources2,240
 2,240
 2,267
 2,262
 2,245
Other Resources (1)
932
 775
 683
 1,009
 799
Total TEP Resources (B)3,172
 3,015
 2,950
 3,271
 3,044
Total Margin (B) – (A)281
 301
 374
 615
 371
Reserve Margin (% of Coincident Peak Demand)10% 11% 15% 23% 14%
(in MW)2017 2016 2015 2014 2013
Retail Customers2,415
 2,278
 2,222
 2,218
 2,230
(1)
Other Resources include firm power purchases and interruptible
In 2017, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale loads.
The chart above shows the relationship over a five-year period between peak demand, and energy resources. Total margin is the difference between total energy resources and coincident peak demand, and thewhile maintaining a reserve margin is the ratio of margin to coincident peak demand. The reserve margin in 2014 was in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of NERC.North American Reliability Corporation (NERC).
Peak demand occurs during the summer months due to the cooling requirements of retail customers.customers in TEP’s service territory. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. Retail peak demand declined over the period of 2010

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in 2017 increased 6% compared to 20142016 due primarily to weak economic conditions and the implementation of energy efficiency programs and distributed generation.unseasonably hot weather.
Forecasted retail peak demand for 20152018 is 2,2222,270 MW compared with actual peak demand of 2,2182,415 MW in 2014.2017. TEP’s 20152018 estimated retail peak demand is based on weather patterns observed over a 10-year period and other factors, including estimates of customer usage. TEP believes that existing generation capacity and PPAs are sufficient to meet the expected demand in 2015 and established reserve margin criteria.requirements in 2018.
FUEL SUPPLYFuture Resources
As of December 31, 2017, approximately 49% of TEP's generation capacity is coal-fired generation. TEP is executing strategies and evaluating additional steps to reduce its dependency on coal-fired generation while still meeting its peak load requirements and maintaining affordable Retail Rates. TEP's five-year capital expenditure forecast includes investments related to Reciprocating Internal Combustion Engines (RICE) at H. Wilson Sundt Generating Station (Sundt) and the planned purchase of Gila River Generating Station (Gila River) Unit 2. These anticipated investments will provide replacement capacity for the planned early retirements of coal-fired and other generation resources.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information regarding TEP's generation resources planned retirements and additions.
Fuel Supply
A summary of Fuel and Purchased Power Summary
Resourceresource information is provided below:
Average Cost per kWh (cents per kWh) Percentage of Total kWh ResourcesAverage Cost (cents per kWh) Percentage of Total kWh Resources
2014 2013 2012 2014 2013 20122017 2016 2015 2017 2016 2015
Coal2.50
 2.66
 2.54
 68% 75% 72%2.41
 2.30
 2.44
 54% 62% 60%
Gas4.99
 4.57
 4.54
 9% 8% 11%3.06
 2.84
 3.35
 23% 25% 19%
Purchased Power4.79
 4.83
 3.44
 23% 17% 17%
All Sources3.64
 3.54
 3.19
 100% 100% 100%
Purchased Power, Non-Renewable3.78
 3.43
 3.04
 18% 8% 18%
Purchased Power, Renewable6.67
 7.00
 9.82
 5% 5% 3%
      100% 100% 100%
Coal
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TEP’s principal fuelCoal
The coal used for electric generation is low-sulfur, bituminous or sub-bituminous coal from mines in Arizona and New Mexico. The table below provides information on the existing coal contracts that supply our generatinggeneration stations. The average cost per ton of coal per million metric British thermal unit (MMBtu), including transportation, was $45.50$2.29 in 2014, $48.512017, $2.21 in 2013,2016, and $45.84$2.34 in 2012.2015.
StationCoal Supplier 2014 Coal
Consumption
(tons in 000s)
 
Contract
Expiration
 
Avg.
Sulfur
Content
 Coal Obtained From Coal Supplier 2017 Coal Consumption (tons in 000s) Contract Expiration Average Sulfur Content Coal Obtained From
SpringervillePeabody CoalSales 2,868 2020 0.9% Lee Ranch Coal Co. Peabody CoalSales 2,289 2020 1.0% Lee Ranch Mine/El Segundo Mine
Four Corners(1)
BHP Billiton 344 2031 0.7% Navajo Indian Tribe NTEC 285 2031 0.7% Navajo Mine
San Juan(1)San Juan Coal Co. 1,146 2017 0.8% Federal and State Agencies San Juan Coal Co. 1,181 2022 0.8% San Juan Mine
NavajoPeabody CoalSales 591 2019 0.6% Navajo and Hopi Indian Tribes Peabody CoalSales 441 2019 0.6% Kayenta Mine
(1) 
Beginning in July 2016 through June 2031,Reflects the coal for Four Corners will be purchasedfuel consumption of San Juan Units 1 and 2. In December 2017, San Juan Unit 2 was removed from the Navajo Transitional Energy Company (NTEC). NTEC purchased the mine located near Four Corners from BHP Billiton and will begin operating the mine in 2016.service.
TEPCoal-Fired Generation Facilities Operated Generating Facilitiesby TEP
The coal supplies for Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects coal reserves to be sufficient to supply the estimated requirements for Springerville Units 1 and 2 for their presently estimated remaining lives.
TEP does not have a long-term coal supply contract for Sundt Unit 4. Prior to 2010, Sundt Unit 4 was predominantly fueled by coal; however, the generating station also can be operated with natural gas. Both fuels are combined with landfill gas, a renewable energy resource, delivered from a nearby landfill. Since 2010, TEP has fueled Sundt Unit 4 with both coal and natural gas depending on which resource is most economic. See Note 6 of Notes to Consolidated Financial Statements.
Coal GeneratingCoal-Fired Generation Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generatinggeneration facilities at the Four Corners Generating Station (Four Corners), the Navajo Generating Station (Navajo), and the San Juan Generating Station (San Juan).Juan. Four Corners, which is operated by Arizona Public Service Company (APS), and San Juan, which is operated by Public Service Company of New Mexico (PNM), are mine-mouth generating stationsgeneration facilities located adjacent to the coal reserves. Navajo, which is operated by SRP,Salt River Project Agricultural Improvement and Power District (SRP), obtains its coal supply from athe nearby Kayenta coal mine and receives deliveries on a dedicated electric rail delivery system. TheTEP expects coal supplies are received under contracts administered byreserves available to these three jointly-owned generation facilities to be sufficient for the operating agents. As indicated inremaining lives of the table above, the current coal supply contract for San Juan expires on December 31, 2017. TEP and other San Juan owners are currently negotiating agreements concerning the future San Juan fuel supply with the existing coal supplier. If the participants are unable to negotiate an economic fuel supply, the continued operation of San Juan could be adversely affected.stations.

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Natural Gas Supply
TEP typically uses generation from its facilities fueled by natural gas, in addition to energypower from its coal-fired generation facilities and purchased power, to meet the summer peak demands of its retail customers and local reliability needs. The average cost of natural gas per MMBtu, including transportation, was $3.58 in 2017, $3.14 in 2016, and $3.49 in 2015.
TEP has long-term firm agreements with El Paso Natural Gas Company, LLC. (EPNG) for transportation from the Permian and San Juan Basins to Sundt under firm transportation agreements. TEP also purchases firm gas transportation for Gila River Unit 3 from EPNG and Transwestern Pipeline Co., and for the Luna Generating Station (Luna) from EPNG. TEP purchases natural gas from Southwest Gas Corporation under a retail tariff for North Loop’sLoop Generating Station's (North Loop) 94 MW of internal combustion turbinesturbine generation and receives distribution service under a transportation agreement for DeMoss Petrie aGenerating Station's (DeMoss Petrie) 75 MW of internal combustion turbine.turbine generation.
Transmission and Distribution
TEP's transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. TEP's transmission system, together with contractual rights on other transmission systems, enables TEP purchases capacity from El Paso Natural Gas (EPNG) for transportation from the San Juanto integrate and Permian Basinsaccess generation resources to meet its Sundt plant under firm transportation agreements and buys gas from third-party suppliers for Sundt and DeMoss Petrie.
TEP also purchases firm gas transportation for Gila from EPNG and Transwestern and for Luna Generating Station (Luna) from EPNG.
TRANSMISSION ACCESS
TEP has transmission access and power transaction arrangements with over 140 electric systems or suppliers. TEP also has various ongoing projects that are designed to increase access to the regional wholesale energy market and improve the reliability, capacity and efficiency of its existingcustomer load requirements. TEP's transmission and distribution systems.systems included approximately 2,175 miles of transmission lines and 7,642 miles of distribution lines as of December 31, 2017.
To improve transmission capacity between Palo VerdeRates and Tucson, TEP participated in the construction and ownership of a 500 kV transmission line from the Palo Verde area to the Pinal Central substation east of Casa Grande, AZ. This project was placed in service in 2014. Also, construction is underway on a 45-mile 500-kV transmission line from the Pinal Central substation to TEP’s Tortolita substation northwest of Tucson. TEP expects the Pinal Central to Tortolita line to be in service in 2016. Additionally, TEP is working with SRP and others to tie the Gila River power plant into TEP’s Palo Verde to Tucson transmission system. This will provide an improved electrical path to bring Gila River Unit 3 power into Tucson.Regulations
As part of TEP’s purchase of the Gila River unit TEP received transmission rights across the APS transmission system. These rights extend from the Gila River switchyard adjacent to the plant to the Jojoba switchyard. TEP is pursuing interconnection of the Jojoba switchyard to the existing transmission line from the Palo Verde area to Pinal Central substation in which TEP has an ownership interest. This interconnection, along with the rights obtained with the purchase, will provide direct transmission access from the Gila Plant to TEP’s service territory.
Discontinued Transmission Project
TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the Federal Energy Regulatory Commission (FERC) before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case.
RATES AND REGULATION
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
2013 TEP Rate Order
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In June 2013, the ACC issued an order (2013 TEP Rate Order) which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.See SeePart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations 2013and Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information that relates to rates and regulations that affect TEP including key provisions of its 2017 Rate Order.
2017 Rate Order
In February 2017, the ACC issued a rate order in the rate case filed by TEP in November 2015, which was based on a test year ended June 30, 2015 (2017 Rate Order). The 2017 Rate Order authorizes an annual increase in non-fuel revenue requirements of $81.5 million. New billing rates were effective starting on February 27, 2017.
Purchased Power and Fuel Adjustment Clause
The Purchased Power and Fuel Adjustment Clause (PPFAC) allows TEP to recoverrecovery of its fuel, transmission, and purchased power, and other similar costs including demand charges, andallowed by the costs of contracts for hedging fuel and purchased power costs forACC to serve its retail customers.load. The PPFAC consists of a forward component and a true-up component.

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The forward component adjusts for any costs over or under base fuel collection rates expected over a 12-month period. The true-up component will reconcilereconciles any over/under collected amounts from the preceding 12-month period and will be creditedis calculated to credit or recoveredrecover these amounts from customers in the subsequent year.
TEP’s PPFAC also includes the recoveryAs of the following costs and/or credits: lime costs used to control SO2 emissions at Springerville, sulfur credits received from TEP’s coal suppliers; broker fees; 100% of short-term wholesale revenues; and all of the proceeds from the sale of SO2 allowances.
At December 31, 2014,2017, TEP had under-collectedover-collected fuel and purchased power costs on a billed-to-customer basis of $32by $9 million.
Renewable Energy Standard and Tariff
The ACC’s Renewable Energy Standard (RES)RES requires TEP and other affectedArizona utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025, with distributed generationDG accounting for 30% of the annual renewable energy requirement. AffectedArizona utilities must file an annual RES implementation plansplan for review and approval by the ACC. The approved costcosts of carrying out those plans isthis plan are recovered from retail customers through the RES surcharge until such costs are reflected in TEP’s Base Rates.surcharge. The associated lost revenues attributable to meeting DG targets will be partially recovered through the Lost Fixed Cost Recovery Mechanism (LFCR).
In December 2014,2017, the ACC approved TEP's 2015 RES implementation plan. Under the plan, TEP expects to collect approximately $33 millionpercentage of retail kilowatt-hour (kWh) sales from retail customers during 2015 to fund the following: the above market cost of renewable energy purchases; performance based incentives for customer installed DG; depreciation and a return on TEP's investments in company-owned solar projects; and various other program costs. TEP expectswas 13% of which approximately 10% was attributable to recognize approximately $4 millionRES exceeding the 2017 requirement of revenue in 2015 as a return on company-owned solar projects.
7%. The 20152018 RES implementation plan authorized a TEP investment of $10 million in 2015 for up to 600 company-owned residential solar projects. Participants in this program will take service under a fixed electric rate. While participating customers could realize significant savings over time if TEP's standard rates or energy costs increase, their payments are expected to cover a majority of the company's fixed service costs associated with that customer.
TEP met the overall 2014 RES renewable energy target of 4.5% of retail kWh sales and expects to meet the 2015 target of 5%requirement is 8% of retail kWh sales. Compliance with RES is determined through periodic filings with the ACC.ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain distributed generationDG Renewable Energy Credits (REC), which are used to demonstrate compliance with the distributed generationDG requirement, the company may requestACC approved a waiver of the RES2017 and 2018 residential distributed generation requirements.renewable energy requirement.
Electric Energy Efficiency Standards
In 2010,Under the Energy Efficiency Standards (EE Standards), the ACC approved new Electric EE Standards designed to requirerequires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The Electric EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. Since the implementationAs of the Electric EE Standards,December 31, 2017, TEP’s cumulative annual energy savings arewas approximately 7.0%14%.
Distributed Generation
In 2016, the ACC held proceedings under the Value and Cost of Distributed Generation (Value of DG) docket to examine the ACC’s net metering rules and determine the value that utilities should pay DG customers who deliver electricity from rooftop solar systems back to the grid. Prior to this proceeding, the ACC’s net metering rules allowed DG customers who overproduced electricity to carry-over or “bank” excess electricity at a value equal to the full retail rate per kWh. Banked kWh sales. TEP’s compliance with the Electric EE Standards is governedcould then be used by the ACC’s approval of implementation plans filedcustomer to offset future energy usage that could not be met by TEP annually.their DG system.
In December 2014,2016, the ACC approved an order that will begin to reform net metering in Arizona. The order adopts a number of net metering changes and policies, including:
placing DG customers in a separate rate class;
grandfathering current DG customers under net metering rules and rate design for 20 years from interconnection application;
eliminating the banking of excess kWh for non-grandfathered DG customers; and
compensating non-grandfathered customers for their exported kWh based on the DG export rate in effect at the time of interconnection.
The initial compensation for DG exports will be based on a five-year historical average cost per kWh of TEP’s 2014portfolio of owned and 2015 Energy Efficiency Implementation Plans. Under the 2015 plan, TEP expects to collect approximately $19 million from retail customerscontracted utility-scale solar projects and will offer customers new and existing DSM programs. Energy savings realized through the programs will count toward Arizona’s Energy Efficiency Standard and the associated lost revenuebe established in a second phase of TEP's rate case (Phase 2). The DG

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export rate will be partially collected throughupdated each year and customers adopting solar will be compensated for 10 years at the Lost Fixed Cost Recovery Mechanism (LFCR)rate in effect at the time they file an application for interconnection. An avoided cost methodology will also be developed for potential use in TEP’s next rate case. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information that relates to Phase 2.
FERC Compliance
In 2016, the FERC issued orders relating to certain late-filed Transmission Service Agreements (TSA), which resulted in TEP recording a liability and paying time-value refunds to the counterparties under these TSAs (FERC Refund Orders). In May 2017, the FERC informed TEP that the related investigation was closed. See Note 27 of Notes to Consolidated Financial Statements. In December 2014,Statements in Part II, Item 8 of this Form 10-K for additional information related to the ACC initiatedFERC Refund Orders.
ENVIRONMENTAL MATTERS
The Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2), particulate matter, mercury, and other by-products produced by generation facilities. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its generation facilities. Environmental laws and regulations are subject to a new rulemaking proceeding that could result inrange of interpretations, which may ultimately be resolved by the eliminationcourts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of specific targeted savingsthe changing laws and instead treat EE as a resource to be evaluatedregulations on its operations and consolidated financial results. TEP expects the recovery of the cost of environmental compliance through the ACC's integrated resource planning process.

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TEP’S UTILITY OPERATING STATISTICS         
 2014 2013 2012 2011 2010
Generation and Purchased Power – kWh (000)         
Remote Generation9,616,347
 10,586,972
 10,284,612
 10,005,127
 9,077,032
Local Tucson Generation864,949
 674,443
 803,146
 906,496
 1,492,885
Renewable Generation48,434
 38,206
 44,930
 28,049
 24,511
Purchased Power3,195,173
 2,328,581
 2,328,420
 2,686,918
 2,846,005
Total Generation and Purchased Power13,724,903
 13,628,202
 13,461,108
 13,626,590
 13,440,433
Less Losses and Company Use859,638
 885,026
 789,613
 822,220
 879,423
Total Energy Sold12,865,265
 12,743,176
 12,671,495
 12,804,370
 12,561,010
Sales – kWh (000)         
Residential3,726,982
 3,866,665
 3,820,637
 3,888,011
 3,869,540
Commercial2,169,897
 2,187,095
 2,187,617
 2,184,241
 2,171,694
Industrial2,098,229
 2,113,659
 2,132,214
 2,145,163
 2,138,749
Mining1,137,188
 1,079,150
 1,092,518
 1,083,071
 1,079,327
Other33,057
 32,350
 31,833
 31,621
 32,478
Total – Electric Retail Sales9,165,353
 9,278,919
 9,264,819
 9,332,107
 9,291,788
Electric Wholesale Sales- Long-Term617,502
 605,426
 657,740
 902,139
 987,957
Electric Wholesale Sales- Short-Term3,082,410
 2,858,831
 2,748,936
 2,570,124
 2,281,265
Total Electric Sales12,865,265
 12,743,176
 12,671,495
 12,804,370
 12,561,010
Operating Revenues ($000)         
Residential$409,964
 $400,999
 $387,840
 $383,908
 $372,212
Commercial261,813
 252,547
 247,157
 241,044
 233,567
Industrial170,436
 164,433
 166,739
 164,024
 159,937
Mining70,110
 65,094
 66,158
 65,720
 62,112
Other2,985
 2,809
 2,693
 2,601
 2,593
RES, DSM, ECA and LFCR54,837
 48,475
 45,292
 46,633
 37,767
Total – Electric Retail Sales970,145
 934,357
 915,879
 903,930
 868,188
Wholesale Revenue- Long-Term28,216
 26,203
 24,910
 41,056
 55,653
Wholesale Revenue- Short-Term113,575
 91,467
 71,257
 72,798
 71,435
California Power Exchange Provision for Wholesale Refunds
 
 
 
 (2,970)
Transmission16,532
 14,830
 15,793
 16,392
 20,863
Other Revenues141,433
 129,833
 133,821
 122,210
 112,098
Total Operating Revenues$1,269,901
 $1,196,690
 $1,161,660
 $1,156,386
 $1,125,267
Customers (End of Period)         
Residential374,204
 372,411
 369,480
 367,396
 366,217
Commercial38,079
 37,913
 37,672
 37,536
 37,215
Industrial604
 617
 632
 636
 635
Mining4
 4
 4
 4
 4
Other1,858
 1,857
 1,833
 1,814
 1,829
Total Retail Customers414,749
 412,802
 409,621
 407,386
 405,900
Average Retail Revenue per kWh Sold (cents)         
Residential11.0
 10.4
 10.2
 9.9
 9.6
Commercial12.1
 11.5
 11.3
 11.0
 10.8
Industrial and Mining7.4
 7.2
 7.2
 7.1
 6.9
Average Retail Revenue per kWh Sold (cents) (excludes RES, DSM, ECA and LFCR)10.0
 9.5
 9.4
 9.2
 8.9
Average Revenue per Residential Customer$1,096
 $1,077
 $1,050
 $1,045
 $1,016
Average kWh Sales per Residential Customer9,960
 10,383
 10,341
 10,583
 10,566

9



ENVIRONMENTAL MATTERSRetail Rates.
National Ambient Air Quality Standards
In November 2014,October 2015, the EPA released a proposedthe final rule that would revisefor the ozone8-hour U.S. National Ambient Air Quality Standards (NAAQS) for ozone (O3). The proposal revisesEPA lowered the primary 8-hour NAAQS to within a range of 65-70standard from 75 parts per billion (ppb), but the EPA is also taking comments on retaining the existing 75 ppb 8-hour standard or adopting an 8-hour standard as low as 60 to 70 ppb.
If Pima County does not meet the standard, is ultimately revised below 70 ppb, Pima Countythe county will be designated as a “non-attainment” area and many other parts of the state would likely not be able to comply based on current ozone levels. Pima County and the State would thenwill need to submitdevelop a plan to meetbring the revised standard which could potentially limitair-shed into compliance. A “non-attainment” designation may slow economic growth in the affected regions. TEP is currently analyzing the proposalregion and expectsimpact our ability to file comments. The EPA is expected to finalize the rule by October 2015.
Hazardous Air Pollutant Requirements
The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final Mercurysite new local generation. Arizona's recommendation of area designations (attainment, non-attainment, or unclassified) was submitted in September 2016, and Air Toxics Standards (MATS) rules to set the standards for the control of mercury emissions and other hazardous air pollutants from power plants.
Navajo
Based on the MATS rules, Navajo will require mercury control equipment by April 2016. TEP’s share of the estimated capital costs of this equipment is less than $1 million for mercury control. TEP expects its share of the annual operating costs for mercury control to be less than $1 million.
San Juan
TEP expects San Juan’s current emission controls to be adequate to comply with the MATS rules.
Four Corners
TEP expects Four Corners' current emission controls to be adequate to comply with the MATS rules.
Springerville Generating Station
Based on the MATS rules, Springerville Generating Station (Springerville) may require mercury emission control equipment by April 2016. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $1 million. Estimated costs are split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015. With the completion of the purchases, Third-Party Owners are responsible for 50.5% of environmental costs attributed to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
Sundt Generating Station
TEP expects the MATS rules will havePima County's was recommended as an immaterial impact on capital or operating expenses at Sundt.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. BART applies to plants built between August 1962 and August 1977. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
Complying with the EPA’s BART findings, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in the units they own at these power plants. TEP cannot predict the ultimate outcome of these matters.
Navajoattainment area.
In August 2014, the EPA published the final Regional Haze Federal Implementation Plan (FIP) for Navajo. Among other things, the FIP calls for the shut-down of one unit or an equivalent reduction in emissions by 2020. The shutdown of one unit

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will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install Selective Catalytic Reduction (SCR) or an equivalent technology on the remaining two units by 2030, and the current owners have to cease their operation of conventional coal-fired generation at Navajo no later than December 22, 2044. The Navajo Nation can continue operation after 2044 at its election. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented.
If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $28 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $28 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.
San Juan
In October 2014,November 2017, the EPA published a final rule approvingin the Federal Register establishing the initial Air Quality designations, for the 2015 Ozone Standard. The majority of Arizona counties were designated as "attainment" or "unclassified" except for Pima and Maricopa counties for which a revised State Implementation Plan (SIP) covering BART requirements for San Juan. The SIP requires the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February of 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its sharedesignation will be addressed in a separate, future action.
Effluent Limitation Guidelines
In 2015, as part of the costClean Water Act, the EPA published the final Effluent Limitation Guidelines (ELG) setting standards and limitations for steam electric generation facility discharges. The ELG rule establishes discharge limits for fly ash and mercury-contaminated wastewater at those facilities that require a National Pollution Discharge Elimination System (NPDES) with an effective date between November 2018 and November 2023. With the exception of Four Corners, none of the other TEP owned facilities require an NPDES permit and therefore are not affected. With regard to install SNCR technology on San Juan Unit 1Four Corners, until a draft NPDES permit is proposed during the 2018-2023 time-frame, TEP cannot predict what will be required to control these discharges to be approximately $12 million. Additionally,in compliance with the SIP approval referencesfinalized effluent limitations at that facility. TEP does not anticipate a New Source Review permit issued bysignificant financial impact from these requirements.
In 2017, the New Mexico Environment DepartmentEPA announced its decision to reconsider the ELG. The EPA also filed and was granted a motion requesting the U.S. Court of Appeals for the Fifth Circuit to hold the litigation challenging the Rule in November 2013abeyance while the Agency reconsiders the ELG, after which among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. PNM,it will inform the operatorCourt of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s shareany portions of the balanced draft upgrades is expected to be approximately $25 millionELG for which it seeks a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million.
In connection with the implementation of the SIP revision and the early retirement of San Juan Units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant.remand so that it can conduct further rulemaking. As a result, the Participants are attemptingU.S. Court of Appeals for the Fifth Circuit approved a briefing schedule for the ELG that puts industry groups’ challenges on hold indefinitely.
TEP believes it is in material compliance with applicable environmental laws and regulations. Refer to negotiate a restructuringPart II, Item 7. Management’s Discussion and Analysis of the ownership in San Juan,Financial Condition and Results of Operations, Liquidity and Capital Resources of this Form 10-K for additional information related to environmental laws and regulations as well as addressing the obligationsenvironmental compliance capital expenditures.
EMPLOYEES
As of the exiting Participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The Participants have engaged a mediator to assist in facilitating the resolution of these matters among the Participants. The Participants of the affected units also may seek approvals of their utility commissions or governing boards. We are unable to predict the outcome of the negotiations and mediation.
Upon the early retirement of San Juan Unit 2, TEP will seek ACC approval to recover any unrecovered cost. TEP's 2013 Rate Case identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. At December 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $110 million.
Four Corners
In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on one unit by October 2016 and the remaining units by October 2017. In December 2013, APS (the operator) decided to shut down Units 1, 2, and 3 and install SCRs on Units 4 and 5. Under this scenario, the installation of SCR technology can be delayed until July 2018. TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $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 Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018.
Sundt
In July 2013, the EPA rejected the Arizona SIP determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule and developed a time-line to issue a federal implementation plan for emissions sources including Sundt Unit 4. TEP submitted a better-than-BART proposal in November 2013 which called for the elimination of coal as a fuel source at Sundt by the end of 2017. In June 2014, the EPA issued a final Regional Haze FIP for Arizona including BART requirements for Sundt. The final FIP would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection (DSI) if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART

11



alternative by the end of 2017. TEP estimates that the cost to install SNCR and DSI would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If retired early, we will request the ACC's approval to recover all the remaining costs of the coal handling facilities.
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. TEP does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on its operations.
In June 2014, the EPA issued proposed carbon emission regulations for existing power plants called the Clean Power Plan. The Clean Power Plan targets a nation-wide reduction in carbon emissions of 30% by 2030. To achieve this goal, the proposed plan sets carbon emission rates for each state that must be achieved by an interim period of 2020-2029, with final emission rates by 2030. States can apply a variety of strategies to achieve the interim and final emission rates. Using 2012 as a baseline year, Arizona's carbon emission rate for 2030 represents a 52% reduction, most of which would be required by the interim emission rate requirement and could lead to the early retirement of coal generation in Arizona by 2020. The EPA expects to issue a final rule by the summer of 2015, and under the current proposal, states must file implementation plans by June 2016 or June 2017, for multi-state plans. In October 2014, the EPA issued a supplemental proposal regarding carbon emissions regulation impacting the Navajo Nation and the Four Corners and Navajo generating stations which are located on land leased from the Navajo Nation. The regulation, if implemented as proposed, will require carbon reductions on the Navajo Reservation; however, the reduction requirement is less than what is anticipated from unit retirements at the Four Corners and Navajo generating stations associated with Regional Haze requirements (see above).
TEP will continue working with federal and state regulatory authorities, other neighboring utilities, and stakeholders to seek relief from the proposed regulation by reducing the disproportionately high level of carbon emissions reduction for Arizona, and to seek relief from the interim and final proposed compliance requirements. On December 1, 2014, UNS Energy submitted comments on the proposal on behalf of TEP and its other utility subsidiaries. The EPA has received over 3.8 million comments in response to the proposed rule. The proposed rule has been challenged in court and is subject to further legal challenge. TEP cannot predict the ultimate outcome of these matters.
Coal Combustion Residuals Regulations
In December 2014, the EPA signed a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. Subject to further review of the rule, we do not anticipate significant impacts to our existing facilities where coal combustion residuals are managed. However, additional requirements will apply to lateral expansions of those existing facilities or to any new facilities.

EMPLOYEES
At December 31, 2014, TEP had 1,4481,510 employees, of which approximately 691 were671 are represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A newThe current collective bargaining agreementagreements between the IBEW and TEP was entered intoexpire in January 2013 and expires in January 2016.December 2018.


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EXECUTIVEEXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers, who are elected annually by TEP’s Board of Directors, acting at the direction of the Board of Directors of UNS Energy, as of January 2, 2018, are as follows:
Name Age Position(s) Held 
Executive
Officer Since
David G. Hutchens 48
 President and Chief Executive Officer 2007
Kevin P. Larson 58
 Senior Vice President and Chief Financial Officer 1997
Philip J. Dion 46
 Senior Vice President, Public Policy and Customer Solutions 2008
Kentton C. Grant 56
 Vice President and Treasurer 2007
Todd C. Hixon 48
 Vice President and General Counsel 2011
Karen G. Kissinger 60
 Vice President and Chief Compliance Officer 1991
Mark C. Mansfield 59
 Vice President, Energy Resources 2012
Frank P. Marino 50
 Vice President and Controller 2013
Thomas A. McKenna 66
 Vice President, Energy Delivery 2007
Catherine E. Ries 55
 Vice President, Human Resources and Information Technology 2007
Herlinda H. Kennedy 53
 Corporate Secretary 2006
Name Age Position(s) Held Executive Officer Since
David G. Hutchens (1)
 51 President and Chief Executive Officer 2007
Frank P. Marino (1)
 53 Vice President and Chief Financial Officer 2013
Erik B. Bakken 45 Vice President, Transmission and Distribution Planning and Environmental 2018
Kentton C. Grant 
 59 Vice President, Rates and Planning 2007
Susan M. Gray 45 Vice President, Energy Delivery 2015
Todd C. Hixon (1)
 51 Vice President, General Counsel and Chief Compliance Officer 2011
Mark C. Mansfield 62 Vice President, Energy Resources 2012
Catherine E. Ries 58 Vice President, Customer and Human Resources 2007
Mary Jo Smith 60 Vice President, Public Policy and Rates 2015
Morgan C. Stoll 47 Vice President and Chief Information Officer 2016
Martha B. Pritz 
 56 Treasurer 2017
Herlinda H. Kennedy 56 Corporate Secretary 2006
David G. Hutchens
(1)
Mr. Hutchens has served as Chief Executive OfficerMember of the TEP Board of Directors. The directors of TEP since 2014; President of TEP since 2011; Executive Vice President of TEP in 2011; Vice President of TEP from 2007-2011. Mr. Hutchens joined TEP in 1995.
Kevin P. LarsonMr. Larson has served as Senior Vice President and Chief Financial Officer of TEP since September 2005. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He wasare elected Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer.
Philip J. DionMr. Dion has served as Senior Vice President, Public Policy and Customer Solutions of TEP since August 2013. Mr. Dion was named Vice President, Public Policy in April 2010. Mr. Dion joined TEP in February 2008 as Vice President of Legal and Environmental Services.
Kentton C. GrantMr. Grant was elected Treasurer in 2010 and has served as Vice President of TEP since January 2007. Mr. Grant joined TEP in 1995.
Todd C. HixonMr. Hixon has served as Vice President and General Counsel of 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. KissingerMs. Kissinger has served as Vice President and Chief Compliance Officer of 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. MansfieldMr. Mansfield has served as Vice President,annually by TEP's sole shareholder, UNS Energy, Resources since 2012. He joined the company in 2008, most recently serving as Senior Director of Generation.
Frank P. MarinoMr. Marino has served as Vice President and Controller of TEP since August 2013. Mr. Marino joined TEP as Assistant Controller in January 2013. Prior to joining TEP, he served various rolesacting 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. McKennaMr. McKenna has served as Vice President, Energy Delivery since August 2013. Mr. McKenna was named Vice President, Engineering in January 2007. Mr. McKenna joined an affiliatedirection of TEP in 1998.
Catherine E. RiesMs. Ries has served as Vice President, Human Resources and Information Technology, since May 2011. Ms. Ries joined TEP as Vice Presidentthe Board of Human Resources in June 2007.
Herlinda H. KennedyMs. Kennedy has served as Corporate SecretaryDirectors of TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999.UNS Energy.

13



SECSEC REPORTS AVAILABLE ON TEP'S WEBSITE
TEP makes available its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practical after weit electronically filefiles or furnishfurnishes them to the Securities and Exchange Commission (SEC). These reports are available free of charge through TEP’s website address at www.tep.com/about/investors/.
UNS Energy’s code of ethics, which applies to the Board of Directors and all officers and employees of UNS Energy and its subsidiaries, including TEP, and any amendments or any waivers made to the code of ethics, is also available on TEP’s website at www.tep.com/about/investors/.
TEP is providing the address of TEP’s website solely for the information of investors and does not intend the address to be an active link. InformationThe information contained aton TEP’s website is not a part of, or incorporated by reference into, any report or other filing filed with the SEC by TEP.


9







ITEM 1A.1A. RISK FACTORS
The business and financial results of TEP are subject to a number of risks and uncertainties, including those set forth below. These risks and uncertainties fall primarily into five major categories: revenues, regulatory, environmental, financial, and operational. Additional risks and uncertainties that are not currently known to TEP or that are not currently believed by TEP to be material may also harm TEP’s business and financial results.
REVENUES
NationalA significant decrease in the demand for electricity in TEP's service area would negatively impact retail sales and local economic conditions can negativelyadversely affect the results of operations, net income, and cash flows at TEP.
Economic conditions have contributed significantly to a reduction in TEP’s retail customer growthNational and lower energy usage by the company’s residential, commercial, and industrial customers. As a result of weaklocal economic conditions TEP’s average retail customer base grew by less than 1% in each year from 2010 through 2014 compared with average increases of approximately 2% in each year from 2005 to 2009. TEP estimates that a 1% change in annual retail sales could impact pre-tax net income and pre-tax cash flows by approximately $6 million.
New technological developments and compliance with the ACC's Energy Efficiency Standards will continue to have a significant impact on customer growth and overall retail sales which could negatively impactin TEP’s resultsservice area. TEP anticipates an annual customer growth rate of operations, net income, and cash flows.1% for the next five years.
Research and development activities are ongoing for new technologies that produce power orand reduce power consumption. These technologies include renewable energy, customer-owned generation, andcustomer-sited DG, appliances, equipment, battery storage and control systems. FurtherContinued development and use of these technologies and compliance with the ACC's Energy Efficiency Standard could negativelyEE Standards and RES continue to have a negative impact the resultson TEP’s use per customer and overall retail sales. TEP's use per customer declined by an average of operations, net income, and cash flows of TEP.1% per year from 2013 through 2017.
The revenues, results of operations, and cash flows of TEP are seasonal and are subject to weather conditions and customer usage patterns, which are beyond the companies’Company’s control.
TEP typically earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during the summer. Conversely, TEP’s first quarter net income is typically limited by relatively mild winter weather in its retail service territory. Cool summers or warm winters may reduce customer usage, adverselynegatively affecting operating revenues, cash flows, and net income by reducing sales.
TEP is dependent on a small segmentnumber of large customers for a significant portion of future revenues. A reduction in the electricity sales to these customers would negatively affect our results of operations, net income, and cash flows.
TEP’s ten largest customers represented 10% of total revenues in 2017. TEP sells electricity to mines, military installations, and other large industrial customers. In 2014, 35% of TEP’s retail kWh sales were to 608 industrialcommercial and miningindustrial customers. Retail sales volumes and revenues from these customer classescustomers could decline as a result of, among other things: global, national, and local economic conditions; commodity prices;curtailments of customer operations due to unfavorable market conditions; military base reorganization or closure decisions by the federal government to close military bases;government; the effects of EEenergy efficiency and DG;distributed generation; or the decision by customers to self-generate all or a portion of thetheir energy needs. A reduction in retail kWh sales toby any one of TEP’s largeten largest customers would negatively affect our results of operations, net income, and cash flows.

14




REGULATORY
TEP is subject to regulation by the ACC, which sets the company’sCompany’s Retail Rates and oversees many aspects of its business in ways that could negatively affect the company’sCompany’s results of operations, net income, and cash flows.
The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.
TEP’s Retail Rates consist of base rates and various rate adjustors that are intended to allow for timely recovery of certain costs between rate cases. The ACC is charged with setting retail electric ratesRetail Rates at levels that are intended to allow TEP recovery of its cost of service and provide electric utilitiesit with an opportunity to recover their costs of service and earn a reasonable rate of return. As part of the ACC’s process of establishing the retail electric rates charged by TEP,In setting TEP’s Retail Rates, the ACC could disallow the recovery of certain costs, if deemed they were imprudently incurred.not provide for the timely recovery of costs or increase regulatory oversight. If customers or regulators have or develop a negative opinion of the Company's utility services or the electric utility industry in general, this could negatively affect TEP's regulatory outcomes. The decisions made by the ACC on such matters impact the net income and cash flows of TEP.
Changes in federal energy regulation may negatively affect the results of operations, net income, and cash flows of TEP.
TEP is subject to the impact of comprehensive and changing governmental regulation at the federal level that continues to change the structure of the electric and gas utility industriesindustry and the ways in which these industries arethis industry is regulated. TEP is subject to regulation

10







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.wholesale.
As a result of the Energy Policy Act of 2005, ownersOwners and operators of bulk power systems, including TEP, are subject to mandatory transmission standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties.
Changes in tax regulation may negatively affect the results of operations, net income, and cash flows of TEP.
The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. Legislation or regulation could be enacted by any of these governmental authorities which could affect the Company’s tax positions.
In December 2017, the Tax Cuts and Jobs Act (TCJA) was signed into law which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. Subsequently, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing any ongoing benefits of the TCJA through to customers. TEP cannot predict the timing or extent of the regulatory treatment related to the TCJA impacts but any decrease in rates paid by customers would have a negative impact on operating cash flows.
ENVIRONMENTAL
TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it to environmentally-relatedenvironmental-related litigation and liabilities. Many of these regulations could have a significant impact on TEP due to its reliance on coal as its primary fuel for electric generation.
Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste, and management of coal combustion residuals.
These laws and regulations can contribute to higher capital, operating, and other costs, particularly with regard to enforcement efforts focused on existing power plantsgeneration facilities and new compliance standards related to new and existing power plants.generation facilities. These laws and regulations generally require usTEP to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable laws and regulations may result in litigation, and the imposition of fines, penalties, and a requirement by regulatory authorities for costly equipment upgrades.
Existing environmental laws and regulations may be revised and new environmental laws and regulations may be adopted or become applicable to our facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adversea negative effect on ourTEP's results of operations, particularly if those costs are not fully recoverable from ourTEP customers. TEP’s obligation to comply with the EPA’s BART determinationsRegional Haze Rule requirements as a participant or owner in the Springerville, 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 plantsgeneration facilities. Additionally, these regulations may jeopardize continued generation facility operations or the ability of individual participants to meet their obligations and willingness to continue their participation in these plants. TEP cannot predictfacilities potentially resulting in an increased operational cost for the ultimate outcome of these matters.remaining participants.
TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stationsgeneration facilities in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generating stations.generation facilities. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.
Proposed federalFederal regulations to limitlimiting greenhouse gas emissions would, if adopted in the form proposed, result inrequire a shift in generation from coal to natural gas and renewable generation and could increase TEP's cost of operations.
In June 20142015, the EPA proposed carbon emission standards to reduce greenhouse gasissued the Clean Power Plan (CPP) limiting CO2 emissions from existing power plants. EPA's proposaland new fossil-fueled generation facilities. The CPP establishes state-level CO2 emission rates and mass-based goals that apply to fossil fuel-fired generation. The plan requires CO2 emission reductions for Arizona would resultexisting facilities by 2030 and establishes interim goals that begin in 2022. In its current form, the CPP requires a significant shift in generation from coal to natural gas and renewables and could

15




lead to the early retirement of coalcoal-fired generation in Arizona by 2020. Theand New Mexico within the 2022 to 2030 compliance time-frame. In 2017, the EPA issued a proposal to repeal the CPP and has not determined whether or not a replacement rule will be issued. TEP will

11







continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies. TEP is scheduledunable to finalize those standards by summer 2015. These proposed regulations would, if adopteddetermine whether the current CPP will remain in effect or be modified or any final CPP rule will impact its facilities until all legal challenges have been resolved and the form proposed, result in a change in the composition of TEP's generating fleet. As of 01/30/15, approximately 54% of TEP's generating capacity is fueled by coal. In 2014, approximately 68% of our total electricity resources were fueled by coal. The final rule issuedcurrently required state compliance plans are developed and approved by the EPA could significantly impair the ability to operate certain of TEP's coal-fired generation plants on an economically viable basis or at all. A substantial change in TEP's generation portfolio could result in increased cost of operations and/or additional capital investments. The impact of final regulations to address carbon emissions will depend on the specific terms of those measures and cannot be determined at this time.EPA.
FINANCIAL
Early closure of TEP's coal-fired generation plants resulting from environmental regulationsfacilities could result in TEP recognizing materialregulatory impairments in respect of such plants andor increased cost of operations if recovery of ourTEP's remaining investments in such plantsfacilities and the costs associated with such early closures wereare not permitted through rates charged to customers.
Some of TEP's coal-fired generating stations may be required togeneration facilities will be closed before the end of their useful lives in response to economic conditions and/or recent or future changes in environmental regulation, including potential regulation relating to greenhouse gas emissions. If any of the coal-fired generation plants, or coal handling facilities from which TEP obtains power are closed prior to the end of their useful life, TEP could be requiredmay need to recognize a material impairmentseek recovery of its assetsthe remaining net book value (NBV) and could incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation and cancellation of long-term coal contracts of such generating plants andgeneration facilities. ClosureAs of any of such generating stations may force TEPDecember 31, 2017, TEP's regulatory assets balance related to incur higherits planned early generation retirement costs for replacement capacity and energy. TEP may not be permitted full recovery of these costs in the rates it charges its customers.
FINANCIAL
The third-party co-owners of Springerville Unit 1 may fail to pay some, or all, of their pro-rata share of the costs and expenses associated with SpringervilleUnit 1.
TEP owns 49.5% of Springerville Unit 1 and two separate third-parties own the remaining 50.5%. Starting in January 2015, TEP is obligated to operate Springerville Unit 1 for these Third-Party Owners under an existing facility support agreement. TEP and the Third-Party Owners disagree on several key aspects of this agreement, including the allocation of Springerville Unit 1 operating and maintenance expenses, capital improvement costs, and transmission rights. In addition, in late 2014 the Third-Party Owners filed separate complaints at the FERC and in New York State court that include allegations that TEP violated certain provisions of the facility support agreement in relation to TEP’s operation of Springerville Unit 1. Because of these disagreements and the pending litigation, the Third-Party Owners may refuse to pay some or all of their pro-rata share of such Springerville Unit 1 costs and expenses. The Third-Party Owners’ share of monthly fixed operating and maintenance costs for Springerville Unit 1 is approximately $1.5 million and their share of 2015 capital expenditures is approximately $7was $84 million.
Volatility or disruptions in the financial markets, rising interest rates, or unanticipated financing needs, could: increase ourTEP's financing costs; limit our access to the credit or bank markets; affect ourthe Company's ability to comply with financial covenants in our debt agreements; and increase ourTEP's pension funding obligations. Such outcomes may adverselynegatively affect our liquidity and ourTEP's ability to carry out ourthe Company's 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 flowflows 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 adverselynegatively 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 competitivereasonable rates, or if our borrowing costs dramatically increase, our ability to finance our operations, meet our short-termdebt obligations, and execute our financial strategy could be adverselynegatively affected.
ChangingIncreases in short-term interest rates would increase the cost of borrowing on TEP's tax-exempt variable rate debt obligations of $137 million as of December 31, 2017, and increase the cost of borrowings under its credit facility. In addition, changing market conditions could negatively affect the market value of assets held in our pension and other retireepostretirement defined benefit plans and may increase the amount and accelerate the timing of required future funding contributions.
PlantGeneration facility closings or changes in power flows into ourTEP's service territory could require us to redeem or defease some or all of the tax-exempt bonds issued for ourthe Company's benefit. This could result in increased financing costs.
TEP has financed a substantial portion of utility plant assets with the proceeds of pollution control revenue bonds and industrial development revenue bonds issued by governmental authorities. Interest on these bonds is, subject to certain exceptions,

16




excluded from gross income for federal tax purposes. This tax-exempt status is based, in part, on continued use of the assets for pollution control purposes or the local furnishing of energypower within TEP’s two-county retail service area.
As of 01/30/15,December 31, 2017, there were outstanding approximately $324$309 million aggregate principal amount of tax-exempt bonds that financed pollution control facilitiesexpenditures at TEP’s generating units.generation facilities. Should certain of TEP’s generating unitsgeneration facilities be retired and dismantled prior to the stated maturity dates of the related tax-exempt bonds, it is possible that some or all of the bonds financing such facilitiespollution control expenditures would be subject to mandatory early redemption by TEP. AsOf the total amount outstanding, $37 million of 01/30/15,the principal amount of the bonds can currently be redeemed at par upon notice to holders, and $272 million of the principal amount of the bonds has early redemption dates or final maturities ranging from 2019 to 2022.
In addition, as of December 31, 2017, there were also outstanding approximately $371$307 million aggregate principal amount of tax-exempt bonds that financed local furnishing facilities. Depending on changes that may occur to the regional generation mix in the desert southwest, to the regional bulk transmission network, or to the demand for retail energypower in TEP’s local service area, it is possible that TEP would no longer qualify as a local furnisher of energypower within the meaning of the Internal Revenue Code. If that were to occur,TEP could no longer qualify as a local furnisher of power, all of TEP’s tax-exempt local furnishing bonds wouldcould be subject to mandatory early redemption by TEP or defeasance to the earliest possible redemption date.date, and TEP could be required to pay additional amounts if interest on such bonds were no longer tax-exempt. Of the total tax-exempt local furnishing bonds

12







outstanding, $164$100 million aggregateof the principal amount isof the bonds can currently redeemable at par, while the remaining $207 million principal amount can be redeemed at par atupon notice to holders, and $207 million of the respective bond'sprincipal amount of the bonds has early redemption datedates ranging from 2020 to 2023.
TEP’s net income and cash flows can be adversely affected by rising interest rates.
At December 31, 2014, TEP had $215 million of tax-exempt variable rate debt obligations. The interest rates are set weekly or monthly. The average weekly interest rates (including Letters of Credit (LOCs) and remarketing fees) ranged from 1.40% to 1.75% in 2014. The average monthly interest rates ranged from 0.85% to 0.95%. A 100 basis point increase in the average interest rates on this debt over a twelve-month period would increase TEP’s interest expense by approximately $2 million.
TEP is also subject to risk resulting from changes in the interest rate on its borrowings under the 2010 and 2014 Credit Agreements. Such borrowings may be made on a spread over London Interbank Offer Rate (LIBOR) or an Alternate Base Rate.
If capital market conditions result in rising interest rates, the resulting increase in the cost of variable rate borrowings would negatively impact our results of operations, net income, and cash flows.
The expected purchase of certain of TEP’s leased assets, as well as the cost of significant investments in TEP’s transmission system could require significant outlays of cash, which could be difficult to finance.
In 2014, TEP committed to purchase the Springerville Coal Handling Facilities 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, 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.
OPERATIONAL
The operation of electric generating stations,generation facilities and transmission and distribution systems involves risks and uncertainties that could result in reduced generatinggeneration capability or unplanned outages that could adverselynegatively affect TEP’s results of operations, net income, and cash flows.
The operation of electric generating stations,generation facilities and transmission and distribution systems involves certain risks and uncertainties, including equipment breakdown or failure,failures, fires, weather, 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 failurefailures or other complications, occur from time to time andtime. They are an inherent risk of our business.business and can cause damage to our reputation. If TEP’s generating stations andgeneration facilities or transmission and distribution systems operate below expectations, TEP’s operating results could be adversely affected.
The operation of the San Juan Generating Stationnegatively affected or TEP's capital spending could be adversely affected if the Participants are unable to secure an economic long-term coal supply.
In connection with the implementation of environmental requirements and the associated retirement of San Juan units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of their San Juan ownership. The current coal supply contract for San Juan expires on December 31, 2017. The Participants have agreed that prior to executing a binding restructuring agreement, the remaining Participants will need to have greater certainty regarding the cost and availability of fuel for San Juan after December 31, 2017. TEP and other San Juan owners are currently negotiating agreements concerning the future San Juan fuel supply. If the Participants are unable to negotiate an economic fuel supply, the continued operation of San Juan could be

17




jeopardized resulting in the retirement of San Juan Unit 1 earlier than expected. At December 31, 2014, the net book value of TEP's investment in San Juan Unit 1 is $96 million.increased.
TEP receives power from certain generatinggeneration facilities that are jointly ownedjointly-owned and operated by third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could adverselynegatively affect TEP’s results of operations, net income, and cash flows.
Certain of the generating stationsgeneration facilities 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.generation facilities. Further, TEP may have no ability or a limited ability to make determinations on how best to manage the changing regulationseconomic conditions or environmental requirements which may affect such facilities. In addition, TEP will not have sole discretion as to how to proceed in the face of requirements relating to environmental compliance which could require significant capital expenditures or the closure of such generating stations. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such generating facilities could negatively impact the business and operations of TEP.
We may beTEP is subject to physical attacks.attacks which could have a negative impact on the Company's business and results of operations.
As operators of critical energy infrastructure, we may faceTEP is facing a heightened risk of physical attacks on ourthe Company's electric systems. Our electric generation, transmission, and distribution assets and systems are geographically dispersed and are often in rural or unpopulated areas which make themmakes it especially difficult to adequately detect, defend from, and respond to such attacks.
If, despite our security measures, a significant physical attack occurred, we could have our operations disrupted, property damaged, experience loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on ourTEP's business and results of operations.
We may beTEP is subject to cyber attacks.cyber-attacks which could have a negative impact on the Company's business and results of operations.
We may faceTEP is facing a heightened risk of cyber attacks. Ourcyber-attacks. The Company's information and operations technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes. OurTEP's operations technology systems have direct control over certain aspects of the electric system, and in addition, ourthe Company's utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.
If, despite ourTEP's security measures, a significant cyber or data breach occurred, wethe Company could havehave: (i) our operations disrupted, property damaged, and customer information stolen; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to our reputation, anyreputation. Any of whichthese could have a negative impact on ourTEP's business and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.


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ITEM 2.2. PROPERTIES
Transmission facilities owned by TEP and by third parties are located in Arizona and New Mexico and transmit the output from TEP’s electric generating stationsgeneration facilities at Four Corners, Navajo, San Juan, Springerville, Gila River, and Luna to the Tucson area for use by TEP’s retail customers.area. The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. TEP has arrangements with approximately 140 companies to interchange generation capacity and for the transmission of energy. See Part I, Item 1. Business, TEP, Generating and Other Resources.Overview of Business of this Form 10-K for additional information regarding the transmission facilities.
At December 31, 2014, TEP owned or participated in an overhead electric transmission and distribution system consisting of:
564 circuit-miles of 500-kV lines;
1,110 circuit-miles of 345-kV lines;
408 circuit-miles of 138-kV lines;
465 circuit-miles of 46-kV lines; and
2,600 circuit-miles of lower voltage primary lines.

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TEP’s underground electric distribution system includes 4,461 cable-miles of lines. TEP owns approximately 77% of the poles on which its lower voltage lines are located. Electric substation capacity consists of 106 substations with a total installed transformer capacity of 15,809,050 kilovolt amperes.
The electric generating stationsTEP's generation facilities (except as noted below), administrative headquarters, warehouses and service centers are located on land owned by TEP. The electric distribution and transmission facilities owned by TEP are located:
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, land easements, or other rightsrights-of-way which generally are generally subject to termination;
under or over private property as a result of land easements obtained primarily from the record holder of title; or
over American Indian reservationstribal lands under the grant of easement by the Secretary of the Interior or lease by Americanleased from Indian tribes.Nations.
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 agreementterm patent with the State of Arizona.TEP, under separate sale and leaseback arrangements, leases a 32.2% undivided interest in the Springerville Common Facilities (which does not include land).
Four Corners and Navajo are located on properties held under land 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, land easements, and leases for the plant,generation facilities, the transmission lines, and a water diversion facility located on land owned by the Navajo Nation. TEP has also has acquired land easements for transmission facilities related to San Juan, Four Corners, and Navajo acrosslocated on tribal lands of the Zuni, Navajo, and Tohono O’odham American Indian Reservations.Nations. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna is located. TEP and UNS Electric, Inc. (UNS Electric), an affiliate subsidiary of TEP, own a 75% and 25%, respectively, undivided interest in Gila River Unit 3. Gila River Unit 3 is situated on land owned by TEP and UNS Electric, who also own a 25% undivided ownership interest in the common facilities at Gila River as tenants in common. TEP and UNS Electric, together with the remaining 75% common facilities owners have a free and clear title of all common facilities.
TEP’s rights under these various land 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;Nations;
possible inability of TEP to legally enforce its rights against adverse claimantsclaims and the American Indian tribesNations without Congressional consent; or
failure or inability of the American Indian tribes to protect TEP’s interests in the land easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants.claims.
These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities.
TEP, under separate sale and leaseback arrangements, leased the following generation facilities (which do not include land):
Springerville Unit 1 which expired in January 2015;
Springerville Coal Handling Facilities; and
a 50.0% undivided interest in the Springerville Common Facilities.
Under separate ground lease agreements, TEP leased parcels of land for the following photovoltaicPV facilities:
Thethe Solar Zone in two areas, Area J and Area B, oflocated at the University of Arizona TechTechnology Park in Pima County, Arizona; and
the Bright Tucson Community Solar Blockslocated in Pima County, Arizona.
In December 2014,addition, TEP placed in service an additional photovoltaichas a 30-year easement agreement related to a PV facility in Cochise County, Arizona, for which TEP entered into a 30-year easement agreement.Arizona. The easement is to facilitate the operations of a solar photovoltaicPV renewable energy generation system on behalf of the Department of the Army, located at Fort Huachuca in Cochise County.Army.
See Part I, Item 7. Management’s Discussion and Analysis1. Business, Overview of Financial Condition and ResultsBusiness of Operations, Factors Affecting Results of Operations, Springerville Unit 1 and Note 5 of Notes to Consolidated Financial Statements.this Form 10-K for additional information regarding generation facilities.

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ITEM 3.3. LEGAL PROCEEDINGS
Springerville Unit 1 Proceedings
Upon the terminationTEP is party to a variety of legal actions arising out of the Springerville Unit 1 Leasesnormal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company believes such normal and routine litigation will not have a material impact on January 1, 2015, 50.5% of Springerville Unit 1, or 195 MW of capacity, continued to be owned by third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners).its consolidated financial results. TEP is not obligatedalso involved in other kinds of legal actions, some of which assert or may assert claims or seek to purchase any of the Third-Party Owners’ Springerville Unit 1 power.impose fines, penalties, and other costs in substantial amounts on TEP.
Commencing on January 1, 2015 with the termination of the leases, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. In 2014, TEP and the Third-Party Owners engaged in discussions regarding the post-lease operation of Springerville Unit 1 and related cost sharing arrangements, but did not reach agreement on several key points.
On NovemberSee Note 7 2014, the Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the facility support agreement and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests after the leases terminate to the locations and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint.
On December 19, 2014, the Third-Party Owners filed a complaint (New York Action) against TEP in the Supreme Court of the State of New York, New York County, alleging, among other things, that TEP has refused to comply with the Third-Party Owners instructions to schedule power and energy to which they are entitled in respect of their undivided interest after the leases terminate on January 1, 2015, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services effective January 1, 2015, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required by the facility support agreement as set forth in the FERC Action and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses.
On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP referencing the New York Action, stating that the New York Action alleges that TEP has disaffirmed or repudiated certain of its obligations under the lease transaction documents and that such disaffirmances and repudiations constitute events of default under the Third-Party Owners’ leases. The notice states that the owner trustees, as lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. The notice also states that any rights to exercise additional remedies or assert additional events of default are preserved. In a letter to Wilmington Trust Company dated December 29, 2014, TEP denied the allegations in the notice. In January 2015, Wilmington Trust Company sent a second notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases by not remediating the defaults alleged in the first notice. The second notice repeated the demand that TEP pay liquidated damages totaling approximately $71 million. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.
TEP believes that it has fully complied with all of its obligations under the two Third-Party Owner leases and the other lease transaction agreements, denies that it has disaffirmed or repudiated any of its obligations under the lease transaction documents, denies that any of the amounts claimed as damages are due, denies the allegation that events of default have arisen under such leases and denies that the lessors are entitled to exercise remedies under such leases. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations, Springerville Unit 1. In addition, see Note 6 of Notes to Consolidated Financial Statements - Contingencies.in Part II, Item 8 of this Form 10-K for additional information.

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.


2015






PART II

ITEM 5.5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Stock TradingMarket Information
TEP’s common stock is wholly-owned by UNS Energy and is not listed for trading on any stock exchange.
Dividends
TEP declared and paid dividends to UNS Energy of $40$70 million in 2014, $402017 and $50 million in 2013,2016 and $30 million in 2012.
TEP can pay dividends if it maintains compliance with the 2014 Credit Agreement, the 2010 Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement which all contain substantially the same financial covenants, and the terms of the Merger order issued by the ACC in August 2014. At December 31, 2014, TEP was in compliance with the terms of all financial covenants and agreements and the Merger order.2015.

ITEM 6.6. SELECTED FINANCIAL DATA
The following table provides selected financial data for the years 2013 through 2017:
 2014 2013 2012 2011 2010
 Thousands of Dollars
Income Statement Data         
Operating Revenues$1,269,901
 $1,196,690
 $1,161,660
 $1,156,386
 $1,125,267
Net Income102,338
 101,342
 65,470
 85,334
 108,260
Balance Sheet Data         
Total Utility Plant – Net$3,425,190
 $2,944,455
 $2,750,421
 $2,650,652
 $2,410,077
Total Investments in Lease Debt and Equity
 36,194
 45,457
 65,829
 103,844
Other Investments and Other Property37,599
 33,488
 35,091
 32,313
 43,588
Total Assets4,232,422
 3,563,285
 3,461,046
 3,277,661
 3,078,411
          
Long-Term Debt$1,372,414
 $1,223,070
 $1,223,442
 $1,080,373
 $1,003,615
Non-Current Capital Lease Obligations69,438
 131,370
 262,138
 352,720
 429,074
Common Stock Equity1,215,779
 925,923
 860,927
 824,943
 709,884
Total Capitalization$2,657,631
 $2,280,363
 $2,346,507
 $2,258,036
 $2,142,573
Cash Flow Data         
Net Cash Flows From Operating Activities$313,663
 $346,191
 $267,919
 $268,294
 $302,483
Capital Expenditures(507,070) (252,848) (252,782) (351,890) (277,309)
Other Investing Cash Flows(10,568) (6,814) 24,901
 39,879
 24,273
Net Cash Flows From Investing Activities(517,638) (259,662) (227,881) (312,011) (253,036)
Net Cash Flows From Financing Activities252,810
 (140,937) 11,987
 51,452
 (51,882)
Ratio of Earnings to Fixed Charges (1)
2.56
 2.67
 2.10
 2.40
 2.74
(in thousands)2017 2016 2015 2014 2013
Income Statement Data         
Operating Revenues$1,340,935
 $1,234,995
 $1,306,544
 $1,269,901
 $1,196,690
Net Income176,668
 124,438
 127,794
 102,338
 101,342
Balance Sheet Data         
Total Utility Plant, Net$3,768,702
 $3,782,806
 $3,558,229
 $3,425,190
 $2,944,455
Total Assets4,590,249
 4,449,989
 4,249,478
 4,119,830
 3,482,860
Long-Term Debt, Net1,354,423
 1,453,072
 1,451,720
 1,361,828
 1,213,367
Non-Current Capital Lease Obligations28,519
 39,267
 55,324
 69,438
 131,370
Other Data         
Ratio of Earnings to Fixed Charges (1)
5.06
 3.69
 3.74
 2.56
 2.67
(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, including capital lease obligations.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.Operations for additional information.


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ITEM 7.7. 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 TEP. It includes the following:
outlook and strategies;
operating results during 2014in 2017 compared with the same periods of 2013,2016, and 20132016 compared with 2012;2015;
factors affecting our results of operations and outlook;
liquidity capital needs,and capital resources including capital expenditures, contractual obligations, and contractual obligations;
dividends; andenvironmental matters;
critical accounting estimates.policies and estimates; and

TEP is a vertically integrated, regulated utility that generates, transmits and distributes electricity to approximately 415,000 retail electric customers in a 1,155 square mile area in southeastern Arizona.recent accounting pronouncements.
Management’s Discussion and Analysis includes financial information prepared in accordance with generally accepted accounting principles (GAAP)Generally Accepted Accounting Principles in the U.S., as well as certainUnited States of America (GAAP) financial measures. It also includes non-GAAP financial measures. The non-GAAP financial measures which should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP financial measures as presented herein may not be comparable to similarly titled measures used by other companies.
Management’s Discussion and Analysis should be read in conjunction with Part 2, Item 6, of this Form 10-KSelected Financial Data and the Consolidated Financial Statements and Notes in Part II, Item 8 of this Form 10-K. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see Forward-Looking Information at the front of this report and Part I, Item 1A. Risk Factors for additional information.
References in Item 1A.this discussion and analysis to "we" and "our" are to TEP.

OUTLOOK AND STRATEGIES
TEP's financial prospects and outlook are affected by many factors including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory factors. Our plans and strategies include the following:
Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe and reliable service.
Continuing to focus on our long-term generation resource diversification strategy, including shifting from coal to natural gas, renewables, and energy efficiency while providing rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, leveraging and leveragingimproving our existing utility infrastructure.
Developing strategic responses to new environmental regulationsinfrastructure, and potential new legislation, including proposed carbon emission standards to reduce greenhouse gas emissions from existing power plants. We are evaluating TEP's existing mixmaintaining financial strength. This long-term strategy includes a target of generation resources and defining steps to achieve environmental objectives that protect the financial stabilitymeeting 30% of our utility business and the interests of our customers.
Strengthening the underlying financial condition of TEPcustomers’ energy needs with non-carbon emitting resources by achieving constructive regulatory outcomes, improving our capital structure and our credit ratings, and promoting economic development in our service territory.2030.
Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in utility rate base, emphasizing customerinfrastructure to ensure reliable service, and maintaining a strong community presence.
Developing strategic responsesOperational and Financial Highlights
For 2017, Management's Discussion and Analysis includes the following notable items:
The ACC issued the 2017 Rate Order approving a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and an equity ratio of approximately 50%. The new rates took effect on February 27, 2017.
The Navajo Nation approved a land lease extension that allows Navajo to operate through December 2019 and decommissioning activities to begin thereafter. As a result of the planned early retirement, we transferred $52 million of the facility's NBV and other related costs to a regulatory asset.
The FERC informed us that no further enforcement actions were necessary as the investigation related to the evolving utility business that includes renewable energy, DG,FERC Refund Orders had been closed. In addition, TEP and EE that protecta counterparty, who had been a recipient of the financial stability of our business while providing benefits and choices to our customers.time-value


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refunds in compliance with the FERC Refund Orders, entered into a settlement agreement which resulted in: (i) the counterparty paying TEP $8 million; and (ii) TEP dismissing a previously filed appeal.
In conjunction with a generation modernization project at Sundt, we will discontinue operation of Sundt Units 1 and 2 by the end of 2020. As a result of the planned early retirements, we transferred $32 million of the facilities' NBV to a regulatory asset.
We entered into a 20-year Tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA will allow us to continue to move toward its long-term goal of resource diversification. Our obligations under the agreement are contingent upon SRP's acquisition of Gila River Units 1 and 2, which is expected to be completed by March of 2018.
We purchased an additional 17.8% undivided ownership interest in Springerville Common Facilities for $38 million bringing its total ownership interest to 67.8%.
San Juan Unit 2 ceased operations in compliance with a State Implementation Plan (SIP) covering BART requirements for San Juan. TEP owns 50% of San Juan Unit 2 and applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order.
RESULTS OF OPERATIONS
The following discussion provides the significant items that affected TEP's results of operations for thein years ended December 31, 2014, 20132017, 2016, and 2012.2015, presented on an after-tax basis.
20142017 compared with 20132016
TEP reported net income of $102$177 million in the year ended December 31, 20142017 compared with net income of $101$124 million in the year ended December 31, 2013.2016. The following factors affected the period over period change in TEP’s results. All amounts are presented on an after-tax basis:
a $22increase of $53 million, increase in retail margin revenues due to a non-fuel base rate increase thator 43%, was effective on July 1, 2013 and a $6 million increase in LFCR revenues recorded in 2014;
a $7 million decrease in interest expense, primarily due to a reductionto:
$52 million in the balance of capital lease obligations. See Note 5 of the Notes to Consolidated Financial Statements;
a $2 million increase in the margin on long-term wholesale sales,higher retail revenue primarily due in part to an increase in rates as approved in the average market price for wholesale power;2017 Rate Order and
a $1 million an increase in transmission revenue; partially offset byusage due to favorable weather;
an $11$21 million increase in Base O&M for retail customer bill credits approved by the ACC as a condition of the Merger;
a $7 million increasehigher net income due to time-value FERC ordered refunds incurred in Base O&M for merger-related expenses including acquisition transaction fees2016 and the accelerationreversal of share-based compensation expense;
a $4 million increaseaccrued refunds in Base O&M exclusive of bill credits and merger-related expenses. The increase results primarily from higher generating plant maintenance expense and increased rent expense associated with the Navajo lease amendment.2017 related to late-filed TSAs. See Note 67 of Notes to Consolidated Financial Statements;Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs; and
a $4$6 million in higher wholesale revenue primarily due to favorable pricing on wholesale contracts in 2017.
The increase was partially offset by:
$8 million in lower revenues related to the Springerville Unit 1 settlement in 2016. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the settlement;
$7 million in higher income tax expense primarily due to the enactment of the TCJA in 2017 as well as changes to our valuation allowance for deferred tax assets in 2016. See Note 12 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA on our financial results;
$6 million in higher depreciation and amortization expenses,expenses; and
$4 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense due to planned generation outages in 2017 and employee wages and benefits.
2016 compared with 2015
TEP reported net income of $124 million in 2016 compared with $128 million in 2015. The decrease of $4 million, or 3%, was primarily due to:
$13 million in lower net income associated with late-filed TSAs;
$6 million in higher depreciation and amortization expenses primarily related to an increase in asset base in the current year;base; and
a $5$4 million in higher operations and maintenance expenses primarily related to an increase in income taxes resulting from an effective tax rate variance primarily generated by a non-recurring $11outside services and employee wages and benefits.

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The decrease was partially offset by:
$8 million tax benefit recorded in June 2013higher revenues related to recover previously recordedthe Springerville Unit 1 settlement in 2016;
$6 million in lower income tax expense as a result of the 2013 TEP Rate Order. This amount is partially offset by a $2 million increasereduction in the valuation allowance in 2013 and a $3 million increase in investmentfor deferred tax credits recorded in 2014. See Note 11 of Notes to Consolidated Financial Statements.
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 the period over period change in TEP’s results. All amounts are presentedassets based on an after-tax basis:
a $25 million increase in retail margin revenues primarily due to a non-fuel base rate increase that was effective on July 1, 2013, and favorable weather during 2013 compared with 2012. Favorable weather conditions contributed to a 0.2% increase in retail kWh sales during 2013;
a $9 million decrease in income taxes, resulting from an effective tax rate variance primarily generated by a non-recurring $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 11 of Notes to Consolidated Financial Statements;
a $5 million decrease in interest expense due to a reduction in the balance of capital lease obligations;
a $3 million increase in income as a result of the 2012 write-off of a portion of the planned Tucson to Nogales transmission line;
a $2 million increase in income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in 2012; and
a $1 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;projected taxable income; and
$4 million from higher LFCR revenues that partially offset by

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a $4 million increase in Base O&M for merger-related expenses recorded in December 2013;lower retail sales.
a $4 million increase in Base O&M, exclusive of merger-related costs, due in part to higher plannedRetail Revenues and unplanned generating plant maintenance expense;
a charge of $2 million recorded to fuel and purchased energy expense resulting from the 2013 TEP Rate Order; and
a $2 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.

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Utility Sales and RevenuesKey Statistics
The table below providesfollowing tables provide a summaryreconciliation of retail kWh sales, revenues,Retail Revenues (GAAP) to Retail Margin Revenues (non-GAAP) and weather data during 2014, 2013 and 2012:other key statistics impacting operating revenues:
 Year Ended Increase (Decrease) Year Ended Increase (Decrease)
 2014 2013 
Percent(1)
 2012 
Percent(1)
Energy Sales, kWh (in Millions):         
Electric Retail Sales:         
Residential3,727
 3,867
 (3.6)% 3,821
 1.2 %
Commercial2,170
 2,187
 (0.8)% 2,187
  %
Industrial2,098
 2,114
 (0.8)% 2,132
 (0.9)%
Mining1,137
 1,079
 5.4 % 1,093
 (1.2)%
Public Authorities33
 32
 3.1 % 32
 1.6 %
Total Electric Retail Sales9,165
 9,279
 (1.2)% 9,265
 0.2 %
Retail Margin Revenues (in Millions):         
Residential$280
 $271
 3.3 % $248
 9.3 %
Commercial188
 181
 3.9 % 171
 5.9 %
Industrial104
 97
 7.2 % 93
 5.4 %
Mining38
 34
 11.8 % 30
 11.5 %
Public Authorities2
 2
  % 2
 5.9 %
Total by Customer Class612
 585
 4.6 % 544
 7.7 %
LFCR Revenues11
 2
 450.0 % 
 NM
Total Retail Margin Revenues (Non-GAAP)(2)
623
 587
 6.1 % 544
 7.9 %
Fuel and Purchased Power Revenues303
 300
 1.0 % 327
 (8.1)%
RES, DSM and ECA Revenues44
 47
 (6.4)% 45
 4.4 %
Total Retail Revenues (GAAP)$970
 $934
 3.9 % $916
 2.0 %
Average Retail Margin Rate (Cents / kWh):(1)
         
Residential7.51
 7.02
 7.0 % 6.50
 8.0 %
Commercial8.66
 8.28
 4.6 % 7.82
 5.9 %
Industrial4.96
 4.61
 7.6 % 4.33
 6.5 %
Mining3.34
 3.14
 6.4 % 2.78
 12.9 %
Public Authorities6.06
 5.56
 9.0 % 5.34
 4.1 %
Total Average Retail Margin Rate Excluding LFCR6.68
 6.30
 6.0 % 5.87
 7.3 %
Average LFCR Rate0.12
 0.02
 500.0 % 
 NM
Total Average Retail Margin Rate Including LFCR6.80
 6.31
 7.8 % 5.87
 7.5 %
Average Fuel and Purchased Power Revenues3.31
 3.24
 2.2 % 3.52
 (8.0)%
Average RES, DSM and ECA Revenues0.48
 0.52
 (7.7)% 0.49
 6.1 %
Total Average Retail Revenues10.59
 10.07
 5.2 % 9.88
 1.9 %
          
Weather Data:
 
 
 
 
Cooling Degree Days         
Year Ended December 31,1,557
 1,631
 (4.5)% 1,556
 4.8 %
10-Year Average1,515
 1,491
 NM
 1,484
 NM
Heating Degree Days         
Year Ended December 31,930
 1,449
 (35.8)% 1,201
 20.6 %
10-Year Average1,335
 1,404
 NM
 1,394
 NM
 
Years Ended
December 31,
 Increase (Decrease) 
Year Ended
December 31
 Increase (Decrease)
($ in millions)2017 2016 Percent 2015 Percent
Retail Revenues (GAAP)$1,041
 $990
 5.2 % $1,022
 (3.1)%
Less recoveries from:         
Fuel and Purchased Power275
 305
 (9.8)% 344
 (11.3)%
DSM and RES Surcharge53
 54
 (1.9)% 49
 10.2 %
Retail Margin Revenues (non-GAAP) (1)
$713
 $631
 13.0 % $629
 0.3 %
          
Electric Sales (kWh in millions)
         
Residential3,786
 3,724
 1.7 % 3,724
  %
Commercial2,192
 2,139
 2.5 % 2,124
 0.7 %
Industrial1,939
 2,006
 (3.3)% 2,063
 (2.8)%
Mining991
 997
 (0.6)% 1,109
 (10.1)%
Public Authorities18
 30
 (40.0)% 33
 (9.1)%
Total Retail Sales8,926
 8,896
 0.3 % 9,053
 (1.7)%
Wholesale Sales, Long-Term587
 463
 26.8 % 750
 (38.3)%
Wholesale Sales, Short-Term3,630
 3,308
 9.7 % 3,928
 (15.8)%
Total Electric Sales13,143
 12,667
 3.8 % 13,731
 (7.7)%
          
Average Retail Rate (cents / kWh)
11.66
 11.13
 4.8 % 11.29
 (1.4)%
Average Fuel and Purchased Power Rate3.08
 3.43
 (10.2)% 3.80
 (9.7)%
Average DSM and RES Surcharge Rate0.59
 0.61
 (3.3)% 0.54
 13.0 %
Total Average Retail Margin Rate7.99
 7.09
 12.7 % 6.95
 2.0 %
(1)
Calculated on un-rounded data and may not correspond exactly to data shown in table.
(2) 
Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i)exclude 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 believeitems. TEP believes the change in Retail Margin Revenues between periods provides useful information for investors and analysts because it

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demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales, and LFCR revenues, DSM performance bonus, and other revenues available to cover the non-fuel operating expenses of our core utility business.
2014 compared with 2013
Residential
Residential kWh sales were 3.6% lower in 2014 due in part to fewer cooling degree days compared with 2013. A non-fuel base rate increase effective July 1, 2013, partially offset by lower sales volumes, led to an increase in residential margin revenues of 3.3%, or $9 million. The average number of residential customers grew by 0.5% in 2014 compared with 2013.
Commercial
Commercial kWh sales decreased by 0.8% compared with 2013. Lower sales volumes were offset by a non-fuel base rate increase effective July 1, 2013 which contributed to an increase in commercial margin revenues of 3.9%, or $7 million.
Industrial
Industrial kWh sales decreased by 0.8% compared with 2013. Lower sales volumes were offset by a non-fuel base rate increase effective July 1, 2013, which led to an increase in industrial margin revenues of 7.2% or $7 million.
Mining
Mining kWh sales increased by 5.4% compared with 2013, which can be attributed to an expansion by one of TEP's mining customers. The increased kWh sales as well as a non-fuel base rate increase effective July 1, 2013 led to an increase in margin revenues from mining customers of 11.8%, or $4 million. See Factors Affecting Results of Operations, Sales to Mining Customers.
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.

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Wholesale Sales and Transmission Revenues
 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Long-Term Wholesale Revenues:     
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)
$10
 $7
 $5
Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues18
 19
 20
Total Long-Term Wholesale Revenues28
 26
 25
Transmission Revenues16
 15
 16
Short-Term Wholesale Revenues114
 92
 70
Electric Wholesale Sales (GAAP)$158
 $133
 $111
(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 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 WholesaleRetail Revenues increased in 2017 compared with 2016 primarily due to higher Retail Margin Revenues related to an increase in 2014rates as approved in the 2017 Rate Order and an increase in usage due to favorable weather in 2017. The increases were higher whenpartially offset by a decrease in revenue from Fuel and Purchased Power recoveries as a result of lower PPFAC rates.
Retail Revenues decreased in 2016 compared with 20132015 primarily due to a decrease in partrevenue from Fuel and Purchased Power recoveries as a result of lower PPFAC rates partially offset by higher Retail Margin Revenues due to higheran increase in LFCR revenues.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the PPFAC mechanism and LFCR revenues.

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Wholesale Revenues
Wholesale Revenues increased by $57 million, or 49%, in 2017 compared with 2016 primarily due to: (i) time-value FERC ordered refunds incurred in 2016 and the reversal of accrued refunds in 2017, related to late-filed TSAs; (ii) favorable commodity pricing on the wholesale market; (iii) a new long-term wholesale contract that commenced in 2017; and (iv) an increase in short-term wholesale volumes.
Wholesale Revenues decreased by $50 million, or 30%, in 2016 compared with 2015 primarily due to: (i) time-value FERC ordered refunds incurred in 2016; (ii) decreased volumes and market prices for wholesale power.
Short-Term Wholesale Revenues
All revenues fromof both short-term and long-term wholesale sales resulting from unfavorable market conditions; and 10%(iii) termination of a firm contract at the profits fromend of May 2016.
Short-term wholesale trading activityrevenues are creditedprimarily related to ACC jurisdictional assets and are returned to retail customers by crediting the revenues against the fuel and purchased power costs eligible for recovery inthrough the PPFAC.
Other Revenues
 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Revenue related to Springerville Units 3 and 4(1)
$112
 $102
 $101
Other Revenue29
 28
 33
Total Other Revenue$141
 $130
 $134
(1)
Represents revenues and reimbursements from Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, 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 its affiliates, UNS Gas, Inc.Other Revenues decreased by $3 million, or 2%, an indirect wholly-owned subsidiary of UNS Energy (UNS Gas) and UNS Electric, for corporate services provided by TEP, and miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees. See Note 4 of Notes to Consolidated Financial Statements.

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Operating Expenses
Fuel and Purchased Power Expense
TEP’s fuel and purchased power expense and energy resources for 2014, 2013, and 2012 are detailed below:
 Generation and Purchased Power Fuel and Purchased Power Expense
 2014 2013 2012 2014 2013 2012
 Millions of kWh Millions of Dollars
Coal-Fired Generation9,271
 10,254
 9,702
 $232
 $273
 $247
Gas-Fired Generation1,210
 1,007
 1,435
 60
 46
 65
Utility Owned Renewable Generation48
 38
 45
 
 
 
Reimbursed Fuel Expense for Springerville Units 3 and 4
 
 
 5
 7
 7
Total Generation10,529
 11,299
 11,182
 298
 326
 319
Total Purchased Power3,195
 2,329
 2,328
 153
 112
 80
Transmission and Other PPFAC Recoverable Costs
 
 
 18
 12
 6
Increase (Decrease) to Reflect PPFAC Recovery Treatment
 
 
 (11) (12) 31
Subtotal13,724
 13,628
 13,510
 $457
 $438
 $436
Less Line Losses and Company Use(859) (885) (839)      
Total Energy Sold12,865
 12,743
 12,671
      
Generation
Total generating output decreased in 2014 when2017 compared with 2013 primarily resulting from outages at Springerville and Sundt generating stations. Coal-fired generation decreased by 9.5% in 2014,2016 primarily due to using natural gas to fuel Sundt Unit 4 instead of coal.
The table below summarizes average fuel cost per kWh generated or purchased:
 2014 2013 2012
 cents per kWh
Coal2.50
 2.66
 2.54
Gas4.99
 4.57
 4.54
Purchased Power4.79
 4.83
 3.44
All Sources3.64
 3.54
 3.19
O&M
The table below summarizes the items included in O&M expense. Base O&M includes $34 million of merger-related expenses and retail customer bill credits in 2014 and $6 million of merger-related expenses in 2013.
 2014 2013 2012
 Millions of Dollars
Base O&M (Non-GAAP)(1)
$281
 $246
 $234
O&M Recorded in Other Expense(9) (7) (6)
Reimbursed Expenses Related to Springerville Units 3 and 484
 70
 72
Expenses Related to Customer Funded Renewable Energy and DSM Programs(2)
23
 26
 35
Total O&M (GAAP)$379
 $335
 $335
(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 because it represents the fundamental level of operating and maintenance expense related to our core business.
(2)
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 Base O&M:
 2014 2013 2012
 Millions of Dollars
Pension Expense Charged to O&M$6
 $10
 $10
Retiree Benefit Expense Charged to O&M5
 5
 5
Total$11
 $15
 $15

FACTORS AFFECTING RESULTS OF OPERATIONS
2013 TEP Rate Order
The 2013 TEP Rate Order, issued by the ACC and effective July 1, 2013, provided for a non-fuel retail Base Rate increase of $76 million, an authorized rate of return of 7.26% on the Original Cost Rate Base (OCRB) of $1.5 billion, and 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 Fair Value Rate Base (FVRB) of approximately $800 million).
In addition, there are provisions within the 2013 TEP Rate Order allowing more timely recovery of certain costs through several recovery mechanisms:
The LFCR mechanism allows recovery of certain non-fuel costs related to kWh sales lost due to EE programs and DG.
The Environmental Compliance Adjustor (ECA) mechanism allows recovery of certain capital carrying costs to comply with government-mandated environmental regulations between rate cases.
The DSM and RES surcharges allow for recovery of costs to implement DSM and renewable energy programs that support the ACC's EE Standards.
As required by the 2013 Rate Order, TEP filed a compliance report in July 2014 that outlined its planned purchases of: (i) certain ownership interests in Springerville Unit 1; (ii) 75% of Gila River Unit 3; and (iii) the Springerville Coal Handling Facilities. The report estimated that as a result of these purchases, and the termination of certain lease obligations, TEP's 2014 non-fuel revenue requirement would decline by approximately $36 million. However, when other changes to TEP's rate base, expenses and retail sales levels were considered, TEP estimated a non-fuel revenue deficiency of approximately $26 million as of December 31, 2014.
See Note 2of Notes to Consolidated Financial Statementsfor more information.
Generating Resources
At December 31, 2014, approximately 57% of TEP's generating capacity was fueled by coal. In January 2015, following the purchase of the final Springerville Unit 1 leased interest of 96 MW, andsettlement agreement in 2016. The decrease was partially offset by an increase in reimbursed costs to TEP from SRP, the expiration of the remaining 195 MWowner of Springerville Unit 1 leased capacity, TEP's coal-fired generating capacity dropped4, related to 54% of total capacity. Existing and proposed federal environmental regulations, as well as potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is implementing coal reduction strategies and evaluating additional steps 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:
Regulatory approvals associated with the closure of San Juan Unit 2, and pending ownership restructuringplanned generation outages of the remaining units, see Item 1 - Environmental Matters;
The outcome of the proposed Clean Power Plan, see Item 1 - Environmental Matters; and
TEP's option to permanently convert Sundt Unit 4 to be fueled by natural gas, see Item 1 - Environmental Matters.
Springerville Unit 1
TEP leased Unit 1 of the Springerville Generating Station and an undivided one-half interestfacility in certain Springerville Common Facilities (collectively Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that were accounted for as capital leases. The leases expired in January 2015 resulting in TEP owning a 49.5% undivided interest. At December 31, 2014, TEP's ownership interest was 24.7%, or 96 MW.

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In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 MW of capacity. In December 2014, TEP purchased a 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million. In January 2015, TEP purchased a leased interest comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million.
The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, continues to be owned by third parties. TEP is not obligated to purchase any of the Third-Party Owners’ generating output. With the expiration of the leases in January 2015, TEP is obligated to operate the unit for the Third-Party Owners. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $1.5 million per month, and their share of capital expenditures, which are approximately $7 million in 2015.
In 2014, TEP and the Third-Party Owners, engaged in discussions regarding the post-lease operation of Springerville Unit 1 and related cost sharing arrangements, but did not reach agreement on several key points. As of 01/30/15, TEP has requested pre-funding for operations from the Third-Party Owners of approximately $5 million for their pro-rata share of Springerville Unit 1 operating and maintenance expenses and for their pro-rata share of capital costs, none of which has been paid as of February 19, 2015.
See Item 3. Legal Proceedings for a description of legal proceedings relating to the Third-Party Owners.
TEP replaced the 195 MW of expired leased capacity with the purchase of Gila River Unit 3. See Gila River Generating Station Unit 3, below.
Gila River Generating Station Unit 3
On December 10, 2014, TEP and UNS Electric acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW) for $164 million, and UNS Electric purchased the remaining 25% undivided interest. TEP’s interest in Gila River Unit 3 will replace the expired coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2 and is a key component in TEP's strategy to diversify its generation fuel mix.
2017. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the Springerville Unit 1 settlement.
Other Revenues increased by $10 million, or 8%, in 2016 compared with 2015 primarily due to the Springerville Unit 1 settlement agreement in 2016. The increase was offset by a decrease in reimbursed costs to TEP from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and SRP related to planned generation outages at Springerville Units 3 and 4 in 2015.
Operating Expenses
Fuel and Purchased Power Expense
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, increased by $5 million, or 1%, in 2017 compared with 2016 primarily due to an increase in Purchased Power volumes that replaced lower Coal-Fired Generation output, and an increase in average fuel cost per kWh (see table below). The increases were partially offset by reduced recovery of PPFAC costs as a result of changes in PPFAC rates. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the PPFAC mechanism.
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, decreased by $75 million, or 15%, in 2016 compared with 2015 primarily due to a decrease in: (i) Purchased Power, Non-Renewable volumes; (ii) Coal-Fired Generation output; and (iii) average cost fuel and purchased power per kWh (see table below). The decrease was partially offset by an increase in Gas-Fired Generation output.
TEP’s sources of energy are detailed in the following table:
 Years Ended December 31, Increase (Decrease) Year Ended December 31, Increase (Decrease)
(kWh in millions)2017 2016 Percent 2015 Percent
Sources of Energy         
Coal-Fired Generation7,530
 8,310
 (9.4)% 8,584
 (3.2)%
Gas-Fired Generation3,237
 3,283
 (1.4)% 2,723
 20.6 %
Utility-Owned Renewable Generation83
 68
 22.1 % 65
 4.6 %
Total Generation10,850
 11,661
 (7.0)% 11,372
 2.5 %
Purchased Power, Non-Renewable2,471
 1,126
 119.4 % 2,627
 (57.1)%
Purchased Power, Renewable646
 666
 (3.0)% 452
 47.3 %
Total Generation and Purchased Power13,967
 13,453
 3.8 % 14,451
 (6.9)%

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TEP’s average fuel cost of generated power and the average cost of purchased power per kWh are detailed in the following table:
 Years Ended December 31, Increase (Decrease) Year Ended December 31, Increase (Decrease)
(cents per kWh)2017 2016 Percent 2015 Percent
Average Fuel Cost of Generated Power         
Coal2.41
 2.30
 4.8 % 2.44
 (5.7)%
Natural Gas3.06
 2.84
 7.7 % 3.35
 (15.2)%
Average Cost of Purchased Power         
Purchased Power, Non-Renewable3.78
 3.43
 10.2 % 3.04
 12.8 %
Purchased Power, Renewable6.67
 7.00
 (4.7)% 9.82
 (28.7)%
Operations and Maintenance Expense
Operations and Maintenance Expense increased by $6 million, or 2%, in 2017 compared with 2016 primarily due to an increase in: (i) maintenance expense related to planned generation outages and an increase in employee wages and benefits. The increase was partially offset by a decrease in RES and DSM program expenses.
Operations and Maintenance Expense increased Item 7. Management's Discussionby$9 million, or 3%, in 2016 compared with 2015 primarily due to an increase in: (i) maintenance expense related to planned generation outages, outside services, and Analysis of Financial Conditionemployee wages and Factors Affecting Results of Operations, Gila River Generating Station Unit 3.benefits; and (ii) an increase in RES and DSM program expenses.
Potential Plant RetirementsRES and DSM program expenses are fully recovered through the cost recovery mechanisms and have no impact on earnings.
Other Income (Deductions)
Other Income (Deductions) increased by $9 million in 2017 compared with 2016 primarily due to a settlement agreement in 2017 related to late-filed TSAs. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
There were no significant changes to Other Income (Deductions) in 2016 compared with 2015.
Income Tax Expense
Income Tax Expense increased by $41 million, or 70%, in 2017 compared with 2016 primarily due to the increase in earnings before tax, the enactment of the TCJA in December 2017, and a reduction in the valuation allowance for deferred tax assets in 2016. See Note 12 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA on our financial results.
Income Tax Expense decreased by $12 million, or 17%, in 2016 compared with 2015 primarily due to the decrease in earnings before tax income and a reduction in the valuation allowance for deferred tax assets based on an increase in projected taxable income.
FACTORS AFFECTING RESULTS OF OPERATIONS
Regulatory Matters
TEP periodically files an Integrated Resource Plan (IRP) withis subject to comprehensive regulation. The discussion below contains material developments to those matters.
2017 Rate Order
In February 2017, the ACC.ACC issued a rate order in the rate case filed by TEP in November 2015. TEP's rate filing was based on a test year ended June 30, 2015. The IRP provides 2017 Rate Order approved new rates that went into effect on February 27, 2017.
The provisions of the 2017 Rate Order include, but are not limited to:
a viewnon-fuel base rate increase of forecasted energy needs over $81.5 million which includes $15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016;
a long term (15 years)7.04% return on original cost rate base of approximately $2 billion;
a cost of equity component of 9.75% and options being considered to meet those needs.a cost of debt component of 4.32%;

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a capital structure for rate making purposes of approximately 50% common equity and 50% long-term debt;
adoption of TEP's 2014 IRP reflectsproposed depreciation and amortization rates, which include a portfolio diversification strategy that includes reducing its overall coal capacity overreduction in the next five years at the Springerville,depreciable life for San Juan Unit 1; and Sundt Generating Stations. TEP's planning assumptions include retiring certain coal-fired generating facilities at
approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt earlier thandue to early retirement.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first half of 2018. TEP cannot predict the outcome of these proceedings. See Phase 2 Proceedings below.
Distributed Generation
In 2016, the ACC held proceedings under the Value and Cost of DG docket to examine the ACC’s net metering rules and determine the value that utilities should pay DG customers who deliver electricity from rooftop solar systems back to the grid. Prior to these proceedings, the ACC’s net metering rules allowed DG customers who over-produced electricity to carry-over or “bank” excess electricity at a value equal to the full retail rate per kWh. Banked kWh could then be used by customers to offset future energy usage that could not be met by their DG system.
In December 2016, the ACC approved an order that will begin to reform net metering in Arizona. The order adopts a number of net metering changes and policies, including:
placing DG customers in a separate rate class;
grandfathering current estimated useful lives. These facilitiesDG customers under net metering rules and rate design for 20 years from interconnection application;
eliminating the banking of excess kWh for non-grandfathered DG customers;
compensating non-grandfathered customers for their exported kWh for 10 years at the DG export rate in effect at the time of interconnection;
updating the DG export rate annually; and
developing an avoided cost methodology for calculating the DG export rate in the utility’s next rate case.
The initial DG export rate will be established in Phase 2. See Phase 2 Proceedings below.
Phase 2 Proceedings
In March 2017, TEP filed direct testimony in its Phase 2 proceedings addressing rate design for new DG customers. The proposals include options for either a Time-Of-Use (TOU) energy rate with a basic customer service charge plus a monthly grid access fee based on the size of the DG system; or a TOU energy rate with a basic customer service charge plus a charge based on the highest hourly demand during the month. TEP also proposed that: (i) new DG customers receive a bill credit for excess energy exported to the grid at an initial rate of 9.7 cents/kWh; (ii) the DG export rate be updated based on a five-year rolling average cost of the company’s owned and contracted utility scale renewable energy projects; (iii) customers who submit DG applications prior to the ACC’s Phase 2 decision be grandfathered under current net metering rules and rate design for a period of 20 years from the date of interconnection of their DG system; and (iv) customers who install DG after the ACC’s Phase 2 decision be compensated for 10 years at the rate in effect at the time they file an application for interconnection. A final ACC decision is currently do not haveexpected in the requisite emission control equipmentfirst half of 2018. TEP cannot predict the outcome of these proceedings.
Federal Income Tax Legislation
On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to meet proposed EPA regulations.the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. TEP continueshas revalued its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment of the TCJA. We are still in the process of analyzing the ongoing impacts of the TCJA on our operations. See Note 12 of Notes to evaluateConsolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding current year impacts of the potential need to retire early these coal-fired generating facilities. The 2013 TEP Rate Order stipulates that in any filingTCJA.
In December 2017, the ACC opened a docket related to the early retirementTCJA. On February 6, 2018, the ACC ordered utilities to file within 60 days either: (i) an application for a tax adjustor mechanism; (ii) an intent to file a rate case within 90 days; or (iii) any other

22






application to address the effects of the TCJA. TEP expects to file a generation asset, TEP would seektax adjustor proposal with the ACC approval to apply any then-existing excess generation depreciation reserveprior to the unrecovered book valuedeadline addressing the method it will use to pass through TCJA benefits to its customers. TEP will defer the ACC jurisdictional tax benefits as a regulatory liability until the proceedings are finalized.
TEP offsets its net operating loss carryforwards against taxable income and does not expect to make federal income tax payments until 2020. Any interim return of benefits to customers related to the retiring assets. TCJA would have a negative impact on TEP's operating cash flows.
TEP would thencannot predict the outcome of these proceedings or the impact on the Company's financial position or results of operations.
Generation Resources
As of December 31, 2017, approximately 49% of TEP's peak generation capacity was sourced from coal-fired generation resources. As part of TEP's long-term diversification strategy, TEP is evaluating additional steps to reduce its reliance on coal-fired generation.
Integrated Resource Plan
TEP’s long-term strategy to shift to a more diverse, sustainable energy portfolio is described in its Integrated Resource Plan (IRP) filed in April 2017 with the ACC. TEP's 2017 IRP discusses continuing efforts to diversify its generation portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generating resources. TEP's existing coal-fired generation fleet faces a number of uncertainties impacting the viability of continued operations including competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for any remaining amounts that would not otherwise be otherwise recovered, if and when any, such assets are retired.as a result of these actions.
See Part I, Item 1 -1. Business, Overview of Business and Liquidity and Capital Resources,Environmental Matters.Matters of this Form 10-K for additional information regarding generation facility operations.
Springerville Coal Handling Facilities Capital Lease Purchase CommitmentArizona Energy Modernization Plan
TEP leases interests inThe ACC will be considering adoption ofa new energy policy for Arizona that would establish a goal of clean energy sources making up at least 80% of the coal handling facilitiesstate’s electricity generation portfolio by 2050. The adoption of a new policy is subject to a rulemaking proceeding at the Springerville Generating Station (Springerville Coal Handling Facilities) under two separate lease agreements (Springerville Coal Handling Facilities Leases). The lease agreements have an initial term that expires in April 2015 and provide TEP the option to renew the leases or to purchase the leased interests at the aggregate fixed price of $120 million.
In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, in April 2014, TEP recorded an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment.

30



Upon TEP’s purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities.
Sales to Mining Customers
Some of 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 over the next several years. The market price for copper and the ability to obtain necessary permits could affect mining industry expansion plans.
In addition to the mining customers that TEP currently serves, the proposed Rosemont Copper Mine near Tucson, Arizona is in the final stages of permitting. 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.
ACC. TEP cannot predict ifthe outcome of this proposal or when existing minesthe impact on the Company's financial position or results of operations.
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. We are currently recovering Navajo capital and operating costs in base rates using a useful life through 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV, and other related costs, were reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017. We plan to seek recovery of all unrecovered costs in our next ACC rate case. See Note 2 for additional information related to the planned early retirement of Navajo.
Sundt Generating Station
In 2017, TEP submitted an Application to the PDEQ related to a generation modernization project at Sundt. In conjunction with the project, TEP will expand operations or new or re-opened mines will commence operations.discontinue operation of Sundt Units 1 and 2 by the end of 2020. As a result of the planned early retirement, $31 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017. We plan to seek recovery of all unrecovered costs in our next ACC rate case. See Note 2 for additional information regarding the 2017 Rate Order.
Springerville Units 3 and 4
TEP receives annual benefitsUnder the project outlined in the formApplication, TEP will invest in 190 MW of rental paymentsRICE generators scheduled for commercial operation between June 2019 through March 2020. The RICE generators balance the variability of intermittent renewable energy resources and other feeswill replace 162 MW of nominal net generating capacity from Sundt Units 1 and cost savings from operating Springerville Unit 3 on behalf2, which are less efficient and lack the quick start, fast ramp capabilities of Tri-State and Unit 4 on behalf of SRP.
The table below summarizes the income statement line items in which TEP records revenues and expensesRICE generators. See Note 2 for additional information related to Springervillethe planned early retirement of Sundt Units 31 and 4:2.

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 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Other Revenues$112
 $102
 $101
Fuel Expense(5) (7) (7)
O&M Expense(84) (69) (72)
Taxes Other Than Income Taxes(1) (2) (1)

Gila River Generating Station
In 2017, TEP entered into a 20-year Tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2 (Tolling PPA). TEP’s obligations under the Tolling PPA are contingent upon SRP's acquisition of Gila River Units 1 and 2. In October 2017, SRP entered into a separate agreement with a third party to acquire Gila River Units 1 and 2 that is expected to be completed by March 2018 (Gila Acquisition). If the Gila Acquisition is terminated for any reason, either TEP or SRP may terminate the Tolling PPA without cost or penalty by providing written notice to the other party. The Tolling PPA provides TEP with an option to purchase Gila River Unit 2 during a three-year period beginning on the date the Gila Acquisition is completed. TEP's purchase option price for Gila River Unit 2 is expected to be $165 million, but is dependent upon SRP's final purchase price. The Tolling PPA will replace coal-fired generation scheduled for early retirement and provide near term opportunities for sales into the wholesale market.
Long-Term Wholesale Sales
Navopache Electric Cooperative
In January 2017, a new long-term contract between TEP and NEC became effective. The contract expires at the end of 2041. TEP served 80% of NEC’s load requirements in 2017 and expects to serve 100% beginning in 2018. In 2017, revenues from the NEC contract accounted for 8% of total Wholesale Revenues on the Consolidated Statements of Income.
Interest Rates
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk.of this Form 10-K for information regarding interest rate risks and its impact on earnings.
Fair Value Measurements
See Note 10 of Notes to Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Cash flows may vary during the year with cash flowflows from operations typically the lowest in the first quarter of the year and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEPWe will use as needed, itsour revolving credit facility as needed to assist in funding its business activities. The table below provides a summary of our liquidity position:
 As of December 31, 2014
 Millions of Dollars
Cash and Cash Equivalents$74
Borrowings under Revolving Credit Facilities(1)
85
Amount Available under Revolving Credit Facilities185
(1)
Includes an LOC issued under the 2010 Credit Agreement.

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Short-term Investments
TEP’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, 2014, TEP's short-term investments included highly-rated and liquid money market funds.
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 with various expiration dates. The 2014 revolving credit facility may be used for revolving borrowings. The 2010 revolving credit facility may be used for revolving borrowings as well as to issue trade LOCs. TEP issues LOCs from time to time to provide credit enhancement to counterparties for its energy procurement and hedging activities.
Liquidity Outlook
We believe that we have sufficient liquidity under our revolving credit facilitiesfacility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. However,The availability and terms under which TEP will needhas access to issue additional long-termexternal financing depends on a variety of factors, including its credit ratings and conditions in the overall capital markets.
Available Liquidity
(in millions)December 31, 2017
Cash and Cash Equivalents$38
Amount Available under Revolving Credit Facility (1)
215
Total Liquidity$253
(1)
TEP's revolving credit facility provides for $250 million of revolving credit commitments and a Letter of Credit (LOC) sublimit of $50 million. TEP requested and was granted two one-year extensions. The new maturity date is October 2022.
Future Liquidity Requirements
We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to dividend payments, debt by April 2015maturities, and obligations as detailed in order to complete the purchase of the Springerville Coal Handling Facilities Contractual Obligations and to ensure adequate revolving credit capacity through the second and third quarters of 2015. Further, TEP will need to issue additional debt by November 2015 to repay amounts borrowed under the 2014 Credit Agreement. forecasted Capital Expenditures tablesbelow.
See Part III, Item 7A7A. Quantitative and Qualitative Disclosures about Market Risk.for additional information regarding TEP's market risks and Note 6of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP's financing arrangements.

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Summary of Cash Flows
Effective December 31, 2017, TEP early adopted accounting guidance that requires entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents on the cash flow statement. The new accounting guidance is applied retrospectively affecting all periods presented. The table below incorporates the new accounting guidance and presents net cash provided by (used for) operating, investing and financing activities:activities and its effect on cash, cash equivalents, and restricted cash:
 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)$314
 $346
 $268
Net Cash Flows – Investing Activities (GAAP)(518) (260) (228)
Net Cash Flows – Financing Activities (GAAP)253
 (141) 12
Net Increase (Decrease) in Cash49
 (55) 52
Beginning Cash25
 80
 28
Ending Cash$74
 $25
 $80
 Years Ended 
Increase
(Decrease)
 Year Ended 
Increase
(Decrease)
(in millions)2017 2016 Percent 2015 Percent
Operating Activities$448
 $425
 5.4 % $365
 16.4 %
Investing Activities(392) (373) 5.1 % (501) (25.5)%
Financing Activities(50) (69) (27.5)% 120
 *
Net Increase (Decrease)6
 (17) *
 (16) 6.3 %
Beginning of Period43
 60
 (28.3)% 76
 (21.1)%
End of Period (1)
$49
 $43
 14.0 % $60
 (28.3)%
The table below shows TEP's net cash flows after capital expenditures and payments on capital lease obligations, net of payments received on lease debt previously held by TEP:
 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)$314
 $346
 $268
Less: Capital Expenditures(1)
(507) (253) (253)
Net Cash Flows after Capital Expenditures (Non-GAAP)(2)
(193) 93
 15
Less: Payments of Capital Lease Obligations(165) (100) (89)
Plus: Proceeds from Investment in Lease Debt
 9
 19
Net Cash Flows after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (Non-GAAP)(2)
$(358) $2
 $(55)
* Not meaningful
(1) 
Includes the purchase of Gila River Unit 3 ($164 million)Calculated on rounded data and Springerville Unit 1 Leased Assets ($20 million) separately presentedmay not tie to amounts on the Consolidated Statements of Cash Flow Statement.Flows.
(2)
Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations, Net of Payments Received on Lease Debt, 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 Capital Lease Obligations, Net of Payments Received on Lease Debt provide useful information as measures of TEP’s ability to fund
Operating Activities
2017 compared with 2016
In 2017, net cash flows provided by operating activities increased by $23 million compared with 2016 primarily due to: (i) higher net income related to an increase in rates as approved in the 2017 Rate Order and an increase in residential usage due to favorable weather; and (ii) $8 million in cash proceeds received in January 2017 from a settlement agreement.
The increase was partially offset by: (i) an ACC approved PPFAC credit that began returning a temporary over-collected PPFAC balance to customers in February 2017; (ii) $12.5 million received in September 2016 related to a settlement for operating costs of Springerville Unit 1 not occurring in 2017; and (iii) changes in working capital requirements and make required payments on capital lease obligations before consideration of financing activities.

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TEP had unusually large expenditures in 2014 related to the purchasetiming of both Gila Riverbilling collections and payments.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, 2017 Rate Order and Note 7, FERC Matters and Claims Related to Springerville Generating Station Unit 3 and Springerville Unit 1 leased assets. Additionally, the structure of our Springerville Unit 1 Leases, that expired on January 1, 2015, required disproportionately large lease payments in 2014. Our capital requirements were met for additional information.
2016 compared with a combination of equity contributions from UNS Energy and long-term borrowings as discussed in Financing Activities below. As shown in our forecasted capital expenditures table below, TEP expects capital requirements to remain high in 2015 and then taper off in 2016 through 2019. We expect to issue new long-term debt in 2015 to meet our capital requirements.
Operating Activities
2014 Compared with 2013
In 2014,2016, net cash flows fromprovided by operating activities were $32increased by $60 million lower compared with 2013. The decrease was2015 primarily due primarily to: $15 million of merger-related costs; $12 million of increased incentive compensation payments; and an increase of $6 million of capital lease interest paid.
2013 Compared with 2012
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 ofto a: (i) over-collected fuel and purchased power costs under the PPFAC mechanism; (ii) decrease in cash paid resulting from a base rate increase that became effective on July 1, 2013, anfor pension and other postretirement benefits funding; (iii) $12.5 million increase in retail sales volumes,cash proceeds related to the settlement of operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners; and an(iv) change in working capital related to the timing of billing collections and payments.
The 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 generating stations; and a $6 million decrease in capital lease interest paid due to a decline in capital lease obligation balances;was partially offset by an increase of $11 million in cash paid for incentive compensation in 2016 not occurring in 2015. As a $6 million increaseresult of the Fortis acquisition in wages2014, payments scheduled to be paid (netin the first quarter of amounts capitalized).2015 under the annual incentive compensation plan were accelerated and paid in the third quarter of 2014.
Investing Activities
2014 Compared2017 compared with 20132016
NetIn 2017, net cash flows used for investing activities increased by $258$19 million in 2014 compared with 20132016 primarily due primarily to:to an increase in cash paid for capital expenditures and for the purchase of a 75% interestRECs.
See Note 6 of Notes to Consolidated Financial Statements in Gila River Unit 3Part II, Item 8 of this Form 10-K for $164 million; the purchaseadditional information on Springerville capital lease purchases.

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2016 compared with 20122015
NetIn 2016, net cash flows used for investing activities increaseddecreased by $32$127 million in 2013 compared with 20122015 primarily due primarily to:to a $14 milliondecrease in cash paid for capital expenditures including generation assets and construction costs in 2015 for a new 500kV transmission line not occurring in 2016.
The decrease was partially offset by: (i) cash proceeds received in 2015 from the sale of an undivided ownership interest in Springerville Coal Handling Facilities not occurring in 2016; and (ii) an increase in purchasescash paid in 2016 for the purchase of RECsRECs.
Financing Activities
2017 compared with 2016
In 2017, net cash flows used for financing activities decreased by $19 million compared with 2016 primarily due to an increase in renewable energy PPAs; and $10proceeds borrowed, net of repayments, under our revolving credit facility. The decrease was partially offset by an increase in dividends paid to UNS Energy.
2016 compared with 2015
In 2016, net cash flows provided by financing activities decreased by $189 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:
 2015 2016 2017 2018 2019
 Millions of Dollars
Transmission and Distribution$211
 $102
 $86
 $89
 $100
Generation Facilities96
 74
 100
 72
 44
Renewable Energy Generation27
 35
 29
 29
 29
Springerville Lease Purchases(1)
119
 
 38
 
 
General and Other55
 41
 41
 41
 52
Total Capital Expenditures$508
 $252
 $294
 $231
 $225
(1)
Includes: Springerville Unit 1 lease interest purchase of $46 million in 2015; TEP's portion of the Springerville Coal Handling facilities purchase of $73 million (net of expected reimbursements from Tri-State and SRP) in 2015; and Springerville Common facilities purchase of $38 million in 2017.
These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimatescompared with 2015 primarily due to changes in business conditions, construction schedules, environmental requirements, state or federal regulations and other factors.

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Financing Activities
2014 Compared with 2013
In 2014, neta decrease in: (i) cash from financing activities was $394 million higher than the same period last year due to: proceeds received from the issuance of $149 millionlong-term debt and term loans, net of repayments made; and (ii) equity contributions from UNS Energy. Proceeds received in 2015 were used to purchase or retire certain tax-exempt long-term debt; an $85 million increase in borrowings (net of repayments) under TEP's revolving credit facilities; and $225 million of UNS Energy equity contributions;debt. The decrease was partially offset by a $66 million increasedecrease in paymentscash paid in 2016, net of capital lease obligations.proceeds borrowed, under our revolving credit facilities.
Following completionSee Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, Debt Issuance and Redemption for additional information.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the Merger, Fortis made equityinvestment of excess cash balances. We periodically review and update this policy in response to market conditions. As of December 31, 2017, TEP's short-term investments in UNS Energy totaling $287 million. UNS Energy then contributed a total of $225 millionincluded highly-rated and liquid money market funds.
Access to TEP. These equity investments in TEP helped fund the Gila River Unit 3 and Springerville Unit 1 purchase commitments.
2013 Compared with 2012
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.Facility
Credit Agreements
2014 Credit Agreement
In December 2014, TEP entered into an unsecuredWe have access to working capital through a revolving credit agreement (2014 Credit Agreement). The 2014 Credit Agreement provides for a $130 million term loan commitment and a $70 million revolving credit commitment. In January 2015,with lenders. TEP expects that amounts borrowed under the term loan commitment werecredit agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of December 31, 2017, $215 million was available under the revolving credit commitments and LOC facility. As of February 14, 2018, $232 million was available under the revolving credit commitments and LOC facility.
For details of TEP's credit facility see Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.
In 2016, the ACC issued an order granting TEP financing authority. The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority.
We anticipate raising additional capital in the second half of 2018 to: (i) refinance tax-exempt local furnishing bonds that are subject to mandatory tender for purchase existing Pima County, Arizonain November 2018; (ii) refinance callable tax-exempt pollution control bonds backed by an LOC which expires in February 2019; and (iii) ensure adequate revolving credit capacity. TEP has, from time to time,

26


refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, TEP may refinance other debt issuances or make additional debt repurchases in the future.
In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt industrial development revenue bonds (IDBs)Industrial Development Revenue Bonds issued in June 2008 by the Industrial Development Authority of Pima County, Arizona for the benefit of TEP in the amount of $130 million. The 2014 Credit Agreement expires in November 2015.
The 2014 Credit Agreement contains substantially the same restrictive covenants as the 2010 Credit Agreement described below. At December 31, 2014, TEP was in compliance with the terms of the 2014 Credit Agreement. See Note 5 of Notes to Consolidated Financial Statements.
At December 31, 2014, TEP had $70 million borrowings at an interest rate of 0.750% under the 2014 Credit Agreement revolving credit facility and no borrowings under the term loan portion of the 2014 Credit Agreement.
2010 Credit Agreement
The 2010 Credit Agreement consists of a $200 million revolving credit, revolving LOC facility and an $82 million LOC facility to support tax-exempt bonds. The 2010 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, 2014, therebonds were $15 million in borrowings outstanding and less than $1 million of LOCs issued under the 2010 Credit Agreement.
not remarketed. The 2010 Credit Agreement contains restrictions on mergers and sales of assets. The 2010 Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the 2010 Credit Agreement, TEP may pay dividends to UNS Energy subject to the terms of the merger order issued by the ACC in August 2014. At December 31, 2014, TEP was in compliance with the terms of the 2010 Credit Agreement. See Note 5 of Notes to Consolidated Financial Statements.
2010 Reimbursement Agreement
In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 Reimbursement Agreement). A $37 million LOC was issued pursuant to the 2010 Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt pollution controlmulti-modal bonds that were issued on behalf of TEP in December 2010.
In February 2014, TEP amended the 2010 Reimbursement Agreement to extend the expirationhad an original maturity date of September 2029. In September 2017 the LOCbonds were retired.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. In April 2017, S&P Global Ratings upgraded TEP’s credit rating on senior unsecured debt to A- from 2014 to 2019.

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The 2010 Reimbursement Agreement contains substantially the same restrictive covenants as the 2010 Credit Agreement described above. At December 31, 2014, TEP was in compliance with the terms of the 2010 Reimbursement Agreement.
2014 Bond Issuances and Redemptions
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may redeem the notes prior to September 2043, with a make-whole premium plus accrued interest. After September 2043, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the outstanding borrowings under the 2010 Credit Agreement with the remaining proceeds used for general corporate purposes. See Note 5 of Notes to Consolidated Financial Statements.
Capital Lease Obligations
At December 31, 2014, TEP had $243 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 LeasesDecember 31, 2014 Expiration Renewal/Purchase Option
 Millions of Dollars    
Springerville Unit 1(1)
$43
 2015 Fair market value
Springerville Coal Handling Facilities117
 2015 
Fixed price purchase
option of $120 million(2)
Springerville Common Facilities(3)
83
 2017 and 2021 
Fixed price purchase
option of $106 million(3)
Total Capital Lease Obligations$243
    
(1)
The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. The $43 million balance represents the lease purchase options that were completed in January 2015.BBB+. As of January 1, 2015 there is no capital lease obligation balance related to Springerville Unit 1.
(2)
The $117 million balance represents the present value of the lease purchase options elected in April 2014. Upon TEP’s purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. See Item 7. Management's Discussion and Analysis of Financial Condition and Factors Affecting Results of Operations, Springerville Coal Handling Facilities Capital Lease Purchase Commitment. Also see Note 5 of Notes to Consolidated Financial Statements.
(3)
The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities.
Our capital lease obligation balances decline over time as scheduled capital lease payments are made by TEP.

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Contractual Obligations
The following chart displays TEP’s contractual obligations by maturity and by type of obligation as of December 31, 2014:
2017, the credit rating remained unchanged. As of December 31, 2017, Moody’s Investors Service credit ratings for TEP’s senior unsecured debt was A3.
Payment Due in Years Ending December 31,2015 2016 2017 2018 2019 Thereafter Other Total
 Millions of Dollars
Long-Term Debt               
Principal(1)
$
 $79
 $
 $100
 $37
 $1,159
 $
 $1,375
Interest(2)
58
 59
 59
 59
 56
 554
 
 845
Capital Lease Obligations(3)
188
 16
 18
 11
 12
 18
 
 263
Operating Leases:(4)
               
Land Easements and Rights-of-Way2
 1
 1
 1
 2
 77
 
 84
Operating Leases Other1
 1
 1
 1
 1
 5
 
 10
Purchase Obligations:               
Fuel(5)
76
 78
 76
 49
 49
 285
 
 613
Purchased Power22
 7
 
 
 
 
 
 29
Transmission6
 6
 6
 6
 4
 16
 
 44
Renewable Power Purchase Agreements(6)
45
 45
 45
 45
 44
 565
 
 789
RES Performance-Based Incentives(7)
8
 8
 8
 8
 8
 76
 
 116
Acquisition of Springerville Common Facilities(8)

 
 38
 
 
 68
 
 106
Other Long-Term Liabilities:(9)
               
Pension & Other Post Retirement Obligations(10)
30
 6
 6
 6
 7
 37
 
 92
Unrecognized Tax Benefits
 
 
 
 
 
 4
 4
Total Contractual Obligations$436
 $306
 $258
 $286
 $220
 $2,860
 $4
 $4,370
(1)
Certain of TEP’s variable rate IDBs or pollution control revenue bonds are secured by LOCs issued pursuant to the 2010 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 2010 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 $2 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 commitments for Springerville Unit 1 in January 2015 and Springerville Coal Handling Facilities at the expiration of the lease term in April 2015. 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)
TEP's operating lease expense is primarily for rail cars, office facilities, land easements, and rights-of-way with varying terms, provisions, and expiration dates.
(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 6 of Notes to Consolidated Financial Statements.
(6)
TEP has entered into 20-year PPAs with renewable energy generation producers to comply with the RES tariff. TEP is 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 has entered into additional long-term renewable PPAs to comply with the RES; however, TEP's obligations to accept and pay for electric power under these agreements does not begin until the facilities are operational.
(7)
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance Based Incentives (PBIs) and are paid in contractually agreed upon

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intervals (usually quarterly) basedTEP's credit ratings are dependent on metered renewable energy production. PBIsa number of factors, both quantitative and qualitative, and are recoverable through the RES tariff. See Note 2subject to change at any time. The disclosure of Notesthese credit ratings is not a recommendation to Consolidated Financial Statements.
(8)
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 its fixed-price purchase options.
(9)
Excludes asset retirement obligations expected to occur through 2066.
(10)
These obligations represent TEP’s expected contributions to pension plans in 2015, expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP), and expected retiree benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. Due to the significant impact that returns on plan assets and changes in discount rates might have on payment obligation amounts, other contributions are excluded beyond 2015.
We have reviewed our contractual obligations and provide the following additional information:buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.
The 2010 Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants AgreementCertain of TEP's debt agreements 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
Debt Covenants
Under certain agreements, should TEP fail to borrow under its revolving credit facilities.
The 2014 Credit Agreement, the 2010 Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement contain certain financial and other restrictivemaintain compliance with covenants, including a leverage test. Failure to comply with these covenants would entitle the lenders tocould accelerate the maturity of all amounts outstanding. AtAs of December 31, 2014,2017, TEP was in compliance with these covenants. See Credit Agreements, 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 a 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, 2014, TEP had posted less than $1 million in LOCs for credit enhancement with wholesale counterparties.
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.
Contribution from Parent
TEP received no equity contributions in 2017 and 2016. UNS Energy made an equity contribution to TEP of $180 million in 2015. The contributions were used to repay revolving credit loans, redeem bonds, and provide additional liquidity to TEP.
Dividends on Common StockPaid to Parent
In 2014, TEP declared and paid $70 million in dividends to UNS Energy of $40 million. TEP paid dividends to UNS Energy of $40in 2017 and $50 million in 20132016 and $302015.
Master Trading Agreements
TEP conducts its wholesale marketing and risk management activities under certain master agreements. Under these agreements, 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, changes in TEP’s credit ratings, or material changes in TEP’s creditworthiness. As of December 31, 2017, TEP had posted no cash or LOCs as credit enhancements with its counterparties.
Capital Expenditures
TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In 2017, total capital expenditures of $346 million, included the purchase of an additional 17.8% undivided interest in 2012.
The approvalSpringerville Common Facilities. In 2016, total capital expenditures of $335 million, included the purchase of the Merger contains a condition restricting subsidiary dividend payments to UNS Energy by TEP to no more than 60 percent of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reaches 50 percent ofremaining ownership interest in Springerville Unit 1. In 2015, total capital expenditures of $500 million, included the purchase of an undivided ownership interest in Springerville Unit 1 and the remaining ownership interest in the Springerville Coal Handling Facilities.

27


We expect capital requirements to increase in 2018 and 2019 to reflect our investment in generating assets and an enhanced metering and distribution network. Capital requirements are expected to level off from 2020 through 2022 as accountedwe focus on sustaining operations and renewable energy. Our forecasted capital expenditures presented below for years ended December 31 exclude amounts for AFUDC and other non-cash items:
(in millions)2018 2019 2020 2021 2022
Generation Facilities:         
Renewable Energy$11
 $18
 $5
 $108
 $
Other Generation Facilities163
 284
 79
 75
 51
Total Generation Facilities174
 302
 84
 183
 51
Transmission and Distribution194
 184
 202
 167
 152
General and Other (1)
99
 88
 67
 96
 65
Total Capital Expenditures$467
 $574
 $353
 $446
 $268
(1)
Includes cost for information technology, fleet, facilities, and communication equipment.
These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in accordancebusiness and market conditions, construction schedules, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, and other factors. We expect to pay for forecasted capital expenditures with GAAP. internally generated funds and external financings, which may include issuances of long-term debt or other borrowings.
Contractual Obligations
The ratios usedfollowing table summarizes our material contractual obligations as of December 31, 2017:
   Payments Due by Period
(in millions)Total Less than 1 Year 1-3 Years 3-5 Years More than 5 Years
Long-Term Debt
        
Principal (1)
$1,466
 $100
 $117
 $250
 $999
Interest (2)
650
 60
 115
 95
 380
Capital Lease Obligations (3)
42
 12
 30
 
 
Operating Leases (4)
8
 1
 2
 2
 3
Land Easements and Rights-of-Way (5)
89
 1
 3
 3
 82
Purchase Obligations:
        
Fuel, Including Transportation (6)
549
 82
 156
 67
 244
Purchased Power29
 29
 
 
 
Transmission59
 19
 27
 5
 8
Renewable Purchase Power Agreements (7)
985
 64
 127
 126
 668
RES Performance-Based Incentives (8)
83
 8
 15
 14
 46
Acquisition of Springerville Common Facilities (9)
68
 
 
 68
 
Other Long-Term Liabilities: (10) (11)

        
Restricted and Performance-Based Stock Units8
 2
 6
 
 
Pension and Other Postretirement Benefits (12)
78
 17
 12
 13
 36
Total Contractual Obligations$4,114
 $395
 $610
 $643
 $2,466
(1)
$37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in February 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate Industrial Development Revenue Bonds (IDRB), which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018. The bonds

28


were reclassified to determineCurrent Maturities of Long-Term Debt on the dividend restrictions will be calculated for each calendar year and reportedConsolidated Balance Sheets in 2017. Total long-term debt is not reduced by $10 million of related unamortized debt issuance costs or $2 million of unamortized original issue discount.
(2)
Excludes interest on revolving credit facilities and includes interest on TEP's 2013 tax-exempt IDRBs through the end of the current five-year term.
(3)
Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP began reimbursing TEP for various operating costs related to the common facilities on an ongoing basis. The common facilities include assets leased by TEP at Springerville. TEP was reimbursed for $9 million of operating costs in 2017 by SRP and Tri-State and expects to be reimbursed $8 million of operating costs in 2018. Capital Lease Obligations do not reflect any reduction associated with this reimbursement. Our capital lease obligation balances decline over time as scheduled capital lease payments are made by TEP.
(4)
Primarily represents leases for land, rail cars, and office facilities with varying terms, provisions, and expiration dates through 2036.
(5)
Have varying terms and provisions and reflect expiration dates through 2054. In November 2017, the Navajo Nation approved an extension for the use of their land that commences in December 2019 and ends in December 2054. The Navajo Nation has until December 2018 to select one of five different rental payments options provided for in the extension. The table above includes TEP's 7.5% ownership share of the option which, in management's opinion, is most probable to occur. The total obligation estimated under this option is $8 million commencing in 2019 through 2053. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Land Easements and Rights-of-Way.
(6)
Excludes TEP’s liability for final mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate as the timing of payments has not been determined. In January 2018, TEP entered into a transportation agreement with EPNG to extend the expiration date of the existing agreement from April 2018 to April 2023. Estimated future payments not included in the table above are: $4 million in 2018; $5 million in 2019 through 2022; and $1 million through the end of the contract. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP’s share of reclamation costs.
(7)
TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. While TEP is not required to make payments under these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PPAs.
(8)
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBI) and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PBIs.
(9)
In December 2017, TEP purchased one of the Springerville Common Facilities Leases that had an initial term ending December 2017. The remaining two leases have an initial term ending January 2021, subject to optional renewal periods of two or more years. TEP may renew the two leases or exercise its remaining fixed-price purchase options. See Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Springerville Common Facilities Leases.
(10)
Excludes Asset Retirement Obligations (ARO) of $46 million expected to occur through 2044.
(11)
Excludes unrecognized tax benefits of $13 million. At this time, we are unable to make a reasonably reliable estimate of the timing of payments in individual years in connection with these tax liabilities.
(12)
Represents TEP’s expected contributions to pension plans in 2018, expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP), and expected other postretirement benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. Due to the significant impact that returns on plan assets and changes in discount rates might have on payment obligation amounts, other contributions beyond 2018 are excluded.
Off-Balance Sheet Arrangements
Other than the ACC annually beginning on April 1, 2016.unrecorded contractual obligations in the table above, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.
Income Tax Position
The 2010 Federal Tax Relief Act, the American Taxpayer Relief Act of 2012, and the Tax Increase Prevention Act of 2014 includelegislation previously in effect included provisions that makemade qualified property placed in service betweenstarting in 2010 and 2014 eligible for bonus depreciation for tax purposes. In addition, the IRS had issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions arewere an acceleration of tax benefits TEPwe otherwise would have received over 20 years and have created net operating loss carryforwards that can becould have been used to offset future taxable income. As a result, TEPwe did not pay any federal or state income taxes in 20142017. Under the TCJA, we will not be eligible for bonus depreciation

29


for property placed in service after 2017, which will accelerate utilization of net operating loss carryforwards. We offset net operating loss carryforwards against taxable income and doesdo not expect to make anyfederal or state income tax payments until 2019.2020.
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. Any decrease in rates charged to customers related to the TCJA would have a negative impact on TEP's operating cash flows. On February 6, 2018, the ACC ordered utilities to file within 60 days either: (i) an application for a tax adjustor mechanism; (ii) an intent to file a rate case within 90 days; or (iii) any other application to address the effects of the TCJA. TEP expects to file a tax adjustor proposal with the ACC prior to the deadline. TEP cannot predict the outcome of these proceedings or the impact on the Company's financial position or results of operations.
Environmental Matters
The EPA regulates the amount of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs.
We capitalized $33 million in 2017, $40 million in 2016, and $33 million in 2015 in costs incurred to comply with environmental rules and regulations. In addition, we recorded operations and maintenance expenses of $5 million in 2017 and $6 million in 2016 and 2015. We expect capital expenditures of $9 million in 2018 and do not expect capital expenditures to be material in years 2019 through 2022. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls 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 land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these generation facilities.
In the western United States, Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). The BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s, after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reductions are not likely to impact Springerville operations until after 2021. In December 2016, the EPA signed a final rule, entitled "Protection of Visibility: Amendments to Requirements for State Plans." Among other things, the rule changes the date for submittal of the next Regional Haze implementation plan from 2018 to 2021. Based on recent Regional Haze requirement time-frames, TEP anticipates that impacts, if any, to Springerville will likely occur three to five years after the 2021 plan submittal date. TEP cannot predict the ultimate outcome of these matters.
Sundt Generating Station
TEP permanently eliminated coal as a fuel source at Sundt to comply with a EPA ruling related to BART.
Four Corners Generating Station
In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy. As a result, APS closed Units 1, 2, and 3 in December 2013 and agreed to install SCR on Units 4 and 5. TEP owns 7% of Four Corners Units 4 and 5. TEP's estimated share of NOx emissions control costs to comply with the rules is $44 million in capital expenditures and $2 million in annual operations and maintenance expenses. The SCR projects are scheduled to be completed by July 2018.
Navajo Generating Station
In August 2014, the EPA published a final Federal Implementation Plan (FIP) which provides that one unit at Navajo will be shut down by 2020, SCR or the equivalent will be installed on the remaining two units by 2030, and conventional coal-fired generation will cease by December 2044. The final BART rule includes options that accommodate potential ownership changes at the facility. The facility has until December 2019 to notify the EPA of how it will comply with the FIP.

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In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. As a result of the early retirement of Navajo, TEP and the co-owners will no longer be responsible for implementing the FIP. See Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the early retirement of Navajo.
San Juan Generating Station
In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which included: (i) the closure of Units 2 and 3 by December 2017; and (ii) the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4. TEP owns 50% of Units 1 and 2. PNM, the operator of San Juan, completed the installation of SNCR in February 2016 and ceased operations at Units 2 and 3 in December 2017.
In 2017, TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. See Note 2 and Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K foradditional information on the early retirement of San Juan Unit 2.
Greenhouse Gas Regulation
In August 2015, the EPA issued the CPP limiting CO2 emissions from existing and new fossil fueled generation facilities. The CPP establishes state-level CO2 emission rates and mass-based goals that apply to fossil fuel-fired generation. The plan targets CO2 emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.
In October 2017, the EPA issued a proposal to repeal the CPP and in December 2017, the EPA issued an Advance Notice of Proposed Rulemaking (ANPRM) soliciting information about the intent to replace the CPP with a rule establishing new emissions guidelines. TEP will continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop appropriate responses to the EPA's proposals and compliance strategies as needed. TEP is unable to determine the impact to its facilities until all legal challenges have been resolved and any new regulations have been promulgated.
Coal Combustion Residuals Regulation
In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residuals to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA Subtitle D) for disposal in landfills and/or surface impoundments. We estimate our share of costs to comply to be $2 million at Springerville. The majority of the costs are capital expenditures associated with site preparation and installation of the groundwater monitoring well system. We also expect to incur additional operating costs for on-going groundwater monitoring and eventual site closure activities. Similarly, we currently estimate our share of costs to be $5 million at Four Corners, $3 million at Navajo, and less than $1 million at San Juan, the majority of which are capital expenditures.
In December 2016, Congress approved the Water Infrastructure Improvements for the Nation Act which authorizes the States to establish permit programs under RCRA Subtitle D for implementing regulation for Coal Combustion Residuals (CCR). TEP is currently working with other affected utilities and the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.
See Capital Expenditures above for TEP's forecasted environmental compliance costs.
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

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subsequent periods. Additional information on TEP’s other significant accounting policies can be found in Note 1 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K.
Accounting for Regulated Operations
We account for our regulated electric operations based onin accordance with 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.Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities

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generally represent expected future costs that have already been collected from customers.customers or amounts that are expected to be returned to customers through billing reductions in future periods. 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,operations, financial position, and future cash flows could be material.
AtAs of December 31, 2014,2017, regulatory liabilities net of regulatory assets on the balance sheet totaled $68 million at TEP.$218 million. There are no current or expected proposals or changes in the regulatory environment that impact our ability to apply accounting guidance for regulated operations. 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 statement, both of which would be material to our financial statements. See Note 2 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K for additional information regarding regulatory matters.
Accounting for Asset Retirement Obligations
We are requiredGAAP requires us 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 regulations imposed by State and other governmental regulations,Federal regulators, 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,AROs. TEP began deferringprimarily defers costs associated with the majority of its legal AROs as regulatory assets because newthese costs are included in depreciation rates approved infor recovery by the 2013 TEP Rate Order include these costs.ACC. 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 assetsfacilities specified in land leases for its jointly-owned Navajo and Four Corners generating stations. The land on which thesefacilities. These stations reside ison land leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Additionally, TEP entered into ground lease agreements with certain land owners for the installation of photovoltaic (PV) assets. The provisions of the PV ground leases require TEP to remove the PV facilities upon expiration of the leases. TEP's ARO related to the PV assets is estimated to be approximately $30 million at the retirement dates. TEP also has certain environmental obligations at the Luna, San Juan, Sundt and Springerville Generating Stations.Springerville. TEP estimates that its share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt, Gila River, and Springerville environmental and contractual obligations will be approximately $164$155 million at the retirement dates. Additionally, TEP entered into land lease agreements or land easement agreements with certain land owners for the installation of PV assets. The provisions of the PV land leases or land easements require TEP to remove the PV facilities upon expiration of the agreements. In December 2014,addition, TEP purchased Gila River Unit 3is required to dispose or recycle the PV assets under the Resource Conservation and assumed anRecovery Act. TEP's ARO obligation. The environmental obligations related to Gila River willthe PV assets is estimated to be approximately $4$31 million at the retirement date.dates. No other legal obligations to retire generation plant assets werehave been identified.
TEP has various transmission and distribution lines that operate under leasesland easements and rights-of-way that contain end dates and may contain site restoration clauses. TEP operates transmission and distribution lines as if they will be operated in perpetuity and wouldwill continue to be used or sold without land remediation. As such, there are no AROs for these assets.
The total net present value of TEP's ARO liability was $28$46 million atas of December 31, 2014.2017. ARO liabilities are reported in Deferred CreditsRegulatory and Other Liabilities—Other on the balance sheet.Consolidated Balance Sheets. See Note 3 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.

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Additionally, the authorized depreciation rates for TEP include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances atas of December 31, 20142017, represent non-legal asset retirement obligationARO accruals, less actual removal costs incurred, net of salvage proceeds realized, and are included in Deferred Credits and Other Liabilities, Regulatory Liabilities – Noncurrentrecorded as a regulatory liability on the balance sheet. See Note 2 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K for additional information regarding future cost of removal.
Pension and Other RetireePostretirement Benefit Plan Assumptions
TEP records 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 8 of Notes to Consolidated Financial Statements discusses the assumptions used in the calculation of pension plan and other retiree plan obligations.
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 retireepostretirement obligations as a liability and a regulatory asset to reflect expected recovery of pension and other retireepostretirement obligations through the rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability may vary significantly in future years. Key assumptions used include:
discount rates used to determine obligations;

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expected returns on plan assets;
compensation increases;
mortality assumptions; and
healthcare cost trend rates.
Discount Rates
AtAs of December 31, 2014,2017, TEP discounted its future pension plan obligations at between 4.1% and 4.2%3.7% and its other retireepostretirement plan obligations at a rate of 3.9%3.6%. The discount rate for future pension plan and other retireepostretirement 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 60th and 90th 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 $14 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 and increase or decrease plan expense by less than $0.5 million.
TEP calculates the market-related value of pension plan assets using the fair value of the assetsExpected Returns on the measurement date. TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7% at December 31, 2014. In establishing its assumption as toPlan Assets
To establish the expected return on assets assumption, 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 expectedAs of December 31, 2017, TEP assumed that its pension plans’ assets would generate a long-term rate of return on assets increases. A 25-basis point change in the expected return on assets would impactof 7%.
Compensation Increases
As of December 31, 2017, TEP used a rate of compensation increase of 2.75% to measure pension expense in 2014 by $1 million.obligations.
TEP selected the RP-2000Mortality
The RP-2014 mortality table projected with Scale BBimprovement scale MP-2017 with 15-year convergence and 0.75% long-term rate was utilized to measure the December 31, 20142017 pension obligations, whereas Scale AAimprovement scales MP-2016 was utilized for the December 31, 20132016 measurement. TEP moved to Scale BB because Scale AA has lagged general US mortality since 2000. The longer life expectancy assumption results in a greater obligation and expense.
Healthcare Cost Trend Rates
TEP used a current year health carehealthcare cost trend rate of 6.7%7.6% in valuing its retireeother postretirement benefit obligation atas of December 31, 2014.2017. This rate reflects both market conditions and historical experience. Assumed health care cost trend rates have a significant
Sensitivity Analysis
The table below shows the effect on the amounts reported for health care plans. A one-percentageTEP's 2017 expense and obligation of a 100 basis point change in assumed health care cost trend rates would change the retiree benefit obligation by an approximately $7 million increase or $6 million decrease and change the related 2015 plan expense by $1 million.to its assumptions:
 Effect on Expense Effect on Obligation
 Increase Decrease Increase Decrease
(in millions)December 31, 2017
Change to Pension       
Discount Rate$(6) $7
 $(65) $83
Long-Term Rate of Return on Plan Assets(4) 4
 N/A
 N/A
Change to Other Postretirement Benefits       
Discount Rate
 1
 (8) 10
Long-Term Rate of Return on Plan Assets
 
 N/A
 N/A
Healthcare Cost Trend Rate1
 (1) 7
 (6)
In 2015,2018, TEP will incur pension costs of approximately $13$10 million and other retireepostretirement benefit costs of approximately $6 million. TEP expects to charge approximately $14$16 million of these costs to O&Moperations and maintenance expense, $4 million to capital, and $1$4 million to Other Expense.as a reduction of other expense. TEP expects to make pension plan contributions of $23$11 million in 2015.2018. In 2009, TEP established a VEBA trust to fund its other retiree benefit plan. In 2015,2018, TEP expects to make benefit payments to retirees under the retiree benefit plan of approximately $5 million and contributions to the VEBAVoluntary Employee Beneficiary Association (VEBA) trust of approximately $3$1 million, net of distributions.

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SeeNote 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension plan and other postretirement benefit plan expenses and obligations.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
TEP enters 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 haswill have excess supply and the market price of energy exceeds its marginal cost. TEP enters into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted gas purchases and to hedge the price risk associated with forward PPAs 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 sheetssheet 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 sheet of TEP based on our ability to recover the 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 mechanism.
The market prices used to determine fair values for TEP’s derivative instruments atas of December 31, 2014,2017, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
TEP manages 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.
Long-Term Power Sale Option
TEP entered into a three-year option to sell power to a long-term wholesale customer. This contract is not subject to regulatory accounting. Unrealized gains or losses are recorded through the income statement in Electric Wholesale Sales.
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 1of Notes to Consolidated Financial Statements.
Interest Rate Swaps
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates tied to LIBORLondon Interbank Offered Rate (LIBOR) on the Springerville Common Facilities Lease.lease. As of December 31, 2014,2017, approximately $32$18 million of variable rate lease debt for the Springerville Common Facilities Leaselease had been hedged through an amortizing interest rate swap agreement throughexpiring in January 2, 2020.
Revenue Recognition
TEP’s retail revenues, which are recognized in the period that electricity is delivered and consumed by customers, include unbilled revenue based on an estimate of kWh 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 delivered to the kWh billed to our retail customers. The excess of estimated kWh delivered over kWh 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’s actual load, the unbilled revenue amount increasesrevenues increase during the spring and summer and decreasesdecrease during the fall and winter. A provision for uncollectible accounts, associated with retail revenues, is recorded as a component of O&Moperations and maintenance expense.
Plant Asset Depreciable Lives
TEP has significant investments in electric generation assets and electric 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 53 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K. 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 statement. The ACC approves depreciation rates for all generation and distribution

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assets. Depreciation rates for such assets cannot be changed without the ACC's approval. TEP's transmission assets are subject to the jurisdiction of the FERC. See Note 1 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K for additional information regarding depreciation rates.
The 2013 TEP Rate Order approved a change in authorized depreciation rates for generation and distribution plant from an average
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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 atas of our balance sheet date.
Income TEP records income tax liabilities are allocated to TEP based on TEP's taxable income and deductions as reported in the FortisUS, Inc. consolidated tax return.return of FortisUS, Inc., a Fortis intermediate holding company (FortisUS).
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. AtTEP recorded no valuation allowance as of December 31, 2014, TEP had a $2 million valuation allowance.2017. See Note 1112 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K for additional information regarding income taxes.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2014, the FASB issued anFor a discussion of new accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effectivepronouncements affecting TEP, see Note 13 of Notes to Consolidated Financial Statements in the first quarter of 2015. We do not expect the adoptionPart II, Item 8 of this guidance to have an impact on the presentation of our financial statements or our disclosures.
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.
In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP does not expect the adoption of this guidance to have an impact on its disclosures.Form 10-K.

ITEM 7A.7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks
TEP’s primaryfinancial statements are exposed to certain market risks include fluctuations in interest rates, returns on marketable securities, commodity priceswhich can impact asset and volumes, and counterparty credit. Fluctuations in interest rates can affect earningsliability fair value, results of operations, and cash flows. WeTEP's significant market risks are primarily associated with interest rates, commodity and coal prices, and extension of credit to counterparties. TEP may enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.
See Forward-Looking Information.
Risk Management Committee
We haveTEP has a Risk Management Committee responsible for the oversight of commodity price risk and credit risk related to the wholesale energy marketing and power procurement activities of TEP. Our Risk Management Committee, which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, and generation operations departments of TEP.activities. To limit TEP’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

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TEP’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits.
See Forward-Looking Information for additional information.
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$137 million at December 31, 2014 in tax-exempt variable rate debt outstanding.outstanding as of December 31, 2017. The outstanding debt included one series of bonds for which interest rates on TEP’s tax-exempt variable rate debt are reset weekly orand one series of bonds for which interest rates are reset monthly. The weighted average weekly rate on TEP's weekly variable rate debt (including letter of creditLOC fees and remarketing fees) was 1.46%1.76% in 20142017 and 1.59%1.33% in 2013.2016. The average weekly interest rate ranged from 1.4% to 1.75%1.53% - 2.68% in 20142017 and 1.43% to 1.78% during 2013.0.93% - 1.76% in 2016. The average monthly rate on TEP’s monthly variable rate debt (issued in November 2013 andis based on a percentage of an index equal to one-month LIBOR plus a bank margin rate)credit spread. The average monthly rate was 0.87%1.41% in 2014.2017 and 1.01% in 2016. The ratesmonthly rate ranged from 0.85% to 0.95%1.08% - 1.58% in 2014.2017 and 0.83% - 1.08% in 2016.
Although short-term interest rates were low and stable in 2014 and 2013, TEP may still beis 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 monthtwelve-month period, would result in a decrease in TEP’s pre-tax net income of approximately $2$1 million.
TEP can manage its exposure to variable interest rate risk by entering into interest rate swaps and financing transactions to rebalance its mixhad $21 million of variable rate and fixed rate long-term debt.debt outstanding related to the Springerville Common Facilities capital lease obligation as of December 31, 2017. TEP has aone fixed-for-floating interest rate swap in place to hedge the floating rate interest rate risk associated with a portion of its Springerville Common Facilitiesthe capital lease debt.obligation. The notional amount of the swap is $32was $18 million at December 31, 2014. The notional amount of lease debt that was unhedged as of December 31, 2014 was $18 million. TEP did not have any other interest rate swaps at December 31, 2014.2017.
Interest Rate SwapsSwap
To adjust the value of TEP’s interest rate swaps,swap, classified as a cash flow hedges,hedge, to fair value in Other Comprehensive Income, (Loss), TEP recorded the following net unrealized gains:
 2014 2013 2012
 Millions of Dollars
Unrealized Gains (Losses)$2
 $4
 $2
(in millions)2017 2016 2015
Net Unrealized Gains$1
 $1
 $1
Revolving
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Credit Facilities
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under its credit agreements.agreement. The interest paid on borrowings is variable. Revolving credit borrowings may beare made on either the basis of a spread over LIBOR or an Alternate Base Rate.Rate (ABR). As a result, TEP may experience significant volatility in the rates paid on LIBOR borrowings under its revolving credit facilities.
Marketable Securities Risk
The majority of TEP’s pension plan assets, as well as assets associated with other employee benefit obligations, are investments in equityCommodity and debt securities. These investments are exposed to price fluctuations in equity markets and changes in interest rates. Of the assets held for employee benefit obligations, the pension plan assets comprise the largest portion. The pension plan assets will help fund defined retirement benefits for substantially all of our employees. Declines in the values of these assets could increase required employer contributions, which would adversely affect cash flows. Declines in values could also increase the reported pension expense, adversely affecting TEP’s results of operations.
CommodityCoal Price Risk
TEP is exposed to commodity price risk primarily relating to changesmarket fluctuations in the market price of electricity, natural gas and coal. This risk is mitigated through hedging practicescoal prices as a result of its obligation to serve retail customer load in its regulated service territory 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 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,long-term wholesale contracts. 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.

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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 salesgenerating facilities represent substantial underlying commodity positions. Exposures to optimize its resource portfolio and take advantagecommodity prices consist mainly 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
TEP has several long-term wholesale agreements for the sale of energy. Sales under some of these agreements are based on indexed energy prices. Changesvariations in the price of power affect TEP's revenuefuel required to generate electricity and income from these agreements. One such agreement with SRP requires SRPwholesale electricity that is purchased and sold. Commodity and coal prices may be subject to purchase 500,000 MWh of on-peak energy per year from TEP throughsignificant price changes as supply and demand are impacted by, among other unpredictable factors, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Under the endguidance of the contract in May 2016. SRP does not pay 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. 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
Risk Management Committee, 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 hedgesmitigates a portion of its total natural gascommodity price risk through the use of commodity contracts, which include forwards, options, swaps and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. TEP's exposure from plant fuel, gas-indexed power purchases,to commodity and spot market purchases with various instruments upcoal price risk is limited by its ability to three yearsinclude these costs in advance. TEP purchasesregulated rates through its remaining gas fuelPPFAC mechanism, which is subject to review by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.
Certain commodity contracts qualify as derivatives and power needsare recorded at fair value. The changes in the spot and short-term markets.
As required by fair value accounting rules, for the year ended December 31, 2014, 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 adjustsuch contracts have a high correlation to price changes in the hedged commodities. The following table shows the changes in fair value of its commodity derivatives to fair value in regulatory assets or regulatory liabilities, TEP recorded the following net unrealized gains (losses):our derivative positions:
 2014 2013 2012
 Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities$(18) $
 $6
(in millions)2017 2016 2015
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities$(18) $12
 $6
TEP's derivative contracts mature on various dates through 2029. The charttable below displays the valuation methodologies and maturities of TEP’s power and gas derivative contracts.contracts by source of fair value:
 Unrealized Gain (Loss) of TEP’s Hedging Activities
Source of Fair Value at December 31, 2014
Maturity 0 – 6
months
 
Maturity 6 – 12
months
 
Maturity
over 1 yr.
 
Total
Unrealized
Gain (Loss)
 Millions of Dollars
Prices Actively Quoted$(4) $(11) $(3) $(18)

43
 Unrealized Gain (Loss) of TEP’s Hedging Activities
 Maturity 0 – 6 months Maturity 6 – 12 months Maturity over 1 yr. Total Unrealized Gain (Loss)
(in millions)December 31, 2017
Prices Actively Quoted$
 $(7) $(8) $(15)




Sensitivity Analysis of Derivatives
TEP uses sensitivity analysis to measure the potential 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,derivatives related to the purchase and sale of electricity, a 10% change in the market price of purchased power would affect unrealized positions reported as a regulatory asset or regulatory liability by approximately $2$1 million; for derivatives related to the natural gas swaps and collars contracts,price hedges, a 10% change in the market price of energy would affect unrealized positions reported as a regulatory asset or liability by approximately $4$38 million.
Coal Supply Agreements
TEP is subject to commodityfuel price risk from changes in the price of coal used to fuel its coal-fired generating plants.generation facilities. This risk is mitigated through a PPFAC mechanism which allows for the recoveryuse of costs from retail customers.
TEP'slong-term coal supply contract for Springerville Units 1 and 2 expires in 2020.agreements with limited price movement. Coal agreements expire from 2020 through 2031. TEP expects coal reserves from the supplying mines to be sufficient to supplyfulfill the estimated requirements for Units 1 and 2 for their presentlyeach coal-fired generation facility's 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.
While TEP has an existing coal inventory, we do not have a long-term coal supply contract for Sundt Unit 4. Prior to 2010, Sundt Unit 4 was predominantly fueled by coal; however, the generating station can also be operated with natural gas. Since 2010, TEP has fueled Sundt Unit 4 with both coal and natural gas depending on which resource is most economic.
TEP participates in jointly-owned generating facilities at Four Corners, Navajo, and San Juan, where coal supplies are received under contracts administered by the operating agents. The coal contracts at Four Corners and Navajo expire in 2031 and 2019, respectively. The current coal supply contract for San Juan expires on December 31, 2017. TEP and other San Juan owners are currently negotiating agreements concerning the future San Juan fuel supply. If the Participants are unable to negotiate an economic fuel supply, the continued operation of San Juan could be jeopardized resulting in the retirement of San Juan Unit 1 earlier than expected.
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 $31 million for the next three years and $19 million thereafter through 2031.life. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources Contractual Obligationsand Note 67 of Notes to Consolidated Financial Statements.Statements in Part II, Item 8 of this Form 10-K for additional information.
Credit Risk
TEP is exposed to credit risk in its energy-related marketing activities related to potential non-performance by counterparties. We manageTEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures,

36



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 counterpartyCounterparty credit exposure is calculated by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts. 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.an LOC.
TEP has 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, 2014, the credit exposure to TEP from financial institution counterparties was less than $1.7 million.
As of December 31, 2014, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities with various counterparties. As of December 31, 2017, TEP’s total credit exposure was approximately $12 million. TEP had one non-investment grade counterparty with exposureapproximately $1 million of greater than 10% of its total credit exposure. TEP’s total exposure to non-investment grade counterparties was $1 million.counterparties.
AtAs of December 31, 2014,2017, TEP posted no cash collateral and less than $1 million innor LOCs as credit enhancements with its counterparties, and did not hold anyTEP holds approximately $6 million in collateral from its wholesale counterparties.


4437



ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s
Report of Independent Registered Public Accounting Firm
To the Stockholder and the Board of Directors of
Tucson Electric Power Company
Tucson, AZ

Opinion on Internal Controls Overthe Financial ReportingStatements
TEP’s managementWe have audited the accompanying consolidated balance sheet of Tucson Electric Power Company (the "Company") as of December 31, 2017, the related consolidated statements of income, comprehensive income, changes in stockholder’s equity, and cash flows, for the year ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for the year ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is responsible for establishingto express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and maintaining adequateare required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. BecauseAs part of its inherent limitations,our audits, we are required to obtain an understanding of internal control over financial reporting maybut not prevent or detect misstatements. Also, projectionsfor the purpose 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 assessedexpressing an opinion on the effectiveness of TEP’sthe Company’s internal control over financial reportingreporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of December 31, 2014. In making this assessment, management used the criteria set forth by the 2013 COSO Internal Control – Integrated Framework.
Based on management’s assessment using those criteria, management has concludedfinancial statements. We believe that as of December 31, 2014, TEP’s internal control over financial reporting was effective.our audits provide a reasonable basis for our opinion.


45
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 15, 2018

38



Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Tucson Electric Power Company:
We have audited the accompanying consolidated balance sheetsheets of Tucson Electric Power Company and subsidiaries as of December 31, 2014,2016, and the related consolidated statements of income, comprehensive income, capitalization,changes in stockholder’s equity and cash flows for each of the year then ended. Our audit also includedtwo years in the financial statement schedules as atperiod ended December 31, 2014 and for the year then ended listed in the Index at Item 15(a)(1) and 15(a)(2).2016. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audit.audits.
We conducted our auditaudits 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our auditaudits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 auditaudits provided a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tucson Electric Power Company and subsidiaries at December 31, 2014,2016, and the consolidated results of their operations and their cash flows for each of the year thentwo years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Ernst & Young LLP
Calgary, Canada
02/19/15

46


Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of
Tucson Electric Power Company:
In our opinion, the consolidated balance sheet and statement of capitalization as of December 31, 2013 and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholder’s equity for each of the two years in the period ended December 31, 2013 present fairly, in all material respects, the financial position of Tucson Electric Power Company and its subsidiaries at December 31, 2013, and the results of their operations and their cash flows for each of the two 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 for each of the two years in the period ended December 31, 2013 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 schedulebased on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Phoenix, Arizona
February 25, 2014, except for the effects of the revision discussed in Note 1 to the consolidated financial statements, as to which the date is August 14, 201416, 2017


4739


TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands)
Years Ended December 31,
2014 2013 2012Years Ended December 31,
Thousands of Dollars2017 2016 2015
Operating Revenues          
Electric Retail Sales$970,145
 $934,357
 $915,879
Electric Wholesale Sales158,323
 132,500
 111,194
Other Revenues141,433
 129,833
 134,587
Retail$1,040,682
 $989,580
 $1,021,543
Wholesale174,742
 117,341
 167,020
Other125,511
 128,074
 117,981
Total Operating Revenues1,269,901
 1,196,690
 1,161,660
1,340,935
 1,234,995
 1,306,544
Operating Expenses          
Fuel297,537
 325,903
 318,901
285,551
 289,862
 305,559
Purchased Power152,922
 112,452
 80,137
136,425
 85,354
 124,764
Transmission and Other PPFAC Recoverable Costs18,179
 12,233
 5,722
36,239
 23,781
 24,798
Increase (Decrease) to Reflect PPFAC Recovery Treatment(11,194) (12,458) 31,113
(32,660) 21,064
 39,787
Total Fuel and Purchased Energy457,444
 438,130
 435,873
Total Fuel and Purchased Power425,555
 420,061
 494,908
Operations and Maintenance378,877
 335,321
 334,553
360,302
 353,905
 345,356
Depreciation126,520
 118,076
 110,931
152,874
 146,097
 138,093
Amortization28,567
 31,294
 39,493
22,255
 22,498
 19,261
Taxes Other Than Income Taxes47,805
 43,498
 40,323
53,623
 49,303
 49,623
Total Operating Expenses1,039,213
 966,319
 961,173
1,014,609
 991,864
 1,047,241
Operating Income230,688
 230,371
 200,487
326,326
 243,131
 259,303
Other Income (Deductions)          
Interest Income208
 120
 136
742
 111
 93
Other Income8,598
 5,770
 3,953
14,128
 5,636
 6,647
Other Expense(12,735) (10,715) (13,574)(3,344) (3,019) (2,833)
Appreciation in Fair Value of Investments1,371
 2,833
 1,892
Appreciation (Depreciation) in Value of Investments2,791
 2,147
 (142)
Total Other Income (Deductions)(2,558) (1,992) (7,593)14,317
 4,875
 3,765
Interest Expense          
Long-Term Debt60,577
 56,378
 55,038
62,018
 62,015
 61,159
Capital Leases10,249
 25,140
 33,613
2,554
 3,356
 3,994
Other Interest Expense810
 87
 1,446
718
 531
 1,134
Interest Capitalized(3,755) (2,554) (1,782)(2,078) (1,710) (2,732)
Total Interest Expense67,881
 79,051
 88,315
63,212
 64,192
 63,555
Income Before Income Taxes160,249
 149,328
 104,579
277,431
 183,814
 199,513
Income Tax Expense57,911
 47,986
 39,109
100,763
 59,376
 71,719
Net Income$102,338
 $101,342
 $65,470
$176,668
 $124,438
 $127,794
See Notes to Consolidated Financial Statements.The accompanying notes are an integral part of these financial statements.


4840



TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in thousands)
 
Years Ended December 31,
2014 2013 2012Years Ended December 31,
Thousands of Dollars2017 2016 2015
Comprehensive Income          
Net Income$102,338
 $101,342
 $65,470
$176,668
 $124,438
 $127,794
Other Comprehensive Income          
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(1,140), $(1,793), and $(887).1,675
 2,738
 1,354
Supplemental Executive Retirement Plan (SERP) Net Unrealized Loss and Prior Service Cost, net of income tax (expense) benefit of $1,068, $(572), and $608.(1,725) 916
 (840)
Total Other Comprehensive Income (Loss), Net of Taxes(50) 3,654
 514
Net Changes in Fair Value of Cash Flow Hedges:     
Net of Income Tax (Expense) Benefit of $(305), $(420), and $(821)485
 652
 1,261
Supplemental Executive Retirement Plan Adjustments:     
Net of Income Tax (Expense) Benefit of $637, $399, and $(63)(2,156) (643) 101
Total Other Comprehensive Income, Net of Tax(1,671) 9
 1,362
Total Comprehensive Income$102,288
 $104,996
 $65,984
$174,997
 $124,447
 $129,156
See Notes to Consolidated Financial Statements.The accompanying notes are an integral part of these financial statements.


4941


TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
 Year Ended December 31,
 2014 2013 2012
 Thousands of Dollars
Net Income$102,338
 $101,342
 $65,470
Adjustments to Reconcile Net Income     
       To Net Cash Flows from Operating Activities     
Depreciation Expense126,520
 118,076
 110,931
Amortization Expense28,567
 31,294
 39,493
Amortization of Deferred Debt-Related Costs included in Interest Expense2,626
 2,452
 2,227
Use of Renewable Energy Credits for Compliance17,818
 15,990
 5,071
Deferred Income Taxes62,609
 59,199
 45,232
Pension and Retiree Expense13,648
 19,878
 19,289
Pension and Retiree Funding(14,388) (27,636) (25,899)
Share-Based Compensation Expense5,010
 2,709
 2,029
Allowance for Equity Funds Used During Construction(6,677) (4,526) (2,840)
LFCR Revenue(11,327) (2,171) 
Increase (Decrease) to Reflect PPFAC Recovery(11,194) (12,458) 31,113
Fortis Acquisition Direct Customer Benefit18,870
 
 
PPFAC Reduction - 2013 TEP Rate Order
 3,000
 
Changes in Assets and Liabilities which Provided (Used)     
Cash Exclusive of Changes Shown Separately     
Accounts Receivable(14,599) (6,041) (871)
Materials and Fuel Inventory666
 16,145
 (38,384)
Accounts Payable10,712
 334
 1,115
Interest Accrued(377) 4,859
 8,055
Taxes Other Than Income Taxes1,625
 1,425
 905
Current Regulatory Liabilities8,388
 3,331
 (3,040)
Other(27,172) 18,989
 8,023
Net Cash Flows – Operating Activities313,663
 346,191
 267,919
Cash Flows from Investing Activities     
Capital Expenditures(323,524) (252,848) (252,782)
Purchase of Gila River Unit 3(163,938) 
 
Purchase of Springerville Unit 1 Lease Assets(19,608) 
 
Purchase of Intangibles—Renewable Energy Credits(28,334) (23,280) (8,889)
Return of Investments in Springerville Lease Debt
 9,104
 19,278
Contributions in Aid of Construction15,903
 3,959
 9,982
Other, net1,863
 3,403
 4,530
Net Cash Flows—Investing Activities(517,638) (259,662) (227,881)
Cash Flows from Financing Activities     
Proceeds from Borrowings Under Revolving Credit Facilities275,000
 78,000
 189,000
Repayments of Borrowings Under Revolving Credit Facilities(190,000) (78,000) (199,000)
Proceeds from Issuance of Long-Term Debt149,168
 
 149,513
Payments of Capital Lease Obligations(165,145) (99,621) (89,452)
Dividends Paid to UNS Energy(40,000) (40,000) (30,000)
Repayments of Long-Term Debt
 
 (6,535)
Payment of Debt Issue/Retirement Costs(1,856) (1,865) (3,547)
Equity Investment from UNS Energy225,000
 
 
Other, net643
 549
 2,008
Net Cash Flows—Financing Activities252,810
 (140,937) 11,987
Net Increase (Decrease) in Cash and Cash Equivalents48,835
 (54,408) 52,025
Cash and Cash Equivalents, Beginning of Year25,335
 79,743
 27,718
Cash and Cash Equivalents, End of Year$74,170
 $25,335
 $79,743
 Years Ended December 31,
 2017 2016 2015
Cash Flows from Operating Activities     
Net Income$176,668
 $124,438
 $127,794
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities:     
Depreciation Expense152,874
 146,097
 138,093
Amortization Expense22,255
 22,498
 19,261
Amortization of Debt Issuance Costs2,349
 2,853
 3,043
Use of Renewable Energy Credits for Compliance25,453
 17,618
 19,731
Deferred Income Taxes100,762
 59,367
 72,026
Pension and Other Postretirement Benefits Expense16,039
 15,338
 18,588
Pension and Other Postretirement Benefits Funding(14,430) (13,459) (30,682)
Allowance for Equity Funds Used During Construction(5,322) (4,522) (5,352)
FERC Transmission Refund Payable(4,878) 4,878
 
Changes in Current Assets and Current Liabilities:     
Accounts Receivable(13,219) 7,809
 (3,019)
Materials, Supplies, and Fuel Inventory175
 7,627
 (8,758)
Regulatory Assets(3,942) (12,147) 18,002
Accounts Payable and Accrued Charges9,790
 14,284
 (13,917)
Regulatory Liabilities(20,227) 18,012
 10,921
Other, Net3,977
 14,777
 (797)
Net Cash Flows—Operating Activities448,324
 425,468
 364,934
Cash Flows from Investing Activities     
Capital Expenditures(345,617) (250,360) (333,841)
Purchase, Springerville Coal Handling Facilities Lease Assets
 
 (120,312)
Purchase, Springerville Unit 1 Assets
 (85,000) (45,753)
Purchase Intangibles, Renewable Energy Credits(51,179) (40,949) (29,184)
Proceeds from Sale, Springerville Coal Handling Facilities
 
 23,656
Contributions in Aid of Construction4,983
 3,432
 4,517
Net Cash Flows—Investing Activities(391,813) (372,877) (500,917)
Cash Flows from Financing Activities     
Proceeds from Borrowings, Revolving Credit Facility70,000
 
 148,000
Repayments of Borrowings, Revolving Credit Facility(35,000) 
 (233,000)
Proceeds from Borrowings, Term Loan
 
 130,000
Repayments of Borrowings, Term Loan
 
 (130,000)
Proceeds from Issuance, Long-Term Debt
 
 299,019
Repayments, Long-Term Debt
 
 (208,600)
Dividends Paid to Parent(70,000) (50,000) (50,000)
Payments of Capital Lease Obligations(15,571) (14,079) (13,464)
Payment of Debt Issuance/Retirement Costs(245) (183) (3,942)
Contribution from Parent
 
 180,000
Other, Net481
 (4,871) 1,458
Net Cash Flows—Financing Activities(50,335) (69,133) 119,471
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash6,176
 (16,542) (16,512)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period43,325
 59,867
 76,379
Cash, Cash Equivalents, and Restricted Cash, End of Period$49,501
 $43,325
 $59,867
See Note 9The accompanying notes are an integral part of Notes to Consolidated Financial Statements for supplemental cash flow information.
See Notes to Consolidated Financial Statements.these financial statements.


5042


TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
December 31,
2014 2013December 31,
Thousands of Dollars2017 2016
ASSETS      
Utility Plant      
Plant in Service$5,175,148
 $4,467,667
$5,780,805
 $5,975,139
Utility Plant Under Capital Leases667,157
 637,957
84,870
 167,413
Construction Work in Progress109,070
 180,485
160,288
 129,955
Total Utility Plant5,951,375
 5,286,109
6,025,963
 6,272,507
Less Accumulated Depreciation and Amortization(2,052,216) (1,826,977)
Less Accumulated Amortization of Capital Lease Assets(473,969) (514,677)
Total Utility Plant—Net3,425,190
 2,944,455
Accumulated Depreciation and Amortization(2,193,656) (2,385,053)
Accumulated Amortization of Capital Lease Assets(63,605) (104,648)
Total Utility Plant, Net3,768,702
 3,782,806
   
Investments and Other Property   51,260
 45,020
Investments in Lease Equity
 36,194
Other37,599
 33,488
Total Investments and Other Property37,599
 69,682
   
Current Assets      
Cash and Cash Equivalents74,170
 25,335
37,701
 35,962
Accounts Receivable—Customer93,521
 80,211
Unbilled Accounts Receivable36,804
 34,369
Allowance for Doubtful Accounts(4,885) (4,825)
Accounts Receivable—Due from Affiliates5,382
 6,064
Accounts Receivable, Net137,932
 124,934
Fuel Inventory25,059
 25,887
Materials and Supplies86,750
 75,200
103,981
 97,126
Deferred Income Taxes—Current102,006
 70,722
Fuel Inventory36,368
 44,027
Regulatory Assets—Current69,383
 42,555
Regulatory Assets93,960
 56,340
Derivative Instruments1,633
 2,137
3,187
 4,966
Other22,848
 12,923
10,777
 13,793
Total Current Assets523,980
 388,718
412,597
 359,008
Regulatory and Other Assets      
Regulatory Assets—Noncurrent223,192
 141,030
Regulatory Assets293,551
 225,453
Derivative Instruments300
 167
8,826
 330
Other Assets22,161
 19,233
Other55,313
 37,372
Total Regulatory and Other Assets245,653
 160,430
357,690
 263,155
Total Assets$4,232,422
 $3,563,285
$4,590,249
 $4,449,989
See Notes to Consolidated Financial Statements.The accompanying notes are an integral part of these financial statements.

(Continued)


5143


TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
December 31,
2014 2013December 31,
Thousands of Dollars2017 2016
CAPITALIZATION AND OTHER LIABILITIES      
Capitalization      
Common Stock Equity$1,215,779
 $925,923
Common Stock Equity:   
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2017 and 2016)$1,296,539
 $1,296,539
Capital Stock Expense(6,357) (6,357)
Retained Earnings380,076
 273,408
Accumulated Other Comprehensive Loss(6,226) (4,555)
Total Common Stock Equity1,664,032
 1,559,035
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2017 and 2016)
 
Capital Lease Obligations69,438
 131,370
28,519
 39,267
Long-Term Debt1,372,414
 1,223,070
Long-Term Debt, Net1,354,423
 1,453,072
Total Capitalization2,657,631
 2,280,363
3,046,974
 3,051,374
Current Liabilities      
Current Obligations Under Capital Leases173,822
 186,056
Borrowings Under Revolving Credit Facilities85,000
 
Accounts Payable—Trade110,480
 88,556
Accounts Payable—Due to Affiliates2,933
 9,153
Current Maturities of Long-Term Debt100,000
 
Borrowings Under Revolving Credit Facility35,000
 
Capital Lease Obligations10,749
 51,765
Accounts Payable97,367
 89,797
Accrued Taxes Other than Income Taxes36,110
 34,485
40,706
 37,639
Accrued Employee Expenses15,679
 24,454
30,929
 29,465
Regulatory Liabilities—Current38,847
 23,701
Accrued Interest21,021
 22,785
14,750
 14,508
Regulatory Liabilities89,024
 76,069
Customer Deposits20,339
 21,354
24,865
 25,778
Derivative Instruments18,874
 5,531
10,667
 2,641
Other9,673
 9,244
18,119
 17,837
Total Current Liabilities532,778
 425,319
472,176
 345,499
Deferred Credits and Other Liabilities   
Deferred Income Taxes—Noncurrent491,546
 428,103
Regulatory Liabilities—Noncurrent321,186
 263,270
Regulatory and Other Liabilities   
Deferred Income Taxes, Net300,258
 529,148
Regulatory Liabilities516,438
 300,700
Pension and Other Postretirement Benefits138,319
 84,936
133,799
 131,630
Derivative Instruments6,288
 5,161
17,907
 2,629
Other84,674
 76,133
102,697
 89,009
Total Deferred Credits and Other Liabilities1,042,013
 857,603
Commitments, Contingencies & Environmental Matters (Note 6)
 
Total Regulatory and Other Liabilities1,071,099
 1,053,116
   
Commitments and Contingencies
 
   
Total Capitalization and Other Liabilities$4,232,422
 $3,563,285
$4,590,249
 $4,449,989
See Notes to Consolidated Financial Statements.The accompanying notes are an integral part of these financial statements.

(Concluded)


5244


TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
      December 31,
      2014 2013
       Thousands of Dollars
COMMON STOCK EQUITY        
Common Stock-No Par Value     $1,116,539
 $888,971
  2014 2013    
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     111,523
 49,185
Accumulated Other Comprehensive Loss     (5,926) (5,876)
Total Common Stock Equity     1,215,779
 925,923
PREFERRED STOCK        
No Par Value, 1,000,000 Shares Authorized, None Outstanding     
 
CAPITAL LEASE OBLIGATIONS        
Springerville Unit 1     42,925
 192,871
Springerville Coal Handling Facilities     117,573
 27,878
Springerville Common Facilities     82,762
 96,677
Total Capital Lease Obligations     243,260
 317,426
Less Current Maturities     173,822
 186,056
Total Long-Term Capital Lease Obligations     69,438
 131,370
LONG-TERM DEBT        
  Maturity Interest Rate    
Variable Rate Bonds 2022 - 2032 Variable 214,830
 214,802
Fixed Rate Bonds 2020 - 2044 3.85% – 5.75% 1,157,584
 1,008,268
Total Long-Term Debt     1,372,414
 1,223,070
Total Capitalization     $2,657,631
 $2,280,363
See Notes to Consolidated Financial Statements.


53



TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY
(Amounts in thousands)
 Common
Stock
 Capital
Stock Expense
 Accumulated Earnings (Deficit) Accumulated
Other
Comprehensive
Loss
 Total
Stockholder's Equity
 Thousands of Dollars
Balances at December 31, 2011$888,971
 $(6,357) $(47,627) $(10,044) $824,943
Net Income    65,470
   65,470
Other Comprehensive Loss, net of tax      514
 514
Dividends Declared

   (30,000)   (30,000)
Balances at December 31, 2012888,971
 (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, 2013888,971
 (6,357) 49,185
 (5,876) 925,923
Net Income    102,338
   102,338
Other Comprehensive Income, net of tax      (50) (50)
Dividends Declared    (40,000)   (40,000)
Contribution from Parent225,000
       225,000
Other2,568
       2,568
Balances at December 31, 2014$1,116,539
 $(6,357) $111,523
 $(5,926) $1,215,779
 Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2014$1,116,539
 $(6,357) $111,523
 $(5,926) $1,215,779
Net Income    127,794
   127,794
Other Comprehensive Income, Net of Tax      1,362
 1,362
Dividends Declared to Parent    (50,000)   (50,000)
Contribution from Parent180,000
       180,000
Balances as of December 31, 20151,296,539
 (6,357) 189,317
 (4,564) 1,474,935
Net Income    124,438
   124,438
Other Comprehensive Income, Net of Tax      9
 9
Dividends Declared to Parent    (50,000)   (50,000)
Adoption of ASU, Cumulative Effect Adjustment    9,653
   9,653
Balances as of December 31, 20161,296,539
 (6,357) 273,408
 (4,555) 1,559,035
Net Income    176,668
   176,668
Other Comprehensive Income, Net of Tax      (1,671) (1,671)
Dividends Declared to Parent    (70,000)   (70,000)
Balances as of December 31, 2017$1,296,539
 $(6,357) $380,076
 $(6,226) $1,664,032
See Notes to Consolidated Financial Statements.The accompanying notes are an integral part of these financial statements.


5445

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




NOTE 1.NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATIONSUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Tucson Electric Power Company (TEP)TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 415,000422,000 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. TEP is a wholly owned subsidiary of UNS Energy, Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis), which is a leader in the North American electric and gas utility business.
FORTIS ACQUISITION OF UNS ENERGY
UNS Energy, the parent of TEP, was acquired by Fortis for $60.25 per share of UNS Energy common stock in cash effective August 15, 2014.
The Arizona Corporation Commission's (ACC) approval was subject to certain stipulations, including, but not limited to, the following:
TEP will provide credits on retail customers' bills totaling approximately $19 million over five years: $6 million in year one and $3 million annually in years two through five. The monthly bill credits will be applied each year from October through March effective October 1, 2014;
Dividends paid from TEP to UNS Energy cannot exceed 60 percent of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reaches 50 percent of total capital; and
Fortis making an equity investment of at least $220 million to UNS Energy and its regulated subsidiaries, including TEP. Fortis exceeded the investment requirement by contributing $287 million to UNS Energy through December 31, 2014. UNS Energy then contributed $225 million to TEP.
As a result of the Merger being completed, TEP recorded approximately $15 million through August 2014 as its allocated share of merger-related expenses, in addition to the customer bill credits discussed above. Merger-related expenses, reported in Operations and Maintenance and Other Expense, include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards.
Completion of the Merger resulted in accelerated vesting and expense recognition of all outstanding non-vested UNS Energy share-based awards that would otherwise have been recognized over remaining vesting periods through February 2017. TEP recognized approximately $2 million of expense in 2014 due to the accelerated vesting of the awards. TEP recorded total share-based compensation expense of $5 million for the year ended December 31, 2014, $3 million for the year ended December 31, 2013, and $2 million for the year ended December 31, 2012. In August 2014, UNS Energy settled all outstanding share-based compensation awards in cash.Fortis.
BASIS OF PRESENTATION
TEP's consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includesGAAP, including specific accounting guidance for regulated operations. See Note 2 of Notes to Consolidated Financial Statements. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stationsgeneration and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly ownedjointly-owned facilities is recorded asin Utility Plant on the consolidated balance sheets,Consolidated Balance Sheets, and ourits proportionate share of the operating costs associated with these facilities is included in the consolidated statementsConsolidated Statements of income.Income. See Note 3 of Notes to Consolidated Financial Statements.for additional information regarding utility plant.
TEP did not reflect the impacts of acquisition accounting in its financial statements. All adjustments of assets and liabilities to fair value and the resultant goodwill associated with the Merger were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis.
As a result of the Merger, TEP has elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current periodyear presentation.

55


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



REVISION OF BALANCE SHEET AND STATEMENT OF CAPITALIZATION AS OF DECEMBER 31, 2013Accounting for Regulated Operations
TEP revised its December 31, 2013 balance sheet and statement of capitalization to correct an immaterial error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. The notes that follow have been updated for this revision.
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
In 2014, we adopted accounting guidance that:
requires an entity to 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. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows.
impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.
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 applyapplies accounting standards that recognize the economic effects of rate regulation. As a result, we capitalizeTEP capitalizes certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI)AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in theRetail Rates or in rates charged to retail customers or to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or itemsamounts that are expected to be returned to customers through billing reductions in future rate reductions.periods.
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 evaluateTEP evaluates regulatory assets and liabilities each period and believebelieves future recovery or settlement 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 2 of Notes to Consolidated Financial Statements.for additional information regarding regulatory matters.
TEP applies 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.ratepayers.
Variable Interest Entities
TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.
TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.
As of December 31, 2017, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principle did not have any impact on TEP's financial position or results of operations as the Company recovers the cost of inventory through its rates.
Effective December 31, 2017, TEP early adopted accounting guidance that requires entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents on the cash flow statement. As a result, TEP no longer presents transfers between cash and cash equivalents and restricted cash and restricted cash equivalents on the cash flow statement. On adoption, using the retrospective method of transition, TEP's Consolidated Statements of Cash Flows included the following adjustments:
 As Filed Adoption of ASU Impacts As Adjusted
(in millions)Year Ended December 31, 2016
Net Cash Flows—Operating Activities$425
 $
 $425
Net Cash Flows—Investing Activities(376) 3
 (373)
Net Cash Flows—Financing Activities(69) 
 (69)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash(20) 3
 (17)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period56
 4
 60
Cash, Cash Equivalents, and Restricted Cash, End of Period$36
 $7
 $43
(in millions)Year Ended December 31, 2015
Net Cash Flows—Operating Activities$365
 $
 $365
Net Cash Flows—Investing Activities(503) 2
 (501)
Net Cash Flows—Financing Activities120
 
 120
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash(18) 2
 (16)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period74
 2
 76
Cash, Cash Equivalents, and Restricted Cash, End of Period$56
 $4
 $60
The standard impacted the presentation of the cash flow statement but did not have an impact on TEP's financial position or results of operations.
USE OF ACCOUNTING ESTIMATES
Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect:
assets and liabilities in the balance sheet at the dates of the financial statements;
disclosures about contingent assets and liabilities at the dates of the financial statements; and
revenues and expenses in the income statement during the periods presented.
Because these estimates involve judgments based upon the Company's evaluation of relevant facts and circumstances, actual results may differ from these estimates.
Asset Retirement Obligations
TEP has identified legal AROs related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its PV assets as a result of entering into various land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of

47


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs as regulatory assets based on the ACC approval of these costs in its depreciation rates.
Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities.
Contingencies
Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
CASH AND CASH EQUIVALENTS
We considerTEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
RESTRICTED CASH
Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:
 Years Ended December 31,
(in millions)2017 2016 2015
Cash and Cash Equivalents$38
 $36
 $56
Restricted Cash included in:     
Investments and Other Property11
 7
 4
Current Assets, Other1
 
 
Total Cash, Cash Equivalents, and Restricted Cash$50
 $43
 $60
Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan. Restricted cash included in Current Assets—Other represents cash required to be set aside by various contractual agreements.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
TEP records 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. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows:
 Years Ended December 31,
(in millions)2017 2016 2015
Beginning of Period$5
 $27
 $5
Additions Charged to Cost and Expense3
 4
 2
Write-offs(3) (3) (3)
Provision for Springerville Unit 1, Third-Party Owners
 (23) 23
End of Period$5
 $5
 $27
The allowance for doubtful accounts decreased in 2016 due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims.

5648


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



RESTRICTED CASH
Cash balances thatINVENTORY
TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other oncapitalized as part of the balance sheets. Restricted cash was $2 million at December 31, 2014 and December 31, 2013.cost of the inventory.
UTILITY PLANT
Utility Plantplant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utilityUtility plant is reported 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 theThe cost of repairs and maintenance, including planned majorgeneration overhauls, are expensed to Operations and Maintenance (O&M) expense inExpense on the income statementConsolidated Statements of Income as costs are incurred.
When TEP retires a unit of regulated property, is retired, we reduce accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement impact.statement.
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 inon the income statement.Consolidated Statements of Income. The capitalized cost for equity funds is recorded asin Other Income inon the income statement.Consolidated Statements of Income.
The average AFUDC rates on regulated construction expenditures are included in the table below:
 2014 2013 2012
Average AFUDC Rates7.30% 7.38% 7.22%
 2017 2016 2015
Average AFUDC Rates7.31% 7.47% 6.12%
Depreciation
We compute depreciationDepreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 2 and Note 3 of Notes to Consolidated Financial Statements.for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).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:
 2014 2013 2012
Average Annual Depreciation Rates2.99% 3.16% 3.22%
 2017 2016 2015
Average Annual Depreciation Rates2.97% 2.85% 2.83%
Utility Plant Under Capital Leases
TEP financedfinances a portion of the following generation assetsSpringerville Common Facilities 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 capitalleases. Capital lease expense incurred consists ofis recorded in Amortization Expense (seeand in Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 of Notesfor additional information regarding utility plant and Note 6 for additional information related to Consolidated Financial Statements) and Interest Expense—Capital Leases. Thethe lease terms are described in Note 5 of Notes to Consolidated Financial Statements.terms.
Computer Software Costs
We capitalize costsCosts incurred to purchase and develop internal use computer software are capitalized and amortize those costsamortized 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 EQUITY
Prior to December 2014, TEP held a 14.1% 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 10 of Notes to Consolidated Financial Statements.

57



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP accounted for its equity interest in the Springerville Unit 1 Lease trust using the equity method. In December 2014, following the purchase of an additional undivided interest in Springerville Unit 1, TEP transferred the balance of its investment in lease equity to Plant in Service.
ASSET RETIREMENT OBLIGATIONS
TEP has identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its 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 increasingor impaired, the carrying amount ofvalue is reduced and recorded as an expense on 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 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.income statement.
EVALUATION OF ASSETS FOR IMPAIRMENT
We evaluate long-livedLong-lived assets and investments are evaluated 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.

49


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



DEFERRED FINANCING COSTS
We deferUsing the effective interest method, costs to issue debt are deferred and amortize such costsamortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as this approximatesa direct deduction from the effective interest method.carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
We defer and amortize theTEP accounts for debt issuance costs related to credit facility arrangements as an asset.
The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt.
OPERATING REVENUES
We recognize revenuesRevenues related to the sale of energy are recognized when services or commodities are delivered to customers. The billing for the delivery of electricity salespower 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.
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events, if certain criteria are met. TEP charges customers the ACC-authorized tariff price plus separate ACC-authorized surcharges. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding regulatory matters.
For purchased power and wholesale sales contracts that are settled financially, TEP nets the salespurchased power contracts with the purchase powersales contracts and reflects the net amount as Electricin Wholesale Sales.Revenues on the Consolidated Statements of Income.
TEP recognizes monthly management fees in Other Revenues on the Consolidated Statements of Income as the operator of 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).SRP. Additionally, Other Revenues includeincludes 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 thetheir respective line items ofon the income statementsstatement 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 on the Consolidated Statements of Income in the period earned.
The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) related to kWh sales lost due to Energy Efficiency (EE) Standards and Distributed Generation (DG). 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.

58



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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.
PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE
We recoverTEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a Purchased Power and Fuel Adjustment Clause (PPFAC); thePPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs 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 2 of Notes to Consolidated Financial Statements.for additional information regarding regulatory matters.
RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS
The ACC’s Renewable Energy Standard (RES)RES requires TEPArizona regulated utilities to increase itstheir use of renewable energy each year until it represents at least 15% of itstheir total annual retail energy requirements inby 2025, with distributed generationDG accounting for 30% of the annual renewable energy requirement. TEPArizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costcosts of carrying out this plan isare 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 projectsassociated lost revenues attributable to meeting DG targets will be partially recovered through the RES tariff until such costs are reflected in retail customer rates.LFCR mechanism.

50


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP is required to implement cost-effective Demand Side Management (DSM)DSM programs to comply with the ACC’s EE Standards. The EE Standards provide forregulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail Kilowatt-hours (kWh)kWh savings equal to 22% by 2020.
Any RES or DSM surcharge collectionssurcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the financial statementsbalance sheet as a regulatory assetliability or liability.asset. TEP recognizes RES and DSM surcharge revenue in Electric Retail SalesRevenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures.
RENEWABLE ENERGY CREDITS
The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs).RECs. A REC represents one kWh generated from renewable resources. When TEP 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.PPFAC mechanism.
When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as Other Assets,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 recognizes Purchased Powerpurchased power expense and Other Revenuesother revenues in an equal amount. TEP had $42 million and $24 million of RECs as of December 31, 2017 and 2016, respectively. RECs are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 of Notesfor additional information regarding regulatory matters.
TAXES OTHER THAN INCOME TAXES
TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to Consolidated Financial Statements.governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
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 ourthe balance sheets.sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduceTEP reduces 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.Expense on the Consolidated Statements of Income.
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

59



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



reflects the future revenues due to TEP from ratepayers as these tax benefits reverse. See Note 2 of Notes to Consolidated Financial Statements.
We accountaccounts 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 – Noncurrentregulatory liabilities and amortized as a reduction in Income Tax Expenseincome tax expense over the tax life of the underlying asset. Income Tax Expensetax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order.asset. All other federal and state income tax credits are treated as a reduction to Income Tax Expenseincome tax expense in the year the credit arises.
IncomeTEP records income tax liabilities are allocated to TEP based on itsTEP's taxable income as reported in the FortisUS Inc. consolidated tax return.return of FortisUS.
TAXESPENSION AND OTHER THAN INCOME TAXESPOSTRETIREMENT BENEFITS
We actTEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees.
The Company recognizes the underfunded status of defined benefit pension plans 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 ona liability in the balance sheetsheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit

51


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



obligation for the pension plans. TEP recognizes a regulatory asset to the extent these taxesfuture costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees.
Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
Pension and assessments. These amountsother postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 8 for additional information regarding the employee benefit plans.
FAIR VALUE
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not reflectednecessarily indicative of the amounts that could be realized in the income statements.a current or future market exchange. See Note 11 for additional information regarding fair value.
DERIVATIVE INSTRUMENTS
We useThe Company uses 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 derivativeDerivative instruments that do not meet the normal purchase or normal sale scope exception we recognize derivative instrumentswill be recognized as either assets or liabilities on the consolidated balance sheetssheet and measure those instrumentsare measured 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 changesCommodity derivatives used in the variable interest rates related to the leveraged lease arrangementsnormal business operations that are settled by physical delivery, among other criteria, are eligible for the Springerville Common Lease and variable rate industrial development revenuemay be designated as normal purchases or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that doesnormal sales. Normal purchases or normal sales contracts are not qualify for regulatory recovery using a six-year power purchase swap agreement. TEP accounts for cash flow hedges as follows:
The effective portion of the change in therecorded at fair value is recorded in AOCI and settled amounts are recognized as cost of fuel, energy, and capacity on the ineffective portion, if any, is recognized in earnings;income statement.
For derivatives designated as hedging contracts, TEP formally assesses, at inception and
When TEP determines a thereafter, whether the hedging contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes 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.item. Also, TEP formally documents hedging activity by transaction type and risk management strategy.
Energy Contracts - Regulatory Recovery
TEPFor derivatives not designated as hedging contracts, the settled amount is authorized to recovergenerally included in regulated rates. Accordingly, the costs of hedging activities entered into to mitigate energy price risk for retail customers. We recordnet unrealized gains and losses associated with interim price movements on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC mechanism.
Energy Contracts - No Regulatory Recovery
From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery.
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.

60



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Normal Purchases and Normal Sales
We enter into forward energy purchase and sales contracts, including 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 engageas derivatives and probable of inclusion in trading of derivative financial instruments for the periods presented.
PENSION AND OTHER RETIREE BENEFITS
We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefitsregulated rates 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 plansrecorded as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’regulatory 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.liabilities. See Note 8 of Notes to Consolidated Financial Statements.11 for additional information regarding derivative instruments.

NOTE 2.REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
2013 TEP2017 RATE ORDER
The provisionsIn February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017. Provisions of the 2013 TEP2017 Rate Order which were effective July 1, 2013, include, but are not limited to:
An annuala non-fuel base rate increase of $81.5 million, which includes $15 million of operating costs related to the 50.5% undivided interest in Base RatesSpringerville Unit 1 purchased by TEP in September 2016;
a 7.04% return on original cost rate base, which includes a cost of approximately $76 million.equity component of 9.75% and a cost of debt component of 4.32%;
A revision
52


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and
approval of a request to apply excess depreciation rates from an averagereserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first half of 3.32% to 3.0% for generation and distribution plant regulated by2018. TEP cannot predict the outcome of these proceedings.
FEDERAL TAX LEGISLATION - ACC DOCKET
In December 2017, the ACC primarily dueopened a docket requesting that all regulated utilities submit proposals to revised estimatesaddress passing the ongoing benefits of asset removal costs, which has the effectTCJA through to customers. TEP will actively participate in this docket and work with the ACC to reach an equitable solution. The Company cannot predict the outcome of reducing depreciation expense by approximately $11 million annually.
A LFCR mechanism that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to EE programs and DG. The LFCR rate adjusts annually and is subject to ACC review and a year-over-year capthese proceedings or how they may impact results of 1% of TEP's total retail revenues.
An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recoveroperations in the costs of complying with environmental standards required by federalcurrent or other governmental agencies between rate cases. The ECA adjusts annually to recover environmental compliance costs and is subject to ACC approval and a cap of 0.025 cents per kWh, which approximates 0.25% of TEP's total retail revenues.future years. See Note 12 for additional information regarding the TCJA.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
TheTEP'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 modified by the ACC. The PPFAC rate includes: 1)(i) a forward component under which TEP recovers or refunds differencesis calculated by taking the difference 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;amount of those costs established in Retail Rates; and 2)(ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period. The PPFAC bank balance was over-collected by $9 million and $38 million as of December 31, 2017 and 2016, respectively.
In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected PPFAC bank balance to customers. The table below presents TEP's PPFAC rates approved by the ACC:
PeriodCents per kWh
March 2017 through March 2018(0.20)
May 2016 through February 20170.15
April 2015 through April 20160.68
October 2014 through March 20150.50
Renewable Energy Standard
The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC.
In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer-installed DG; and (iii) various other program costs. TEP recognized $1 million of revenue in 2017 as a return on company-owned solar projects. TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism and plans to request recovery of these types of costs through its rate case process. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case.
In 2017, the percentage of TEP's retail kWh sales attributable to the RES was approximately 10%, exceeding the overall 2017 RES requirement of 7%. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG RECs, which reconcilesare used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2017 and 2018 residential distributed renewable energy requirement.

Energy Efficiency Standards
61Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of

53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



differences between actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.
In April 2014, the ACC approved a PPFAC rate for TEP of 0.10 cents per kWh for the period May through September 2014 and 0.50 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was 0.77 cents per kWh for the period of January 2013 through June 2013 and a credit of approximately 0.14 cents per kWh for the period July 2013 through April 2014.
San Juan Mine Fire Insurance Proceeds
In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. As of December 31, 2014, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.
Environmental Compliance Adjustor
The 2013 TEP Rate Order provided for the ECA to recover costs associated with qualified investments to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP recognized ECA revenues of less than $1 million in 2014.
Renewable Energy Standards
TEP is required to expand its use of renewable2017, TEP’s cumulative annual energy in order to meet the ACC’s Renewable Energy Standards (RES)savings were approximately 14%. TEP is authorized to recover costs associated with meeting the RES through a customer surcharge. These costs include 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 December 2014, the ACC approved TEP's 2015 RES plan that included a spending budget of $40 million with $33 million to be recovered through the RES surcharge. TEP earned returns on solar investments of less than $1 million in 2014 and $2 million in 2013.
Energy Efficiency Standards
TEP is required to implement cost-effective DSM programs to comply with the ACC'sACC’s EE Standards. The EE Standards provide forregulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as aan annual performance incentive. For the year ended December 31, 2014, TEP recorded arecords its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million that isin both 2017 and 2016, and $3 million in 2015 related to performance, included in Electric Retail RevenueRevenues on the Consolidated Statements of Income.
In February 2016, the ACC approved TEP's 2016 energy efficiency implementation plan with a budget of approximately $22 million, which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customers through the DSM surcharge. Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the LFCR mechanism.
In June 2016, TEP notified the ACC that it would not file a 2017 energy efficiency implementation plan and instead continue the 2016 level of recovery through the end of 2017. TEP reduced its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017.
In August 2017, TEP submitted its application for the 2018 energy efficiency implementation plan with a budget of $23 million and requested a waiver of the 2018 EE Standard. TEP expects to receive a decision on its 2018 energy efficiency implementation plan in the TEP income statement.first half of 2018.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to lostreduced retail kWh sales as a result of implementing ACC approved EEACC-approved energy efficiency programs and DG targets. For recovery of lost fixed costs,customer-installed DG. TEP is required to file an annual LFCR adjustment request with the ACC for costs related to the prior year,records a regulatory asset and recovery is subject to a year-over-year cap of 1% of the company's total retail revenues.
The ACC approved TEP's annual LFCR recovery request for lost fixed costs incurred in 2013 of approximately $5 million. The approved rates, of approximately 0.41% of retail revenue for EE and approximately 0.31% of retail revenue for DG, became effective August 2014.
TEP recorded, in Electric Retail Sales,recognizes LFCR revenues of $11 million forwhen the year ended December 31, 2014 related to reductions in retail kWh sales for 2013 and 2014. We recognize LFCR revenue whenamounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.
TEP recorded regulatory assets and recognized LFCR revenues of $22 million in 2017, $18 million in 2016, and $12 million in 2015. LFCR revenues are included in Retail Revenues on the Consolidated Statements of Income.

6254

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



REGULATORY ASSETS AND LIABILITIES
The following table summarizes regulatoryRegulatory assets and liabilities:liabilities recorded in the balance sheet are summarized in the table below:
 Remaining Recovery Period (years) December 31,
($ in millions) 2017 2016
Regulatory Assets     
Pension and Other Postretirement Benefits (Note 8)Various $126
 $128
Early Generation Retirement Costs (1)
Various 84
 
Income Taxes Recoverable through Future Rates (2)
Various 40
 29
Final Mine Reclamation and Retiree Healthcare Costs (3)
20 31
 27
Lost Fixed Cost Recovery1 29
 23
Property Tax Deferrals (4)
1 24
 23
Springerville Unit 1 Leasehold Improvements (5)
6 14
 17
Sundt Coal Handling Facilities (6)
N/A 
 14
Other Regulatory AssetsVarious 40
 20
Total Regulatory Assets  388
 281
Less Current Portion1 94
 56
Total Non-Current Regulatory Assets  $294
 $225
Regulatory Liabilities     
Income Taxes Payable through Future Rates (2)
Various $353
 $3
Net Cost of Removal (7)
Various 180
 270
Renewable Energy StandardVarious 44
 32
Deferred Investment Tax Credits (8)
Various 14
 23
Purchased Power and Fuel Adjustment Clause1 9
 38
Other Regulatory LiabilitiesVarious 5
 11
Total Regulatory Liabilities  605
 377
Less Current Portion1 89
 76
Total Non-Current Regulatory Liabilities  $516
 $301
(1)
Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Consolidated Balance Sheets due to the planned early retirement of the facilities. As of December 31, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 3 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2.
(2)
Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA. See Note 1 and Note 12 for additional information regarding income taxes.
(3)
Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037.
(4)
Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.
(5)
Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year amortization period.
(6)
In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued 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. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order.

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    


 December 31, 2014 December 31, 2013
 Millions of Dollars
Regulatory Assets—Current   
Property Tax Deferrals (1)
$21
 $20
PPFAC (2)
19
 4
Derivative Instruments (Note 10)15
 1
LFCR and DSM (2)
8
 3
San Juan Mine Fire Cost Deferral (2)
2
 10
Other Current Regulatory Assets (3)
4
 5
Total Regulatory Assets—Current69
 43
Regulatory Assets—Noncurrent   
Pension and Other Retiree Benefits (Note 8)126
 75
Income Taxes Recoverable Through Future Rates (4)
31
 22
PPFAC - Final Mine Reclamation and Retiree Health Care Costs (5)
29
 25
Springerville Lease Purchase Commitment Deferrals (6)
16
 2
Unamortized Loss on Reacquired Debt (7)
6
 7
LFCR (2)
4
 
Tucson to Nogales Transmission Line (8)
4
 5
Other Regulatory Assets (3)
7
 5
Total Regulatory Assets—Noncurrent223
 141
Regulatory Liabilities—Current   
RES (2)
(28) (22)
DSM (2)
(6) 
Fortis Merger Customer Credits (9)
(5) 
Other Current Regulatory Liabilities
 (2)
Total Regulatory Liabilities—Current(39) (24)
Regulatory Liabilities—Noncurrent   
Net Cost of Removal for Interim Retirements (10)
(265) (254)
Deferred Investment Tax Credits (11)
(25) (4)
Income Taxes Payable through Future Rates (4)
(20) (5)
Fortis Merger Customer Credits (9)
(11) 
Total Regulatory Liabilities—Noncurrent(321) (263)
Total Net Regulatory Assets (Liabilities)$(68) $(103)

(7)
Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal.
(8)
Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period.Rates. With the exception of interest earned on under-recovered PPFAC costs, we doEarly Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that weTEP either expectexpects to pay to customers through billing reductions in future periods or planplans to use for the purpose for which they were collected from customers.
(1)
Property Taxes are recovered over approximately a six months period as costs are paid, rather than as costs are accrued.
(2)
See Cost Recovery Mechanisms discussed above.
(3)
Other regulatory assets include self-insured medical costs and short-term disability costs recovered on a pay-as-you-go or cash basis; San Juan Coal Contract Amendment costs (recovery through 2017); rate case costs (recovery over three years); and environmental compliance costs (recovery over one year).
(4)
Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. See Note 1 of Notes to Consolidated Financial Statements.

63


With the exception of over-recovered PPFAC costs, TEP does not pay a return on regulatory liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    FERC COMPLIANCE

In 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 7 for additional information related to FERC compliance associated with these transmission contracts.


(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 deferred the increase in lease interest expense relating to the purchase commitments for Springerville Unit 1 and the Springerville Coal Handling Facilities to a regulatory asset because TEP believes the full purchase price is recoverable in rate base. See Note 5 of Notes to Consolidated Financial Statements.
(7)
In accordance with FERC guidelines, when TEP refinances its long-term debt, TEP defers and amortizes losses on reacquired debt over the life of the debt agreement.
(8)
TEP will request recovery from FERC for the costs incurred to develop a high-voltage transmission line from Tucson to Nogales; the project is not going forward. See Note 6 of Notes to Consolidated Financial Statements
(9)
Fortis Merger Customer Credits represent credits to be applied to customers’ bills according to the Merger Agreement. These credits will be applied to customer bills each year, October through March for a period of five years. See Note 1 of Notes to Consolidated Financial Statements.
(10)
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.
(11)
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 determineTEP determines that weit no longer meetmeets the criteria for continued application of regulatory accounting, weTEP would be required to write off ourits regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on ourTEP's financial statements.

NOTE 3.UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Utility Plant in Service on the Consolidated Balance Sheets by major class:
 December 31,
 2014 2013
 Millions of Dollars
Plant in Service:   
Electric Generation Plant$2,388
 $1,889
Electric Transmission Plant898
 825
Electric Distribution Plant1,398
 1,298
General Plant338
 312
Intangible Plant - Software Costs (1) (2)
149
 141
Electric Plant Held for Future Use4
 3
Total Plant in Service$5,175
 $4,468
    
Utility Plant under Capital Leases(3)
$667
 $638
 
Annual Depreciation Rate (4)
 
Average Remaining Life in Years (4)
 December 31,
($ in millions)  2017 2016
Plant in Service       
Generation Plant3.19% 25 $2,548
 $2,866
Transmission Plant1.48% 32 1,001
 1,024
Distribution Plant1.56% 36 1,632
 1,512
General Plant5.89% 12 389
 381
Intangible Plant, Software Costs, and Other (1)
Various Various 207
 185
Plant Held for Future Use  4
 7
Total Plant in Service (2)
    $5,781
 $5,975
        
Utility Plant Under Capital Leases (3)
    $85
 $167
(1) 
Primarily represents computer software. Unamortized computer software costs were $31$59 million and $52 million as of December 31, 2014,2017 and $392016, respectively. The amortization of computer software costs was $19 million asin 2017, $17 million in 2016, and $14 million in 2015. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of December 31, 2013.three years for large enterprise software.
(2) 
The amortizationIncludes plant acquisition adjustments of computer software costs was $17$(134) million in 2014, $14and $(139) million in 2013,as of December 31, 2017 and $13 million in 2012.2016, respectively.
(3) 
In 2014,December 2017, TEP entered into agreements tocompleted the purchase certainof an undivided ownership interest in the Springerville Coal Handling Facilities leased interests.Common Facilities. See Note 5 of Notes to Consolidated Financial Statements.

64


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Utility Plant under Capital Leases
All utility plant under capital leases is used in generation operations and amortized over the primary lease term. See Note 5 of Notes to Consolidated Financial Statements. At December 31, 2014, 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 generation-related capital leases:
 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Lease Expense:     
Interest Expense – Included in:     
Capital Leases$10
 $25
 $34
Operating Expenses – Fuel1
 2
 3
Amortization of Capital Lease Assets – Included in:     
Operating Expenses – Fuel6
 5
 4
Operating Expenses – Amortization16
 15
 14
Total Lease Expense$33
 $47
 $55
Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2014, were as follows:
 December 31, 2014
 
Annual Depreciation Rate (3)
 Average Remaining Life in Years
Major Class of Utility Plant in Service:   
Electric Generation Plant (1)
3.31% 22
Electric Transmission Plant1.48% 32
Electric Distribution Plant (1)
2.08% 35
General Plant (1)
5.48% 11
Intangible Plant (2)
Various Various
(1)
In June 2013,6 for additional information regarding 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 2 of Notes to Consolidated Financial Statements.Springerville leases.
(2)(4) 
The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life of three to five years for smaller application software. For large enterprise software, we use the remaining life depreciation method. At December 31, 2014, remaining lives ranged from one to six years.
(3)
The depreciation rates representRepresents a composite of the depreciation rates of assets within each major class of utility plant.plant and is based on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order.

6556

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Utility Plant Under Capital Leases
All assets included in Utility Plant Under Capital Leases are used in generation operations and amortized over the primary lease term. The following table shows the amount of lease expense incurred for capital leases:
 Years Ended December 31,
(in millions)2017 2016 2015
Lease Expense     
Interest Expense included in:     
Interest Expense, Capital Leases$3
 $3
 $4
Amortization of Capital Lease Assets included in:     
Operating Expenses, Fuel
 
 2
Operating Expenses, Amortization6
 5
 6
Total Lease Expense$9
 $8
 $12
Springerville Acquisitions
In September 2016, TEP purchased an undivided interest in Springerville Unit 1. The purchase increased TEP's total ownership interest to 100%. In December 2017, TEP purchased an undivided interest in the Springerville Common Facilities. As of December 31, 2017, Utility Plant Under Capital Leases represented a 32.2% undivided interest in certain Springerville Common Facilities. See Note 6 for additional information regarding the Springerville capital lease purchases.
JOINTLY-OWNED FACILITIES
AtAs of December 31, 2014,2017, TEP was a participant in the following jointly-owned generating stationsgeneration facilities and transmission systems as follows:systems:
Ownership Percentage Plant in Service 
Construction Work in
Progress
 Accumulated Depreciation Net Book Value
 Millions of Dollars
San Juan Units 1 and 250.0% $453
 $8
 $242
 $219
Navajo Units 1, 2, and 37.5% 153
 1
 112
 42
(in millions)Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value
San Juan Unit 150.0% $274
 $6
 $83
 $197
Four Corners Units 4 and 57.0% 104
 3
 77
 30
7.0% 113
 54
 79
 88
Luna Energy Facility33.3% 55
 
 2
 53
Luna33.3% 55
 
 3
 52
Gila River Unit 375.0% 186
 
 54
 132
75.0% 203
 3
 60
 146
Gila River Common Facilities18.75% 42
 
 11
 31
18.8% 25
 
 8
 17
Springerville Coal Handling Facilities83.0% 202
 
 81
 121
Transmission FacilitiesVarious 371
 21
 193
 199
Various 483
 5
 247
 241
Total $1,364
 $33
 $691
 $706
 $1,355
 $68
 $561
 $862
In December 2014, TEP completed the purchase of Gila River Unit 3. TEP jointly owns Gila River Unit 3 with UNS Electric, Inc., an affiliated subsidiary of UNS Energy (UNS Electric). See Note 7 of Notes to Consolidated Financial Statements.
As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. TEPThe Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
SpringervilleRETIREMENTS
San Juan Generating Station
In October 2014, the EPA published a final rule approving a SIP covering BART requirements for San Juan, which included the closure of Units 2 and 3 by December 2017. TEP is a participant in San Juan Units 1 and 2. Given the closure of Units 2 and 3 and the desire of certain participants to exit their ownership in San Juan, PNM, TEP, and the other participants negotiated restructured ownership agreements which became effective upon the sale of San Juan Coal Company (SJCC) stock in January 2016. Under the new restructured ownership agreements, TEP and the other remaining participants have the option to exit their remaining ownership interests in San Juan as of June 30, 2022.
In 2017, TEP recorded the early retirement San Juan Unit 12 and applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. The Consolidated Balance Sheets reflect a $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2. On December 20, 2017, San Juan Unit 2 was removed from service. See Note 2 for additional information regarding the 2017 Rate Order.
At
57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2014,2017. See Note 2 for additional information related to the planned early retirement of Navajo.
Sundt Generating Station
In March 2016, TEP owned 24.7%notified the EPA of Springerville Unitits decision to permanently eliminate coal as a fuel source to comply with the EPA rules and transferred the NBV of the coal handling facilities at Sundt to a regulatory asset. As approved in the 2017 Rate Order, TEP applied excess depreciation reserves against the regulatory asset as of December 31, 2017. See Note 2 for additional information regarding the 2017 Rate Order.
In 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of RICE generators in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and continued to lease2 by the remaining portionend of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the facility. Effective January 1, 2015, following completionplanned early retirement, $31 million of the purchasefacilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of anDecember 31, 2017. See Note 2 for additional 24.8% leased interest in Springerville Unitinformation related to the planned early retirement of Sundt Units 1 and expiration of the lease, TEP has a 49.5% ownership interest in the Springerville Unit 1 generating station and will operate the facility on behalf of third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). The Third-Party Owners are responsible for their share of operating and capital costs for the facility. See Note 6 of Notes to Consolidated Financial Statements.2.
ASSET RETIREMENT OBLIGATIONS
The accrual of AROs is primarily related to generation and photovoltaicPV assets and is included in Deferred CreditsRegulatory and Other LiabilitiesLiabilities—Other on the balance sheets.Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets:Consolidated Balance Sheets:
 December 31,
 2014 2013
 Millions of Dollars
Beginning Balance$22
 $14
Liabilities Incurred5
 
Accretion Expense or Regulatory Deferral1
 1
Revisions to the Present Value of Estimated Cash Flows (1)

 7
Ending Balance$28
 $22
 December 31,
(in millions)2017 2016
Beginning of Period$33
 $32
Liabilities Incurred3
 
Liabilities Settled(1) 
Regulatory Deferral/Accretion Expense2
 2
Revisions to the Present Value of Estimated Cash Flows (1)
9
 (1)
End of Period$46
 $33
(1) 
Primarily related to changes in expected cost estimates and the acceleration of asset retirement dates of generatingcertain generation facilities.

NOTE 4.ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:
 December 31,
(in millions)2017 2016
Customer$81
 $74
Due from Affiliates (Note 5)7
 9
Unbilled39
 34
Other16
 13
Allowance for Doubtful Accounts(5) (5)
Accounts Receivable, Net$138
 $125


6658

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 4. 5.RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including Unisource Energy Services, Inc., UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy affiliates)Affiliates). These transactions include salesthe sale and purchasespurchase of power and transmission services, common cost allocations, and the provision of corporate and other labor related services. Additionally, TEP and UNS Electric jointly own a generating station unit. See Note 7 of Notes to Consolidated Financial Statements.
The following table summarizespresents the components of related party transactions:balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets:
 Years Ended December 31,
 2014 2013 2012
 Millions of Dollars
Wholesale Sales - TEP to UNS Electric (1)
$4
 $1
 $2
Wholesale Sales - UNS Electric to TEP (1)
4
 2
 1
Control Area Services - TEP to UNS Electric (2)
3
 4
 3
Common Costs - TEP to UNS Energy Affiliates (3)
13
 12
 12
Supplemental Workforce - UNS Energy Affiliate to TEP (4)
16
 16
 17
Corporate Services - UNS Energy to TEP (5)
14
 5
 2
Corporate Services - UNS Energy Affiliates to TEP (6)
1
 1
 1
 December 31,
(in millions)2017 2016
Receivables from Related Parties   
UNS Electric$5
 $7
UNS Gas2
 2
Total Due from Related Parties$7
 $9
    
Payables to Related Parties   
SES$3
 $2
UNS Energy1
 
Total Due to Related Parties$4
 $2
The following table presents the components of related party transactions included in the Consolidated Statements of Income:
 Years Ended December 31,
(in millions)2017 2016 2015
Goods and Services Provided by TEP to Affiliates     
Transmission Revenues, UNS Electric (1) 
$7
 $7
 $6
Wholesale Revenues, UNS Electric (1)

 
 2
Control Area Services, UNS Electric (2)
3
 2
 2
Common Costs, UNS Energy Affiliates (3)
16
 14
 12
Corporate Services, Fortis Affiliates (4)
2
 
 
      
Goods and Services Provided by Affiliates to TEP     
Wholesale Revenues, UNS Electric (1)

 1
 1
Supplemental Workforce, SES (5)
15
 14
 16
Corporate Services, UNS Energy (6)
5
 7
 7
Corporate Services, UNS Energy Affiliates (7)
5
 4
 1
(1) 
TEP and UNS Electric sell power and transmission services to each otherother. Wholesale power is sold at prevailing market prices.prices while transmission services are sold at FERC approved rates through the applicable Open Access Transmission Tariff.
(2) 
TEP charges UNS Electric for control area services under a FERC-acceptedFERC-approved Control Area Services Agreement.
(3) 
Common costs (systems,(information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes thisThe method of allocation is reasonable.deemed reasonable by management and is reviewed by the ACC as part of the rate case process.
(4) 
SESTEP provides supplemental workforcenon-tariffed goods and meter-reading services to TEP. Amounts are based on costsFortis affiliate companies at the higher of services performed, and management believes that the charges for the services are reasonable.fully burdened cost or fair market value.
(5) 
Corporate costsSES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.
(6)
Costs for corporate services at UNS Energy such as merger costs and legal and audit fees, are allocated to its subsidiaries using the Massachusetts'Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 81%82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis Management fees. TEP's share of Fortis' management fees were $6 million in both 2017 and 2016, and $5 million in 2015.

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(6)(7) 
All Corporate ServicesCosts for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
At December 31, 2014CONTRIBUTION FROM PARENT
UNS Energy made no equity contributions to TEP in 2017 or 2016. TEP received a contribution from UNS Energy of $180 million in 2015. The contributions were used to repay revolving credit loans, redeem bonds, purchase additional generation capacity, and December 31, 2013, our Balance Sheets include the following intercompany balances:
provide additional liquidity to TEP.
 December 31, 2014 December 31, 2013
 Millions of Dollars
Receivables from Related Parties   
UNS Electric$4
 $3
UNS Gas1
 2
UNS Energy
 1
Total Due from Related Parties$5
 $6
    
Payables to Related Parties   
SES$2
 $2
UNS Electric1
 
UNS Energy
 7
Total Due to Related Parties$3
 $9
DIVIDENDS PAID TO PARENT


67


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    TEP declared and paid $70 million in dividends to UNS Energy in 2017 and $50 million in both 2016 and 2015.



NOTE 5. 6.DEBT, CREDIT FACILITIES,FACILITY, AND CAPITAL LEASE OBLIGATIONS
DEBT
Long-term debt matures more than one year from the date of the financial statements. We summarize TEP’s long-term debt in the statements of capitalization.
DEBT ISSUANCES AND REDEMPTIONS
Fixed Rate Notes
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may redeem the notes prior to September 2043, with a make-whole premium plus accrued interest. After September 2043, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the outstanding borrowings under the 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.
In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 2022, with a make-whole premium plus accrued interest. After December 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 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes.
Tax-Exempt Fixed Rate Bonds
In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit 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 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.
Tax-Exempt Variable Rate Bonds and Interest Rate Swap
In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP, 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. In 2014, the average monthly variable rate was 0.87% and ranged from 0.85% to 0.95%. In 2013, the average monthly variable rate was 0.95%. 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 $100 million variable rate bonds in December 2013.
Certain of TEP's tax-exempt, variable rate bonds are supported by Letter of Credits (LOCs) issued under the 2010 Credit Agreement and TEP Reimbursement Agreement, see below.
The following table shows interest rates (exclusivepresents the components of LOC and remarketing fees)Long-Term Debt, Net on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents:
the Consolidated Balance Sheets:
 Years Ended December 31,
 2014 2013 2012
Interest Rates on Bonds:     
Average Interest Rate0.08% 0.10% 0.17%
Range of Average Weekly Rates.05% - 0.13% 0.06% - 0.25% 0.06% - 0.26%
     December 31,
($ in millions)Interest Rate Maturity Date 2017 2016
Notes       
2011 Notes5.15% 2021 $250
 $250
2012 Notes3.85% 2023 150
 150
2014 Notes5.00% 2044 150
 150
2015 Notes3.05% 2025 300
 300
Tax-Exempt Local Furnishings Bonds       
2010 Pima A5.25% 2040 100
 100
2012 Pima A4.50% 2030 16
 16
2013 Pima A4.00% 2029 91
 91
2013 Apache A (1)
1.41% 2032 100
 100
Tax-Exempt Pollution Control Bonds       
2009 Pima A4.95% 2020 80
 80
2009 Coconino A5.13% 2032 15
 15
2010 Coconino A (2)
1.76% 2032 37
 37
2012 Apache A4.50% 2030 177
 177
Total Long-Term Debt (3)
    1,466
 1,466
Less Unamortized Discount and Debt Issuance Costs    12
 13
Less Current Maturities of Long-Term Debt (1)
    100
 
Total Long-Term Debt, Net    $1,354
 $1,453
(1)
The bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average based on a percentage of an index equal to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in November 2018, and were reclassified to Current Maturities of Long-Term Debt on the Consolidated Balance Sheets as of December 31, 2017.
(2)
The bonds are variable rate debt for which rates are reset weekly. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019.
(3)
As of December 31, 2017, all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by an LOC.

In September 2014, an interest rate swap TEP entered into in August 2009, expired. The interest rate swap had the economic effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014.
TEP MORTGAGE INDENTURE
Prior to November 2013, the 2010 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 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 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.

6860

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



CREDIT AGREEMENTS
2014 Credit AgreementDEBT ISSUANCES AND REDEMPTIONS
Fixed Rate Debt
In February 2015, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to December 2014,2024, with a make-whole premium plus accrued interest. On or after December 2024, TEP may redeem the notes at par plus accrued interest.
In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt IDRBs issued in June 2008 by the Industrial Development Authority (IDA) of Pima County, Arizona for the benefit of TEP. The bonds were not remarketed and were subsequently retired in September 2017.
Variable Rate Debt
In August 2015, TEP redeemed two series of variable rate tax-exempt bonds at par with an aggregate principal amount of $79 million prior to maturity. In September 2015, TEP terminated the associated LOCs issued under a revolving credit facility.
CREDIT FACILITY
In October 2015, TEP entered into an unsecured credit agreement (2014 Credit Agreement).which replaced its previous credit agreements. The 2014 Credit Agreement provides forcredit facility included: (i) a $130borrowing capacity of $250 million term loan commitment and a $70 millionin revolving credit commitment. Any amounts borrowed under the revolving credit commitment can be used for general corporate purposes. Amounts borrowed under the term loan can only be used to purchase certain tax-exempt bonds in lieucommitments; (ii) an LOC facility with a sublimit of redemption. All loans made pursuant to the term loan commitment$50 million; and the revolving credit commitment will be due and payable in November 2015, the termination(iii) an original maturity date of October 2020 with a provision allowing TEP to request up to twoone-year maturity extensions.
As permitted by the 2014 Credit Agreement.
In January 2015, amounts borrowed under the term loan commitment were used to purchase $130 million aggregate principal amount of unsecured IDRBs issued in June 2008 for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.750%credit agreement, TEP requested and mature in September 2029. At December 31, 2014, the bonds are classified as Long-Term Debt on TEP's balance sheet.
Loans under the 2014 Credit Agreement bear interest at a variable interest rate consisting of a spread over LIBOR or Alternate Base Rate. Alternate Base Ratewas granted twoone-year extensions. The facility's new maturity date is equal to the greater of (i) issuing bank's reference rate, (ii) the federal funds rate plus 1/2 of 1% or (iii) adjusted LIBOR for an interest period of one month plus 0.750%. The interest rate in effect on borrowings is LIBOR plus 0.750% for Eurodollar loans or Alternate Base Rate for Alternate Base Rate loans.
At December 31, 2014, TEP had a $70 million loan balance under the revolving credit facility and no borrowings under the term loan portion of the 2014 Credit Agreement. The revolving loan balance was included in Current Liabilities on TEP’s balance sheets. At December 31, 2014, there was nothing available under the revolving credit facility and $130 million available under the term loan for the 2014 Credit Agreement. As of 01/30/15, TEP had a $130 million term loan balance outstanding under the 2014 Credit Agreement and a $70 million revolving loan balance.
2010 Credit Agreement
TEP’s core credit facility, which was entered into in 2010 and amended in 2011 (2010 Credit Agreement), has an expiration date of November 2016, and will continue to provide TEP with access to $200 million of revolving credit and $82 million in LOCs supporting variable-rate tax-exempt bonds.October 2022.
Interest rates and fees under the 2010 Credit Agreementcredit facility 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%1.00% for Eurodollar loans or Alternate Base Rate plus 0.125%ABR with no spread for Alternate Base RateABR loans. The margin rate currently
TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of December 31, 2017, TEP had $35 million borrowings outstanding included in effectCurrent Liabilities on the $82 million LOC facility is 1.125%.
At December 31, 2014, TEP had $15 million in borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2013, TEP had no borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2014,Consolidated Balance Sheets. As of February 14, 2018, there was $185$232 million available under the revolving credit facilitycommitments and LOC facilities.
TEP's previous credit agreements provided for the 2010 Credit Agreement. The revolving loan balance was includeda total of $270 million in Current Liabilities on TEP’s balance sheets. The outstanding LOCs are not shown as liabilities on TEP’s balance sheets. As of 01/30/15, TEP had $170 million available under the 2010 Credit Agreement revolving credit facility.commitments, LOCs supporting variable-rate, tax-exempt bonds, and a $130 million term loan commitment, with original expiration dates of November 2016 and November 2015, respectively.
2010 TEP REIMBURSEMENT AGREEMENT
AIn December 2010, a $37 million LOC was issued to support certain variable rate tax-exempt bonds 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 LOChas an expiration date from 2014 toof February 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 1.00%0.75% per annum.annum based on TEP's current credit ratings.
COVENANT COMPLIANCE
The 2014 Credit Agreement, 2010 Credit Agreement, 2010 TEP Reimbursement Agreement, 2013 Covenants Agreement,Certain of TEP's credit 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.
At As of December 31, 2014, we were2017, TEP was in compliance with the terms of ourits credit and long-term debt 2014 Credit Agreement, 2010 Credit Agreement, 2013 Covenants Agreement, andagreements.
CAPITAL LEASE OBLIGATIONS
The following table details Capital Lease Obligations on the 2010 TEP Reimbursement Agreement.Consolidated Balance Sheets:
 December 31,
(in millions)2017 2016
Capital Lease Obligations$39
 $91
Less Current Obligations Under Capital Leases11
 52
Total Capital Lease Obligations, Non-Current$28
 $39

6961

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



CAPITAL LEASE OBLIGATIONS
In January 2015, TEP reduced its capital lease obligations through the scheduled purchase payment for Springerville Unit 1 of $43 million and scheduled payments on other leases of $9 million.
Springerville Unit 1 Capital Lease Purchases
The Springerville Unit 1 Leases had an initial term toIn January 2015, and included a fair market value purchase option at the endupon expiration of the initial lease term.
In December 2014, TEP purchased a 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million, the appraised value. Upon purchase, TEP reduced Capital Lease Obligations on its balance sheet for the purchase price. In January 2015,term, TEP purchased 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.
With the completion of these lease option purchases,the purchase, TEP ownsowned 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore,
In September 2016, TEP is obligatedpurchased the remaining undivided interest in Springerville Unit 1 for $85 million, bringing its total ownership of the assets to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated100% and total generating capacity to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $1.5 million per month and their share of capital expenditures, which are approximately $7 million in 2015.387 MW. See Note 6 of Notes7 for more information regarding the settlement agreement relating to Consolidated Financial Statements.Springerville Unit 1.
Springerville Coal Handling Facilities Lease Purchase Commitment
In April 2014,2015, upon expiration of the lease term, TEP notified the owner participants and their lessors that TEP has elected to purchase theirpurchased an 86.7% undivided ownership interestsinterest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, upon the expirationbringing its total ownership of the lease term in April 2015. Dueassets to TEP’s100%. Upon purchase commitment, in April 2014, TEP recorded an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the totalleased interest, TEP reduced Capital Lease Obligations on the Consolidated Balance Sheets for the purchase commitment.price.
Upon TEP's purchase,In May 2015, SRP, is obligated to buythe owner of Springerville Unit 4, purchased from TEP a portion of17.05% undivided interest in the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at December 31, 2014.million.
Springerville Common Facilities Leases
TheAs of December 31, 2017, the Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the otherinclude two leases subject to optional renewalwith a total fixed price purchase options of $68 million and initial terms ending January 2021.
Under the two leases, TEP has options to: (i) renew the leases for periods of two or more years through 2025. Instead of extendingyears; or (ii) exercise the leases,fixed price purchase options under these contracts. In addition, 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 agreedentered into agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions if the Springerville Coal Handling Facilities and Common Facilities Leases are not renewed,renewed: (i) TEP will exercise the purchase options under these contracts.contracts; (ii) SRP will then be obligated to buy a portion of these facilities14% undivided interest in the facilities; and (iii) Tri-State will then be obligated to either: (a) buy a portion of these14% undivided interest in the facilities; or (b) continue makingto make payments to TEP for the use of these facilities.
In December 2017, TEP purchased a 17.8% undivided interest in the Springerville Common Facilities for$38 million, bringing its total ownership of the assets to 67.8%. Upon purchase of the leased interest, TEP reduced Current Lease Debt and Equity
Investments in Springerville Lease Debt and Equity
In January 2013, TEP received the final maturity payment of $9 millionObligations on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totalingConsolidated Balance Sheets by $36 million at December 31, 2013. At December 31, 2014, $36 million was transferred from Lease Equity Investment to Plant in Service on TEP's balance sheet.million.
Interest Rate Swap—Springerville Common Facilities Lease DebtInterest Rate Swap
TEP’sTEP entered into an interest rate swap agreement in 2006 that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month LIBOR plus a credit spread. The applicable spread was 1.75% at December 31, 2014 and December 31, 2013.

70


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The swap has the effect of fixing the interest ratesbenchmark LIBOR rate on a portion of the amortizing principal balancesbalance. The swap matures in January 2020 with interest on the lease debt payable at a swapped rate of 5.77% plus an applicable margin per the lease agreement. The lease debt outstanding as follows:
of December 31, 2017 consisted of a notional amount of $18 million on which interest was fixed by the swap and a notional amount of $3 million of debt that was not hedged. The applicable margin was 1.88% as of December 31, 2017 and 2016.
Lease Debt Outstanding at December 31, 2014
Fixed
Rate
 
LIBOR
Spread
Notional Amount $32 million - Effective Date June 20065.77% 1.75%
TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 1011 for additional information.

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



DEBT MATURITIES
Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
Long-Term
Debt
Maturities (1)
 
Capital
Lease
Obligations
 

Total
Millions of Dollars
2015$
 $188
 $188
201679
 16
 95
2017
 18
 18
(in millions)
Long-Term Debt(1)
 Capital Lease Obligations 
Total Debt Maturities(2)
2018100
 11
 111
$100
 $11
 $111
201937
 12
 49
37
 11
 48
Total 2015 - 2019216
 245
 461
202080
 18
 98
2021250
 
 250
2022
 
 
Total 2018 - 2022467
 40
 507
Thereafter1,159
 18
 1,177
999
 
 999
Less: Imputed Interest
 (20) (20)
 (1) (1)
Total$1,375
 $243
 $1,618
$1,466
 $39
 $1,505
(1) 
$11537 million of TEP’s variable rate bonds are backed by LOCsan LOC issued pursuant to the 2010 Credit Agreement, which expires in November 2016, and the TEP 2010 Reimbursement Agreement, which expires in DecemberFebruary 2019. Although the variable rate bonds mature between 2022 andbond matures in 2032, the above table reflects a redemption or repurchase of such bondsbond in 2016 and 2019 as though the LOCs terminateLOC terminates without replacement upon expiration of the 2010 Credit Agreement and the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018. The repayment
(2)
Total long-term debt excludes $10 million of TEP Unsecured Notes is not reduced by the remainingrelated unamortized debt issuance costs and $2 million of unamortized original issue discount.

NOTE 6. 7.COMMITMENTS CONTINGENCIES, AND ENVIRONMENTAL MATTERSCONTINGENCIES
COMMITMENTS
AtAs of December 31, 2014,2017, TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases.leases:
2015 2016 2017 2018 2019 Thereafter Total
Millions of Dollars
(in millions)2018 2019 2020 2021 2022 Thereafter Total
Fuel, Including Transportation$76
 $78
 $76
 $49
 $49
 $285
 $613
$82
 $83
 $73
 $43
 $24
 $244
 $549
Purchased Power22
 7
 
 
 
 
 29
29
 
 
 
 
 
 29
Transmission6
 6
 6
 6
 4
 16
 44
19
 19
 8
 4
 1
 8
 59
Renewable Power Purchase Agreements45
 45
 45
 45
 44
 565
 789
64
 64
 63
 63
 63
 668
 985
RES Performance-Based Incentives8
 8
 8
 8
 8
 76
 116
8
 8
 7
 7
 7
 46
 83
Operating Leases:             
Operating Leases (1)
1
 1
 1
 1
 1
 3
 8
Land Easements and Rights-of-Way2
 1
 1
 1
 2
 77
 84
1
 1
 1
 2
 2
 82
 89
Operating Leases Other1
 1
 1
 1
 1
 5
 10
Total Purchase Commitments$160
 $146
 $137
 $110
 $108
 $1,024
 $1,685
$204
 $176
 $153
 $120
 $98
 $1,051
 $1,802

(1)
Primarily represents leases for land, rail cars, and office facilities with varying terms, provisions, and expiration dates through 2036. TEP's operating lease expense totaled $1 million in 2017, $2 million in 2016, and $3 million in 2015.
71


Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBIs costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Fuel, Including Transportation
TEP has long-term contractsagreements for the purchase and delivery of coal with various expiration dates throughbetween 2020 and 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contractsagreements include a price adjustment clausecomponents 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.costs.

63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These contractsagreements expire in various years between 20172018 and 2040. In January 2018, TEP entered into a transportation agreement with EPNG extending the expiration date of the existing agreement from April 2018 to April 2023. Estimated future payments not included in the table above are: $4 million in 2018; $5 million in 2019 through 2022; and $1 million through the end of the contract.
Purchased Power and Transmission
TEP has agreementscontracts 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 expirewith various expiration dates through 2017.the fourth quarter of 2018. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2014.2017.
Transmission
TEP has agreements with other utilities to providepurchase transmission services.services over lines that are part of the Western Interconnection, a regional grid in the United States. These contractsagreements expire in various years between 20182019 and 2028.
TEP's purchased power and transmission costs are recoverable from customers through the PPFAC mechanisms.2030.
Renewable Power Purchase Agreements and RES Performance-Based Incentives
TEP has enteredenters into 20 year Renewablelong-term renewable PPAs which require TEP to purchase 100% of the output of certain renewable energy generation facilities that have achievedoutput once commercial operation.operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements haveexpire in various expiration dates through 2034. TEP has entered into additional long-term renewable PPAs to comply with years between 2027 and 2036.
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 2 of Notes to Consolidated Financial Statements.Performance-Based Incentives
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs)PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2 of Notes to Consolidated Financial Statements.These agreements expire in various years between 2020 and 2034.
Operating LeasesLand Easements and Rights-of-Way
Our operating lease expense is primarily for rail cars, office facilities, land easements,Land Easements and rights-of-way withRights-of-Way have varying terms and provisions, and various expiration dates. TEP's operating lease expense totaled $3 million in 2014, and $2 million in each of 2013 and 2012.
CONTINGENCIES
Navajo Generating Station Lease Extension
Navajo Generating Station (Navajo) is located on a site that is leased fromdates through 2054. In November 2017, the Navajo Nation withapproved an initial lease term through 2019.extension for the use of their land. The extension, signed by TEP and the co-owners of Navajo, commences in December 2019 and ends in December 2054. The Navajo Nation signed a lease amendment that would extendhas until December 2018 to select one of five different rental payments options provided for in the leaseextension. The table above includes TEP's 7.5% ownership share of the option which, in management's opinion, is most probable to occur. The total obligation estimated under this option is $8 million commencing in 2019 through 2053. Under the remaining payment options, TEP's share of estimated total payment obligation ranges from $3 million to $8 million with various payment schedules with dates ranging from 2019 through 2044. The participants in Navajo, including 2053.
CONTINGENCIES
Legal Matters
TEP have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agreeis party to the terms. To become effective, this lease amendment must be signed by alla variety of legal actions arising out of the participants, approved by the Departmentnormal course of the Interior,business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its consolidated financial results. TEP is subjectalso involved in other kinds of legal actions, some of which assert or may assert claims or seek to environmental reviews.impose fines, penalties, and other costs in substantial amounts on TEP owns 7.5% of Navajo and in December 2014, recorded additional lease expense of approximately $2 million related to the lease extension in Deferred Credits and Other Liabilities—Other on TEP's balance sheet.are disclosed below.
Claims Related to Springerville Generating Station Unit 1
On November 7, 2014,In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the Third-Party Owners filed a complaint (FERC Action) againstOwners’ undivided interest in Springerville Unit 1 for $85 million. As also provided for in the Agreement, TEP at the FERC alleging that TEP had not agreed to wheel power and energy forreceived $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues—Other on the manner specified inConsolidated Statements of Income. Following the Springerville Unit 1 facility support agreementpurchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1 2015 to the Palo Verde switchyard and for thewere dismissed with prejudice.

7264

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint.
On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners' instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses.
On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice.
TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.
Claims Related to San Juan Generating Station
San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC 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.WildEarth Guardians
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.
In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United StatesU.S. District Court for the District of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for reliefincluding two issued in the WEG Petition, two concern SJCC’s2008 related to SJCC 's San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEGThe petition alleges various National Environmental Policy Act (NEPA) violations against the OSM, including, but not limited to, OSM’s allegedincluding: (i) failure to provide requisite public notice and participation, allegedparticipation; and (ii) failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.impacts. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until they can demonstrate compliance with the NEPA, has been demonstrated, and enjoining operations at the sevenaffected mines. SJCC intervened in this matter. The Courtmatter and was granted SJCC’sits motion to sever its claims from the lawsuit and transfer venue to the United StatesU.S. District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtainspending. In July 2016, the relief it has requested, suchfederal defendants filed a ruling could require significant expendituresmotion asking that the matter be voluntarily remanded to reconfigure operations at the San Juan mine,OSM so the OSM may prepare a new environmental impact statement (EIS) under the production of coal, and impactNEPA regarding the economic viabilityimpacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSM’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine and San Juan.plan will immediately be vacated, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

73


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Claims Related to Four Corners Generating Station
In October 2011, EarthJustice, on behalf ofEndangered Species Act
On April 20, 2016, several environmental organizations,groups filed a lawsuit in the United StatesU.S. District Court for the District of New MexicoArizona against Arizona Public Service Company (APS)the OSM and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s review processnecessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the other Four Corners Generating Station (Four Corners) participants alleging violations ofadjacent Navajo Mine. In addition, the Prevention of Significant Deterioration (PSD) provisions oflawsuit alleges that these federal agencies violated both 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,ESA and the plaintiffs seekNEPA in providing the federal approvals necessary to have the court issue an order to ceaseextend operations at Four Corners until any required PSD permits are issued and order the paymentNavajo Mine past July 6, 2016. The lawsuit seeks various forms of civil penalties,relief, including a beneficial mitigation project.finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo Mine pending compliance with NEPA. In April 2012,July 2016, the defendants answered the complaint and APS, filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until March 31, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation.
TEP owns 7%operator of Four Corners, Units 4 and 5 and is liable for its share of any resulting liabilities. TEP's estimated share of the settlement offer submitted by APSfiled a motion to intervene in this matter. APS’ motion was granted in August 2014 is less than $1 million.2016. In September 2016, Navajo Transitional Energy Company, LLC (NTEC), the company that owns the Navajo Mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice. In November 2017, the plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit the District Court’s decision to dismiss the case. TEP cannot currently 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 ofmatter or the range of costs at this time.
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. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting 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. The New Mexico Taxation and Revenue Department and APS continue with settlement negotiations. TEP cannot predict the outcome or timing of resolution of this claim.potential impact.
Mine Closure Reclamation at Generating StationsFacilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generating stationsgeneration facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine 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 $49$61 million upon expiration of the coal supply agreements, which expire between 20172019 and 2031. The Consolidated Balance Sheets reflect a total liability related to reclamation liability (present value of future liability) recorded was $22$34 million atand $26 million as of December 31, 20142017 and $18 million at December 31, 2013.2016, respectively.
Amounts recorded for final mine 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.expected inflation rate. 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 usthe Company to pass through final mine reclamation costs, as a component of fuel cost,costs, to retail 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. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case.
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-

7465

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



defaultingFERC Compliance
In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews), and made compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard service agreement form.
In 2016, as a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016. In 2016, Wholesale Revenues on the Consolidated Statements of Income reflected $22 million, and, as of December 31, 2016, Current Liabilities—Other on the Consolidated Balance Sheets reflected $5 million related to the time-value refunds.
In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In accordance with the agreement, the counterparty paid TEP $8 million, which TEP recorded in Other Income on the Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017.
In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Consolidated Balance Sheets, offsetting Wholesale Revenues on the Consolidated Statements of Income.
Performance Guarantees
TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear aits 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 generatinggeneration capacity of the defaulting participants.participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of December 31, 2014,2017, there have been no such payment defaults under any of the remote generating stationparticipation agreements. TEP's jointThe Navajo participation agreements expireagreement expires in 2016 through 2046.
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 $11 million in 2014, $5 million in 2013, and $2 million in 2012 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $28 million in 2015 and $19 million in 2016. In addition, TEP recorded O&M expenses of $5 million in 2014, $8 million in 2013, and $15 million in 2012. TEP expects environmental O&M expenses to be $4 million in each of 2015 and 2016.
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 Standards (MATS) rules, additional emission control equipment will be required by April 2015. TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules. TEP's share of the estimated costs to comply with the MATS rules includes the following:
Estimated Mercury Emissions Control Costs:Navajo 
Springerville(1)
 Millions of Dollars
Capital Expenditures$1
 $5
Annual O&M Expenses1
 1
(1)
Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
TEP expects Four Corners, Sundt, and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules. Therefore, TEP expects no additional capital expenditures or O&M expenses will be incurred to comply. Although expected to be compliant, Sundt would be required to install additional monitoring equipment, at an estimated cost of less than $1 million, to continue to burn coal after the MATS rules become effective.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on land leased from the Navajo Nation, 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 selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.

75


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP's estimated costs involved in meeting these rules are:
Estimated NOx Emissions Control Costs:
Navajo (1)
 
San Juan (2)
 
Four Corners (3)
 
Sundt (4)
 Millions of Dollars
Capital Expenditures$28
 $37
 $35
 $12
Annual O&M Expenses1
 1
 2
 5-6
(1)
In August 2014, the EPA published a final FIP wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The plant has until December 2019, to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
(2)
In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
(3)
In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
(4)
In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection 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. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

NOTE 7. PURCHASE OF GAS-FIRED GENERATION FACILITY
On December 10, 2014, TEP and UNS Electric acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW) for $164 million, and UNS Electric purchased the remaining 25% undivided interest. Upon the closing of the transaction, the letter of credit TEP provided in June 2014 for $15 million was canceled.
TEP’s purchase of Gila River Unit 3 is intended to replace the reduction of 195 MW of output from Springerville Unit 1 and the 170 MW of capacity expected to be retired at San Juan in 2017.
The transaction has been accounted for using the acquisition method of accounting which requires that assets acquired2022, Four Corners in 2041, and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:
 Millions of Dollars
Utility Plant - Net$163
Materials and Supplies2
ARO Obligation Assumed (1)
(1)
Total Purchase Price$164
(1)
The ARO obligation was recorded at net present value in Deferred Credits and Other Liabilities - Other on TEP's balance sheet.


76


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    Luna in 2046.



NOTE 8.EMPLOYEE BENEFIT PLANS
PENSION BENEFIT PLANS
We sponsor twoTEP has three noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees.plans. Benefits are based on years of service and average compensation. We fundTwo of the pensionplans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.
We TEP also maintainmaintains a Supplemental Executive Retirement Plan (SERP)SERP for executive management.
OTHER RETIREE BENEFIT PLANSPOSTRETIREMENT BENEFITS PLAN
TEP provides limited health carehealthcare 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.
TEP funds its other retireepostretirement benefits for classified employees through a Voluntary Employee Beneficiary Association (VEBA).VEBA. TEP contributed $3 million in each of 2014, 20132017, $2 million in 2016, and 2012$4 million in 2015 to the VEBA. Other retireepostretirement 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 recordTEP records changes in our non-SERP pension plans and other retireepostretirement defined benefit plan,plans, 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 our balance sheet are:

 Pension Benefits 
Other Retiree
Benefits
 Years Ended December 31,
 2014 2013 2014 2013
 Millions of Dollars
Regulatory Pension Asset Included in Other Regulatory Assets$117
 $71
 $9
 $4
Accrued Benefit Liability Included in Accrued Employee Expenses(1) (1) (2) (2)
Accrued Benefit Liability Included in Pension and Other Retiree Benefits(71) (23) (67) (62)
Accumulated Other Comprehensive Loss (related to SERP)5
 2
 
 
Net Amount Recognized$50
 $49
 $(60) $(60)

77

66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the Consolidated Balance Sheets:
 Pension Benefits Other Postretirement Benefits
 December 31,
(in millions)2017 2016 2017 2016
Regulatory Assets$121
 $123
 $5
 $5
Accrued Employee Expenses(1) (1) (2) (2)
Pension and Other Postretirement Benefits(71) (69) (63) (63)
Accumulated Other Comprehensive Loss, SERP9
 6
 
 
Net Amount Recognized$58
 $59
 $(60) $(60)
OBLIGATIONS AND FUNDED STATUS
WeThe Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations and other retiree benefit plans atas of December 31, 20142017 and December 31, 2013.2016. The table below includespresents the status of all of TEP’s pension and other postretirement benefit plans. All plans have projected benefit obligations in excess of the fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below:presented:
 Pension Benefits 
Other Retiree
Benefits
 Years Ended December 31,
 2014 2013 2014 2013
 Millions of Dollars
Change in Projected Benefit Obligation       
Benefit Obligation at Beginning of Year$330
 $357
 $74
 $77
Actuarial (Gain) Loss67
 (35) 5
 (5)
Interest Cost16
 14
 3
 3
Service Cost10
 11
 4
 3
Benefits Paid(16) (17) (5) (4)
Projected Benefit Obligation at End of Year407
 330
 81
 74
Change in Plan Assets       
Fair Value of Plan Assets at Beginning of Year307
 275
 10
 7
Actual Return on Plan Assets35
 27
 1
 1
Benefits Paid(16) (17) (5) (4)
Employer Contributions (1)9
 22
 6
 6
Fair Value of Plan Assets at End of Year335
 307
 12
 10
Funded Status at End of Year$(72) $(23) $(69) $(64)
 Pension Benefits Other Postretirement Benefits
 Years Ended December 31,
(in millions)2017 2016 2017 2016
Change in Benefit Obligation       
Beginning of Period$424
 $394
 $79
 $78
Actuarial Loss42
 20
 1
 
Interest Cost15
 15
 2
 2
Service Cost13
 12
 4
 4
Benefits Paid(19) (17) (4) (5)
End of Period475
 424
 82
 79
Change in Fair Value of Plan Assets       
Beginning of Period354
 336
 14
 13
Actual Return on Plan Assets59
 27
 2
 1
Benefits Paid(19) (17) (4) (5)
Employer Contributions (1)
9
 8
 5
 5
End of Period403
 354
 17
 14
Funded Status at End of Period$(72) $(70) $(65) $(65)
(1) 
In 2015, TEP expects to contribute $23$11 million to the pension plans.plans in 2018.
The following table provides the components of TEP’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
Pension Benefits Other Postretirement Benefits
Years Ended December 31,Years Ended December 31,
2014 2013 2014 2013
Millions of Dollars
(in millions)2017 2016 2017 2016
Net Loss$118
 $74
 $11
 $6
$129
 $128
 $5
 $6
Prior Service Cost (Benefit)4
 
 (2) (2)1
 
 (1) (1)
The accumulated benefit obligation aggregated for all pension plans is $365$428 million atand $384 million as of December 31, 20142017 and $297 million at December 31, 2013.
Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
 December 31,
 2014 2013
 Millions of Dollars
Accumulated Benefit Obligation at End of Year$365
 $13
Fair Value of Plan Assets at End of Year335
 
Only2016, respectively. Two of the SERP, which is unfunded, had accumulated benefit obligations in excess of plan assets at December 31, 2013. Due to decreases in discount rates, and changes in mortality projections which reflect a longer life expectancy, all of ourpension plans had accumulated benefit obligations in excess of plan assets atas of December 31, 2014.2017, compared to three as of December 31, 2016, as a result of market gains on plan assets in 2017. The following table

7867


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:
 December 31,
(in millions)2017 2016
Accumulated Benefit Obligation$237
 $384
Fair Value of Plan Assets206
 354
Beginning in 2016, the Company elected to measure service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Prior to 2016, the Company measured service and interest costs for pension and other postretirement benefits utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. TEP believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans' liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of its plan obligations nor the funded status. TEP accounted for this change as a change in accounting estimate, and accordingly, accounted for it on a prospective basis. Net periodic benefit plan cost includes the following components:
Pension Benefits Other Retiree BenefitsPension Benefits Other Postretirement Benefits
Year Ended December 31,Years Ended December 31,
2014 2013 2012 2014 2013 2012
Millions of Dollars
(in millions)2017 2016 2015 2017 2016 2015
Service Cost$10
 $11
 $9
 $4
 $3
 $3
$13
 $12
 $12
 $4
 $4
 $4
Interest Cost16
 14
 15
 3
 3
 3
15
 15
 17
 2
 2
 3
Expected Return on Plan Assets(21) (19) (17) (1) (1) 
(25) (23) (23) (1) (1) (1)
Actuarial Loss Amortization3
 8
 7
 
 
 
Amortization of Net Loss8
 7
 7
 
 
 
Net Periodic Benefit Cost$8
 $14
 $14
 $6
 $5
 $6
$11
 $11
 $13
 $5
 $5
 $6
Approximately 20%18% 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 arewere as follows:
 Pension Benefits
 2014 2013 2012
 
Regulatory
Asset
 AOCI 
Regulatory
Asset
 AOCI 
Regulatory
Asset
 AOCI
 Millions of Dollars
Current Year Actuarial (Gain) Loss$49
 $3
 $(42) $(1) $28
 $1
Amortization of Actuarial Gain (Loss)(3) 
 (8) 
 (7) 
Total Recognized (Gain) Loss$46
 $3
 $(50) $(1) $21
 $1
 Other Retiree Benefits
 2014 2013 2012
 
Regulatory
Asset
 
Regulatory
Asset
 
Regulatory
Asset
 Millions of Dollars
Current Year Actuarial (Gain) Loss$5
 $(6) $2
 Pension Benefits Other Postretirement Benefits
 Regulatory Asset AOCI Regulatory Asset
(in millions)2017 2016 2015 2017 2016 2015 2017 2016 2015
Current Year Actuarial (Gain) Loss$5
 $15
 $5
 $3
 $1
 $
 $(1) $
 $(4)
Amortization of Net Loss(7) (7) (7) 
 
 
 
 
 
Total Recognized (Gain) Loss$(2) $8
 $(2) $3
 $1
 $
 $(1) $
 $(4)
For all pension plans, we amortizeTEP amortizes 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 $7 million estimated net loss and less than $0.5 million prior service creditplans. Estimated amortization from other regulatory assets and less than $0.5 million net loss and less than $0.5 million prior service cost from AOCI into net periodic benefit cost in 2015. Less than $0.5 million estimated net loss and less than $0.5 million prior service benefit for the other retiree benefit plan will be amortized from other regulatory assets into net periodic benefit cost in 2015.2018 includes the following:
 Pension Benefits 
Other Retiree
Benefits
 2014 2013 2014 2013
Weighted-Average Assumptions Used to Determine
Benefit Obligations as of December 31,
       
Discount Rate4.1 - 4.2% 5.0% - 5.1% 3.9% 4.7%
Rate of Compensation Increase3.0% 3.0% N/A N/A
 Pension Benefits Other Retiree Benefits
 2014 2013 2012 2014 2013 2012
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31,           
Discount Rate5.0% - 5.1% 4.1% - 4.1% 4.9% - 5.0% 4.7% 3.8% 4.7%
Rate of Compensation Increase3.0% 3.0% 3.0% N/A N/A N/A
Expected Return on Plan Assets7.0% 7.0% 7.0% 7.0% 7.0% 7.0%
(in millions)Pension Benefits Other Postretirement Benefits
Net Loss$7
 $

79



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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. 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.
We useTEP uses 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 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward lookingforward-looking return expectations only. The above method is used for all asset classes.

68


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Changes that may arise over time with regardThe following table includes the weighted average assumptions used to thesedetermine benefit obligations:
 Pension Benefits Other Postretirement Benefits
 2017 2016 2017 2016
Discount Rate3.7% 4.2% 3.6% 4.0%
Rate of Compensation Increase2.8% 2.8% N/A N/A
The following table includes the weighted average assumptions and determinations will change amounts recorded in the future asused to determine net periodic benefit cost. The assumed health carecosts:
 Pension Benefits Other Postretirement Benefits
 2017 2016 2015 2017 2016 2015
Discount Rate, Service Cost4.4% 4.8% 4.2% 4.3% 4.6% 3.9%
Discount Rate, Interest Cost3.7% 3.9% 4.2% 3.3% 3.4% 3.9%
Rate of Compensation Increase2.8% 3.0% 3.0% N/A N/A N/A
Expected Return on Plan Assets7.0% 7.0% 7.0% 7.0% 7.0% 7.0%
Healthcare cost trend rates follow:are assumed to decrease gradually from next year to the year the ultimate rate is reached:
 December 31,
 2014 2013
Health Care Cost Trend Rate Assumed for Next Year6.7% 6.7%
Ultimate Health Care Cost Trend Rate Assumed4.5% 4.5%
Year that the Rate Reaches the Ultimate Trend Rate2027 2027
 December 31,
 2017 2016
Next Year7.6% 7.6%
Ultimate Rate Assumed4.5% 4.5%
Year Ultimate Rate is Reached2036 2037
Assumed health carehealthcare cost trend rates significantly affect the amounts reported for health carehealthcare plans. A one-percentage-point change in assumed health carehealthcare cost trend rates would have the following effects on the December 31, 2014, 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 Obligation7
 6
 
One-Percentage-
Point Increase
 
One-Percentage-
Point Decrease
(in millions)December 31, 2017
Increase (Decrease) on Total Service and Interest Cost Components$1
 $(1)
Increase (Decrease) on Other Postretirement Benefits Obligation7
 (6)
PENSION PLAN AND OTHER RETIREEPOSTRETIREMENT BENEFIT ASSETS
Pension Assets
We calculateTEP calculates the fair value of plan assets on December 31, the measurement date. Pension plan assetAsset allocations, by asset category, on the measurement date were as follows:
Pension Other Postretirement Benefits
2014 20132017 2016 2017 2016
Asset Category      
Equity Securities48% 50%46% 49% 63% 60%
Fixed Income Securities43% 40%45% 41% 35% 35%
Real Estate7% 7%7% 8% % 2%
Other2% 3%2% 2% 2% 3%
Total100% 100%100% 100% 100% 100%
As of December 31, 2017, the fair value of VEBA trust assets was $17 million, of which $6 million were fixed income investments and $11 million were equities. As of December 31, 2016, the fair value of VEBA trust assets was $14 million, of which $5 million were fixed income investments and $9 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust.

8069


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following tables set forthpresent the fair value measurements of pension plan assets by level within the fair value hierarchy:
Fair Value Measurements of Pension Assets
December 31, 2014
Level 1 Level 2 Level 3 Total
Quoted Prices
in Active
Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
Millions of Dollars
(in millions)December 31, 2017
Asset Category              
Cash Equivalents$1
 $
 $
 $1
$1
 $
 $
 $1
Equity Securities:              
United States Large Cap
 82
 
 82

 66
 
 66
United States Small Cap
 17
 
 17

 19
 
 19
Non-United States
 61
 
 61

 72
 
 72
Global
 30
 
 30
Fixed Income
 143
 
 143

 179
 
 179
Real Estate
 8
 16
 24

 9
 21
 30
Private Equity
 
 7
 7

 
 6
 6
Total$1
 $311
 $23
 $335
$1
 $375
 $27
 $403
              
Fair Value Measurements of Pension Assets
December 31, 2013
Level 1 Level 2 Level 3 Total
Millions of Dollars
(in millions)December 31, 2016
Asset Category              
Cash Equivalents$1
 $
 $
 $1
$1
 $
 $
 $1
Equity Securities:      
      

United States Large Cap
 76
 
 76

 61
 
 61
United States Small Cap
 16
 
 16

 18
 
 18
Non-United States
 62
 
 62

 67
 
 67
Global
 28
 
 28
Fixed Income
 124
 
 124

 144
 
 144
Real Estate
 7
 14
 21

 9
 19
 28
Private Equity
 
 7
 7

 
 7
 7
Total$1
 $285
 $21
 $307
$1
 $327
 $26
 $354
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 onvalues are generally determined by appraisals comprising 100%conducted in accordance with accepted appraisal guidelines, including consideration of real estate assets tracked byprojected income and expenses of the index in 2014 and comprising 85% in 2013.property as well as recent sales of similar properties.
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.

70


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following tables set forthtable presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.

81



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



 Year Ended
December 31, 2014
 
Private
Equity
 Real Estate Total
 Millions of Dollars
Beginning Balance at January 1, 2014$7
 $14
 $21
Actual Return on Plan Assets:     
Assets Held at Reporting Date1
 2
 3
Purchases, Sales, and Settlements(1) 
 (1)
Ending Balance at December 31, 2014$7
 $16
 $23
Year Ended
December 31, 2013
Private
Equity
 Real Estate Total
Millions of Dollars
Beginning Balance at January 1, 2013$6
 $13
 $19
(in millions)Private Equity Real Estate Total
Balance as of December 31, 2015$7
 $18
 $25
Actual Return on Plan Assets:         

Assets Held at Reporting Date1
 1
 2
1
 1
 2
Ending Balance at December 31, 2013$7
 $14
 $21
Purchases, Sales, and Settlements(1) 
 (1)
Balance as of December 31, 20167
 19
 26
Actual Return on Plan Assets:     
Assets Held at Reporting Date1
 2
 3
Purchases, Sales, and Settlements(2) 
 (2)
Balance as of December 31, 2017$6
 $21
 $27
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 considerTEP considers 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 expectTEP expects 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 recognizeTEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognizeThe Company recognizes 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: (i) plan status,status; (ii) plan sponsor financial status and profitability,profitability; (iii) plan features,features; and (iv) workforce characteristics. We haveTEP 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.

8271


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, 2014 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced.
TEP Plans VEBA TrustPension Other Postretirement Benefits
December 31, 2017
Cash/Treasury Bills—% 2%
Equity Securities: 
United States Large Cap16% 39%
United States Small Cap5% 5%
Non-United States Developed14% 7%
Non-United States Emerging4% 9%
Global Equity4% —%
Global Infrastructure3% —%
Fixed Income41% 38%45% 38%
United States Large Cap24% 39%
Non-United States Developed15% 7%
Real Estate8% —%8% —%
United States Small Cap5% 5%
Non-United States Emerging5% 9%
Private Equity2% —%1% —%
Cash/Treasury Bills—% 2%
Total100% 100%100% 100%
Pension Fund Descriptions
For each type of asset category selected by the Pension Committee, ourTEP's 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, ourTEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds.
Other Retiree Benefit Assets
As of December 31, 2014, the fair value of VEBA trust assets was $12 million, of which $4 million were fixed income investments and $8 million were equities. 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. 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.
 2015
 2016
 2017
 2018
 2019
 2020-2024
 Millions of Dollars
Pension Benefits$17
 $17
 $19
 $20
 $21
 $121
Other Retiree Benefits5
 5
 5
 5
 6
 33
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.
(in millions)2018 2019 2020 2021 2022 2023-2027
Pension Benefits$21
 $22
 $23
 $24
 $25
 $137
Other Postretirement Benefits5
 5
 5
 6
 6
 30
DEFINED CONTRIBUTION PLAN
We offerTEP offers 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. We matchThe Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $6 million in 2017, and $5 million in each of 2014, 2013,both 2016 and 2012.2015.

NOTE 9.SHARE-BASED COMPENSATION
2015 SHARE UNIT PLAN
The Human Resources and Governance Committee (Committee) of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (Plan) effective January 2015. Under the Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of performance-based share units (PSUs) and time-based restricted share units (RSUs) annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula.

8372


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following table represents PSUs and RSUs awarded by UNS Energy:
 2017 2016 2015
PSUs68,126
 66,974
 47,776
RSUs34,063
 33,488
 23,888
The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $9 million and $4 million as of December 31, 2017 and 2016, respectively.
TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2017, $2 million in 2016, and $1 million in 2015 based on its share of UNS Energy's compensation expense.

NOTE 9. 10.SUPPLEMENTAL CASH FLOW INFORMATION
CASH PAYMENTSTRANSACTIONS
 Years Ended December 31,
 2014 2013 2012
 Thousands of Dollars
Interest Paid, Net of Amounts Capitalized$(82,653) $(52,589) (52,125)
Income Taxes Paid
 
 (1,796)
 Years Ended December 31,
(in millions)2017 2016 2015
Interest, Net of Amounts Capitalized$61
 $61
 $65
Income Taxes (1)

 
 
(1)
TEP did not pay federal or state income taxes due to net operating loss carryforwards offsetting taxable income.
NON-CASH TRANSACTIONS
In 2014, the following non-cash transactions occurred:
In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase leased interests in April 2015. See Note 5 of Notes to Consolidated Financial Statements.
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.
In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit of TEP. The proceeds were used 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.
In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP. 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 5 of Notes to Consolidated Financial Statements.
In 2012, the following non-cash transactions occurred:
In June 2012, the Industrial Development Authority of Pima County, Arizona issued approximately $16 million of unsecured tax-exempt IDBs. In March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds. In 2012, TEP redeemed the $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.
Other significant 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,
 2014 2013 2012
 Thousands of Dollars
(Decrease)/Increase to Utility Plant Accruals(1)
$5,138
 $4,995
 $4,813
Net Cost of Removal of Interim Retirements(2)
12,128
 25,182
 35,983
Capital Lease Obligations(3)
1,107
 9,039
 11,967
Asset Retirement Obligations(4)
4,117
 8,064
 789
 Years Ended December 31,
(in millions)2017 2016 2015
Net Cost of Removal Increase (Decrease) (1)
$(88) $8
 $1
Accrued Capital Expenditures24
 29
 28
Commitment to Purchase Capital Lease Interests
 36
 
Asset Retirement Obligations Increase (Decrease) (2)
10
 (1) 3
(1) 
The non-cash additions to Utility Plant represent accrualsRepresents an accrual for capital expenditures.future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information.
(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 obligationsAROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future asset retirement obligations.AROs.

84


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 10. 11.FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
We categorize ourTEP categorizes financial instruments 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. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

73


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, TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities arebasis classified in their entirety based on the lowest level of input that is significant to the fair value measurement.measurement:
 Total Level 1 Level 2 Level 3 
Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)
 Net Amount
 December 31, 2014
 Millions of Dollars
Assets   
Cash Equivalents(1)
$15
 $15
 $
 $
 $
 $15
Restricted Cash(1)
2
 2
 
 
 
 2
Rabbi Trust Investments(2)
26
 
 26
 
 
 26
Energy Contracts - Regulatory Recovery(3)
1
 
 
 1
 (1) 
Energy Contracts - No Regulatory Recovery(3)
1
 
 
 1
 (1) 
Total Assets45
 17
 26
 2
 (2) 43
Liabilities           
Energy Contracts - Regulatory Recovery(3)
(18) 
 (9) (9) 1
 (17)
Energy Contracts - No Regulatory Recovery(3)
(1) 
 
 (1) 1
 
Energy Contracts - Cash Flow Hedge(3)
(1) 
 
 (1) 
 (1)
Interest Rate Swaps(4)
(5) 
 (5) 
 
 (5)
Total Liabilities(25) 
 (14) (11) 2
 (23)
Net Total Assets (Liabilities)$20
 $17
 $12
 $(9) $
 $20
 Level 1 Level 2 Level 3 Total
(in millions)December 31, 2017
Assets 
Cash Equivalents(1)
$30
 $
 $
 $30
Restricted Cash(1)
12
 
 
 12
Energy Derivative Contracts, Regulatory Recovery(2)

 9
 
 9
Energy Derivative Contracts, No Regulatory Recovery(2)

 
 3
 3
Total Assets42
 9
 3
 54
Liabilities       
Energy Derivative Contracts, Regulatory Recovery(2)

 (26) 
 (26)
Energy Derivative Contracts, No Regulatory Recovery(2)

 
 (1) (1)
Interest Rate Swap(3)

 (1) 
 (1)
Total Liabilities
 (27) (1) (28)
Total Assets (Liabilities), Net$42
 $(18) $2
 $26
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
(in millions)December 31, 2016
Assets    
Cash Equivalents(1)
$
 $
 $
 $
 $
 $
$23
 $
 $
 $23
Restricted Cash(1)
2
 2
 
 
 
 2
7
 
 
 7
Rabbi Trust Investments(2)
22
 
 22
 
 
 22
Energy Contracts - Regulatory Recovery(3)
2
 
 1
 1
 (1) 1
Energy Derivative Contracts, Regulatory Recovery(2)

 3
 
 3
Energy Derivative Contracts, No Regulatory Recovery(2)

 
 2
 2
Total Assets26
 2
 23
 1
 (1) 25
30
 3
 2
 35
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)
Energy Derivative Contracts, Regulatory Recovery(2)

 (2) (1) (3)
Interest Rate Swap(3)

 (2) 
 (2)
Total Liabilities(10) 
 (7) (3) 1
 (9)
 (4) (1) (5)
Net Total Assets (Liabilities)$16
 $2
 $16
 $(2) $
 $16
Total Assets (Liabilities), Net$30
 $(1) $1
 $30

85


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(1) 
Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets.Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the balance sheets.Consolidated 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 Derivative Contracts include gas swap agreements (Level 2), and forward purchased power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and a power sale option (Level 3).risk. These contracts are included in Derivative Instruments on the balance sheets.Consolidated Balance Sheets. The valuation techniques are described below.
(4)(3) 
The Interest Rate Swaps still held areSwap is valued using an income valuation approach based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities IndustryLIBOR and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps areis included in Derivative Instruments on the balance sheets.Consolidated Balance Sheets.
(5)

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.
 Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount
  Counterparty Netting of Energy Contracts Cash Collateral Received/Posted 
(in millions)December 31, 2017
Derivative Assets       
Energy Derivative Contracts$12
 $10
 $
 $2
Derivative Liabilities       
Energy Derivative Contracts(27) (10) 
 (17)
Interest Rate Swap(1) 
 
 (1)
(in millions)December 31, 2016
Derivative Assets       
Energy Derivative Contracts$5
 $2
 $
 $3
Derivative Liabilities       
Energy Derivative Contracts(3) (2) 
 (1)
Interest Rate Swap(2) 
 
 (2)
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 enterTEP enters into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with ourits natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC.PPFAC mechanism.
WeThe Company primarily applyapplies the market approach for recurring fair value measurements. When we haveTEP has observable inputs for substantially the full term of the asset or liability or useuses quoted prices in an inactive market, we categorizeit categorizes the instrument in Level 2. We categorizeTEP categorizes derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.brokers is used.
For both purchased power and natural gas prices, we obtainTEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relyrelies on ourits own price experience from active transactions in the market. WeThe Company primarily useuses one set of quotations each for purchased power and fornatural gas and then validatevalidates those prices using other sources. We believeTEP believes 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 applyTEP applies adjustments based on historical price curve relationships, transmission costs, 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. In the first half of 2013, weTEP also used this pricing model to value our power purchase options. Beginning in the third quarter of 2013, the fair value of our power purchase 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 purchase 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.
The valuation of our power sale option is a function of observable market variables, regional power and gas prices, as well as the ratio between the two, the prevailing market heat rate.
We also considerconsiders the impact of counterparty credit risk using current and historical default and recovery rates, as well as ourits own credit risk using credit default swap data.
The inputs and ourthe Company's 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 reviewTEP reviews the assumptions underlying ourits price curves monthly.

86


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Cash Flow Hedges
We enter into interest rate swaps toTo mitigate the exposure to volatility in variable interest rates on debt. At December 31, 2014, we have onedebt, TEP has an interest rate swap agreement whichthat expires in January 2020. We also haveTEP had a purchased power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expireswhich expired in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statementsstatement of comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3$1 million.

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Realized losses from cash flow hedges are shown in the following table:
 Years Ended December 31,
(in millions)2017 2016 2015
Capital Lease Interest Expense$1
 $1
 $2
Purchased Power
 
 1
As of December 31, 2017, the total notional amount of the interest rate swap was $18 million.
Energy Derivative Contracts, - Regulatory Recovery
We recordTEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheetssheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statementsstatement or in the statementsstatement of other comprehensive income, as shown in the following tables:table:
 Year Ended December 31,
 2014 2013 2012
 Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities$(18) $
 $6
Realized gains and losses on settled contracts are fully recoverable through the PPFAC.
 Years Ended December 31,
(in millions)2017 2016 2015
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities$(18) $12
 $6
Energy Derivative Contracts, - No Regulatory Recovery
From time to time, TEP may enterenters into forwardcertain contracts with long-term wholesale customers that qualify as derivatives. We recordderivatives, but do not meet the regulatory recovery criteria. The Company records unrealized gains and losses onfor these energy derivativescontracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as they do not qualify for regulatory recovery. In December 2014,defined in the PPFAC plan of administration, TEP entered into a three-year sales option contract. The unrealized gain recorded in Electric Wholesale Sales in 2014 was less than $1 million.must share 10% of any realized gains with retail customers through the PPFAC mechanism.
Derivative Volumes
AtAs of December 31, 2014, we have2017, TEP has energy contracts that will settle on various expiration dates through the fourth quarter of 2017.2029. The volumes associated with ourthe energy contracts were as follows:
December 31,
December 31, 2014 December 31, 20132017 2016
Power Contracts GWh2,604
 779
2,589
 2,610
Gas Contracts GBtu19,932
 9,615
Gas Contracts BBtu (1)
137,952
 12,355

87


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(1)
Increase in volume of gas contracts is a result of the planned early retirement of certain coal-fired generation. To reduce exposure to energy price risk associated with natural gas, the Company entered into longer term gas contracts increasing its overall volume outstanding in 2017. See Note 3 for additional information related to the planned early retirement of coal-fired generation.
Level 3 Fair Value Measurements
The following table providestables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
   Fair Value at       
 Valuation December 31, 2014   Range of
��Approach Assets Liabilities Unobservable Inputs Unobservable Input
   Millions of Dollars   Minimum Maximum
Forward Power ContractsMarket approach $1
 $(6) Market price per MWh $22.35
 $39.05

           
Power Sale OptionMarket approach 1
 (1) Market price per MWh $27.75
 $44.94

      Market price per MMbtu $2.88
 $4.02
            
Gas Option ContractsOption model 
 (4) Market price per MMbtu $2.72
 $3.26

      Gas volatility 30.8% 53.29%
Level 3 Energy Contracts  $2
 $(11)      
            
   Fair Value at       
 Valuation December 31, 2013   Range of
 Approach Assets Liabilities Unobservable Inputs Unobservable Input
   Millions of Dollars   Minimum Maximum
Forward Power ContractsMarket approach $
 $(3) Market price per MWh $27.00
 $48.25
            
Gas Option ContractsOption model 1
 
 Market price per MMbtu $3.88
 $4.32
       Gas volatility 25.05% 35.07%
Level 3 Energy Contracts  $1
 $(3)      
 Valuation Fair Value of   Range of
 Approach Assets Liabilities Unobservable Inputs Unobservable Input
(in millions)December 31, 2017
Forward Power ContractsMarket approach $3
 $(1) Market price per MWh $17.65
 $34.60
            
(in millions)December 31, 2016
Forward Power ContractsMarket approach $2
 $(1) Market price per MWh $20.90
 $40.00
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. Generally, theThe impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following tables presenttable presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy:hierarchy and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:
  Year Ended December 31,
  2014 2013
  Millions of Dollars
Balances at Beginning of Year $(2) $
Realized/Unrealized Gains/(Losses) Recorded to:    
Net Regulatory Assets/Liabilities – Derivative Instruments (8) (2)
Settlements 1
 
Balances at End of Year $(9) $(2)
     
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period $(8) $(1)
 Years Ended December 31,
(in millions)2017 2016
Beginning of Period$1
 $(2)
Gains (Losses) Recorded   
Regulatory Assets or Liabilities, Derivative Instruments1
 2
Wholesale Revenues4
 4
Settlements(4) (3)
End of Period$2
 $1
    
Gains (Losses), Assets (Liabilities) still held$2
 $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 enterTEP enters into contracts for the physical delivery of energypower and natural 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.

88


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



We haveTEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each companyTEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, wethe Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, a LOC, or LOCsother acceptable security to fully collateralize our exposure to these counterparties.beyond the allowed amounts.
We considerTEP considers 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 allocatethen allocates the credit risk adjustment to individual contracts. WeTEP also considerconsiders the impact of our ownits credit risk after considering collateral posted on instruments that are in a net liability position, after considering the collateral posted, and allocatethen allocates the credit risk adjustment to allthe individual contracts.
Material adverse changes could trigger credit risk-related contingent features. At December 31, 2014, theThe value of all derivative instruments in a net liability positionpositions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $21$27 million as of December 31, 2017, compared with $5$8 million atas of December 31, 2013. At2016. As of December 31, 2014,2017, TEP had no cash collateral posted and less than $1 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-riskIf the credit risk contingent features were triggered on December 31, 2017, TEP would be $21 million.have been required to post an additional $27 million of collateral of which $12 million relates to outstanding net payable balances for settled positions.
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 useTEP uses the following methods and assumptions for estimating the fair value of our financial instruments:
The carrying amounts of our current maturities of long-term debt and amounts outstandingBorrowings under ourrevolving credit agreementsfacilities approximate the fair valuesvalue due to the short-term nature of these financial instruments. These items have been excluded from the table below.
For Investment in Lease Equity, we estimated the price at which an investor would realize a target internal rate of return. Our estimates included: the mix oflong-term 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 assumed a residual value based on an appraisal of Springerville Unit 1 conducted in 2011. No impairment has been recorded as TEP expects to recover the full carrying value in retail rates. The balance was transferred to Plant in Service upon the December 2014 purchase of an additional undivided interest in Springerville Unit 1. See Note 3 of Notes to Consolidated Financial Statements.
For Long-Term Debt, we useuses quoted market prices, when available, or calculatecalculates the present value of the remaining cash flows atas of the balance sheet date. When calculating present value, we usethe Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We considerTEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. WeThe Company also incorporateincorporates the impact of ourits own credit risk using a credit default swap rate.

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded onfollowing table includes the balance sheetsface value and the estimated fair valuesvalue of our financial instruments include the following:TEP's long-term debt:
   December 31, 2014 December 31, 2013
 
Fair Value
Hierarchy
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
   Millions of Dollars
Assets:         
Investment in Lease Equity(1)
Level 3 N/A
 N/A
 $36
 $25
Liabilities:         
Long-Term DebtLevel 2 1,372
 1,457
 1,223
 1,214
(1)
Balance was transferred to Plant in Service in December 2014.


89


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    
 
Fair Value
Hierarchy
 Face Value Fair Value
   December 31,
(in millions)  2017 2016 2017 2016
Liabilities         
Long-Term Debt, including Current MaturitiesLevel 2 $1,466
 $1,466
 $1,547
 $1,472



NOTE 11. 12.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:
 Years Ended December 31,
 2014 2013 2012
 Millions of Dollars
Federal Income Tax Expense at Statutory Rate$56
 $52
 $37
State Income Tax Expense, Net of Federal Deduction7
 7
 5
Federal/State Tax Credits(5) (2) (1)
Allowance for Equity Funds Used During Construction(2) (1) (1)
Deferred Tax Asset Valuation Allowance
 2
 
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset
 (11) 
Other2
 1
 (1)
Total Federal and State Income Tax Expense$58
 $48
 $39
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 assets 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.
 Years Ended December 31,
(in millions)2017 2016 2015
Federal Income Tax Expense at Statutory Rate$97
 $64
 $70
State Income Tax Expense, Net of Federal Deduction9
 6
 8
Federal/State Tax Credits(9) (8) (8)
Allowance for Equity Funds Used During Construction(2) (1) (1)
Deferred Tax Asset Valuation Allowance
 (2) 1
Impact of Enactment, TCJA7
 
 
Other(1) 
 2
Total Federal and State Income Tax Expense$101
 $59
 $72
Income tax expense included in the income statementsstatement consists of the following:
Years Ended December 31,Years Ended December 31,
2014 2013 2012
Millions of Dollars
Current Tax Expense (Benefit):     
(in millions)2017 2016 2015
Current Income Tax Expense     
Federal$(1) $(8) $(4)$
 $
 $
State
 (2) (2)
 
 
Total Current Tax Expense (Benefit)(1) (10) (6)
Deferred Tax Expense (Benefit):     
Total Current Income Tax Expense
 
 
Deferred Income Tax Expense     
Federal54
 47
 38
98
 60
 66
Federal Investment Tax Credits(4) (1) 
(6) (6) (6)
State9
 12
 7
9
 5
 12
Total Deferred Tax Expense (Benefit)59
 58
 45
Total Deferred Income Tax Expense101
 59
 72
Total Federal and State Income Tax Expense$58
 $48
 $39
$101
 $59
 $72
On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. In addition, the TCJA provides modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities. The Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment of the TCJA. This resulted in a net decrease to deferred income tax liabilities. Since the Company believes it is probable that a significant portion of the decrease will be returned to customers through future rates, a regulatory liability was established. The impacts of the new tax law to the Company's financial results included: (i) a $7 million increase to Income Tax Expense on the Consolidated Statements of Income in 2017; and (ii) a $343 million net increase to Regulatory Liabilities and a $336 million net decrease to Deferred Income Tax Liabilities on the Consolidated Balance Sheets as of December 31, 2017.

9078

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP is still in the process of evaluating the bonus depreciation carve-out for regulated utilities and anticipates further clarification from the IRS. TEP has recorded an estimated provision for bonus depreciation for its fixed assets placed in service between September 27, 2017 and December 31, 2017, which impacts TEP’s Operating Loss Carryforward Deferred Tax Asset and Plant Deferred Tax Liability.
The significant components of deferred income tax assets and liabilities consist of the following:
December 31,December 31,
2014 2013
Millions of Dollars
Gross Deferred Income Tax Assets:   
(in millions)2017 2016
Gross Deferred Income Tax Assets   
Capital Lease Obligations$96
 $127
$10
 $35
Net Operating Loss Carryforwards187
 104
Operating Loss Carryforwards, Net56
 129
Customer Advances and Contributions in Aid of Construction19
 19
14
 20
Alternative Minimum Tax Credit24
 24
26
 25
Accrued Postretirement Benefits23
 23
Other Postretirement Benefits15
 23
Emission Allowance Inventory10
 10
3
 9
Investment Tax Credit Carryforward31
 6
34
 32
Income Taxes Recoverable Through Future Rates88
 
Other54
 38
47
 60
Total Gross Deferred Income Tax Assets444
 351
293
 333
Deferred Tax Assets Valuation Allowance(2) (2)
 
Gross Deferred Income Tax Liabilities:   
Plant – Net(699) (615)
Capital Lease Assets – Net(74) (47)
Gross Deferred Income Tax Liabilities   
Plant, Net(518) (774)
Plant Abandonments(21) 
Capital Lease Assets, Net(5) (24)
Pensions(27) (22)(16) (26)
PPFAC(8) (2)
Income Taxes Payable Through Future Rates(10) 
Other(24) (20)(23) (38)
Total Gross Deferred Income Tax Liabilities(832) (706)(593) (862)
Net Deferred Income Tax Liabilities$(390) $(357)
Deferred Income Taxes, Net$(300) $(529)
The netTEP recorded no valuation allowance against credit and loss carryforward deferred income tax liability on the balance sheets isassets as follows:
 December 31,
 2014 2013
 Millions of Dollars
Deferred Income Taxes – Current Assets$102
 $71
Deferred Income Taxes – Noncurrent Liabilities(492) (428)
Net Deferred Income Tax Liability$(390) $(357)
TEP has recorded a $2 million valuation allowance against state tax credit carryforward deferred tax assets atof December 31, 2014.2017 and 2016. Management believes TEP will not produce sufficient taxable income in the future to use all state tax creditsrealize credit and loss carryforwards before they expire.
As of December 31, 2014,2017, TEP had the following carryforward amounts:
Amount Expiring Year
Millions of Dollars  
(in millions)Amount Expiring Year
Federal Net Operating Loss$507
 2031-34$263
 2031-35
State Net Operating Loss237
 2016-34
State Credits8
 2016-198
 2021-29
Alternative Minimum Tax Credit24
 None26
 None
Investment Tax Credits31
 2032-3434
 2031-37

91


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Uncertain Tax Positions
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
 December 31,
 2014 2013
 Millions of Dollars
Unrecognized Tax Benefits, Beginning of Year$2
 $23
Additions Based on Tax Positions Taken in the Current Year2
 1
Reductions of Positions from Prior Year Based on Tax Authority Ruling
 (22)
Unrecognized Tax Benefits, End of Year$4
 $2
 December 31,
(in millions)2017 2016
Beginning of Period$12
 $5
Additions Based on Tax Positions Taken in the Current Year7
 7
Reduction to Positions, TCJA(6) 
End of Period$13
 $12

79

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Unrecognized tax benefits, if recognized, would not reduce income tax expense atby $1 million as of December 31, 20132017 and December 31, 2014.2016.
TEP recognized a $1 million reduction torecorded no interest expense in 2013 and no reduction in 2014.during 2017, 2016, or 2015 related to uncertain tax positions. In addition, TEP had no interest payable balances at December 31, 2014 and December 31, 2013. 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 lifeas 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, TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.December 31, 2017 and 2016.
TEP has been audited by the IRS through tax year 2010. TEP is not currently under audit by any federal or state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of IRS audits, but we arethe Company is 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 TEP resulted in a $22 million increase to plant-related deferred tax liabilities and net operating loss deferred tax assets at December 31, 2014.

NOTE 12. 13.RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2014,TEP considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, an accounting standards update that limits the circumstances under which a disposal maybut have not yet been adopted by TEP. Updates not listed below were assessed and either determined to not be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidanceapplicable or are expected to have ana minimal impact on the presentationTEP's consolidated financial position, results of our financial statementsoperations, or our disclosures.
REVENUE FROM CONTRACTS WITH CUSTOMERS
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be requiredASU intended to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to ourenable users of financial statements to better understand and disclosures.
In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt aboutconsistently analyze an entity's ability to continue as a going concernrevenues across industries and provide related disclosures. This update istransactions. The ASU was effective for annual and interim periods beginning January 1, 2017; early2018 and permits two implementation approaches: (i) retrospective application; or (ii) modified retrospective application by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings on the date of adoption supplemented by additional disclosures. TEP adopted this ASU on January 1, 2018, using the modified retrospective approach, and did not identify or record any adjustment to the opening balance of retained earnings on adoption. Under the new standard, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this ASU did not affect revenue recognition for tariff-based sales to retail and wholesale customers, which represent TEP's primary source of revenue. Accordingly, the adoption of this standard did not have a material effect on TEP's financial statements. However, the presentation and disclosure requirements of the ASU will result in a change in the presentation of revenues on TEP's income statement as well as expanded disclosures.
LEASES
In February 2016, the FASB issued an ASU that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under current GAAP. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. TEP does not expectis evaluating the impact of this ASU to its financial statements and disclosures.
COMPENSATION—RETIREMENT BENEFITS
In March 2017, the FASB issued an ASU to improve the presentation of net periodic benefit cost for pension and other postretirement benefits. TEP adopted this ASU on January 1, 2018, the effective date of the ASU. Effective in the first quarter of 2018, TEP will no longer capitalize the non-service cost components of net periodic benefit cost as part of inventory or plant in service and will present non-service costs retrospectively in Other Income—Other Expense on the Consolidated Statements of Income. The adoption of thisthe ASU did not have a material impact on the Company's financial position or results of operations.
DERIVATIVES AND HEDGING
In August 2017, the FASB issued an ASU that enables entities to better align their risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance and the presentation of hedge results. The ASU expands an entity's ability to apply hedge accounting to non-financial and financial risk components and simplify fair value hedges of interest rate risk. The ASU eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The amendments to the ASU also ease hedge documentation and effectiveness assessments requirements under previous guidance. The standard is effective for fiscal years beginning January 1, 2019. Early adoption is permitted. The ASU is expected to have anminimal impact on itsto TEP's financial statements and disclosures.


9280

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 13. 14.QUARTERLY FINANCIAL DATA (UNAUDITED)
OurTEP's quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. OurTEP's utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
First Second Third Fourth
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
Thousands of Dollars
2014       
(in millions)2017
Operating Revenue$255,513
 $321,618
 $387,411
 $305,359
$268
 $352
 $417
 $304
Operating Income31,999
 79,653
 84,898
 34,138
37
 107
 138
 44
Net Income9,172
 38,725
 39,644
 14,797
21
 61
 82
 13
2013       
       
2016
Operating Revenue$247,751
 $304,263
 $371,239
 $273,437
$243
 $317
 $394
 $281
Operating Income22,747
 53,433
 123,177
 31,014
12
 72
 122
 37
Net Income1,478
 30,787
 64,167
 4,910
Net Income (Loss)(1) 41
 72
 12

81

Schedule II—Valuation and Qualifying Accounts




Allowance for Doubtful Accounts (1)
 
Beginning
Balance
 
Additions-
Charged to
Income
 Deductions 
Ending
Balance
  Millions of Dollars
Year Ended December 31,        
2014 $5
 $2
 $2
 $5
2013 5
 2
 2
 5
2012 14
 3
 12
 5
Other Reserves (2)
 Beginning Balance Ending Balance
  Millions of Dollars
Year Ended December 31,    
2014 $4
 $5
2013 8
 4
2012 4
 8
(1)
TEP records 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. Other reserves are made up of reserves for sales tax audits, litigation matters, and damages billable to third parties.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

ITEM 9A.9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its 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 TEP’s periodic reports filed or

93



submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States 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 TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures are effective.effective as of December 31, 2017.
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during 2014the fourth quarter of 2017 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.
Management’s Report on Internal Control 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, 2017. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations Internal Control – Integrated Framework.
Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2017, TEP’s internal control over financial reporting was effective.
Changes in Internal Control Over Financial Reporting
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during the fourth quarter of 2017 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION
None.


9482


PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors
All of the members of the TEP Board of Directors are executive officers and employees of TEP, a wholly owned subsidiary of UNS Energy.
The directors of TEP are elected annually by TEP's sole shareholder, UNS Energy, acting at the direction of the Board of Directors of UNS Energy.
The names and information concerning the members of the TEP Board of Directors are set forth below:
NameAgeServed As Director SinceBusiness Experience
David G. Hutchens482014
Mr. Hutchens has served as Chief Executive Officer of TEP since 2014; President of TEP since 2011; Executive Vice President of TEP in 2011; Vice President of TEP from 2007-2011. Mr. Hutchens joined TEP in 1995.
Mr. Hutchens' extensive experience in the electric and gas utility business and his position as President and Chief Executive Officer provide him with intimate knowledge of TEP's operations.
Kevin P. Larson582014
Mr. Larson has served as Senior Vice President and Chief Financial Officer of TEP since September 2005. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He was elected Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer. Mr. Larson is also a Chartered Financial Analyst.
Mr. Larson's extensive experience in the electric and gas utility business and his position as Senior Vice President and Chief Financial Officer provide him with intimate knowledge of TEP's financial affairs.
Philip J. Dion462014
Mr. Dion has served as Senior Vice President, Public Policy and Customer Solutions of TEP since August 2013. Mr. Dion was named Vice President, Public Policy in April 2010. Mr. Dion joined TEP in February 2008 as Vice President of Legal and Environmental Services. Mr. Dion previously held positions at the Federal Energy Regulatory Commission and the Arizona Corporation Commission.
Mr. Dion’s extensive experience in utility regulatory matters and his position as Senior Vice President of Public Policy and Customer Solutions provide him with intimate knowledge of TEP's regulatory affairs.
Executive Officers
See Item 1. Business, Executive Officers of the Registrant.
Code of Ethics
See Item 1. Business, SEC Reports Available on TEP's Website.
Audit and Risk Committee of the UNS Energy Board
The Audit and Risk Committee of the Board of Directors of UNS Energy was established for the purpose of overseeing the accounting and financial reporting process and audits of the financial statements of UNS Energy and its consolidated subsidiaries, including TEP.

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The Audit and Risk Committee reviews current and projected financial results of operations, selects an independent registered public accounting firm to audit UNS Energy’s and TEP’s financial statements annually, reviews and discusses the scope of such audit, receives and reviews the audit reports and recommendations, transmits its recommendations to the Board of Directors of The Audit and Risk Committee of UNS Energy reviews UNS Energy’s and TEP’s accounting and internal control procedures with the internal audit department from time to time, makes recommendations to the board of UNS Energy for any changes deemed necessary in such procedures and performs such other functions as delegated by the UNS Energy Board of Directors.
The following UNS Energy directors are members of the Audit and Risk Committee of UNS Energy’s Board of Directors:
Ramiro G. Peru, Chair
Robert A. Elliott
James P. Laurito
Gregory A. Pivirotto
Joaquin Ruiz
All Audit and Risk Committee members possess the level of financial literacy and accounting or related financial management expertiseInformation required by New York Stock Exchange (NYSE) rules. UNS Energy’s BoardItem 10 is omitted pursuant to General Instruction I(2)(c) of Directors has determined that, while each member of the Audit and Risk Committee has accounting and/or related financial management expertise, Mr. Ramiro Peru is an “audit committee financial expert” as that term is defined by applicable SEC regulations.Form 10-K.
Compensation Committee
TEP is a wholly owned subsidiary of UNS Energy. As described in Item 11 below, the TEP Board of Directors does not have a Compensation Committee and does not make compensation-related decisions for the executive officers of TEP. The same individuals serve as executive officers of both UNS Energy and TEP and, prior to the acquisition of UNS Energy by Fortis, the UNS Board of Directors Compensation Committee made compensation decisions for such officers, including the design of the 2014 executive compensation plan described in Item 11. Following the acquisition of UNS Energy by Fortis, the UNS Energy Board of Directors dissolved its Compensation Committee and established a separately standing Human Resources and Governance Committee, which has assumed many, but not all, of the responsibilities of the former Compensation Committee, including the approval of the Compensation Discussion and Analysis (CD&A) set forth in Item 11.
The following UNS Energy directors are members of the Human Resources and Governance Committee of UNS Energy’s Board of Directors:
Louise L. Francesconi, Chair
Lawrence J. Aldrich
Robert A. Elliott
Barry Perry
John C. Walker

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UNS Energy Directors
Due to the role of the Audit and Risk Committee and the Human Resources and Governance Committee of the UNS Energy Board of Directors described above, the following information is included with respect to the members of the UNS Energy Board of Directors (other than with respect to Mr. Hutchens, who is also a member of the Board of Directors of UNS Energy)
NameAgeServed as Director SinceBusiness Experience
Lawrence J. Aldrich622000
Chairman and Executive Director, Arizona Business Coalition on Health, since 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 2007; Chief Operating Officer of The Critical Path Institute, a non-profit medical research company focusing in drug development, from 2005 to 2007.
Mr. Aldrich’s extensive experience in the areas of public relations/advertising, finance, legal, human resources, marketing, engineering, operations, government/regulatory, information technology, insurance/health care, and his significant community involvement in Arizona and Tucson contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.
Robert A. Elliott592003
President and owner of Elliott Accounting, an accounting, tax, management and investment advisory services firm, since 1983; Chair of AAA of Arizona, a regional automotive and travel club, since 2014 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 2011-2013; Director of University of Arizona Foundation, a philanthropic organization, since 2011.
Mr. Elliott’s extensive experience in the areas of accounting, audit, banking and corporate tax, and his significant community involvement in Arizona and Tucson contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.
Louise L. Francesconi622008
President of Raytheon Missile Systems, a defense electronics corporation, from 1997 until her retirement in 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.
Ms. Francesconi’s extensive experience in the areas of accounting, public relations/advertising, finance, legal, human resources/benefits, marketing, engineering, operations, audit, government/regulatory, information technology and insurance/healthcare, and her significant community involvement in Arizona and Tucson contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.
James P. Laurito582014
President and CEO of Central Hudson Gas & Electric Company since November 1, 2014. Mr. Laurito joined Central Hudson as President in November 2009. Prior to that, he served as President of both New York State Electric and Gas Corporation and Rochester Gas & Electric Corporation from 2003 until 2009.
Mr. Laurito's extensive experience in the electric and gas utility business contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.

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Barry Perry502014
President and CEO of Fortis since December 31, 2014.
Prior to his current position at Fortis, Mr. Perry served as Vice President, Finance and CFO of Fortis since 2004. Mr. Perry joined the Fortis organization in 2000 as VP, Finance and CFO of Newfoundland Power. Previously, he held the position of VP, Treasurer with a global forest products company and Corporate Controller with a large crude oil refinery.
Mr. Perry's extensive experience in the electric and gas utility business contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.
Ramiro G. Peru582008
Executive Vice President and Chief Financial Officer of Swift Corporation, a trucking company, from June 2007 until his retirement in December 2007; Executive Vice President and Chief Financial Officer of Phelps Dodge Corporation, a mining corporation, from 2004 to 2007; Senior Vice President and Chief Financial Officer of Phelps Dodge Corporation from 1999 to 2004; Director of Anthem, Inc. (formerly WellPoint, Inc.), a health benefits company, since 2004; Board of Directors, Fiesta Bowl, since 2012; Director of SM Energy Company since 2014.
Mr. Peru’s extensive experience in the areas of accounting, corporate communications, finance, legal, human resource/benefits, audit, government/regulatory, corporate tax, information technology, insurance/health care and environmental contributes to the diverse knowledge, skills and qualifications of the UNS Energy Board.
Gregory A. Pivirotto622008
President, Chief Executive Officer and Director of University Medical Center Corporation, in Tucson, from 1994 until his retirement in 2010; Adjunct Professor at the University of Arizona College of Law since 2013; 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 to January 2014; Member of the Advisory Board of Harris Bank from 2010 to 2013. Director of the Arizona Donor Network Association from 1993 to 2006 and since 2012.
Mr. Pivirotto’s extensive experience in the areas of accounting, public relations/advertising, finance, legal, human resources/benefits, marketing, operations, audit, government/regulatory, banking, corporate tax, information technology and insurance/healthcare, and his significant community involvement in Arizona and Tucson contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.
Joaquin Ruiz632005
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.
Mr. Ruiz’s extensive experience in the areas of renewables and environmental, public relations/advertising, human resources/benefits, operations, government/regulatory, information technology, and his significant community involvement in Arizona and Tucson contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.
John C. Walker572014
Executive Vice President, Western Canadian Operations of Fortis, effective August 1, 2014. His career with the Fortis Group spans more than 30 years. Mr. Walker was appointed President and CEO, FortisBC Electric in 2005 and in 2010 he also became President and CEO, FortisBC Gas and served in such position until August 2014. Prior to his leadership positions at FortisBC, he served as President and CEO, Fortis Properties from 1997 through 2005.
Mr. Walker's extensive experience in the electric and gas utility business contribute to the diverse knowledge, skills and qualifications of the UNS Energy Board.


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ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
This section describes TEP’s overall executive compensation policies and practices and specifically analyzes the total compensation for the following executive officers, referred to as the Named Executives:
Paul J. Bonavia, Board Chair and Chief Executive Officer*;
David G. Hutchens, President and Chief Executive Officer;
Kevin P. Larson, Senior Vice President and Chief Financial Officer;
Philip J. Dion, Senior Vice President, Public Policy and Customer Solutions;
Karen G. Kissinger, Vice President and Chief Compliance Officer; and
Todd C. Hixon, Vice President and General Counsel
*Mr. Bonavia retired from his position as CEO of TEP on May 2, 2014, and his position as Board Chair of UNS Energy on September 19, 2014.
COMPENSATION PHILOSOPHY
Compensation Committee
TEP is a wholly owned subsidiary of UNS Energy. The TEP Board of Directors does not have a Compensation Committee and does not make compensation-related decisions for the executive officers of TEP. The same individuals serve as executive officers of both UNS Energy and TEP and, prior to the acquisition of UNS Energy by Fortis, the UNS Board of Directors Compensation Committee made all compensation decisions for all such officers, including the design of the 2014 executive compensation program described herein. Following the acquisition of UNS Energy by Fortis, the UNS Energy Board of Directors dissolved the Compensation Committee and established a separately standing Human Resources and Governance Committee, which has assumed many, but not all, of the responsibilities of the former Compensation Committee, including the approval of this disclosure. Because this Compensation Discussion and Analysis (CD&A) focuses on 2014 compensation, any references to a Compensation Committee in this section refer to the former UNS Energy Compensation Committee unless the UNS Energy Human Resources and Governance Committee is specifically identified.
TEP Compensation as a Component of UNS Energy Total Compensation
The Compensation Committee designs its programs to compensate UNS Energy executive officers for services to UNS Energy and all UNS Energy subsidiaries, including TEP. The amounts shown in this section represent the Named Executives' compensation allocated to TEP and its subsidiaries only, which, in 2014 amounts to 80.46% of the Named Executives total compensation for service provided to UNS Energy and its subsidiaries. The percentage allocated to TEP is obtained using the Massachusetts formula, an industry accepted method of allocating common costs to affiliated entities based on an equal weighting of payroll costs, plant/tangible assets and total revenues. References to Company refer to UNS Energy and include all UNS Energy subsidiaries. The Performance Enhancement Plan (PEP) includes target goals attributable to TEP, UNS Electric, and UNS Gas.
Objectives of the Compensation Program
The Compensation Committee has established a balanced total compensation program and ensures that a significant part of executive officer compensation is performance-based. Corporate goals are designed to focus executive officers and all non-union employees on successful execution of the Company’s strategy and annual operating plan.
The Company’s executive officer compensation policies and decisions have the following objectives:
1.Attracting, motivating and retaining highly-skilled executives;
2.Linking the payment of compensation to the achievement of critical short- and long-term financial and strategic objectives; providing safe, reliable and economically available electric and gas service; and aligning performance objectives of management with those of its other employees by using similar performance measures for both groups;

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3.Balancing risk and reward to align the interests of management with those of the Company’s stakeholders and encouraging management to think and act like owners, taking into account the interests of the public that the Company serves;
4.Maximizing the financial efficiency of the compensation program to avoid unnecessary tax, accounting and cash flow costs; and
5.Encouraging management to achieve outstanding results through appropriate means by delivering compensation in a manner consistent with established and emerging corporate governance “best practices.”
Summary of 2014 Executive Officer Compensation Program
Compensation ComponentKey FeaturesPurpose
Base Salary
Increases considered on an annual basis to remain near the median of the Company's peer group (as described in Element of Compensation - Base Salary, below)
Intended to constitute a sufficient component of total compensation to discourage inappropriate risk-taking
Provide a fixed amount of cash compensation to the Company's Named Executives
Short-term Incentive
Compensation (Performance Enhancement Program or PEP)
Incentive plans are structured identically for executive and non-executive employees and across business units/functions, uniting all non-union employees in the achievement of common goals
All incentive plans are capped at 150% of target, protecting against the possibility that executives take short-term actions not supportive of long-term objectives to maximize bonuses
Must achieve at least the threshold level of net income to receive payment above 50% of target for other performance measures; this cap limits non-financial goal payout if the financial goals are not met
Motivate and reward achieving or exceeding the Company's short-term performance goals, reinforcing pay-for-performance
Focus entire Company on key customer, operational and financial objectives
Long-Term Incentive
Compensation (LTI or equity-
based compensation)
LTI compensation is delivered in a combination of performance shares and restricted stock units
Ultimate value earned from the LTI program is based on both absolute and relative shareholder value and longer-term operating performance
Performance shares represent 67% of the target award with 50% of the shares earned based on achievement of cumulative net income goals and 50% of the shares earned based on achievement of relative TSR over a three-year period
RSUs represent 33% of the target awards, and cliff vest on the 3rd anniversary of grant
Opportunities for ownership and financial reward in support of the Company’s longer-term financial goals and stock price growth; also supports retention objective
Provide a link between compensation and long-term shareholder interests as reflected in changes in stock price
The Compensation Committee considers decisions regarding each component of pay in the context of each executive officer’s total compensation. For example, if the Compensation Committee increases an executive officer’s base salary, it also considers the resultant impact on short- and long-term performance-based incentive compensation and compares total compensation levels to competitive practice, see Compensation Analysis, below. The Compensation Committee does not directly consider the value of previous equity awards in setting current year total compensation opportunities, but does review the value of outstanding equity awards to assess the degree to which such awards support the Company’s performance motivation, retention, and shareholder alignment objectives.
Each of these components is described in more detail below and in the narrative and footnotes to the supporting tables. The following sections highlight how the above objectives are reflected in the Company’s compensation program.

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Attracting, Retaining and Motivating Executives
To attract, retain and motivate highly-skilled employees, the Company provides the Named Executives with compensation packages that are competitive with those offered by other electric and gas utility companies of comparable size and complexity and/or electric and gas utility companies thought to be competitors for executives.
The Compensation Committee generally targets total direct compensation for the Named Executives to be, on average, at the median of selected comparable companies identified below under the Compensation Analysis section. Under this approach, newly promoted executives and those new to their role may be placed below the median to reflect their limited experience and evolving skill set. Similarly, executives with longer tenure and therefore an above-market skill set, or those executives who are sustained high performers over time and are most critical to the Company’s long-term success, may be placed above the median. The Company believes that this strategy enables it to successfully hire, motivate and retain talented executives while ensuring a reasonable overall compensation cost structure relative to its peers.
In addition to providing competitive direct compensation opportunities, the Company also provides certain indirect compensation and benefits programs that are intended to assist in attracting and retaining high quality executives. These programs include pension and retirement programs and are described in more detail below and in the narratives that accompany the tables that follow this section.
Linking Compensation to Performance
The Company’s compensation program seeks to link the actual compensation earned by the Named Executives to their performance and that of the Company. Prior to the merger, UNS achieved this goal primarily through two elements of executive compensation: (i) short-term cash awards and (ii) equity-based compensation. After the merger, UNS did not use equity-based compensation in 2014. To ensure that the executive officers are held accountable for achieving the Company’s financial, operational and strategic objectives and for creating shareholder value, the Company believes that the percentage of pay at risk should increase with the level of responsibility within the Company. The target amounts of performance-based pay programs comprise approximately 45% to 70% of the total direct compensation opportunity for the Named Executives. Of the performance-based compensation, approximately 30-50% is short-term and 50-70% is long-term. Placing a greater emphasis on long-term performance-based compensation encourages executive officers to focus on the long-term impact of their actions. Non-variable compensation, such as benefits and perquisites, is de-emphasized in the total compensation program to reinforce the linkage between compensation and performance.
Balancing Risk and Reward to Align the Interests of the Company’s Named Executives with Stakeholders
The Company's compensation program seeks to align the interests of the Named Executives with those of the Company’s key stakeholders, including shareholders, customers, the community and employees. The Company uses the short-term incentive compensation component to focus the Named Executives on the importance of providing safe and reliable customer service, creating a safe work environment for employees and improving financial performance by linking their short-term cash incentive compensation to achievement of these objectives. Prior to the Merger, the Company primarily relied on the equity compensation element of its compensation package to align the interests of the Named Executives with those of the former UNS Energy shareholders. The Company's compensation strategy was intended to mitigate risk by emphasizing long-term compensation and financial performance measures correlated with shareholder value. UNS Energy believed that equity-based compensation, together with the three-year vesting of stock-based awards and the stock ownership guidelines, result in compensation programs that did not encourage excessive risk-taking by management relating to the Company’s business and operations, and increase executive officer accountability in the performance of the Company. In addition, the Compensation Committee has the ability to reduce short-term incentive compensation award payouts, in its sole discretion, based upon factors other than Company performance measures. In considering the design alternatives, the Compensation Committee continually evaluates the potential for unintended consequences of its compensation program.
Maximizing the Financial Efficiency of the Program
In structuring the total compensation package for the Named Executives, the Compensation Committee evaluates the accounting cost, cash flow implications and tax deductibility of compensation to mitigate financial inefficiencies to the greatest extent possible. For instance, as part of this process, the Compensation Committee evaluates whether compensation costs are fixed or variable and places a heavier weighting on variable pay elements to calibrate expense with the achievement of operating performance objectives.

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Adhering to Corporate Governance “Best Practices”
The Compensation Committee continually seeks to evaluate the executive officer compensation program in light of corporate governance “best practices.” For example, the short-term and long-term incentive compensation programs include a clawback provision, and the Change in Control Agreements does not contain an excise tax gross-up provision, all of which are discussed in more detail below.
The Compensation Committee also reviews tally sheets and wealth accumulation analysis, which are designed to assist the Compensation Committee in evaluating the reasonableness of the compensation provided to Named Executives. Based on this review, the Compensation Committee concluded that the current program design supports the Company’s objectives and that no changes were warranted to the program for 2014 compensation.
Compensation Analysis
To provide a foundation for the executive officer compensation program, the Company periodically benchmarks its Named Executives’ compensation levels and practices against a peer group of companies intended to represent the Company's competitors for business and talent. The peer group, which is reviewed periodically and approved by the Compensation Committee, includes the 12 utility companies named below that are comparable to UNS Energy in size, as measured by annual revenues and market capitalization (the Peer Group). As of November 2013, the date when the most recent benchmarking analysis was performed, UNS Energy’s revenues and number of employees approximate the median of the Peer Group; total assets and market capitalization are between the 25th percentile and the median; net income is below the 25th percentile.
Frederic W. Cook & Co., Inc., the independent consultant retained by the Compensation Committee, supplements the benchmark information annually with information relating to general market trends, changes in regulatory requirements related to executive officer compensation and emerging “best practices” in corporate governance.
2014 Peer Group
ALLETE, Inc.NorthWestern Corp.
Avista Corp.NV Energy, Inc.
Cleco Corp.PNM Resources Inc.
El Paso Electric Co.Portland General Electric Co.
Great Plains Energy, Inc.UIL Holdings Corp.
IDACORP Inc.Westar Energy Inc.
ELEMENTS OF COMPENSATION
Base Salary
The Company uses base salary to provide each Named Executive a set amount of money during the year with the expectation that he or she will perform his or her responsibilities to the best of his or her ability and in the best interests of the Company. The Company believes that competitive base salaries are necessary to attract and retain executive talent critical to achieving its business goals. In general, Named Executives’ base salaries are targeted to the median of the Peer Group described above. However, individual salaries can and do vary from the Peer Group median data based on such factors as (i) the competitive environment for Named Executives, and (ii) incumbent responsibilities, experience, skills and performance relative to similarly situated executive officers within the Company. Named Executives' salaries range from below the 25th percentile to the median of the Peer Group.
Increases to Named Executives’ base salaries are considered annually by the Compensation Committee. In approving base pay increases for Named Executives other than the CEO, the Compensation Committee also considers recommendations made by the CEO.
In February 2014, the Compensation Committee approved 3% base salary increases for the Named Executives, which were consistent with salary increases as a percent of salary for other non-union Company employees. Separately, the Compensation Committee approved a promotion for David Hutchens to President & CEO effective May 2, 2014, at which time his base salary was increased to $540,000 to address the added responsibility of CEO. Base salary as a percentage of total compensation for the Named Executives ranges from approximately 30-55%. Additional information is provided in the Summary Compensation Table below.

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Short-Term Incentive Compensation (Cash Awards)
The Company's short-term incentive compensation consists of cash awards under the Performance Enhancement Plan (“PEP”), which links a significant portion of the Named Executives’ annual compensation to the Company’s annual financial and operational performance.
Each year, before the end of the first quarter, the Compensation Committee establishes performance objectives that must be met in whole or in part before the Company pays PEP awards. The key performance objectives are tailored to drive behavior that supports the Company’s strategy of delivering safe, reliable service and value to customers and a fair return to shareholders over time. The Compensation Committee generally attempts to align the target opportunity for each Named Executive, stated as a percentage of base salary, with the median rate for equivalent positions at the Peer Group companies. In 2014, the target incentive opportunity for the Named Executives ranged from 40% to 80% of base salary, depending upon the Named Executive’s responsibilities (i.e., the greater the responsibility, the more pay at risk). The Company's Named Executives’ target incentive opportunities as a percent of base salary are near the Peer Group median. As described more fully below, the actual amounts paid depend on the achievement of specified performance objectives and could range from 50% of the target award upon achievement of threshold performance to 150.0% of the target award upon achievement of exceptional performance.
Financial and Operating Performance Objectives-2014
The PEP performance targets and weighting are based on factors that are essential for the long-term success of the Company and are identical to the performance objectives used in its performance plan for other non-union employees. In 2014, the objectives were (i) net income; (ii) O&M cost containment; and (iii) excellent operations and safe work environment, which include both quantitative and qualitative measures. The Compensation Committee selected the goals and individual weightings for the 2014 PEP to ensure an appropriate focus on profitable growth and expense control, as well as operational and customer service excellence, process improvements, and establishing new rates. This balanced scorecard approach encourages all employees to work toward common goals that are in the interests of UNS Energy’s various stakeholders.
The financial and other metrics for the Company’s 2014 Short-Term Incentive Compensation program were:
Financial – 50%
Net Income – 40%
O&M Cost Containment – 10%
Excellent Operations and Safe Work Environment – 50%
In developing the PEP performance targets, Company management compiles relevant data such as Company historic performance and industry benchmarks and makes recommendations to the Compensation Committee for a particular year, but the Compensation Committee ultimately determines the performance objectives that are adopted.
The 2014 financial performance objectives were:
Performance Objectives Threshold Target Exceptional
  Millions of Dollars
Net Income $133.5
 $141.9
 $150.3
O&M Costs 279.0
 274.0
 269.0

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The 2014 performance objectives were:
  Threshold Target Exceptional
Excellent Operations      
Equivalent Availability Factor (“EAF”) Generation Reliability – Summer 91.0% 91.1% - 92.0% 92.1% +
System Average Interruption Duration Index (“SAIDI”) Transmission/Distribution Reliability 81-95 60-80 < 60
Customer Satisfaction - Improve Residential Customer Satisfaction Score Measured by JD Powers 635 656 ≥665
Generation Mix - Diversify Fuel Mix SGS Unit 1 SGS Unit 1 & Combined Cycle Asset SGS Unit 1, Combined Cycle Asset and a 3-year firm wholesale sale with a third party or complete long-term firm wholesale sale to a third party, revised hedging plan
Safe Work Environment      
OSHA Rate (Employee Safety Measure) 1.90 and Safety Process Analysis (SPA) complete 1.50 and SPA and 80% Process Improvement Goals < 1.1 and SPA and 90% Process Improvement Goals
2014 PEP Results
Effect of the Merger on 2014 PEP:
The Merger agreement called for PEP to be paid 30 days from the date of the closing of the Merger, in a manner consistent with past practices. Since the PEP program is based on annual goals, we used a combination of actual results as of the merger date and forecasted performance for the rest of the year where needed in an effort to establish a fair and consistent manner of reviewing goal attainment.
Summary:
Overall, the 2014 combined actual and forecasted results produced a total weighted performance for all goals of 108.7% of target performance, as summarized in Table A below. The Compensation Committee approved an overall PEP payout of 108.7% of target awards for all participants. Individual performance was not factored into any individual payouts in 2014 given the timeline requiring distribution of PEP awards within 30 days of the Merger.
The actual final 2014 year-end PEP results would have calculated to a total payout of 118.7% under the program. Three goals contributed to the difference between the results forecasted in August 2014 for PEP payments made in September 2014 and the actual final year-end results: 1) UNS Energy's 2014 Net Income was significantly higher than the August forecast; 2) the reliability measure SAIDI performed at a year-end "Exceptional" level rather than the forecasted "Target" performance; and 3) the safety incident rate was higher than forecasted at year-end resulting in a final outcome of "Threshold" rather than "Target" performance.
Table A: Summary of 2014 PEP Results
Goal 
Weighting of
Goal (A)
 
Percentage of
Target Performance
Achieved (B) (1)
 
Payout Percentage
(A x B)
Net Income 40% 100% 40.0%
Safe Work Environment 5% 100% 5.0%
O&M Cost Containment 10.0% 112% 11.2%
Excellent Operations 45.0% Various 52.50%
  100%   108.7%
(1)
Additional details provided below.

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Net Income Goal:
In 2014, the Company projected $141.9 million of net income, which was target performance. The calculation, per the Merger Agreement, was based on net income excluding any merger-related costs. Table B, below, reflects the net income goal, which ranged from $133.5 million (threshold) to $150.3 million (exceptional), and the corresponding payout levels, which ranged from 50% to 150% of the target award, as well as the actual net income achieved for 2014. Net income must have been more than $133.5 million to produce a payout. The anticipated achievement of $141.9 million in net income resulted in a payout level of 100% of the target amount for that performance objective. Achievement was calculated on actual results from January to June 2014, plus forecasted results from July to December 2014.
Table B: Net Income
 Final Result: $141.9
 Range (Millions of Dollars)
 $134$135$137$139$140$142$144$145$147$149$150
Payout % of Target50%60%70%80%90%100%110%120%130%140%150%
 á    á    á
 Threshold   Target   Exceptional
O&M Cost Containment Goal:
The Company projected an O&M spending level for 2014 of $272.8 million. For this goal, lower spending represents better performance. O&M spending, for purposes of a PEP calculation, is defined as the sum of O&M expenses for TEP and UES operations, excluding (1) any reimbursable items for O&M costs incurred by TEP for operating Units 3 and 4 at the Springerville Generating Station; (2) reimbursable O&M expenses for renewable and demand side management programs; (3) any PEP accrued expense; and (4) any merger-related costs. TEP operates Unit 3 for Tri-State, which leases the unit from financial owners, and Unit 4, which is owned by Salt River Project Agricultural Improvement and Power District. Achievement was calculated on actual results from January to June 2014, plus forecasted results from July to December 2014. Table C, below, reflects the O&M cost containment goal, which ranged from $279 million (threshold) to $269 million (exceptional), and the corresponding payout levels, which ranged from 50% to 150% of the target award, as well as the anticipated O&M spending level achieved for 2014. The achievement of O&M spending of $272.8 million was less than the threshold amount of $279 million, which resulted in a payout level of 112.0%.
Table C: O & M Cost Containment
 Final Result: $272.8
 Range (Millions of Dollars)
 $279$278$277$276$275$274$273$272$271$270$269
Payout % of Target50%60%70%80%90%100%110%120%130%140%150%
 á    á    á
 Threshold   Target   Exceptional
Excellent Operations Goals:
Equivalent Availability Factor (“EAF”): The reliability of the Company's plant performance during the peak summer demand season is critical to its customers and due to approved rate design, to financial performance; therefore, a Summer EAF goal is used in measuring the reliability of the Company's coal generation fleet.
System Average Interruption Duration Index (“SAIDI”): This reliability measure in the Company's Transmission and Distribution business area is a good outage duration performance measure, as it tracks the length or duration of outages across all customers, giving the Company a focus on reducing the outage time a customer experiences. UNS Energy generally compares well to industry ranges given by the EEI. Achievement was calculated on actual results from January to July 2014, plus forecasted results based on five years of historical trends from August to December 2014.
Customer Satisfaction: In 2014, the Company introduced a new Customer Satisfaction goal, measured by our JD Power performance. A concentration on improving our interactions with our customers was critical to the outcome of this goal. Focus areas included call center response time, customer communication improvements, and a new outage map. Achievement of this goal was based on the first two 2014 quarter results, which was all that was available at the time of calculation.

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Generation Mix: The Company has had a strong focus on executing the strategy around our generation fleet as we divest of coal and optimize our generation resources. The goal concentrated on wholesale sales and the successful acquisition of a new power plant. Achievement of this goal was based on a status update of three separate transactions all contributing to the success of this goal.
Safe Work Environment Goal:
Safety: The Company's safety measure tracks the OSHA Recordable Incident Rate, which is a good indicator of a company’s safety efforts. Continued focus on safety initiative components (leadership, employee involvement, and regulatory compliance) is a priority for the Company. Historically the Company has continued to improve its safety record. Achievement was calculated on actual results from January to July 2014, plus forecasted results based on five years of historical trends from August to December 2014.
Table D, below, reflects the final achievement at the various levels of performance for the Excellent Operations and Safe Work Environment goals. According to the guidelines set by the Compensation Committee, the achievement of these goals yielded a result of 57.5% for this combination of performance objectives.
Table D: Excellent Operations/Safe Work Environment Goals
  Weight Actual Result Final Value Totals
Excellent Operations (45.0% Weighting)
        
Equivalent Availability Factor (“EAF”) Generation Reliability – Summer 7.50% Below Threshold —%  
System Average Interruption Duration Index (“SAIDI”) Transmission/Distribution Reliability 7.50% Target 7.50%  
Customer Satisfaction - Improve Residential Customer Satisfaction Score Measured by JD Powers 15.00% Exceptional 22.50%  
Generation Mix - Diversify Fuel Mix 15.00% Exceptional 22.50%  
Subtotal: Excellent Operations       52.50%
Safe Work Environment (5.0% Weighting)
        
OSHA Rate (Employee Safety Measure) 5.00% Target 5.00%  
Subtotal: Safe Work Environment       5.00%
Total Percentage for Excellent Operations and Safe Work Environment       57.50%
 The Company’s internal audit department verified that the reported results for the 2014 PEP goals were accurate and reported its findings to the Compensation Committee at the time of the Merger.
The amounts of the 2014 PEP awards paid to each of the Named Executives are listed in the Summary Compensation Table below.
Long-Term Incentive Compensation (Equity Awards)
Prior to the Merger, UNS Energy believed that equity awards, in tandem with the Company’s executive officer stock ownership guidelines discussed below, encouraged ownership of UNS Energy stock by executive officers and held executive officers accountable for the long-term impact of their actions, which in turn aligned the interest of those executive officers with the interest of UNS Energy’s shareholders. In addition, the vesting provisions applicable to the awards encouraged a focus on long-term operating performance, linking compensation expense to the achievement of multi-year financial results and helping to retain executive officers.
The long-term incentive (“LTI”) opportunity for each Named Executive is based on a percentage of salary. The 2014 LTI multiples are 125% for Mr. Hutchens, 100% for Mr. Larson, 125% for Mr. Dion, 40% for Ms. Kissinger, and 40% for Mr. Hixon. Mr. Dion's 2014 LTI opportunity reflects his contribution to TEP's 2013 rate case and will return to its regular percentage in 2015. The 2014 LTI multiple was 150% of base salary for Mr. Bonavia, who retired from his position as CEO of TEP on May 2, 2014. The values of the Named Executives’ long-term incentives, as a dollar value, are generally in the 25th percentile to median range of the Peer Group. Under the design of the compensation plan for 2014, two-thirds of the award opportunity was to be granted as performance shares and one-third was granted as restricted stock units that vest 100% on the third anniversary of grant to support retention objectives as well as succession planning initiatives. Pursuant to the terms of the Merger agreement, the outstanding 2012, 2013, and 2014 LTI awards were canceled in exchange for cash payments to each of the Named Executives at the time of the merger.

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2014 Performance Shares
If the Merger had not occurred, performance share awards granted in 2014 were to be distributed, along with dividend equivalents (to the extent that the performance shares become earned and vested), at the end of the three-year performance period ending in 2016, based on the following equally-weighted performance targets:
TSR Performance Criteria
TSR Percentile Rank
Payout as a Percent of 
Target Award
75th percentile and above
75.0%
62.5th percentile
62.5%
50th percentile
50.0%
42.5th percentile
37.5%
35th percentile
25.0%
Below 35th percentile
0.0%
Intermediate payouts determined by interpolation.
Cumulative Net Income Performance Criteria
Degree of Performance Attainment
Three-Year Cumulative
Net Income
 
Payout as a Percent of Target
Award Earned
 Millions of Dollars  
Outstanding$531
 75.0%
Target462
 50.0%
Threshold393
 17.5%
Less than Threshold< 393
 0.0%
Intermediate payouts determined by interpolation.
Equity Grant Timing and Practice
Generally, during the first quarter following the close of a fiscal year, prior to the Merger, the Compensation Committee approved and granted the long-term incentive awards for that year, including the type of equity to be granted, as well as the size of the awards for Named Executives. In determining the type and aggregate size of awards to be provided, as well as the performance metrics that would apply, the Compensation Committee considered the strategic goals of the Company, trends in corporate governance, accounting impact, tax deductibility, cash flow considerations, the impact on earnings per share and the number of shares that would be required to be allocated for the award and the resulting impact to shareholders. The timing of awards was not coordinated with the release of material non-public information.
CLAWBACK PROVISION FOR VARIABLE COMPENSATION
Consistent with current “best practices,” all short- and long-term incentive compensation awards approved after 2009 are subject to a clawback provision. The clawback provision may apply to the income derived from the financial component of the PEP and the performance shares in the event of a restatement of financial results that, in the view of the Compensation Committee, results from intentional misconduct or intentional error. The Compensation Committee has discretion to determine to whom the clawback will apply and the amount subject to clawback, if such repayment is determined to be necessary.
ELEMENTS OF POST EMPLOYMENT COMPENSATION
Termination and Change in Control
The Compensation Committee determined that it is in the Company’s and shareholders’ best interest to enter into change in control agreements with its executive officers in order to attract highly qualified executives and to retain those executives through any future challenges that might arise. All of these agreements were designed to be consistent with contemporary “best practices,” such as double trigger severance payments and equity vesting and no excise tax gross-ups. These various agreements and the effects of the Merger are discussed in detail in Potential Payments Upon Termination or Change in Control, below.

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Generally speaking, the Company does not enter into or extend employment agreements with current officers and instead only uses employment agreements when needed in recruiting a new officer. The Company currently has no employment agreements in place.
UNS Energy also maintains a severance pay plan for all of the Company’s non-union employees, including its Named Executives, which continues the Company’s historical practice of providing severance pay in certain termination situations without a change in control and provides consistency in that practice.
Retirement and Other Benefits
The Company offers retirement and other core benefits to its employees, including the Named Executives, in order to provide them with a reasonable level of financial support in the event of illness or injury and to enhance productivity and job satisfaction. The benefits are the same for all employees and Named Executives and include medical and dental coverage, disability insurance and life insurance. In addition, the Tucson Electric Power Company 401(k) Plan (the “401(k) Plan”) and the Tucson Electric Power Company Salaried Employees Retirement Plan (the “Retirement Plan”) provide a reasonable level of retirement income reflecting employees’ careers with the Company. All employees, including Named Executives, participate in these plans; the cost of these benefits (other than the Retirement Plan) is partially borne by the employee, including each Named Executive. In addition, the Company provides all of its officers with an optional executive physical annually.
To the extent that any executive officer’s retirement benefit exceeds Internal Revenue Code (Code) limits for amounts that can be paid through a qualified plan, the Company also offers non-qualified retirement plans, including the Tucson Electric Power Company Excess Benefit Plan (Excess Benefit Plan) and the Management and Directors Deferred Compensation Plan (DCP). These plans provide only the difference between the calculated benefits and Code limits. These benefits are not tied to any formal individual or Company performance criteria but are intended to enhance the attraction and retention value of the executive officer compensation program and are consistent with similar competitive compensation benefits made available to executives in the industry. UNS Energy believes the DCP and the Excess Benefit Plan assist with the Company’s attraction and retention objectives. The DCP provides an industry-competitive and tax-efficient benefit to the executive officers. The DCP is not funded by the Company, and participants have an unsecured contractual commitment by the Company to pay amounts owed under the DCP. The Excess Benefit Plan provides the retirement benefits to executive officers that would have been provided under the Retirement Plan if the Code limitations did not apply. For more information on retirement and certain related benefits, see the discussion in Pension Benefits and Non-Qualified Deferred Compensation, below.
ROLE OF EXECUTIVES IN ESTABLISHING COMPENSATION
Certain executive officers, including the CEO, the CFO, the General Counsel and the Vice President of Human Resources and Information Technology, routinely attend regular sessions of Compensation Committee meetings; however, they are excused for executive sessions when their compensation is discussed and/or determined. The CEO makes recommendations to the Compensation Committee with respect to changes in compensation for senior executive officer positions (other than the CEO) and payouts under the annual incentive plan. The CEO also makes suggestions to the Compensation Committee regarding the design of incentive plans and other programs in which senior management participates.
The CFO provides information regarding short-term and long-term compensation targets, as well as updates on the progress of short- and long-term objectives. Additional Company personnel with expertise in and responsibility for compensation and benefits provide information regarding executive officer and director compensation, including cash compensation, equity awards, pensions, deferred compensation and other related information.
COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Human Resources and Governance Committee has reviewed and discussed with management the Compensation Discussion and Analysis section required by Item 402(b) of SEC Regulation S-K and contained in this annual report. Based on such review and discussions, the Human Resources and Governance Committee recommended to the Board of Directors of TEP that the Compensation Discussion and Analysis section be included in TEP’s annual report on Form 10-K for the year ending December 31, 2014.

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Respectfully submitted,
THE HUMAN RESOURCES AND GOVERNANCE COMMITTEE OF UNS ENERGY CORPORATION
Louise L. Francesconi, Chair
Lawrence J. Aldrich
Robert A. Elliott
Barry Perry
John C. Walker


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SUMMARY COMPENSATION TABLE – 2014 (1)
The following table sets forth summary compensation information for the years ended December 31, 2012; December 31, 2013; and December 31, 2014 for the Company’s Named Executives. Note that the column titled All Other Compensation includes for 2014 amounts received by the Named Executives for cancellation of all outstanding equity awards, including awards that were previously disclosed in the Summary Compensation Table in prior years, to the extent those awards represent compensation for services to TEP and its subsidiaries.
Name and Principal Position Year Salary 
Stock Awards (4)
 
Non-Equity Incentive Plan Compensation (5)
 
Change in Pension Value and Non-Qualified Deferred Compensation Earnings (6)
 
All Other Compensation (2)
 Total
Paul J. Bonavia
Former Board Chair and Chief Executive Officer (7)
 2014 $446,870
 $790,257
 $465,729
 $261,168
 $5,474,229
 $7,438,253
 2013 512,726
 904,888
 417,196
 165,574
 13,948
 2,014,331
 2012 498,557
 933,643
 377,372
 228,697
 13,408
 2,051,677
David G. Hutchens
President and Chief Executive Officer (3)
 2014 397,962
 417,359
 377,827
 555,358
 2,529,306
 4,277,812
 2013 306,482
 432,998
 198,513
 105,379
 14,209
 1,057,580
 2012 286,116
 446,431
 135,356
 331,559
 13,288
 1,212,750
Kevin P. Larson
Senior Vice President, Chief Financial Officer
 2014 289,922
 286,845
 158,639
 259,605
 4,122,921
 5,117,932
 2013 279,435
 327,989
 142,107
 46,725
 12,574
 808,831
 2012 271,713
 339,116
 128,542
 382,204
 12,226
 1,133,802
Philip J. Dion
Senior Vice President, Public Policy and Customer Solutions
 2014 236,367
 292,582
 129,615
 100,651
 662,457
 1,421,672
 2013 199,218
 70,005
 114,992
 16,221
 9,363
 409,799
Karen G. Kissinger
Vice President and Chief Compliance Officer
 2014 219,094
 86,054
 95,088
 325,958
 2,272,033
 2,998,227
 2013 216,627
 252,798
 107,659
 
 10,147
 587,230
 2012 213,880
 266,857
 80,946
 270,224
 10,019
 841,927
Todd C. Hixon
Vice President and General Counsel
 2014 226,742
 86,054
 96,072
 242,704
 460,900
 1,112,472
(1)
The amounts included in the Summary Compensation Table represent only the amounts paid by UNS for services to TEP and its subsidiaries and do not include amounts paid by UNS for services to others. For 2014 services, 80.46% of the amounts paid by UNS were allocable to services to TEP and its subsidiaries. For 2013 services, 79.7% of the amounts paid by UNS were allocable to services to TEP and its subsidiaries. For 2012 services, 78.9% of the amounts paid by UNS were allocable to services to TEP and its subsidiaries.
(2)
The amounts in the All Other Compensation column are composed primarily of payments in exchange for stock awards canceled in connection with the Merger, to the extent those awards represent compensation for services to TEP and its subsidiaries. Except for the 2014 awards disclosed in the Stock Awards column, above, all of the awards for which amounts were paid were previously disclosed in the Summary Compensation Table in prior years, and were also disclosed in the table showing Outstanding Equity Awards at Fiscal Year End. Except for the portion allocable to the 2014 awards, shown above, none of the amounts in this column are attributable to awards not previously disclosed.
The amounts in the All Other Compensation column also include Qualified 401 (k) Plan and Non-Qualified Plan Matching Contributions, and also include charitable gifts made on behalf of some Named Executives to a charity of the Named Executive’s choice. These amounts are reported in the year in which the Company committed to the contribution, even though the amount may not have been actually paid until a later year.
Finally, the amounts in the All Other Compensation column include additional payments that Messrs. Larson and Hixon received in 2014. Mr. Larson received a retention bonus in connection with the Merger and as consideration for amending his Change in Control Agreement, as explained in more detail in the section Potential Payments Upon Termination or Change in Control, below. Mr. Hixon received a bonus for his work in connection with the Merger.

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Mr. Bonavia’s total listed in the All Other Compensation column for 2014 included payments in exchange for stock awards canceled in connection with the Merger totaling $5,460,148, qualified plan 401(k) matching contributions of $9,414 and non-qualified plan 401(k) matching contributions of $4,667.
Mr. Hutchens’ total listed in the All Other Compensation column for 2014 included payments in exchange for stock awards canceled in connection with the Merger totaling $2,515,225, qualified plan 401(k) matching contributions of $9,414 and non-qualified plan 401(k) matching contributions of $4,667.
Mr. Larson’s total listed in the All Other Compensation column for 2014 included payments in exchange for stock awards canceled in connection with the Merger totaling $3,908,725, qualified plan 401(k) matching contributions of $9,414 and non-qualified plan 401(k) matching contributions of $3,632, and a retention bonus related to the amendment of his Change in Control Agreement of $201,150.
Mr. Dion’s total listed in the All Other Compensation column for 2014 included payments in exchange for stock awards canceled in connection with the Merger totaling $651,419, qualified plan 401(k) matching contributions of $9,414 and non-qualified plan 401(k) matching contributions of $1,222, and a $402 charitable contribution.
Ms. Kissinger’s total listed in the All Other Compensation column for 2014 included payments in exchange for stock awards canceled in connection with the Merger totaling $2,261,790, qualified plan 401(k) matching contributions of $9,414 and non-qualified plan 401(k) matching contributions of $427, and a $402 charitable contribution.
Mr. Hixon’s total listed in the All Other Compensation column for 2014 included payments in exchange for stock awards canceled in connection with the Merger totaling $320,919, qualified plan 401(k) matching contributions of $9,414 and non-qualified plan 401(k) matching contributions of $771, and a bonus for work in connection with the Merger of $129,796.
(3)
Mr. Hutchens became TEP's CEO on May 2, 2014, when Mr. Bonavia became the Executive Board Chair.
(4)The amounts included in the Stock Awards column reflect 80.46% of the grant date fair value calculated in accordance with FASB ASC Topic 718 for restricted stock units and performance shares granted in each of the years reported, excluding the effect of forfeitures. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $57.47 per share. These awards are based on UNS Energy's compound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index for the three year performance period ended December 31, 2016. The remaining half had a grant date fair value, based on the grant date closing price, of $60.39 per share based on cumulative net income for the performance period ended December 31, 2016. The restricted stock units had a grant date fair value, based on the grant date closing price, of $60.39 per share. The restricted stock units vest on the third anniversary of grant over the vesting period. In the case of performance shares the amounts in the column reflect the grant date fair value assuming the probable outcome of the performance conditions. The 2014 amounts attributable to Restricted Stock Units and Performance Shares are shown on the following table:
 Restricted Stock Units Performance Shares Total
Paul J. Bonavia267,729
 522,528
 790,257
David G. Hutchens141,396
 275,963
 417,359
Kevin P. Larson97,180
 189,665
 286,845
Philip J. Dion99,123
 193,459
 292,582
Karen G. Kissinger29,154
 56,900
 86,054
Todd C. Hixon29,154
 56,900
 86,054
If the merger had not occurred, the maximum amount that each person could have received assuming the maximum level of performance and using the fair market value of a share of Company common stock on the grant date ($60.39), would have been: $1,051,522 for Paul Bonavia, $555,341 for David G. Hutchens, $381,677 for Kevin P. Larson, $389,311 for Philip J. Dion, $114,503 for Karen G. Kissinger and $114,503 for Todd C. Hixon.
Pursuant to the terms of the Merger agreement, all outstanding stock awards were canceled in exchange for cash payments in the amounts shown in the appropriate column of the table in Footnote (7) below, providing additional detail for the All Other Compensation column of the Summary Compensation Table, and also shown in Option Exercises and Stock Vested, below.
(5)
The 2014 PEP awards included in this column, pursuant to the terms of the Merger agreement, were paid in 2014 to each of the Named Executives.
(6)
Any increase in the present value of the accrued benefit in the Retirement Plan and Excess Benefit Plan is reported in this column. All named executives experienced an increase in the present value of their respective accrued pension benefits during 2014. The present value of accumulated benefits payable is reflected in Pension Benefits, below. UNS Energy does not pay “above market” interest on non-qualified deferred compensation; therefore, this column reflects change in pension value only. See Non-qualified Deferred Compensation, below.
(7)
Mr. Bonavia retired from his position as CEO of TEP on May 2, 2014.

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GRANTS OF PLAN-BASED AWARDS – 2014
The following table sets forth information regarding plan-based awards by UNS to the Company’s Named Executives in 2014 on account of services to TEP and its subsidiaries. As described above, 80.46% of the amount paid by UNS on account of services in 201411 is allocable to services to TEP and its subsidiaries. The compensation plans under which the grants in the following table were made are generally described in Compensation Discussion and Analysis, above and include the PEP, which provides for non-equity (cash) performance awards, and the 2011 Omnibus Plan, which provides for equity-based performance awards including stock options, restricted stock units and performance shares.
  Grant Date 
Estimated Possible Payouts 
Under Non-Equity
 Incentive Plan Awards(1)
 
Estimated Future Payouts Under
Equity Incentive Plan Awards(2)
 
All Other Stock Awards: Number of Shares of Stock or Units (3)
 
Grant
Date
Fair
Value
of
Stock
and
Option
Awards(4)
Name   Threshold Target Maximum Threshold Target Maximum    
PAUL J. BONAVIA                
PEP 2/24/2014 $214,226
 $428,454
 $642,680
          
Performance Shares 2/24/2014       3,769
 8,867
 13,300
   $522,528
Restricted Stock Units 2/24/2014             4,433
 267,729
DAVID G. HUTCHENS                
PEP 2/24/2014 173,794
 347,587
 521,381
          
Performance Shares 2/24/2014       1,991
 4,683
 7,024
   275,963
Restricted Stock Units 2/24/2014             2,341
 141,396
KEVIN P. LARSON                
PEP 2/24/2014 72,971
 145,942
 218,913
          
Performance Shares 2/24/2014       1,368
 3,218
 4,828
   189,665
Restricted Stock Units 2/24/2014             1,609
 97,180
KAREN G. KISSINGER                
PEP 2/24/2014 43,739
 87,477
 131,216
          
Performance Shares 2/24/2014       410
 966
 1,448
   56,900
Restricted Stock Units 2/24/2014             483
 29,154
PHILIP J. DION                
PEP 2/24/2014 59,621
 119,242
 178,863
          
Performance Shares 2/24/2014       1,395
 3,283
 4,924
   193,459
Restricted Stock Units 2/24/2014             1,641
 99,123
TODD C. HIXON                
PEP 2/24/2014 44,191
 88,382
 132,589
          
Performance Shares 2/24/2014       410
 966
 1,448
   56,900
Restricted Stock Units 2/24/2014             483
 29,154
(1)
The amounts shown in this column reflect the range of payouts (50%-150% of the target award) for 2014 performance under the PEP, as described in Compensation Discussion and Analysis - Short-Term Incentive Compensation, above. These amounts are based on the individual’s current salary and position. The amount of cash incentive actually paid under the PEP for 2014 is reflected in the Summary Compensation Table above.
(2)
The amounts shown in this column reflect the range (35%-150% of the target award) of payouts in the form of performance shares targeted for 2014 performance under the 2011 Omnibus Plan for long-term incentive compensation, as described in the “Long-Term Incentive Compensation” section of the CD&A, above.
The target 2014 LTI multiples, as a percentage of base salary, are 125% for Mr. Hutchens, 100% for Mr. Larson, 125% for Mr. Dion, 40% for Ms. Kissinger, and 40% for Mr. Hixon. Mr. Dion's 2014 LTI opportunity reflects his contribution to TEP's 2013 rate case and will return to its regular percentage in 2015. The 2014 LTI multiple for Mr. Bonavia, who retired from his position as CEO of TEP on May 2, 2014, was 150% of base salary. The target LTIP award was granted partly in the form of performance shares and partly in the form of restricted stock units, with 67% of the value in the form of performance shares and the remaining 33% in the

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form of restricted stock units. Accordingly, each Named Executive received an LTIP target award of performance shares and restricted stock units the total value of which was equal to the executive’s base salary multiplied by the applicable multiple (e.g., 100% for CFO), divided by the grant date fair market value of a share of UNS Energy’s common stock ($60.39), rounded down to the nearest 10 shares. For example, the CFO's 2014 base salary (and LTIP target award) was $362,769. That amount divided by $60.39, and rounded down to the nearest 10 shares, resulted in an LTIP target award of 4,000 performance shares and 2,000 restricted stock units.
The 2014 awards of performance shares and restricted stock units were intended to issue shares at the end of the performance period depending on the Company’s performance relative to the two performance criteria described in Compensation Discussion and Analysis, above. The two performance criteria operate independently; a Named Executive would have received a payment on account of one of the criteria without regard to performance on the other criteria. However,omitted pursuant to the termsGeneral Instruction I(2)(c) of the Merger agreement, the 2014 stock awards were canceled in exchange for cash payments as shown in Option Exercised and Stock Vested, below.
(3)
The amounts shown in this column represent the number of time-based restricted stock units that were granted in 2014 under the 2011 Omnibus Plan.
(4)
 The amounts shown in this column represent the grant date fair value calculated in accordance with FASB ASC Topic 718. The amounts shown for performance shares are based on the probable outcome of performance conditions. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $57.47 per share. These awards are based on UNS Energy's compound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index for the three year performance period ended December 31, 2016. The remaining half had a grant date fair value, based on the grant date closing price, of $60.39 per share based on cumulative net income for the performance period ended December 31, 2016. The restricted stock units had a grant date fair value, based on the grant date closing price, of $60.39 per share. The restricted stock units vest on the third anniversary of grant over the vesting period. For more information about these awards, please refer to footnote 1 of the Summary Compensation Table and Compensation Discussion and Analysis, above.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END - 2014
There were no equity awards outstanding at the end of 2014. All outstanding equity awards were canceled in exchange for cash at the time of the Merger.
OPTION EXERCISES AND STOCK VESTED
The following table includes certain information with respect to the disposition by the Company’s Named Executives of outstanding stock options and stock awards that vested during the year ended December 31, 2014. The awards were originally issued by UNS Energy for services to UNS Energy and all of its subsidiaries. Only a portion of the awards represented compensation for services to TEP and its subsidiaries, which was 80.46% in 2014.
 Option Awards 
Stock Awards (2)
Number of
Shares Acquired
on Exercise
 
Value Realized on
Exercise(1)
 
Number of
Shares Acquired
on Vesting
 
Value Realized on
Vesting
Paul J. Bonavia48,228
 $1,646,494
 87,486.7
 $5,270,103
David G. Hutchens21,990
 650,358
 33,623.4
 2,025,704
Kevin P. Larson80,798
 2,524,679
 31,755.6
 1,912,920
Philip J. Dion3,412
 116,469
 10,760.0
 648,213
Karen G. Kissinger44,173
 1,324,742
 22455.3.
 1,352,657
Todd C. Hixon
 
 5,326.5
 320,919
(1)
Pursuant to the Merger agreement, all outstanding stock options were cancelled in exchange for a cash payment per share equal to the difference between the option exercise price and $60.25 pursuant to the Merger agreement.
(2)
The amounts shown in the Stock Awards columns of the table above include 80.46% of the performance shares earned for the 2011-2013 performance period, payment of which the Compensation Committee approved on February 6, 2014 and paid in shares of Company stock on February 14, 2014. The table below shows the number of performance shares that vested and the value realized on vesting, calculated using the fair market value of a share of Company stock on February 14, 2014 ($60.21).

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 Number of Shares Acquired on Vesting Value Realized on Vesting
Paul J. Bonavia24,189.5
 $1,456,449
David G. Hutchens2,671.3
 160,837
Kevin P. Larson8,783.8
 528,873
Philip J. Dion1,881.2
 113,264
Karen G. Kissinger6,902.7
 415,609
The amounts shown in the Stock Awards columns of the table above also include 80.46% of the total amounts paid, pursuant to the terms of the Merger agreement, for (i) all outstanding performance shares for the 2012-2014 performance period, the 2013-2015 performance period and the 2014-2016 performance period, and (ii) all outstanding restricted stock units. The per share value realized was $60.25, the price paid under the Merger.
 Number of Shares Acquired on Vesting Value Realized on Vesting
Paul J. Bonavia63,297.2
 $3,813,654
David G. Hutchens30,952.2
 1,864,867
Kevin P. Larson22,971.7
 1,384,046
Philip J. Dion8,878.8
 534,950
Karen G. Kissinger15,552.7
 937,048
Todd C. Hixon5,326.5
 320,919

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PENSION BENEFITS
The following table shows 80.46% of the present value of accumulated benefits payable to each of the Named Executives, including the number of years of service credited to each such Named Executive, under each of the Retirement Plan and the Excess Benefit Plan determined using interest rate and mortality rate assumptions used in the Company’s financial statements. See Note 8 of Notes to Consolidated Financial Statements. Information regarding the Retirement Plan and the Excess Benefit Plan can be found above in Retirement and Other Benefits.
  Plan Name 
Number of Years
Credited Service
 
Present Value of
Accumulated Benefit
 
Payments During Last
Fiscal Year
Paul J. Bonavia 
Tucson Electric Power
Salaried Employees
Retirement Plan(1)(3)
 5.75 $225,777
 $
  
Tucson Electric Power
Excess Benefit Plan(2)(3)
 5.75 811,940
 
David G. Hutchens 
Tucson Electric Power
Salaried Employees
Retirement Plan(1)(3)
 19.50 741,593
 
  
Tucson Electric Power
Excess Benefit Plan(2)(3)
 19.50 812,778
 
Kevin P. Larson 
Tucson Electric Power
Salaried Employees
Retirement Plan(1)(3)
 29.83 1,296,566
 
  
Tucson Electric Power
Excess Benefit Plan(2)(3)
 29.83 1,412,277
 
Philip J. Dion 
Tucson Electric Power
Salaried Employees
Retirement Plan(1)(3)
 6.83 150,201
 
  
Tucson Electric Power
Excess Benefit Plan(2)(3)
 6.83 68,941
  
Karen G. Kissinger 
Tucson Electric Power
Salaried Employees
Retirement Plan(1)(3)
 24 1,183,911
 
  
Tucson Electric Power
Excess Benefit Plan(2)(3)
 24 716,043
 
Todd C. Hixon 
Tucson Electric Power
Salaried Employees
Retirement Plan(1)(3)
 16.58 484,813
 
  
Tucson Electric Power
Excess Benefit Plan(2)(3)
 16.58 168,767
 
(1)
The Retirement Plan is intended to meet the requirements of a qualified benefit plan for Code purposes and is funded by the Company and made available to all eligible employees. The Retirement Plan provides an annual income upon retirement based on the following formula:
1.6% x years of service (up to 25 years) x final average pay
Final average pay is calculated as the average of basic monthly earnings on the first of the month following the employee’s birthday during the five consecutive plan years in which basic monthly earnings were the highest, within the last 15 plan years before retirement. Basic monthly earnings means the monthly base salary prior to any reduction for contributions to a Code section 401(k) plan, but excluding overtime pay, bonuses or other compensation. Years of service are based on years and months of employment. A Retirement Plan participant vests in his or her retirement benefit after five years of service. The maximum benefit available under the Retirement Plan is an annual income of 40% of final average pay (as defined above). Plan compensation for purposes of determining final average pay is limited by compensation limits under Code Section 401(a)(17). For 2014, the limit was $260,000 in annual income. Employees are eligible to retire early with an unreduced pension benefit if (i) the combination of their age and years of service equals or exceeds 85, or (ii) they are age 62 and have completed 10 years of service. Employees are also eligible for early retirement with a reduced pension benefit at age 55 with at least 10 years of service. The reduction at age 55 with 10 years of service is 42.6% and continues to be reduced at a lesser amount up to age 62, at which point there is no reduction. All optional forms of the benefit are actuarially equivalent. Mr. Larson and Ms. Kissinger are currently eligible for early retirement.
(2)
The Retirement Plan is subject to Code limitations on the amount of compensation that can be taken into account and on the amount of benefits that can be provided. The Excess Benefit Plan provides the retirement benefits to executive officers that would have been

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provided under the Retirement Plan if the Code limitations did not apply. The Excess Benefit Plan retirement benefit is calculated generally using the same pension formula as the Retirement Plan formula but with some modifications. Compensation for purposes of the Excess Benefit Plan is determined without regard to Code limits on compensation and by including voluntary salary reductions to the DCP and any annual incentive payment received under the PEP. The retirement benefit payable from the Excess Benefit Plan is reduced by the benefit payable to that person from the Retirement Plan. Vesting occurs after five years of service. Benefits are payable in a lump sum or annuity, at the participant’s election. Mr. Larson and Ms. Kissinger are currently eligible for early retirement.
(3)
The present value of accumulated benefits was calculated using a discount rate of 4.1% and RP-2000 Healthy Mortality tables.
NON-QUALIFIED DEFERRED COMPENSATION
UNS Energy sponsors the DCP for directors, executive officers and certain other employees of UNS Energy. Under the DCP, employee participants are allowed to defer on a pre-tax basis up to 100% of base salary and cash bonuses, and non-employee director participants are allowed to defer up to 100% of their cash compensation. The DCP also allows the executive employee participants to receive the 401(k) Company match that cannot be contributed to the 401(k) Plan because of limitations imposed by the Code. The deferred amounts are valued daily as if invested in one or more of a number of investment funds, including UNS Energy stock units, each of which may appreciate or depreciate in value over time. The choice of investment funds is determined by the individual participant. The amounts shown in the table below represent 80.46% of the total amounts, to reflect the portion allocable to TEP and its subsidiaries.
  
Executive
Contributions
in Last Fiscal
Year (1)
 
Registrant
Contributions
in Last Fiscal
Year(2)
 
Aggregate
Earnings in
Last Fiscal
Year (3)
 
Aggregate
Withdrawals/
Distributions
 
Aggregate
Balance at
Last Fiscal
Year End (4)
Paul J. Bonavia $
 $
 $
 $43,357
 $
David G. Hutchens 
 
 
 19,443
 
Kevin P. Larson 
 
 3,123
 59,835
 54,068
Philip J. Dion 
 
 
 1,222
 
Karen G. Kissinger 
 
 3,441
 6,292
 121,766
Todd C. Hixon 
 
 
 771
 
(1)
Represents contributions to the DCP by the Named Executives during the year. The amounts shown, if any, are included in the salary column of the Summary Compensation Table, above.
(2)
Represents Company contributions to the DCP in 2014 for the 2014 plan year. These amounts are included in the “All Other Compensation” column of the Summary Compensation Table, above.
(3)
Represents the total market based earnings (losses) for the year on all deferred compensation under the DCP based on the investment returns associated with the investment choices made by the Named Executive. Amounts in this column are not included in the Summary Compensation Table.
(4)The aggregate balance includes compensation that was previously earned and reported in the Summary Compensation Table for 2012 and 2013 (if any) as follows: Mr. Larson—$8,779 and Ms. Kissinger—$1,934. Benefits under the plan will be distributed on the first to occur of the following events: separation from service, disability or death, in the form of either a lump sum or installment payments. The following table shows the deemed investment options available under the DCP and the annual rate of return for the calendar year ended December 31, 2014.
Name of Fund Rate of Return Name of Fund Rate of Return
Fidelity Retirement Money Market 0.01% Fidelity Spartan Us Equity Index 13.65%
Fidelity Intermediate Bond 3.31% Fidelity Growth Company 14.57%
Janus Flexible Bond 4.93% Fidelity Low Price Stock 7.75%
Fidelity Asset Manager 5.48% Janus Worldwide 7.25%
Fidelity Equity-Income 8.81% T. Rowe Price Blue Chip Growth 9.28%
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
In order to ensure that the Company is able to retain its Named Executives, the Compensation Committee had determined that it is in the best interest of the Company and its shareholders to enter into change in control agreements with those Named Executives, as well as to maintain a severance pay plan for all of the Company’s non-union employees, including the Named Executives.

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Change in Control Agreements
Each of our current executive officers, including our named executive officers who are currently employed by the Company, is party to a change in control agreement with UNS Energy. Under the change in control agreements, the executive officer will be entitled to receive change in control benefits if he or she incurs a separation from service due to the Company’s termination of his or her employment without “Cause” or due to the executive officer’s termination of employment with the Company for “Good Reason” during the six-month period prior to the occurrence of a Change in Control and if the executive officer’s separation from service is effected in contemplation of such Change in Control. The executive officer also will be entitled to receive these benefits if he or she incurs a separation from service due to the Company’s termination of his or her employment without Cause or due to the executive officer’s termination of employment for Good Reason during the 24-month period following the occurrence of a Change in Control.
A Change in Control is defined as (i) the acquisition of beneficial ownership of 40% of the common stock of UNS Energy, (ii) certain changes in the Board, (iii) the closing of certain mergers or consolidations or (iv) certain transfers of the assets of UNS Energy. Notwithstanding the foregoing, a Change in Control will not be deemed to have occurred until: any required regulatory approval, including any final non-appealable regulatory order, has been obtained; and the transaction that would otherwise be considered a Change in Control closes. A Change in Control with UNS Energy occurred on August 15, 2014, the time of the Merger. Since there was a Change in Control, if a qualifying separation occurs during the protection period, then the executive officer will be entitled to severance benefits in the form of: (i) a single lump sum payment in an amount equal to two (for Mr. Hutchens, who was entitled to one and one-half in his previous role as President and COO, and Mr. Bonavia in both his CEO and Executive Board Chair roles), one and one-half (for Messrs. Larson and Dion) or one (for Ms. Kissinger and Mr. Hixon) times the greater of (a) the executive officer’s annualized base salary as of the date of the executive officer’s separation from service, or (b) the executive officer’s annualized base salary in effect immediately prior to any material diminution in the executive officer’s base salary following execution of the change in control agreement; (ii) a single lump sum cash payment in an amount equal to two (for Mr. Hutchens, who was entitled to one and one-half in his previous role as President and COO, and Mr. Bonavia in both his CEO and Executive Board Chair roles), one and one-half (for Messrs. Larson and Dion) or one (for Ms. Kissinger and Mr. Hixon) times the average payment to which the executive officer was entitled pursuant to the short-term incentive compensation plan for the three calendar years immediately preceding the calendar year in which the executive officer’s separation from service occurs or, if that data is not available, the executive officer’s target payment under the short-term incentive compensation plan; (iii) a single lump sum cash payment in an amount equal to a prorated portion of the actual payment to which the executive officer would have been entitled under the short-term incentive compensation plan for the calendar year in which the executive officer’s separation from service occurs; and (iv) a single lump sum cash payment in the amount of the payment, if any, to which the executive officer is entitled under the short-term incentive compensation plan (based on the executive officer’s actual performance) for the year prior to the year in which the executive officer’s separation from service occurs, to the extent not already paid to the executive officer. “Good reason” is defined under these agreements to mean (1) a material, adverse diminution in the executive officer’s authority, duties or responsibilities; (2) a material change in the geographic location at which the executive officer must primarily perform services; (3) a material diminution in the executive officer’s base salary provided that such diminution is not a result of a generally applicable reduction in the base salary of all officers of the Company in an amount that does not exceed 10%; or (4) any action or inaction that constitutes a material breach of the agreement by the Company. “Cause” is defined under these agreements to mean (i) the willful failure of the executive officer to perform any of the executive officer’s duties for the Company which continues after the Company has given the participant written notice describing the failure and an opportunity to cure the failure, (ii) a material violation of Company policy, (iii) any act of fraud or dishonesty, (iv) the executive officer’s gross misconduct in the performance of the executive officer’s duties that results in material economic harm to the Company, (v) the executive officer’s conviction of, or plea of guilty or no contest, to a felony, or (vi) the executive officer’s material breach of the executive officer’s employment agreement with the Company, if any.
The executive officer would also be entitled to continue to participate in TEP’s health, life, disability or other insurance benefit plans for a period expiring on the earlier of (a) 24 months (for Mr. Hutchens, who was entitled to 18 months in his previous role as President and COO, and Mr. Bonavia in both his CEO and Executive Board Chair roles), 18 months (for Messrs. Larson and Dion), or 12 months (for Ms. Kissinger and Mr. Hixon) following the executive officer’s separation from service, or in some cases for the respective period following the Change in Control event, or (b) the day on which the executive officer becomes eligible to receive any substantially similar benefits, on a benefit-by-benefit basis, under any plan or program of any successor employer. In the event the executive officer elected a high deductible health care plan pursuant to which TEP has agreed to make contributions to the executive officer’s health savings account, then TEP will pay to the executive officer a single lump sum cash payment in an amount equal to the contributions that TEP would have made to the executive officer’s health savings account during the respective benefit continuation period described above had the executive officer not incurred the separation from service.

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The Change in Control Agreements provide that the executive officer shall be employed by UNS Energy or one of its subsidiaries or affiliates, in a position comparable to the current position, with base compensation and benefits at least equal to the then-current compensation and benefits, for an employment period of two years after a Change in Control (subject to earlier termination for cause or the executive officer’s termination without good reason).
The Change in Control Agreements also contain a number of material conditions or obligations applicable to the receipt of payments or benefits, which require the executive officer to (i) continue to abide by the terms and provisions of the Company’s policies that protect various forms of confidential information and intellectual property; (ii) refrain from consulting with, engaging in or acting as an advisor to another company about business that competes with the Company; (iii) refrain from soliciting business for or in connection with any competing business (a) from any individual or entity that obtained products or services from the Company at any time during the executive officer’s employment with the Company or (b) from any individual or entity that was solicited by the executive officer on behalf of the Company; and (iv) refrain from soliciting employees of the Company who would have the skills and knowledge necessary to enable or assist efforts by the executive officer to engage in a competing business. Item (i) referred to in this paragraph contains no durational limit, nor do the Change in Control Agreements include any provision providing for waiver of a breach of item (i). Items (ii) through (iv) referred to in this paragraph are effective for a period of one year following the date of the executive officer’s termination. Breach of items (ii) through (iv) is waived if the Company materially defaults on any of its obligations under the Change in Control Agreements.
No excise tax gross-ups are provided. Rather, severance payments to executives are cut back to the safe harbor limit if the reduction results in the executive receiving a greater after-tax benefit than if the excise tax were paid by the executive on the excess parachute payments; otherwise, all payments would be paid and the executive would pay the excise tax.
All long-term incentive awards contain a double trigger vesting provision, which provides for accelerated vesting only if outstanding awards are not assumed by an acquirer. As a result of the Merger, Fortis, Inc. did not assume the outstanding awards and the 2012, 2013, and 2014 awards vested and were paid pursuant to the Merger agreement. This double trigger vesting provision applies to future awards and/or if the Named Executive is terminated without cause within 24 months of a Change in Control. The double trigger, which is viewed as a corporate governance “best practice,” ensures that the Named Executives do not receive accelerated benefits unless they are adversely affected by the Change in Control.
Effective May 2, 2014, Mr. Bonavia became Executive Board Chair of UNS Energy and TEP and retired from his position as CEO. Incident to his relinquishing his position as CEO, Mr. Bonavia waived his right to claim that the change in responsibility will provide him with good reason to terminate his employment and receive benefits under his Change in Control agreement. Mr. Bonavia also agreed to the termination of his Change in Control agreement on the 31st day following the closing of the Merger. Mr. Bonavia retired from UNS Energy on September 19, 2014.
On May 2, 2014, Mr. Hutchens was appointed CEO of UNS Energy and TEP in addition to his duties as President and Chief Operating Officer of each company. Incident to the appointment, Mr. Hutchens's Change in Control agreement was modified to increase the benefits to which he will be entitled if his employment is terminated by UNS Energy without cause or by Mr. Hutchens with good reason following a change in control and to provide that he was not entitled to terminate employment and receive the benefits provided by his Change in Control Agreement solely for the reason that he would no longer be CEO of a publicly traded company as a result of the Merger.
On November 13, 2014, UNS Energy and Mr. Larson entered into a retention bonus agreement, the terms of which were approved by the UNS Energy Human Resources and Governance Committee. The retention bonus agreement amends Mr. Larson's change in control agreement to provide that changes in Mr. Larson's responsibilities that occurred as a result of the Merger, or that may occur for succession purposes based on a future mutually-agreed transition process, shall not constitute good reason for Mr. Larson to terminate his employment and receive benefits under the change in control agreement.
Severance Pay Plan
In addition, the Company has a severance pay plan (Severance Plan) for all of the Company’s non-union employees, including its Named Executives, which provides for severance benefits in the event of a qualifying termination, which means a termination without cause without a change in control. Cause for termination under the Severance Plan means (i) the willful failure of the employee to perform any of the employee’s duties for the employer which continues after the employer has given the participant written notice describing the failure and an opportunity to cure the failure, (ii) a material violation of Company policy, (iii) any act of fraud or dishonesty, (iv) willful failure to report to work for three days or to report to work on the agreed-upon date after a scheduled leave, or (v) willfully engaging in conduct that is demonstrably and materially injurious to the Company or any affiliate, monetarily or otherwise, including acts of fraud, misappropriation, violence or embezzlement for personal gain at the expense of the Company or any affiliate, conviction of (or plea of guilty or no contest or its equivalent to) a felony, or a misdemeanor involving immoral acts.

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In the event of a qualifying termination, the Named Executive would be entitled to (i) a cash severance payment equal to a multiple of base salary (two times for Mr. Hutchens, who was entitled to one and one-half times in his previous role as President and COO, one and one-half times for Messrs. Larson and Dion, and one time for Ms. Kissinger and Mr. Hixon; Mr. Bonavia, who retired from TEP May 2, 2014 was eligible for two times his base salary); (ii) continued subsidy of the premiums for COBRA medical, dental and vision coverage at the same rate as that paid by the Company prior to the separation from service for a period of the lesser of (a) 12 months, or (b) the date when the Named Executive becomes eligible for comparable benefits offered by a subsequent employer; and (iii) a portion of the amount to which the Named Executive would have been entitled under the Company’s PEP or any successor plan, based on the executive’s target payment for the year in which the executive’s separation from service occurs, had the Named Executive not incurred a separation from service. Receipt of benefits under the Severance Plan is contingent upon execution of a release of claims against the Company and subject to compliance with restrictive covenants, including perpetual confidentiality and non-disparagement provisions, and non-compete and non-solicitation requirements effective for the applicable severance period (two years for Mr. Hutchens, who was entitled to one and one-half years in his previous role as President and COO, one and one-half years for Messrs. Larson and Dion, and one year for Ms. Kissinger and Mr. Hixon; Mr. Bonavia, who retired from his position as CEO of TEP on May 2, 2014 was eligible for two years in both his CEO and Executive Board Chair roles). Duplication of benefits provided under the Severance Plan is not permitted, and benefits payable under the Severance Plan cease in the event the Named Executive becomes eligible for change in control severance benefits or if the Named Executive has an employment agreement that provides for severance benefits.
In the event a Named Executive becomes eligible to receive severance benefits under the Severance Plan and has elected a health care option pursuant to which the Company has agreed to make pre-tax contributions to the Named Executive’s Health Savings Account, then the Company will pay the Named Executive an amount equal to the contributions the Company would have made to the Named Executive’s health savings account during the twelve-month period immediately following the Named Executive’s separation from service, plus a tax allowance in an amount equal to the federal, state and local taxes imposed on the Named Executive with respect to such contributions and with respect to the tax allowance. While as a general matter the Company does not provide tax gross-ups for severance arrangements or other benefits, it was deemed appropriate in this very limited circumstance because (1) this particular type of benefit would be provided pre-tax, if the individual were still employed; (2) the amounts in question are exceptionally small; and (3) this treatment is available to all unclassified employees, not just the Named Executives, who become entitled to severance benefits under the Severance Plan and participate in the type of health care option described in this paragraph, above.
Other than the agreements described above, UNS Energy has not entered into any severance agreements or employment agreements with any Named Executives.
The following table and summary set forth potential payments payable to the Named Executives (other than Mr. Bonavia, who retired from his position as CEO of TEP on May 2, 2014) upon termination of employment or a Change in Control assuming their employment was terminated on December 31, 2014.
  
If Retirement or
Voluntary
Termination
Occurs (1)
 
If “Change In Control”
and Qualifying
Termination Occurs(2)
 
If Death or
Disability
Occurs(3)
 
If “Non-
Change In
Control”
Termination
Occurs(4)
David G. Hutchens $
 $1,199,170
 $
 $883,562
Kevin P. Larson 
 656,546
 
 439,227
Philip J. Dion 
 533,863
 
 373,267
Karen G. Kissinger 
 331,132
 
 235,683
Todd C. Hixon 
 306,096
 
 225,825
(1)
In the event of retirement or voluntary termination, each of the Named Executives would be entitled to receive vested and accrued benefits payable from the Retirement Plan and the Excess Benefit Plan, but no form or amount of any such payment would be increased or otherwise enhanced nor would vesting be accelerated with respect to such plans. In addition, no accelerated vesting of options, restricted stock units or performance shares would occur. Retirement Plan and Excess Benefit Plan information for the Named Executives is set forth in the Pension Benefits Table above.

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(2)The amounts shown represent the following:
  Cash 
Prorated
Non-equity
Incentive Award
 
Medical
Benefits
 Total
David G. Hutchens $1,169,983
 $
 $29,187
 $1,199,170
Kevin P. Larson 654,443
 
 2,103
 656,546
Philip J. Dion 510,548
 
 23,315
 533,863
Karen G. Kissinger 314,142
 
 16,990
 331,132
Todd C. Hixon 301,227
 
 4,869
 306,096
Amounts shown in the column headed Prorated Non-equity Incentive Award above represent the total "target" PEP award for 2014.
(3)
In the event of death, the Named Executive’s survivor would be entitled to receive a survivor annuity from the Retirement Plan and Excess Benefit Plan. The amount payable to the survivor would be less than the amount that would otherwise have been payable to the Named Executive had the Named Executive survived and received retirement benefits under the Retirement Plan and Excess Benefit Plan. There would be no enhancements as to form, amount or vesting of such benefits in the event of a Named Executive’s death.
(4)This column reflects the amounts payable to the Named Executives in the event of an involuntary termination without cause or a resignation for good reason, as of December 31, 2014, under the Severance Plan. The amounts shown represent the following:
  Cash 
Pro-Rated
Non-equity
Incentive
Award
 
Medical
Benefits
 Total
David G. Hutchens $868,968
 $
 $14,594
 $883,562
Kevin P. Larson 437,826
 
 1,401
 439,227
Philip J. Dion 357,725
 
 15,542
 373,267
Karen G. Kissinger 218,693
 
 16,990
 235,683
Todd C. Hixon 220,955
 
 4,870
 225,825
Director Compensation
All TEP directors are also named executive officers of TEP and received no additional compensation for services as a director. All of their compensation is reflected in the Summary Compensation Table, above.
Compensation Committee Interlocks and Insider Participation
All members of the UNS Energy Compensation Committee and Human Resources and Governance Committee during fiscal year 2014 were independent directors, except for Messrs. Perry and Walker, who are executive officers of Fortis. No Compensation Committee member had any relationship requiring disclosure under Transactions with Related Persons, in Item 13, below. During fiscal year 2014, none of the Company’s executive officers served on the Compensation Committee (or its equivalent) or Board of Directors of another entity whose executive officer(s) served on UNS Energy’s Compensation Committee or Human Resources and Governance Committee, any other board committee, or the Board of Directors of UNS Energy or TEP as a whole.Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
AllInformation required by Item 12 is omitted pursuant to General Instruction I(2)(c) of the outstanding shares of common stock, no par value, of TEP are held by UNS Energy, which is an indirect, wholly owned subsidiary of Fortis.Form 10-K.


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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Director Independence
TEP’s directors are not independent since they are executive officersInformation required by Item 13 is omitted pursuant to General Instruction I(2)(c) of TEP and UNS Energy. There are no standing committees of the Board of Directors of TEP.
As described in Item 10 above, the Audit and Risk Committee of the UNS Energy Board of Directors is responsible for overseeing the accounting and financial reporting process and audits of the financial statements of UNS Energy and its consolidated subsidiaries, including TEP.
As described in Item 11 above, the Human Resources and Governance Committee of the UNS Energy Board of Directors is responsible for overseeing the executive compensation policies and practices of UNS Energy and its consolidated subsidiaries, including TEP.
The Board of Directors of UNS Energy has adopted Director Independence Standards that comply with New York Stock Exchange (NYSE) rules for determining independence, among other things, in order to determine eligibility to serve on the Audit and Risk Committee and the Human Resources and Governance Committee of UNS Energy. Neither UNS Energy nor TEP has any securities listed on the NYSE or any other national securities exchange or inter-dealer quotation system requiring that directors or committee members be independent but, in approving the acquisition of UNS Energy by Fortis, the ACC required that a majority of the members of the UNS Energy Board of Directors be independent. The written charters of the UNS Energy Audit and Risk Committee and Human Resources and Governance Committee each require that a majority of the members of each such committee meet both UNS Energy’s Director Independence Standards and independence standards of the NYSE. The UNS Energy Director Independence Standards are available on TEP’s website at www.tep.com/about/investors/.
No director may be deemed independent unless the Board of Directors of UNS Energy affirmatively determines, after due deliberation, that the director has no material relationship with UNS Energy or any of its subsidiaries either directly or as a partner, shareholder or executive officer of an organization that has a relationship with UNS Energy or any of its subsidiaries. In each case, the Board of Directors of UNS Energy broadly considers all the relevant facts and circumstances from the standpoint of the director as well as from that of persons or organizations with which the director has an affiliation and applies these standards.
Annually, the UNS Energy board determines whether each director meets the criteria of independence. Based upon the foregoing criteria, the UNS Energy board has deemed each director of UNS Energy to be independent, with the exception of Messrs. Hutchens, Perry, Walker and Laurito. Mr. Hutchens is the President and Chief Executive Officer of UNS Energy and TEP. Messrs. Perry and Walker are executive officers of Fortis. Mr. Laurito is an executive officer of Central Hudson Gas and Electric Corporation, another wholly owned subsidiary of Fortis. For each other director who is deemed independent, there were no other significant transactions, relationships or arrangements that were considered by the UNS Energy board in determining that the director is independent. See “Transactions with Related Persons” below.
Each member of UNS Energy’s Audit and Risk Committee and Human Resources and Governance Committee meets the independence criteria of both the Director Independence Standards and the NYSE listing standards, with the exception of Messrs. Perry and Walker, who are executive officers of Fortis, and Mr. Laurito, who is an executive officer of Central Hudson Gas and Electric Corporation. Mr. Hutchens is not a member of either committee.
Transactions with Related Persons
The UNS Energy Board of Directors has adopted a written Policy on Review of Transactions with Related Persons (“Related Person Policy”) under which it reviews related person transactions. The policy is available on TEP’s website at www.tep.com/about/investors/. The Related Person Policy specifies that certain transactions involving directors, executive officers, significant shareholders and certain other related persons in which UNS Energy or its subsidiaries, including TEP, is or will be a participant and are of the type required to be reported as a related person transaction under Item 404 of Regulation S-K shall be reviewed by the UNS Energy Audit and Risk Committee for the purpose of determining whether such transactions are in the best interest of UNS Energy and its subsidiaries. The Related Person Policy also establishes a requirement for directors and executive officers of UNS Energy and its subsidiaries to report transactions involving a related party that exceed $120,000 in value. TEP is not aware of any transactions entered into since the beginning of last year that did not follow the procedures outlined in the Related Person Policy.Form 10-K.


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ITEM 14.14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
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 and Risk 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 and Risk Committee to be informed of each service and does not include any delegation of the Audit and Risk Committee’s responsibilities to management. The Audit and Risk Committee may delegate to the Chair of the Audit and Risk Committee the authority to grant pre-approvals of audit and non-audit services requiring Audit and Risk Committee approval where the Audit and Risk Committee Chair believes it is desirable to pre-approve such services prior to the next regularly scheduled Audit and Risk Committee meeting. The decisions of the Audit and Risk Committee Chair to pre-approve any such services from one regularly scheduled Audit Committee meeting to the next shall be reported to the Audit and Risk Committee.
Fees
The following table details fees paid to PricewaterhouseCoopersEffective May 4, 2017, Ernst and Young LLP (PwC) for professional services during 2013. Effective October 7, 2014 PwC(EY) was dismissed as the independent auditorsauditor and replaced with Ernst and YoungDeloitte & Touche LLP (EY)(Deloitte) as a result of the Fortis acquisition. The table details fees paid to EY for professional services during 2014.Company’s independent registered public accounting firm. The Audit and Risk Committee has considered whether the provision of services to TEP by Deloitte and EY, beyond those rendered in connection with their audit and review of the TEP’s financial statements, is compatible with maintaining their independence as auditor.

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TEP'sThe following table details principal accountant fees paid to Deloitte and EY for professional services during 2017 and 2016:
 Deloitte EY
(in thousands)2017 2016
Audit Fees$1,145
 $1,484
Audit-Related Fees17
 
Tax Fees68
 100
All Other Fees24
 
Total$1,254
 $1,584
Audit Fees includes fees for principal accountantaudit services are as follows:
 EY PwC
 2014 2013
 Thousands of Dollars
Audit Fees(1)
$966
 $1,731
Audit-Related Fees
 47
Tax Fees84
 94
All Other Fees
 53
Total$1,050
 $1,925
(1)
Includes $991 thousand of fees billed directly to TEP in 2013, and $739 thousand of fees billed to UNS Energy and allocated to TEP in 2013.
Decrease in Audit-Related and Other Fees are due to the change in our principal accountant in 2014, resulting in exclusion of such prior accountant fees for services provided in 2014.
Audit fees include fees for the audit of TEP’sTEP's consolidated financial statements included in TEP’sits Annual Report on Form 10-K and review services of TEP's condensed consolidated financial statements included in TEP’sits Quarterly Reports on Form 10-Q. Audit feesFees also includeincludes services provided in connection with comfort letters, consents and other services related to SEC matters, financing transactions, and statutory and regulatory audits. For 2013, audit fees included TEP's allocated share of
Audit-Related Fees includes fees for the audit of effectiveness of internal control over financial reporting and management's assessment of the effectiveness of internal control over financial reporting for UNS Energy.consulting services with respect to ASC 606 Revenue Recognition.
Audit-related fees during 2013 principally includeTax Fees includes fees for employee benefit plan audits,research and accounting consultationsdevelopment services with respect to the extent necessary for PwC to fulfill their responsibilities under generally accepted auditing standards.
Tax fees reported for 2013 include fees for tax compliance servicescredits in 2017 and tax advice. Tax fees reported for 2014 include fees for tax appeals and consulting.in 2016.
All Other Fees consist ofincludes fees for all otherconsulting services other than those reported above, principally including subscription fees for research tools and training.with respect to regulatory filings.

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All services performed by our principal accountant are approved in advance by the Audit and Risk Committee in accordance with the Audit and Risk Committee’s pre-approval policy for services provided by the Independent Registered Public Accounting Firm.


12384


PART IV
ITEM 15.15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 Page
(a)(1)Consolidated Financial Statements as of December 31, 20142017 and 20132016, and for Eacheach of the Three Yearsthree years in the Period Endedperiod ended December 31, 20142017: 
  
  
(2)Financial Statement Schedule 
Schedule II 
All schedules have been omitted because they are either not applicable, not required, or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.
  
(3)Exhibits 
  
Reference is made to the Exhibit Index commencing on page 12686.
 

ITEM 16. FORM 10-K SUMMARY
Not Applicable.


12485



Exhibit Index
Exhibit No.Description
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. 1-05924 - Exhibit 2.1).
First Amendment to the Agreement and Plan of Merger, dated as of August 14, 2014, by and among FortisUS Inc., Color Acquisition Sub Inc. and UNS Energy Corporation (Form 8-K, dated August 14, 2014, File No. 1-05924 - Exhibit 2.2).
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. 1-05924 - Exhibit No 3(a)).
TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-05924 - Exhibit 3(a)).
Bylaws of TEP, as amended as of August 12, 2015 (Form 10-Q for the quarter ended September 30, 2015, File No. 1-05924 - Exhibit 3).
Amendment to Articles of Incorporation of UNS Energy Corporation, creating series of Limited Voting Junior Preferred Stock (Form 8-K dated August 12, 2015, File No. 1-05924 - Exhibit 3.2).
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. 1-05924 - Exhibit 4(A)).
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. 1-05924 - Exhibit 4(B)).
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. 1-05924 - Exhibit 4(C)).
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. 1-05924 - Exhibit 4(D)).
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. 1-05924 Exhibit 4(a)).
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. 1-05924 - Exhibit 4(b)).
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. 1-05924 - Exhibit 4(c)).

86



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. 1-05924 - Exhibit 4(d)).
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. 1-05924 - Exhibit 4(a)).
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. 1-05924 - Exhibit 4(b)).
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. 1-05924 - Exhibit 4(a)).
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. 1-05924 - Exhibit 4(b)).
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. 1-05924 - Exhibit 4(a)).
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. 1-05924 - Exhibit 4(b)).
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. 1-05924 - Exhibit 4(a)).
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. 1-05924 - Exhibit 4(b)).
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. 1-05924 - Exhibit 4(c)).
Amendment, dated May 26, 2015, between Tucson Electric Power Company, STI Institutional & Government, Inc., and Branch Banking and Trust Company, to Lender Rate Made Covenants Agreement, dated November 1, 2013 (Form 10-Q for the quarter ended June 30, 2015, File No. 1-05924 - Exhibit 4).
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 1-05924 - Exhibit 4.1).
Officers Certificate, dated November 8, 2011, authorizing 5.15% Notes due 2021. (Form 8-K dated November 8, 2011, File No. 1-05924 - Exhibit 4.2).

87



Officers Certificate, dated September 14, 2012, authorizing 3.85% Notes due 2023. (Form 8-K dated September 14, 2012, File No. 1-05924 - Exhibit 4.1).
Officer's Certificate, dated March 10, 2014, authorizing 5.00% Senior Notes due 2044 (Form 8-K dated March 10, 2014, File No. 1-05924 - Exhibit 4.1).
Officer's Certificate, dated February 27, 2015, authorizing 3.05% Senior Notes due 2025 (Form 8-K dated February 27, 2015, File No. 1-05924 - Exhibit 4(a)).
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. 1-05924 - Exhibit 4(a)).
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 (Form 10-K for the year ended December 31, 2013, File No. 1-05924 - Exhibit 4(t)(2)).
Credit Agreement, dated as of October 15, 2015, among Tucson Electric Power Company, MUFG Union Bank, N.A. as Administrative Agent, and a group of lenders (Form 8-K dated October 15, 2015, File No. 1-05924 - Exhibit 4.1).
Computation of Ratio of Earnings to Fixed Charges.
Power of Attorney.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino.
Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.LABXBRL Taxonomy Extension Label Linkbase Document.
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.
*Previously filed as indicated and incorporated herein by reference.
**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.


88




SIGNATURES
Pursuant to the requirements of section 13 or 15(b) 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
   (Registrant)
    
Date:02/19/February 15, 2018 /s/ KevinFrank P. LarsonMarino
   KevinFrank P. LarsonMarino
   Senior Vice President, Chief Financial Officer, and ChiefDirector
   (Principal Financial Officer and Principal Accounting 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:02/19/February 15, 2018 /s/ David G. Hutchens*
   David G. Hutchens
   President, Chief Executive Officer, and Director
   (Principal Executive Officer)
   
Date:02/19/February 15,/s/ Kevin P. Larson
Kevin P. Larson
Senior Vice President, Chief Financial Officer, and Director
(Principal Financial Officer)
Date:02/19/15 2018 /s/ Frank P. Marino*Marino
   Frank P. Marino
   Vice President, Chief Financial Officer, and ControllerDirector
   (Principal Financial Officer and Principal Accounting Officer)
   
Date:February 19, 201515, 2018 /s/ Philip J. Dion*Todd C. Hixon*
   Philip J. DionTodd C. Hixon
   Director
   
Date:02/19/February 15, 2018By:/s/ KevinFrank P. LarsonMarino
   KevinFrank P. LarsonMarino
   *As attorney-in-fact for each of the persons indicated


12589




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(a)(1)First Amendment to the Agreement and Plan of Merger, dated as of August 14, 2014, by and among FortisUS Inc., Color Acquisition Sub Inc. and UNS Energy Corporation (Form 8-K, dated August 14, 2014, File No. 1-05924 - Exhibit 2.2)
*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. (Form 10-K for the year ended December 31, 2013, File No. 1-13739 - Exhibit 2(b)(2))
*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).
*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)).
*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)).

126




*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)).
*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)).

127




*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)).
*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).

128




*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)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(n)(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(o)(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(o)(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 (Form 10-K for the year ended December 31, 2013, File No. 1-13739 - Exhibit 4(t)(2))
*4(p)(1)Credit Agreement, dated as of December 2, 2014, among Tucson Electric Power Company, MUFG Union Bank, N.A., as Administrative Agent, and a group of lenders (Form 8-K dated December 2, 2014, File No. 1-05924, Exhibit 4(a))
*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)).

129




*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)).
*10(a)(8)Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(8)).
*10(a)(9)Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(9)).
*10(a)(10)Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(10)).
*10(a)(11)Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(11)).
*10(a)(12)Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(12)).
*10(a)(13)Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(13)).
*10(a)(14)Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J.C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924 — Exhibit 10(f)(14)).
*10(a)(15)Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbell Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar). (Form S-4 Registration No. 33-52860 — Exhibit 10(f)(15)).
*10(a)(16)Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(12)).
*10(a)(17)Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(13)).

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*10(a)(18)Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(14)).
*10(a)(19)Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(19)).
*10(a)(20)Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 —Exhibit 10(f)(20)).
*10(a)(21)Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(21)).
*10(a)(22)Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(22)).
*10(a)(23)Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J.C. Penney Company, Inc., as Owner Participant, and Valencia and TEP, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(15)).
*10(a)(24)Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924 — Exhibit 10(e)(16)).
*10(a)(25)Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and TEP, as Indemnitors, J.C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(25)).
*10(a)(26)Valencia Agreement, dated as of June 30, 1992, among TEP, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia’s lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860 — Exhibit 10(f)(26)).
*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)).

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*10(b)(1)Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(1)).
*10(b)(2)Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and TEP and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(2)).
*10(b)(3)Participation Agreement, dated as of December 1, 1985, among TEP and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924 — Exhibit 10(f)(3)).
*10(b)(4)Restructuring Commitment Agreement, dated as of June 30, 1992, among TEP and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding, William J. Wade, as Owner Trustee and Co-Trustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(4)).
*10(b)(5)Lease Supplement No.1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860 — Exhibit 10(g)(5)).
*10(b)(6)Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732 — Exhibit 10(g)(6)).
*10(b)(7)Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and TEP and San Carlos, jointly and severally, as Lessee. (Form S-1, Registration No. 33-55732 — Exhibit 10(g)(7)).
*10(b)(8)Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(8)).
*10(b)(9)Amendment No. 2, dated as of December 1, 1999, to Lease Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit Financing Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(9)).
*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)).

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*10(b)(11)Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(11)).
*10(b)(12)Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit Financing Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(12)).
*10(b)(13)Amendment No. 2, dated as of December 1, 1999, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Emerson Finance Co. as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1999, File No. 1-5924 — Exhibit 10(b)(13)).
*10(b)(14)Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Philip Morris Capital Corporation as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(a)).
*10(b)(15)Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with IBM Credit, LLC as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(b)).
*10(b)(16)Amendment No. 3 dated as of June 1, 2003, to Lease Agreements, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement with Emerson Finance Co. as Owner Participant. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(c)).
*10(b)(17)Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and Philip Morris Capital Corporation as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(d)).
*10(b)(18)Amendment No. 3 dated as of June 1, 2003, to Tax Indemnity Agreement, dated as of December 1, 1985, between TEP and San Carlos, jointly and severally, as Lessee, and IBM Credit, LLC as Owner Participant, beneficiary under a Trust Agreement dated as of December 1, 1985, with Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-Q for the quarter ended June 30, 2003, File No. 1-5924 – Exhibit 10(e)).
*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 Co-trustee, 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).

133




*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 Co-trustee, 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 Co-trustee, 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 Co-trustee, 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 Co-trustee, 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 Co-trustee, 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)).
*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)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(e)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))
+*10(f)Retention Bonus Agreement between Kevin P. Larson and UNS Energy Corporation (Form 8-K, dated November 13, 2014, File No. 1-05924 - Exhibit 10(a))
12Computation of Ratio of Earnings to Fixed Charges.
21Subsidiaries of the Registrant.
24Power of Attorney.

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31(a)Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens.
31(b)Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Kevin P. Larson.
**32Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
*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.


135