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EX-32 - EXHIBIT 32 - TUCSON ELECTRIC POWER COtepex3212312016.htm
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EX-24 - EXHIBIT 24 - TUCSON ELECTRIC POWER COtepex2412312016.htm
EX-21 - EXHIBIT 21 - TUCSON ELECTRIC POWER COtepex2112312016.htm
EX-12 - EXHIBIT 12 - TUCSON ELECTRIC POWER COtepex1212312016.htm


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 1934
For the fiscal year ended December 31, 2016
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     . 
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in 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, 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  ¨
 
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  ¨
 
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  ¨

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  ¨




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. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer
¨
Accelerated Filer
¨
Non-accelerated Filer
x
Smaller Reporting Company
¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  ¨
 
 No  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates: None
As of February 15, 2017, 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, 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





iv




DEFINITIONS
The abbreviations and acronyms used in the 2016 Form 10-K are defined below:
2010 Reimbursement Agreement
 
Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2013 Rate Order
 
A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013
2017 Rate Order
 
A rate order issued by the ACC resulting in a new rate structure for TEP, effective on or before on or before March 1, 2017
ACC
 
Arizona Corporation Commission
APS
 
Arizona Public Service Company
BART
 
Best Available Retrofit Technology
BBtu
 
Billion British thermal unit(s)
CDD
 
Cooling Degrees Days is an index used to measure the impact of weather on power usage calculated by subtracting 75 from the average of the high and low daily temperatures
DG
 
Distributed Generation
DSM
 
Demand Side Management
EE Standards
 
Energy Efficiency Standards
EPA
 
Environmental Protection Agency
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
Gila River
 
Gila River Generating Station
GWh
 
Gigawatt-hour(s)
HDD
 
Heating Degrees Days is an index used to measure the impact of weather on power 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
LOC
 
Letter(s) of Credit
Luna
 
Luna Generating Station
MATS
 
Mercury and Air Toxics Standards
MMBtu
 
Million British thermal units
MW
 
Megawatt(s)
MWh
 
Megawatt-hour(s)
Navajo
 
Navajo Generating Station
NBV
 
Net Book Value
PNM
 
Public Service Company of New Mexico
PPA
 
Power Purchase Agreement
PPFAC
 
Purchased Power and Fuel Adjustment Clause
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 to recover its costs of providing services and an opportunity to earn a reasonable return on its investment
San Juan
 
San Juan Generating Station
SCR
 
Selective Catalytic Reduction

v




SES
 
Southwest Energy Solutions, Inc.
SJCC
 
San Juan Coal Company
SNCR
 
Selective Non-Catalytic Reduction
Springerville
 
Springerville Generating Station
SRP
 
Salt River Project Agricultural Improvement and Power District
Sundt
 
H. Wilson Sundt Generating Station
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 Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
TSA
 
Transmission Service Agreement
Tri-State
 
Tri-State Generation and Transmission Association, Inc.
UES
 
UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy Corporation, and 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 Affiliates
 
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


vi




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 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 TEP in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future operational, economic, 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, 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, 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, including changes in tax policies; changes in, and compliance with, environmental laws and regulations, decisions and policies that could increase operating and capital costs, reduce generation facility output or accelerate generation 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 changing interest rate environment, which affect the value of our pension and other retiree benefit plan assets and the related contribution requirements and expense; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations 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 attacks, data breaches, or other challenges to our information security, including our operations and technology systems; and the performance of TEP's generation facilities.


vii




PART I
ITEM 1. BUSINESS
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson metropolitan area for almost 125 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 420,000 retail customers. TEP’s service territory covers 1,155 square miles and includes a population of approximately 1,200,000 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 sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing 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 August 2014, UNS Energy was acquired by Fortis Inc. (Fortis) and became an indirect wholly owned subsidiary of Fortis which is a leader in the North 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 solar 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 system.
TEP operates under a certificate of public convenience and necessity as regulated by the Arizona Corporation Commission (ACC), under which TEP is obligated to provide electricity service to customers within its service territory. Retail rates are rates designed to allow a regulated utility to recover its costs of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates). The ACC establishes Retail Rates.
Customers
Electricity sold to retail and wholesale customers by class of customer and the average number of retail customers over the last three years were as follows:
(sales in GWh)
2016
 
2015
 
2014
Electric Sales
 
 
 
 
 
 
 
 
 
 
 
Residential
3,724
 
29
%
 
3,724
 
28
%
 
3,727
 
29
%
Commercial
2,139
 
17
%
 
2,124
 
15
%
 
2,170
 
17
%
Industrial, non-Mining
2,006
 
16
%
 
2,063
 
15
%
 
2,098
 
16
%
Industrial, Mining
997
 
8
%
 
1,109
 
8
%
 
1,137
 
9
%
Other
30
 
%
 
33
 
%
 
33
 
%
Total Retail Sales by Customer Class
8,896
 
70
%
 
9,053
 
66
%
 
9,165
 
71
%
Long-Term Wholesale Sales
463
 
4
%
 
750
 
5
%
 
618
 
5
%
Short-Term Wholesale Sales
3,308
 
26
%
 
3,928
 
29
%
 
3,082
 
24
%
Total Electric Sales
12,667
 
100
%
 
13,731
 
100
%
 
12,865
 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average Number of Retail Customers
 
 
 
 
 
 
 
 
 
 
 
Residential
378,991
 
90
%
 
376,439
 
90
%
 
374,204
 
90
%
Commercial
38,403
 
9
%
 
38,253
 
9
%
 
38,079
 
9
%
Industrial, non-Mining
580
 
%
 
588
 
%
 
604
 
%
Industrial, Mining
4
 
%
 
4
 
%
 
4
 
%
Other
1,866
 
1
%
 
1,857
 
1
%
 
1,858
 
1
%
Total Retail Customers
419,844
 
100
%
 
417,141
 
100
%
 
414,749
 
100
%

1



Retail Customers
TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, health care, education, military bases, and other governmental entities. TEP’s retail sales are influenced by several factors including economic conditions, seasonal weather patterns, Demand Side Management (DSM) initiatives and the increasing use of energy efficient products, and customer-sited Distributed Generation (DG).
Local, regional, and national economic factors impact the growth in the number of customers in TEP’s service territory. In each of the past five years, TEP’s average number of retail customers increased by less than 1%. TEP expects the number of retail customers to increase at a rate of approximately 1% in 2017 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 2016 was 8,896 gigawatt-hours (GWh), which is a decrease of 4% from 2012 levels. During the past five years, local economic conditions combined with state requirements to reduce retail sales through energy efficiency and DG have resulted in lower sales volumes and lower use per customer.
Two of TEP’s largest retail customers are in the copper mining industry. TEP’s GWh sales to mining customers depend on a variety of factors including commodity prices, electricity prices, and the mines’ development of self-generating resources. TEP’s GWh sales to mining customers decreased by 10% in 2016 as a result of mining curtailments due to declining commodity prices. TEP cannot predict how long the commodity prices will remain low or the impact prices will have on mining production and any resulting impact commodity prices may have on TEP's GWh sales.
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 mining customers.
Wholesale Customers
TEP’s 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.
Generally, TEP commits to future sales based on expected generation 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:
Long-Term Wholesale Sales
Contracts for long-term wholesale sales cover periods of one year or greater. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers.
TEP’s long-term wholesale contract with Salt River Project Agricultural Improvement and Power District (SRP) expired in May 2016. TEP's current primary long-term wholesale sale contracts customers are presented in the table below:
 
Contracts Expire
 
December 31,
Shell Energy North America
2017
Navajo Tribal Utility Authority
2022
TRICO Electric Cooperative
2024
Navopache Electric Cooperative
2041
Short-Term Wholesale Sales
Forward contracts commit TEP to sell a specified amount of capacity or power at a specified price over a given period of time, typically for one-month or three-month periods. TEP also engages in short-term sales by selling power in the daily or hourly markets at fluctuating spot market prices and making other non-firm power sales. The majority of our revenues from short-term wholesale sales offset fuel and purchased power costs and are passed through to TEP’s retail customers. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices.

2



Competition
Retail Customers
TEP is the primary electric service provider to retail customers within its service territory and operates under a certificate of public convenience and necessity as regulated by the ACC.
Wholesale 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 December 31, 2016, TEP owned 2,696 megawatts (MW) of nominal generation capacity, as set forth in the following table. Nominal capacity is based on unit design net output, and measured in direct current (DC).
 
Unit
 
 
 
Date
 
Resource
 
Capacity
 
Operating
 
TEP’s Share
Generation Source
No.
 
Location
 
In Service
 
Type
 
MW
 
Agent
 
%
 
MW
Springerville Station (1)
1
 
Springerville, AZ
 
1985
 
Coal
 
387
 
TEP
 
100
 
387

Springerville Station (2)
2
 
Springerville, AZ
 
1990
 
Coal
 
406
 
TEP
 
100
 
406

San Juan Station
1
 
Farmington, NM
 
1976
 
Coal
 
340
 
PNM
 
50.0
 
170

San Juan Station
2
 
Farmington, NM
 
1973
 
Coal
 
340
 
PNM
 
50.0
 
170

Navajo Station
1
 
Page, AZ
 
1974
 
Coal
 
750
 
SRP
 
7.5
 
56

Navajo Station
2
 
Page, AZ
 
1975
 
Coal
 
750
 
SRP
 
7.5
 
56

Navajo Station
3
 
Page, AZ
 
1976
 
Coal
 
750
 
SRP
 
7.5
 
56

Four Corners Station
4
 
Farmington, NM
 
1969
 
Coal
 
785
 
APS
 
7.0
 
55

Four Corners Station
5
 
Farmington, NM
 
1970
 
Coal
 
785
 
APS
 
7.0
 
55

Gila River Power Station
3
 
Gila Bend, AZ
 
2003
 
Gas
 
550
 
Ethos Energy
 
75.0
 
413

Luna Generating Station
1
 
Deming, NM
 
2006
 
Gas
 
555
 
PNM
 
33.3
 
185

Sundt Station
1
 
Tucson, AZ
 
1958
 
Gas/Oil
 
81
 
TEP
 
100
 
81

Sundt Station
2
 
Tucson, AZ
 
1960
 
Gas/Oil
 
81
 
TEP
 
100
 
81

Sundt Station
3
 
Tucson, AZ
 
1962
 
Gas
 
104
 
TEP
 
100
 
104

Sundt Station 
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 Solar Station
 
 
Springerville, AZ
 
2002-2014
 
Solar
 
16
 
TEP
 
100
 
16

Tucson Solar Projects
 
 
Tucson, AZ
 
2010-2014
 
Solar
 
13
 
TEP
 
100
 
13

Ft. Huachuca Project (3)
 
 
Ft. Huachuca, AZ
 
2014
 
Solar
 
17
 
TEP
 
100
 
17

Total TEP Capacity (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,696

(1) 
In 2016, TEP purchased a 50.5% undivided interest in Unit 1 of the Springerville Generating Station (Springerville) increasing its total ownership interest to 100%. See Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the Springerville Unit 1 settlement.
(2) 
Springerville Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.
(3) 
In January 2017, a second phase of the Ft. Huachuca Project was commissioned adding 5 MW of solar generation to TEP's total generation capacity.
(4) 
Excludes 781 MW of additional resources, which consist of certain capacity purchases and interruptible retail load.

3



Springerville Generating Station
TEP's other interests in Springerville include: (i) a 100% undivided interest in certain common facilities at Springerville (Springerville Common Facilities), that includes assets such as, but not limited to: administration building, roads, and well fields used to serve all four units at Springerville that cannot be proportioned to each unit; and (ii) an 82.95% ownership interest in the Springerville Coal Handling Facilities.
Springerville Common Facilities Leases
TEP holds leveraged lease arrangements related to a 50% undivided interest in Springerville Common Facilities that are scheduled to expire in December 2017 and January 2021. In December 2016, TEP notified the owner participant and the lessor of the lease scheduled to expire in December 2017 that TEP had elected to purchase an undivided ownership interest in the Springerville Common Facilities at the fixed purchase price of $38 million upon the expiration of the lease term. The leases scheduled to expire in January 2021 each have fair market value renewal options as well as fixed-price purchase options. The fixed prices to acquire the leased interests in January 2021 are $68 million.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the capital leases and the purchase commitment.
Springerville Units 3 and 4
Springerville Units 3 and 4 are each approximately 400 MW coal-fired generation facilities that are operated, but not owned by TEP. These facilities are located at the same site as Springerville Units 1 and 2. The lessee of Springerville Unit 3 compensates TEP for operating the facilities and pays 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. TEP 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 Rates and Regulations below for additional information regarding RES.
Owned Renewable Resources
As of December 31, 2016, TEP owned 46 MW of photovoltaic (PV) solar generation capacity measured in DC. In January 2017, TEP completed an additional solar project adding 5 MW of PV solar generation capacity. The solar generation facilities are located on properties held under easements and leases.
Renewable Power Purchase Agreements
As of December 31, 2016, TEP had renewable PPAs for 196 MW of capacity measured in DC from solar resources, 80 MW of capacity measured in alternating current (AC) from wind resources and 4 MW of capacity measured in AC from a landfill gas generation facility. 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 generation from its natural gas-fired units, 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 for a maximum of three years. Certain of these contracts are at a fixed price per MWh and others are indexed to natural gas prices. TEP also purchases power in the daily and hourly markets to meet

4



higher than anticipated demands, to cover unplanned 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.
Peak Demand and Future Resources
Peak Demand
(in MW)
2016
 
2015
 
2014
 
2013
 
2012
Retail Customers
2,278

 
2,222

 
2,218

 
2,230

 
2,290

In 2016, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale peak demand, while maintaining a reserve margin in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional council of North American Reliability Corporation (NERC).
Peak demand occurs during the summer months due to the cooling requirements of retail customers. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. Retail peak demand in 2016 increased due to unseasonably hot weather. From 2012-2015, retail peak demand was negatively impacted by weak economic conditions, the implementation of energy efficiency programs, and an increased level of customer-installed DG.
Forecasted retail peak demand for 2017 is 2,233 MW compared with actual peak demand of 2,278 MW in 2016. TEP’s 2017 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 and reserve margin requirements in 2017.
Future Resources
As of December 31, 2016, approximately 52% 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.
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.
Fuel Supply
A summary of Fuel and Purchased Power resource information is provided below:
 
Average Cost (cents per kWh)
 
Percentage of Total kWh Resources
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Coal
2.30

 
2.44

 
2.50

 
62
%
 
60
%
 
68
%
Gas
2.84

 
3.35

 
4.99

 
25
%
 
19
%
 
9
%
Purchased Power, Non-Renewable
3.43

 
3.04

 
4.14

 
8
%
 
18
%
 
21
%
Purchased Power, Renewable
7.00

 
9.82

 
10.50

 
5
%
 
3
%
 
2
%
All Resources
3.15

 
3.31

 
3.64

 
100
%
 
100
%
 
100
%

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Coal
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 generation stations. The average cost of coal per million metric British thermal unit (MMBtu), including transportation, was $2.21 in 2016, $2.34 in 2015, and $2.43 in 2014.
Station
 
Coal Supplier
 
2016 Coal Consumption (tons in 000s)
 
Contract Expiration
 
Average Sulfur Content
 
Coal Obtained From
Springerville
 
Peabody CoalSales (1)
 
2,706
 
2020
 
1.0%
 
Lee Ranch Mine/El Segundo Mine
Four Corners
 
NTEC (2)
 
260
 
2031
 
0.8%
 
Navajo Mine
San Juan
 
San Juan Coal Co. (3)
 
1,212
 
2022
 
0.8%
 
San Juan Mine
Navajo
 
Peabody CoalSales (1)
 
433
 
2019
 
0.6%
 
Kayenta Mine
(1) 
In April 2016, Peabody Energy Corp. (Peabody) filed for reorganization under Chapter 11 of the Bankruptcy Code. TEP has continued to receive its contracted coal as planned and believes it has sufficient access to coal inventory for the near future. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to Peabody's bankruptcy.
(2) 
Beginning in July 2016 through June 2031, the coal for the Four Corners Generating Station (Four Corners) is being purchased from the Navajo Transitional Energy Company (NTEC). NTEC purchased the mine located near Four Corners from BHP Billiton and began overseeing the mine operation in 2016.
(3) 
BHP Billiton sold San Juan Coal Company (SJCC) to Westmoreland Coal Company (WCC), effective January 31, 2016.
Coal-Fired Generation Facilities Operated by 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 remaining lives.
Coal-Fired Generation Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generation facilities at Four Corners, the Navajo Generating Station (Navajo), and the San Juan Generating Station (San Juan). Four Corners, which is operated by Arizona Public Service Company (APS), and San Juan, which is operated by Public Service Company of New Mexico (PNM), are mine-mouth generation facilities located adjacent to the coal reserves. Navajo, which is operated by SRP, obtains its coal supply from the nearby Kayenta coal mine and receives deliveries on a dedicated electric rail delivery system. In 2016, WCC purchased SJCC from BHP Billiton and entered into a new coal supply agreement for San Juan with the operator, PNM. The new coal supply agreement has an expiration date of June 2022. TEP expects coal reserves available to these three jointly-owned generation facilities to be sufficient for the remaining lives of the stations.
Natural Gas Supply
TEP uses generation from its facilities fueled by natural gas, in addition to power 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 $3.14 in 2016, $3.49 in 2015, and $5.17 in 2014.
TEP has long-term firm agreements with El Paso Natural Gas (EPNG) for transportation from the Permian and San Juan Basins to Sundt under firm transportation agreements. TEP also purchases firm gas transportation for Unit 3 of the Gila River Generating Station (Gila River) 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 the North Loop Generating Station's (North loop) 94 MW of internal combustion turbines and receives distribution service under a transportation agreement for DeMoss Petrie Generating Station's (DeMoss Petrie) 75 MW internal combustion turbine.
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 to integrate and access generation resources to meet its customer load requirements.

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TEP's transmission and distribution systems included approximately 2,170 miles of transmission lines and 7,590 miles of distribution lines as of December 31, 2016.
Rates and Regulations
The ACC and the FERC each regulate portions of 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.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations and Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this From 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. TEP's rate filing 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 will be effective starting on or before March 1, 2017.
Purchased Power and Fuel Adjustment Clause
The Purchased Power and Fuel Adjustment Clause (PPFAC) allows TEP to recover its fuel, transmission, and purchased power costs, including demand charges, and the costs of contracts for hedging fuel and purchased power costs for its retail customers. The PPFAC consists of a forward component and a true-up component.
The forward component adjusts for any costs over or under base fuel collection rates expected over a 12-month period. The true-up component reconciles any over/under collected amounts from the preceding 12-month period and is calculated to credit or recover these amounts from customers in the subsequent year.
TEP’s PPFAC also includes the recovery of the following costs and/or credits: lime costs used to control sulfur dioxide (SO2) emissions; sulfur credits received from TEP’s coal suppliers; broker fees; revenues from short-term wholesale sales; all of the proceeds from the sale of SO2 allowances; and all other costs as allowed by the ACC.
As of December 31, 2016, TEP had over-collected fuel and purchased power costs by $38 million.
Renewable Energy Standard and Tariff
The ACC’s RES requires Arizona 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 DG accounting for 30% of the annual renewable energy requirement. Affected utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out those plans is recovered from retail customers through the RES surcharge until such costs are reflected in TEP’s non-fuel base rates. The associated lost revenues attributable to meeting distributed generation targets will be partially recovered through the Lost Fixed Cost Recovery Mechanism (LFCR).
In May 2016, the ACC approved TEP's 2016 RES implementation plan of $57 million, which was partially offset by applying approximately $9 million of previously recovered carryover funds. TEP will recover the remaining $48 million through the RES surcharge. The recovery will fund the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer installed DG; (iii) depreciation and a return on certain TEP investments in company-owned solar projects; and (iv) various other program costs. TEP recognized approximately $3 million of revenue in 2016 as a return on company-owned solar projects. 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 a second phase of TEP’s rate case proceedings (Phase 2).
In July 2016, TEP submitted an application for the 2017 RES implementation plan with a budget amount of $54 million. TEP expects to recover less than $1 million of revenue in 2017 through the RES surcharge as a return on certain company-owned solar projects. This amount reflects the return and related recovery on projects that are not included in TEP’s Retail Rates. In addition, TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism. TEP expects to receive a decision on its 2017 RES implementation plan in first half of 2017.
The percentage of retail kilowatt-hour (kWh) sales attributable to the 2016 RES renewable energy requirement was approximately 10%, exceeding the overall 2016 requirement of 6%. TEP expects to meet the 2017 RES renewable energy

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requirement of 7% of retail kWh sales. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain distributed generation Renewable Energy Credits (REC), which are used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2016 and 2017 residential DG requirement.
Energy Efficiency Standards
Under the Energy Efficiency Standards (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 December 2016, TEP’s cumulative annual energy savings was approximately 12%. Compliance with the EE Standards is governed by the ACC’s approval of TEP's annual implementation plan.
In February 2016, the ACC approved TEP's 2016 energy efficiency implementation plan, including recovery of approximately$14 million from retail customers for new and existing DSM programs. 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. TEP notified the ACC that it would not file a 2017 implementation plan and will continue its 2016 plan through the end of 2017 without change. TEP expects to file its 2018 implementation plan by June 1, 2017.
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 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 the customer 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 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 portfolio of owned and contracted utility-scale solar projects, and will be established in Phase 2. The DG export rate will be updated annually and customers adopting solar will be compensated for 10 years at the 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.
FERC Compliance
In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that TEP 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 form of service agreement.
In 2016, the FERC issued orders related to the late-filed Transmission Service Agreements (TSA), which directed TEP to issue time value refunds to the counterparties to these TSAs (FERC Refund Orders). As a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded $22 million in time value refunds in 2016. Of the total amount recorded, TEP paid $17 million in 2016 and accrued the remaining $5 million as of December 31, 2016. In June 2016, to preserve its rights, TEP petitioned the D.C. Circuit Court of Appeals to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement. Under the settlement, the counterparty paid TEP $8 million in January 2017 and TEP dismissed the appeal with prejudice. 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 FERC Refund Orders.


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ENVIRONMENTAL MATTERS
The Environmental Protection Agency (EPA) regulates the amount of 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 range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance through Retail Rates.
National Ambient Air Quality Standards
In October 2015, the EPA released the final rule for the 8-hour U.S. National Ambient Air Quality Standards (NAAQS) for ozone (O3). The EPA lowered the standard from 75 parts per billion (ppb) to 70 ppb. If Pima County does not meet the standard, the county will be designated as a “non-attainment” area and will need to develop a plan to bring the air-shed into compliance. A “non-attainment” designation may slow economic growth in the region and impact our ability to site new local generation. The States’ recommendation of area designations (attainment, non-attainment, or unclassified) was submitted in September 2016 and Pima County was designated as an attainment area.
Implementation of the rule is scheduled as follows:
EPA's response to the States’ designation recommendations by June 2017.
EPA's finalization of area designations by October 2017, based on 2014-2016 air quality data.
Effluent Limitation Guidelines
In September 2015, as part of the Clean 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 a NPDES permit and therefore are not affected. With regard to Four Corners, until a draft NPDES permit is proposed during the 2018-2023 timeframe, we cannot predict what will be required to control these discharges to be in compliance with the finalized effluent limitations at that facility. TEP does not anticipate a significant financial impact from these requirements.
TEP believes it is in material compliance with applicable environmental laws and regulations. Refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Environmental Laws and Regulations of this Form 10-K for additional information related to environmental laws and regulations impacting TEP's liquidity and capital resources and Liquidity and Capital Resources for TEP's forecasted environmental-related capital expenditures.

EMPLOYEES
As of December 31, 2016, TEP had 1,508 employees, of which approximately 686 were represented by the International Brotherhood of Electrical Workers (IBEW) Local No. 1116. A new collective bargaining agreement between the IBEW and TEP was entered into in January 2016 and expires in December 2018.


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EXECUTIVE 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, 2017, are as follows:
Name
 
Age
 
Position(s) Held
 
Executive Officer Since
David G. Hutchens (1)
 
50
 
President and Chief Executive Officer
 
2007
Kevin P. Larson
 
60
 
Senior Vice President
 
1997
Frank P. Marino (1)(2)
 
52
 
Vice President and Chief Financial Officer
 
2013
Kentton C. Grant (3)
 
58
 
Vice President, Rates and Planning
 
2007
Susan M. Gray
 
44
 
Vice President of Energy Delivery
 
2015
Todd C. Hixon (1)
 
50
 
Vice President and General Counsel
 
2011
Karen G. Kissinger
 
62
 
Vice President and Chief Compliance Officer
 
1991
Mark C. Mansfield
 
61
 
Vice President, Energy Resources
 
2012
Catherine E. Ries
 
57
 
Vice President, Customer and Human Resources
 
2007
Mary Jo Smith
 
59
 
Vice President, Public Policy
 
2015
Morgan C. Stoll (4)
 
46
 
Vice President and Chief Information Officer
 
2016
Martha B. Pritz (5)
 
55
 
Treasurer
 
2016
Herlinda H. Kennedy
 
55
 
Corporate Secretary
 
2006
(1) 
Member of the TEP Board of Directors. 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.
(2) 
Frank P. Marino was named Vice President and Chief Financial Officer effective January 2, 2017. The appointment was subsequent to the announcement in November 2016 of the retirement of Kevin P. Larson, TEP's former Chief Financial Officer, in 2017.
(3) 
In November 2016, Kentton C. Grant was named Vice President of Rates and Planning. Mr. Grant was formerly the Vice President and Treasurer.
(4) 
In November 2016, Morgan C. Stoll was named Vice President and Chief Information Officer.
(5) 
In November 2016, Martha B. Pritz was named Treasurer.

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

ITEM 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.

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REVENUES
National and local economic conditions can negatively affect the results of operations, net income, and cash flows at TEP.
Economic conditions in TEP’s service area have a significant impact on customer growth, use per customer and overall sales levels. As a result of weak economic conditions, TEP’s average retail customer base grew by less than 1% in each year from 2012 through 2016. Additionally, economic conditions contributed to a declining average use per customer and lower overall sales over this same period.
New technological developments and compliance with the ACC's EE Standards and RES will continue to have a significant impact on retail sales, which could negatively affect TEP’s results of operations, net income, and cash flows.
Research and development activities are ongoing for new technologies that produce power and reduce power consumption. These technologies include renewable energy, customer-sited DG, appliances, equipment, battery storage and control systems. Continued development and use of these technologies and compliance with the ACC's EE Standards and RES could negatively impact the results of operations, net income, and cash flows of TEP.
The revenues, results of operations, and cash flows of TEP are seasonal, and are subject to weather conditions and customer usage patterns, which are beyond the 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, negatively affecting operating revenues, cash flows, and net income by reducing sales.
TEP is dependent on a small number of 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 11% of total revenues in 2016. TEP sells electricity to mines, military installations, and other large commercial and industrial customers. Retail sales volumes and revenues from these customers could decline as a result of, among other things: global, national, and local economic conditions; curtailments of customer operations due to unfavorable market conditions; military base reorganization or closure decisions by the federal government; the effects of energy efficiency and distributed generation; or the decision by customers to self-generate all or a portion of their energy needs. A reduction in retail kWh sales by any one of TEP’s ten largest customers would negatively affect our results of operations, net income, and cash flows.
REGULATORY
TEP is subject to regulation by the ACC, which sets the Company’s Retail Rates and oversees many aspects of its business in ways that could negatively affect the Company’s results of operations, net income, and cash flows.
The ACC is a constitutionally created body composed of five elected commissioners. Commissioners are elected state-wide for staggered four-year terms and are limited to serving a total of two terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.
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 Rates at levels that are intended to allow TEP to recover its costs of service and provide it with an opportunity to earn a reasonable rate of return. In setting TEP’s Retail Rates, the ACC could disallow the recovery of costs, 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 utility industry and the ways in which this industry is regulated. TEP is subject to regulation by the FERC. The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale.

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Owners and operators of bulk power systems, including TEP, are subject to mandatory transmission standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new transmission standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory transmission standards could subject TEP to sanctions, including substantial monetary penalties.
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. The Company cannot predict the timing or extent of such tax-related developments which could have a negative impact on TEP's financial results.
ENVIRONMENTAL
TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it to environmental-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 generation facilities and compliance standards related to new and existing generation facilities. These laws and regulations generally require TEP 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, 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 a negative effect on TEP's results of operations, particularly if those costs are not fully recoverable from TEP customers. TEP’s obligation to comply with the EPA’s Regional Haze Rule requirements as a participant or owner in the Springerville, San Juan, Four Corners, and Navajo, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations, could jeopardize the economic viability of these generation faculties. 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 facilities potentially resulting in increased operational cost for the remaining participants. TEP cannot predict the ultimate outcome of these matters.
TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generation facilities in which it has a minority interest and is obligated to pay similar costs at the mines that supply these 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.
Federal regulations limiting greenhouse gas emissions require a shift in generation from coal to natural gas and renewable generation and could increase TEP's cost of operations.
In 2015, the EPA issued the Clean Power Plan (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 requires CO2 emission reductions for existing facilities by 2030 and establishes interim goals that begin in 2022. In its current form, the CPP requires a shift in generation from coal to natural gas and renewables and could lead to the early retirement of coal-fired generation in Arizona and New Mexico within the 2022 to 2030 compliance time-frame. TEP will continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies. TEP is unable to determine 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 currently required state compliance plans are developed and approved by the EPA.

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FINANCIAL
Early closure of TEP's coal-fired generation facilities could result in TEP recognizing impairments or increased cost of operations if recovery of TEP's remaining investments in such facilities and the costs associated with early closures were not permitted through rates charged to customers.
TEP's coal-fired generation facilities may be required to 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 facilities from which TEP obtains power are closed prior to the end of their useful life, TEP could be required to recognize an impairment of its assets and incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation and cancellation of long-term coal contracts of such generation facilities. Closure of any of such generation facilities may force TEP to incur higher costs for replacement capacity and energy. TEP may not be permitted full recovery of these costs in the rates it charges its customers. As of December 31, 2016, approximately 52% of TEP's generation facilities are coal-fired generation.
Volatility or disruptions in the financial markets, rising interest rates, or unanticipated financing needs, could: increase TEP's financing costs; limit access to the credit markets; affect the Company's ability to comply with financial covenants in debt agreements; and increase TEP's pension funding obligations. Such outcomes may negatively affect liquidity and TEP's ability to carry out the 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 flows 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 negatively 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 reasonable rates, or if our borrowing costs dramatically increase, our ability to finance our operations, meet our debt obligations, and execute our financial strategy could be negatively affected.
Increases 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, 2016, 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 postretirement plans and may increase the amount and accelerate the timing of required future funding contributions.
Generation facility closings or changes in power flows into TEP's service territory could require us to redeem or defease some or all of the tax-exempt bonds issued for the 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, 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 power within TEP’s two-county retail service area.
As of December 31, 2016, there were outstanding approximately $309 million aggregate principal amount of tax-exempt bonds that financed pollution control expenditures at TEP’s generation facilities. Should certain of TEP’s generation 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 pollution control expenditures would be subject to mandatory early redemption by TEP. Of the total amount outstanding, $37 million of the principal amount of the bonds can currently be redeemed at par upon notice to holders, and $272 million principal amount of the bonds have early redemption dates or final maturities ranging from 2019 to 2022.
In addition, as of December 31, 2016, there were outstanding approximately $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 power in TEP’s local service area, it is possible that TEP would no longer qualify as a local furnisher of power within the meaning of the Internal Revenue Code. If TEP could no longer qualify as a local furnisher of power, all of TEP’s tax-exempt local furnishing bonds could be subject to mandatory early redemption by TEP or defeasance to the earliest possible redemption 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 outstanding, $100 million of the principal amount of the bonds can currently be redeemed at par upon notice to holders, and $207 million principal amount of the bonds have early redemption dates ranging from 2020 to 2023.

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OPERATIONAL
The operation of electric generation facilities and transmission and distribution systems involves risks and uncertainties that could result in reduced generation capability or unplanned outages that could negatively affect TEP’s results of operations, net income, and cash flows.
The operation of electric generation facilities and transmission and distribution systems involves certain risks and uncertainties, including equipment breakdown or 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 failures or other complications, occur from time to time. They are an inherent risk of our business and can cause damage to our reputation. If TEP’s generation facilities and transmission and distribution systems operate below expectations, TEP’s operating results could be negatively affected and/or TEP's capital spending could be increased.
TEP receives power from certain generation facilities that are jointly-owned and operated by third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could negatively affect TEP’s results of operations, net income, and cash flows.
Certain of the generation 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 generation facilities. Further, TEP may have no ability or a limited ability to make determinations on how best to manage the changing economic conditions or environmental requirements which may affect such facilities. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such facilities could negatively impact the business and operations of TEP.
TEP may be subject to physical attacks which could have a negative impact on the Company's business and results of operations.
As operators of critical energy infrastructure, TEP may face a heightened risk of physical attacks on the 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 makes 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 TEP's business and results of operations.
TEP may be subject to cyber attacks which could have a negative impact on the Company's business and results of operations.
TEP may face a heightened risk of cyber 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. TEP's operations technology systems have direct control over certain aspects of the electric system, and the Company's utility business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business.
If, despite TEP's security measures, a significant cyber or data breach occurred, the Company could have our operations disrupted, property damaged, and customer information stolen; experience loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on TEP's business and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.


14




ITEM 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 generation facilities at Four Corners, Navajo, San Juan, Springerville, Gila River, and Luna to the Tucson area for use by TEP’s retail customers. The transmission system is interconnected at various points in Arizona and New Mexico with other regional utilities. See Part I, Item 1. Business, Overview of Business of this Form 10-K for additional information regarding the transmission facilities.
TEP's generation facilities (except as noted below), administrative headquarters, warehouses and service centers are located on land owned by TEP. The distribution and transmission facilities owned by TEP are located:
on property owned by TEP;
under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises, easements, or other rights-of-way which generally are subject to termination;
under or over private property as a result of easements obtained primarily from the record holder of title; or
over tribal lands under grant of easement by the Secretary of the Interior or lease by Indian 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 term patent with the State of Arizona. TEP, under separate sale and leaseback arrangements, leases a 50% undivided interest in the Springerville Common Facilities (which do not include land).
Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Nation. TEP, individually and in conjunction with PNM in connection with San Juan, has acquired land rights, easements, and leases for the generation facilities, the transmission lines, and a water diversion facility located on land owned by the Navajo Nation. TEP has also acquired easements for transmission facilities related to San Juan, Four Corners, and Navajo located on Indian Country of the Zuni, Navajo, and Tohono O’odham 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 owners have free and clear title of all common facilities.
TEP’s rights under these various easements and leases may be subject to defects such as:
possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs (BIA) and the Indian Nations;
possible inability of TEP to legally enforce its rights against adverse claimants and the Indian Nations without Congressional consent; or
failure or inability of the Indian tribes to protect TEP’s interests in the easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claimants.
These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities.
Under separate ground lease agreements, TEP leased parcels of land for the following PV facilities:
the Solar Zone located at the University of Arizona Technology Park in Pima County, Arizona; and
the Bright Tucson Community Solar located in Pima County, Arizona.
In addition, TEP has a 30-year easement agreement related to a PV facility in Cochise County, Arizona. The easement is to facilitate the operations of a solar PV renewable energy generation system on behalf of the Department of the Army.
See Part I, Item 1. Business, Overview of Business of this Form 10-K for additional information regarding generation facilities.

15




ITEM 3. LEGAL PROCEEDINGS
TEP is party to a variety of legal actions arising out of the normal 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 its consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP.
See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

16



PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market 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 $50 million in 2016 and 2015 and $40 million in 2014.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 5 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on regulatory restrictions that limit TEP's ability to pay dividends.

ITEM 6. SELECTED FINANCIAL DATA
The following table provides selected financial data for the years 2012 through 2016.
(in thousands)
2016
 
2015
 
2014
 
2013
 
2012
Income Statement Data
 
 
 
 
 
 
 
 
 
Operating Revenues
$
1,234,995

 
$
1,306,544

 
$
1,269,901

 
$
1,196,690

 
$
1,161,660

Net Income
124,438

 
127,794

 
102,338

 
101,342

 
65,470

Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total Utility Plant, Net
$
3,782,806

 
$
3,558,229

 
$
3,425,190

 
$
2,944,455

 
$
2,750,421

Total Assets
4,449,989

 
4,249,478

 
4,119,830

 
3,482,860

 
3,413,638

Long-Term Debt, Net
1,453,072

 
1,451,720

 
1,361,828

 
1,213,367

 
1,213,246

Non-Current Capital Lease Obligations
39,267

 
55,324

 
69,438

 
131,370

 
262,138

Other Data
 
 
 
 
 
 
 
 
 
Ratio of Earnings to Fixed Charges (1)
3.69

 
3.74

 
2.56

 
2.67

 
2.10

(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 for additional information.


17




ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for TEP. It includes the following:
outlook and strategies;
operating results during 2016 compared with 2015, and 2015 compared with 2014;
factors affecting our results of operations and outlook;
liquidity and capital resources including capital expenditures, contractual obligations, and environmental matters;
critical accounting policies and estimates; and
recent accounting pronouncements.
Management’s Discussion and Analysis includes financial information prepared in accordance with Generally Accepted Accounting Principles in the United States of America (GAAP), as well as certain non-GAAP financial measures. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP 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, Selected 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 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: global, national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:
Achieving constructive outcomes in our regulatory proceedings that 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 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 improving our existing utility infrastructure, and maintaining financial strength. This long-term strategy includes a target of meeting 30% of our customers’ energy needs with non-carbon emitting resources by 2030.
Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
Operational and Financial Highlights
Management's Discussion and Analysis includes the following notable items:
In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase by TEP of the Third-Party Owners' 50.5% undivided interest in Springerville Unit 1 for $85 million. In September 2016, the purchase was completed and all asserted claims were dismissed. The Third-Party Owners paid TEP $12.5 million for previously unreimbursed operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners.

18




In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source as a better-than-BART alternative at Sundt.
In 2016, TEP recorded $22 million in time value refunds as a result of FERC orders relating to late filed TSAs. TEP paid a total of $17 million in 2016 in time value refunds to the counterparties to these TSAs. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement resulting in the counterparty paying TEP $8 million and TEP dismissing an appeal previously filed in June 2016.
In December 2016, TEP notified the owner participant and the lessor of the lease at the Springerville Common Facilities expiring in December 2017 that TEP had elected to purchase its undivided ownership interest in the facilities at the fixed purchase price of $38 million upon the expiration of the lease term.
In February 2017, the ACC issued a decision in TEP’s rate case approving a non-fuel base rate increase of $81.5 million and a 7.04% return on original cost rate base. The new rates will be effective on or before March 1, 2017.

RESULTS OF OPERATIONS
The following discussion provides the significant items that affected TEP's results of operations in years ended December 31, 2016, 2015, and 2014, presented on an after-tax basis.
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 refunds associated with late-filed TSAs. See Note 7 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-K;
$6 million in higher depreciation and amortization expense related primarily to an increase in asset base; and
$4 million in higher operations and maintenance expense resulting primarily from an increase in outside services and employee wages and benefits.
The decrease was partially offset by:
$8 million in higher revenues related to the Springerville Unit 1 settlement. For further information related to the settlement. See Note 7 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-K;
$6 million in higher net income as a result of a reduction in the valuation allowance for deferred tax assets based on an increase in projected taxable income; and
$4 million from higher LFCR revenues that partially offset lower retail sales.
2015 compared with 2014
TEP reported net income of $128 million in 2015 compared with $102 million in 2014. The increase of $26 million, or 25%, was primarily due to:
$16 million in lower operations and maintenance expense resulting primarily from Fortis acquisition-related costs and planned generation outages at Springerville Units 1 and 2 that occurred in 2014, partially offset by higher operations and maintenance expense related to Gila River Unit 3, labor costs, and outside services;
$6 million in higher transmission revenues resulting primarily from an increase in sales volumes on favorably priced contracts; and
$4 million in lower interest expense primarily due to a reduction in the balance of capital lease obligations.

19



Retail Sales and Revenues
Retail Revenues were $990 million in 2016, $1,022 million in 2015, and $970 million in 2014. Retail Margin Revenues (non-GAAP) were $631 million in 2016, $629 million in 2015, and $626 million in 2014. The table below provides a summary of retail kWh sales, a reconciliation of Retail Margin Revenues to Retail Revenues, and weather data:
 
Years Ended
December 31,
 
Increase (Decrease)
 
Year Ended
December 31
 
Increase (Decrease)
 
2016
 
2015
 
Percent
 
2014
 
Percent
Retail Sales by Customer Class (kWh in millions)
 
 
 
 
 
 
 
 
 
Residential
3,724

 
3,724

 
 %
 
3,727

 
(0.1
)%
Commercial
2,139

 
2,124

 
0.7
 %
 
2,170

 
(2.1
)%
Industrial
2,006

 
2,063

 
(2.8
)%
 
2,098

 
(1.7
)%
Mining
997

 
1,109

 
(10.1
)%
 
1,137

 
(2.5
)%
Public Authorities
30

 
33

 
(9.1
)%
 
33

 
 %
Total Retail Sales by Class
8,896

 
9,053

 
(1.7
)%
 
9,165

 
(1.2
)%
Retail Revenues (in millions)
 
 
 
 
 
 
 
 
 
Residential
$
281

 
$
281

 
 %
 
$
280

 
0.4
 %
Commercial
186

 
185

 
0.5
 %
 
188

 
(1.6
)%
Industrial
102

 
103

 
(1.0
)%
 
104

 
(1.0
)%
Mining
35

 
38

 
(7.9
)%
 
38

 
 %
Public Authorities
2

 
2

 
 %
 
2

 
 %
Retail Margin Revenues by Class
606

 
609

 
(0.5
)%
 
612

 
(0.5
)%
LFCR Revenues
18

 
12

 
50.0
 %
 
11

 
9.1
 %
DSM Performance Bonus
2

 
3

 
(33.3
)%
 
2

 
50.0
 %
Other Retail Margin Revenues
5

 
5

 
 %
 
1

 
*

Retail Margin Revenues (non-GAAP) (1)
631

 
629

 
0.3
 %
 
626

 
0.5
 %
Fuel and Purchased Power Revenues
305

 
344

 
(11.3
)%
 
303

 
13.5
 %
DSM and RES Surcharge Revenues
54

 
49

 
10.2
 %
 
41

 
19.5
 %
Total Retail Revenues (GAAP)
$
990

 
$
1,022

 
(3.1
)%
 
$
970

 
5.4
 %
Average Retail Margin Rate by Class (cents / kWh)
 
 
 
 
 
 
 
 
 
Residential
7.55

 
7.55

 
 %
 
7.51

 
0.5
 %
Commercial
8.70

 
8.71

 
(0.1
)%
 
8.66

 
0.6
 %
Industrial
5.08

 
4.99

 
1.8
 %
 
4.96

 
0.6
 %
Mining
3.51

 
3.43

 
2.3
 %
 
3.34

 
2.7
 %
Public Authorities (2)
5.68

 
5.61

 
1.2
 %
 
6.06

 
(7.4
)%
Average Retail Margin Rate by Class
6.81

 
6.73

 
1.2
 %
 
6.68

 
0.7
 %
Total Average Retail Margin Rate (3)
7.09

 
6.95

 
2.0
 %
 
6.80

 
2.2
 %
Average Fuel and Purchased Power Rate
3.43

 
3.80

 
(9.7
)%
 
3.31

 
14.8
 %
Average DSM and RES Surcharge Rate
0.61

 
0.54

 
13.0
 %
 
0.48

 
12.5
 %
Total Average Retail Rate
11.13

 
11.29

 
(1.4
)%
 
10.59

 
6.6
 %
Weather Data

 

 

 

 

Cooling Degree Days
 
 
 
 
 
 
 
 
 
Actual
1,515

 
1,576

 
(3.9
)%
 
1,557

 
1.2
 %
10-Year Average
1,535

 
1,520

 
*

 
1,515

 
*

Heating Degree Days
 
 
 
 
 
 
 
 
 
Actual
992

 
1,072

 
(7.5
)%
 
930

 
15.3
 %
10-Year Average
1,286

 
1,317

 
*

 
1,335

 
*

* Not meaningful

20



(1) 
Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information for investors and analysts because it 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, LFCR Revenues, DSM Performance Bonus, and certain Other Retail Margin Revenues available to cover the non-fuel operating expenses of our core utility business.
(2) 
Calculated on unrounded data and may not correspond exactly to data shown in table.
(3) 
Total Average Retail Margin Rate includes revenue related to LFCR Revenues, DSM Performance Bonus, and Other Retail Margin Revenues included in Retail Margin Revenues.
Retail Revenues were lower in 2016 compared with 2015 primarily due to a decrease in the PPFAC rate partially offset by higher Retail Margin Revenues. Retail Margin Revenues were higher primarily due to an increase in LFCR revenues.
Retail Revenues were higher in 2015 compared with 2014 primarily due to an increase in the PPFAC rate and higher Retail Margin Revenues. Retail Margin Revenues were higher primarily due to higher LFCR Revenues, DSM Performance Bonus, and Other Retail Margin Revenues related to adjustor mechanisms.
Wholesale Revenues
 
Years Ended December 31,
(in millions)
2016
 
2015
 
2014
Long-Term Wholesale
$
27

 
$
36

 
$
28

Short-Term Wholesale
81

 
104

 
114

Transmission
31

 
27

 
16

Transmission Refunds (1)
(22
)
 

 

Total Wholesale Revenues
$
117

 
$
167

 
$
158

(1) 
FERC ordered TEP to make refunds associated with various late-filed TSAs for the time period during which rates were charged without FERC authorization. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the FERC ordered refunds.
Wholesale Revenues decreased by $50 million, or 30%, in 2016 compared with 2015 primarily due to refunds related to the late-filed TSAs and decreased volumes and market prices of both short-term and long-term wholesale sales resulting from unfavorable market conditions and termination of a firm contract at the end of May 2016.
Wholesale Revenues increased by $9 million, or 6%, in 2015 compared with 2014 primarily due to a new long-term transmission agreement with UNS Electric related to Gila River Unit 3, transmission contract renewals resulting in favorable pricing, and new long-term wholesale agreements, partially offset by a decrease in market prices of short-term sales resulting from unfavorable market conditions.
Short-Term Wholesale Revenues are primarily related to the ACC jurisdictional assets and are returned to retail customers by crediting the revenues against fuel and purchased power costs eligible for recovery through the PPFAC.
Other Revenues
 
Years Ended December 31,
(in millions)
2016
 
2015
 
2014
Springerville Units 3 and 4 (1)
$
86

 
$
91

 
$
112

Other
42

 
27

 
29

Total Other Revenues
$
128

 
$
118

 
$
141

(1) 
Represents revenues and reimbursements to TEP from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, related to the operation of these generation facilities.
Other Revenues includes: (i) reimbursements related to Springerville Units 3 and 4; (ii) inter-company revenues from TEP's affiliates, UNS Gas, Inc. (UNS Gas), an affiliated subsidiary of TEP, and UNS Electric, for corporate services provided by TEP; and (iii) miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees.

21



Other Revenues increased by $10 million, or 8%, in 2016 compared with 2015 primarily due to the Springerville Unit 1 settlement agreement. For further information related to the Springerville Unit 1 settlement. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K. The increase was offset by a decrease in reimbursed costs in 2016 for Springerville Units 3 and 4 related to planned generation outages in 2015.
Other Revenues decreased by $23 million, or 16%, in 2015 compared with 2014 primarily due to a decrease in reimbursed costs in 2015 for Springerville Units 3 and 4 related to planned generation outages in 2014.
Operating Expenses
Generation Output and Fuel and Purchased Power Expense
TEP’s fuel and purchased power expense and energy resources are detailed below:
 
Generation and Purchased Power (kWh)
 
Fuel and Purchased Power Expense
 
Years Ended December 31,
(in millions)
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Coal-Fired Generation
8,310

 
8,584

 
9,271

 
$
192

 
$
209

 
$
232

Gas-Fired Generation
3,283

 
2,723

 
1,210

 
93

 
91

 
60

Utility Owned Renewable Generation
68

 
65

 
48

 

 

 

Reimbursed Fuel Expense, Springerville Units 3 and 4 (1)

 

 

 
5

 
5

 
5

Total Generation
11,661

 
11,372

 
10,529

 
290

 
305

 
297

Purchased Power, Non-Renewable
1,126

 
2,627

 
2,895

 
39

 
81

 
121

Purchased Power, Renewable
666

 
452

 
300

 
46

 
44

 
32

Total Purchased Power
1,792

 
3,079

 
3,195

 
85

 
125

 
153

Transmission and Other PPFAC Recoverable Costs

 

 

 
24

 
25

 
18

Increase (Decrease) to Reflect PPFAC Recovery Treatment

 

 

 
21

 
40

 
(11
)
Total Generation and Purchased Power
13,453

 
14,451

 
13,724

 
$
420

 
$
495

 
$
457

Less Line Losses and Company Use
(786
)
 
(719
)
 
(859
)
 
 
 
 
 
 
Total Power Sold
12,667

 
13,732

 
12,865

 
 
 
 
 
 
(1) 
Springerville Units 3 and 4 Fuel Expense is reimbursed by Tri-State and SRP.
Fuel and Purchased Power Expense decreased by $75 million, or 15%, in 2016 compared with 2015 primarily due to a decrease in non-renewable purchased power volumes, Coal-Fired Generation kWhs, and fuel costs per kWhs (see table below). The decrease was partially offset by an increase in Gas-Fired Generation kWhs.
Fuel and Purchased Power Expense increased by $38 million, or 8%, in 2015 compared with 2014 primarily due to an increase in the PPFAC charge and additional generation and transmission costs associated with Gila River Unit 3. The increase was partially offset by a decrease in fuel and purchased power costs per kWhs (see table below) and decreased coal-fired generation at Springerville Unit 1 as a result of the lease expiration in January 2015.
The table below summarizes average fuel cost of generated and purchased kWh:
 
Years Ended December 31,
(cents per kWh)
2016
 
2015
 
2014
Coal
2.30

 
2.44

 
2.50

Gas
2.84

 
3.35

 
4.99

Purchased Power, Non-Renewable
3.43

 
3.04

 
4.14

Purchased Power, Renewable
7.00

 
9.82

 
10.50

All Resources
3.15

 
3.31

 
3.64


22



Operations and Maintenance Expense
The table below summarizes the items included in Operations and Maintenance Expense:
 
Years Ended December 31,
(in millions)
2016
 
2015
 
2014
Reimbursed Expenses, Springerville Units 3 and 4 (1)
$
61

 
$
65

 
$
84

Reimbursed Expenses, Customer Funded Renewable Energy and
DSM Programs (2)
31

 
25

 
23

Other (3)
262

 
255

 
272

Total Operations and Maintenance Expense
$
354

 
$
345

 
$
379

(1) 
Expenses related to Springerville Units 3 and 4 are reimbursed with corresponding amounts recorded in Other Revenue.
(2) 
These expenses are collected from customers and the corresponding amounts are recorded in Retail Revenue.
(3) 
Includes the Third-Party Owners' share of expenses related to Springerville Unit 1 for years ended 2015 and 2014 and part of 2016.
Operations and Maintenance Expense increased by $9 million, or 3%, in 2016 compared with 2015 primarily due to an increase in expenses related to planned generation outages, outside services, and employee wages and benefits and an increase in RES and DSM program expenses.
Operations and Maintenance Expense decreased by $34 million, or 9%, in 2015 compared with 2014 primarily due to a decrease in Springerville Units 3 and 4 expenses, related to outages that incurred in 2014 as well as Fortis acquisition-related costs and outages at Springerville Units 1 and 2 that occurred in 2014. The decrease was partially offset by higher operations and maintenance expenses related to Gila River Unit 3, labor costs, and outside services.

FACTORS AFFECTING RESULTS OF OPERATIONS
2017 RATE ORDER
In February 2017, the 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 2017 Rate Order approved new rates to be effective on or before March 1, 2017.
The provisions of the 2017 Rate Order include, but are not limited to:
a non-fuel base rate increase of $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 7.04% return on original cost rate base of approximately $2 billion;
a cost of equity component of 9.75% and a cost of debt component of 4.32%;
a capital structure for rate making purposes of approximately 50% common equity and 50% long-term debt;
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and
a request to apply excess depreciation reserves against the unrecovered net book value (NBV) of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.
The ACC deferred TEP's proposed changes to net metering and rate design for new DG customers to Phase 2, which is expected to begin in the second quarter of 2017. TEP cannot predict the outcome of this proceeding.
Generation Resources
As of December 31, 2016, approximately 52% of TEP's generation capacity is coal-fired generation. TEP is evaluating additional steps to reduce its reliance on coal-fired generation.

23



Integrated Resource Plan
In March 2016, as required by the ACC, TEP filed its 2016 Preliminary Integrated Resource Plan (IRP). A Supplement to the Preliminary IRP was filed on September 30, 2016, with the final 2017 IRP to be filed by April 2017. TEP's Preliminary IRP and Supplement disclose TEP's plan to reduce its overall coal capacity by 170 MW at San Juan in 2017, and outlines options for further reductions at San Juan in 2022, Navajo in 2030, and Four Corners in 2031. TEP’s final IRP will address the long-term viability of Navajo. TEP's existing generation fleet faces a number of uncertainties impacting the viability of continued operations including competition from other resources, fuel contract extensions, environmental regulations and the ability of existing owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or sale of generation assets to third-parties. TEP plans to seek regulatory recovery for amounts that would not otherwise be recovered if and when any assets are retired.
See Part I, Item 1. Business, Environmental Matters of this Form 10-K for additional information regarding the impact of environmental matters on generation facility operations and Business, Overview of Business for additional information regarding TEP's generation facilities.
Navajo Generating Station
Navajo is located on a site that is leased from the Navajo Nation with an initial lease term through 2019. In February 2017, SRP, the operator of Navajo announced that they do not currently intend to operate Navajo past the current term of the lease. TEP supports continued operation of the plant through December 2019 if a lease extension can be reached with the Navajo Nation. Without a lease extension, the owners would be forced to cease operations at Navajo this year to allow enough time for decommissioning to be completed before the current lease expires. As of December 31, 2016, TEP's NBV of Navajo was $40 million. Upon the retirement of Navajo, TEP will seek rate recovery of any unrecovered costs. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Springerville Common Facilities Purchase Commitment
The Springerville Common Facilities leases have an initial term ending December 2017 for one lease and January 2021 for the other two leases.
In December 2016, TEP notified the owner participant and the lessor of the lease that expires in December 2017 that TEP had elected to purchase a 17.8% undivided ownership interest in the Springerville Common Facilities at the fixed purchase price of $38 million upon the expiration of the lease. Due to TEP's purchase commitment, in December 2016, TEP recorded an increase of $36 million to Current Obligations Under Capital Leases and Utility Plant Under Capital Lease, which represents the present value of the total purchase commitment, on the Consolidated Balance Sheets.
Under the remaining two leases, TEP has options to: (i) renew the leases for periods of two or more years; or (ii) exercise the purchase options under these leases.
See Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Springerville Coal Handling Facilities Lease Purchase
In April 2015, upon expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million.
Tri-State, the lessee of Springerville Unit 3, is obligated to either: (i) buy a 17.05% undivided interest in the facilities for approximately $24 million; or (ii) continue to make payments to TEP for the use of the facilities. In March 2016, Tri-State notified TEP that it was exercising its option to purchase the undivided interest in the facilities. As of December 31, 2015, the 17.05% undivided interest in the Springerville Coal Handling Facilities was classified as Assets Held for Sale, Net. However, as of December 31, 2016, TEP's management no longer believed the sale would be completed. As a result, in December 2016 Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities was reclassified as Utility Plant from Assets Held for Sale, Net on the Consolidated Balance Sheets. In 2016, TEP recorded $1 million of catch-up depreciation for the period of time the facilities were recorded in Assets Held for Sale, Net. In 2016, TEP was reimbursed $4 million per year in operations costs by Tri-State related to its portion of the Springerville Coal Handling Facilities.
Sales to Mining Customers
TEP's largest mining customer took steps to reduce operational expenses by curtailing production in 2016 due to a decline in commodity prices. As a result, retail sales to mining customers declined by 10% in 2016 compared with the same period in 2015. While TEP cannot predict how long commodity prices will remain low or the total impact the prices will have on mining

24



production in the future, any future curtailment of mining production could negatively impact retail sales to mining customers. As of December 31, 2016, mining customers accounted for 11% of TEP's total retail sales and 6% of Retail Revenues.
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.

LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Cash flows may vary during the year with cash flows 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, we will use, as needed, our revolving credit facility to assist in funding business activities. We believe that we have sufficient liquidity under our revolving credit facility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which TEP has access to external financing depends on a variety of factors, including its credit ratings and conditions in the overall capital markets.
Available Liquidity
(in millions)
December 31, 2016
Cash and Cash Equivalents
$
36

Amount Available under Revolving Credit Facility (1)
250

Total Liquidity
$
286

(1) 
TEP's revolving credit facility provides for $250 million of revolving credit commitments with a Letter of Credit (LOC) sublimit of $50 million through its original maturity date of October 2020. In October 2016, TEP extended the agreement one year to October 2021. The credit facility commitments will be reduced to $217.5 million in the final year of the agreement.
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 maturities, and obligations included in the Contractual Obligations and forecasted Capital Expenditures tables below.
See Part III, Item 7A. Quantitative and Qualitative Disclosures about Market Risk for additional information regarding TEP's market risks and Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP's financing arrangements.
Summary of Cash Flows
The table below presents net cash provided by (used for) operating, investing and financing activities:
 
Years Ended
 
Increase
(Decrease)
 
Year Ended
 
Increase
(Decrease)
(in millions)
2016
 
2015
 
Percent
 
2014
 
Percent
Operating Activities
$
425

 
$
365

 
16.4
 %
 
$
314

 
16.2
 %
Investing Activities
(376
)
 
(503
)
 
(25.2
)%
 
(518
)
 
(2.9
)%
Financing Activities
(69
)
 
120

 
(157.5
)%
 
253

 
(52.6
)%
Net Increase (Decrease) in Cash
(20
)
 
(18
)
 
(11.1
)%
 
49

 
(136.7
)%
Cash and Cash Equivalents, Beginning of Year
56

 
74

 
(24.3
)%
 
25

 
196.0
 %
Cash and Cash Equivalents, End of Year
$
36

 
$
56

 
(35.7
)%
 
$
74

 
(24.3
)%
Cash flows in 2016 reflect a reduction in capital expenditures compared with prior years and no new long-term debt or revolving credit agreement borrowings. Cash flows in both 2015 and 2014 included large capital expenditures. These capital requirements were met with a combination of equity contributions from UNS Energy and long-term borrowings as discussed in Financing Activities below.

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In 2015, we issued long-term debt and used the proceeds to repay revolving and term loans under our credit agreements and pay a portion of the purchase price for interests in the Springerville Coal Handling Facilities. In addition, we received an equity contribution from UNS Energy and used the proceeds to repay the outstanding balances under our revolving credit facilities and redeem long-term variable rate tax-exempt bonds which were called for redemption in June 2015.
In 2014, we received an equity contribution from UNS Energy and used the proceeds to pay for the purchase of both Gila River Unit 3 and Springerville Unit 1 leased assets.
Operating Activities
2016 compared with 2015
In 2016, net cash flows from operating activities increased by $60 million compared with 2015 primarily due to a:
$20 million temporary over-recovery of fuel and purchased power costs under the PPFAC mechanism;
$17 million decrease in cash paid for pension and other postretirement benefits funding;
$12.5 million increase in cash proceeds related to the settlement of operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners; and
$28 million increase attributable to timing differences in Accrued Payable and Accrued Charges.
The increase in net cash flows from operating activities was partially offset by an increase of $11 million in cash paid for incentive compensation in 2016 compared with the same period in 2015 in which no incentive compensation was paid. As a result of the Fortis acquisition in 2014, payments under the annual incentive compensation plan were accelerated to the third quarter of 2014 from the first quarter of 2015.
2015 compared with 2014
In 2015, net cash flows from operating activities increased by $51 million compared with 2014 primarily due to a:
$39 million increase in cash proceeds from retail and wholesale sales, net of fuel and purchased power costs paid, driven primarily by an increase in the average PPFAC rate; and
$34 million decrease in cash paid for acquisition-related costs and incentive compensation primarily due to the 2014 acquisition.
The increase in net cash flows from operating activities was partially offset by $16 million of higher cash paid to fund pension and other postretirement plans.
Investing Activities
2016 compared with 2015
In 2016, net cash flows used for investing activities decreased by $127 million compared with 2015 primarily due to a:
$120 million purchase in April 2015 of an additional 86.7% undivided ownership interest in the Springerville Coal Handling Facilities increasing its total ownership interest to 100%; and
$83 million decrease in cash paid in 2016 for capital expenditures primarily due to construction cost in 2015 of a new 500kV transmission line.
The decrease in net cash flows used for investing activities was partially offset by a:
$85 million purchase in September 2016 of a 50.5% undivided ownership interest in Springerville Unit 1 compared to a $46 million purchase in January 2015 of a 24.8% undivided ownership interest in the same generation facility;
$24 million in cash proceeds in May 2015 from the sale of a 17.05% undivided ownership interest in Springerville Coal Handling Facilities to SRP; and
$12 million increase in cash paid in 2016 for the purchase of renewable energy credits.

26



2015 compared with 2014
In 2015, net cash flows used for investing activities decreased by $15 million compared with 2014 primarily due to a:
$164 million purchase in December 2014 of a 75% undivided ownership interest in Gila River Unit 3; and
$20 million purchase in December 2014 of a 10.6% interest in Springerville Unit 1.
The decrease in net cash flows used for investing activities was partially offset by a:
$96 million net purchase in 2015 of the Springerville Coal Handling Facilities consisting of the $120 million purchase of an additional 86.7% undivided ownership interest, partially offset by a $24 million sale of the 17.05% undivided ownership interest to SRP;
$46 million purchase in January 2015 of an additional 24.8% undivided ownership interest in Springerville Unit 1 increasing our total ownership interest to 49.5%;
$11 million decrease in cash receipts for contributions in aid of construction received; and
$10 million increase in capital expenditures to fund system reinforcement through replacements and betterments.
Financing Activities
2016 compared with 2015
In 2016, net cash flows from financing activities decreased by $189 million compared with 2015 primarily due to a:
$299 million decrease in cash proceeds in 2016 for the issuance of long-term debt in February 2015; and
$180 million decrease in cash proceeds in 2016 from a UNS Energy equity contribution in June 2015.
The decrease in net cash flows from financing activities was partially offset by a:
$209 million decrease in cash paid in 2016 for the purchase of $130 million in tax-exempt long-term debt in January 2015, and the retirement of $79 million in long-term debt in August 2015; and
$85 million decrease in cash paid in 2016, net of proceeds borrowed, under TEP's revolving credit facilities.
2015 compared with 2014
In 2015, net cash flows from financing activities decreased by $133 million compared with 2014 primarily due to:
$209 million increase in cash paid to purchase of $130 million in fixed rate tax-exempt long-term debt in January 2015, and the retirement of $79 million in variable rate tax-exempt bonds in August 2015;
$170 million decrease in cash proceeds borrowed and higher repayments under TEP's revolving credit facilities;
$45 million decrease in cash proceeds from UNS Energy's equity contributions; and
$10 million increase in cash paid for dividend payments.
The decrease in net cash flows from financing activities was partially offset by:
$152 million decrease in cash payments due to the expiration of capital lease obligations in 2015; and
$150 million increase in cash proceeds from the issuance of long-term debt, in February 2015.
External Sources of Liquidity
Short-Term Investments
TEP’s short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of December 31, 2016, TEP's short-term investments included highly-rated and liquid money market funds.

27



Access to Revolving Credit Facility
We have access to working capital through a revolving credit agreement with lenders. 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, 2016, no amounts were drawn under the revolving credit facility.
For details on 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. TEP's cost of capital is also affected by our credit ratings.
In January 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 have no plans to raise additional capital in 2017. TEP has, from time to time, 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.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2016, TEP’s credit ratings for senior unsecured debt were A3 from Moody’s and BBB+ from S&P Global Ratings.
TEP's credit ratings are dependent on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.
Debt Covenants
Certain 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. Also, under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of December 31, 2016, TEP was in compliance with these covenants.
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, 2016, TEP had posted no LOCs as credit enhancements with its 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 2016. UNS Energy made an equity contribution to TEP of $180 million in 2015 and $225 million in 2014. The contributions were used to repay revolving credit loans, redeem bonds, and provide additional liquidity to TEP.
Dividends Paid to Parent
TEP declared and paid $50 million in dividends to UNS Energy in 2016 and 2015 and $40 million in 2014.
The ACC's approval of the acquisition of UNS Energy by Fortis in August 2014 contained a condition restricting TEP's dividend payments to UNS Energy to no more than 60% of TEP's annual net income for the earlier of five years or until such time that TEP's equity capitalization reached 50% as accounted for in accordance with GAAP. In June 2016, TEP reached the equity capitalization threshold.

28



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 2016, total capital expenditures of $335 million, included the purchase of the remaining 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. In 2014, total capital expenditures of $507 million, included the purchase of an interest in Gila River Unit 3, undivided ownership interests in Springerville Unit 1, and construction costs for a new 500-kilovolt (kV) transmission line in Pinal County that began in December 2014 and concluded in late 2015.
We expect capital requirements to remain stable from 2017 through 2021. TEP's forecasted capital expenditures are summarized below:
(in millions)
2017
 
2018
 
2019
 
2020
 
2021
Generation Facilities:
 
 
 
 
 
 
 
 
 
Environmental Compliance
$
23

 
$
10

 
$
1

 
$
4

 
$
2

Renewable Energy

 
26

 
26

 
26

 
26

Springerville Common Lease Purchase
38

 

 

 

 
9

Other Generation Facilities
67

 
49

 
60

 
79

 
108

Total Generation Facilities
128

 
85

 
87

 
109

 
145

Transmission and Distribution
151

 
152

 
125

 
142

 
148

General and Other (1)
66

 
47

 
106

 
53

 
37

Total Capital Expenditures
$
345

 
$
284

 
$
318

 
$
304

 
$
330

(1) 
General and Other 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 business 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 internally generated funds and external financings, which may include issuances of long-term debt or other borrowings.

29



Contractual Obligations
The following chart displays TEP’s contractual obligations by maturity and by type of obligation as of December 31, 2016:
 
 
 
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

 
$

 
$
137

 
$
330

 
$
999

Interest (2)
709

 
59

 
118

 
111

 
421

Capital Lease Obligations (3)
97

 
54

 
24

 
19

 

Operating Leases: (4)

 
 
 
 
 
 
 
 
Land Easements and Rights-of-Way
81

 
1

 
2

 
3

 
75

Operating Leases Other
9

 
1

 
2

 
2

 
4

Purchase Obligations:

 
 
 
 
 
 
 
 
Fuel, Including Transportation (5)
631

 
100

 
152

 
110

 
269

Purchased Power
32

 
32

 

 

 

Transmission
78

 
18

 
38

 
12

 
10

Renewable Purchase Power Agreements (6)
1,048

 
64

 
128

 
126

 
730

RES Performance-Based Incentives (7)
99

 
8

 
16

 
16

 
59

Acquisition of Springerville Common Facilities (8)
68

 

 

 
68

 

Other Long-Term Liabilities: (9) (10)

 
 
 
 
 
 
 
 
Restricted and Performance-Based Stock Units
4

 

 
4

 

 

Pension and Other Postretirement (11)
78

 
16

 
12

 
13

 
37

Total Contractual Obligations
$
4,400

 
$
353

 
$
633

 
$
810

 
$
2,604

(1) 
$37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in 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 2018. Total long-term debt is not reduced by $10 million of related unamortized debt issuance costs or $3 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. Upon expiration of the Springerville Coal Handling lease in April 2015, TEP purchased the interests in those assets. SRP then purchased an undivided interest in the coal handling assets from TEP. Tri-State and SRP each continue to reimburse TEP for their shares of common assets owned or leased by TEP. TEP was reimbursed for $10 million of operating costs in 2016 by SRP and Tri-State and expects to be reimbursed $10 million of operating costs in 2017. 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) 
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 Navajo, San Juan, and Four Corners as the timing of payment has not been determined. 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.
(6) 
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.

30



(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 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.
(8) 
The Springerville Common Facilities Leases have an initial term ending December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years. In December 2016, TEP entered into a commitment to purchase the lease, which has an initial term ending December 2017. TEP may renew the other two leases or exercise its remaining fixed-price purchase options.
(9) 
Excludes Asset Retirement Obligations (ARO) of $33 million expected to occur through 2066.
(10) 
Excludes unrecognized tax benefits of $12 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.
(11) 
These obligations represent TEP’s expected contributions to pension plans in 2017, 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 beyond 2017 are excluded.
Off Balance Sheet Arrangements
Other than the 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
Prior year tax legislation and the Consolidated Appropriations Act of 2016, include provisions that make qualified property placed in service between 2010 and 2019 eligible for bonus depreciation for tax purposes. In addition, the IRS issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits TEP otherwise would have received over 20 years and have created net operating loss carryforwards that can be used to offset future taxable income. As a result, TEP did not pay any federal or state income taxes in 2016 and does not expect to make any payments until 2020.
Environmental Matters
The EPA regulates the amount of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced by generation facilities. TEP 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, TEP is 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. TEP capitalized $40 million in 2016, $33 million in 2015, and $11 million in 2014 in costs incurred to comply with environmental rules and regulations. In addition, we recorded operations and maintenance expenses of $6 million in 2016, 2015, and 2014. TEP expects to recover the cost of environmental compliance through Retail Rates.
Hazardous Air Pollutant Requirements
In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from generation facilities. Based on the EPA's final Mercury and Air Toxics Standards (MATS) rules, additional emission control equipment would have been required by April 2015. TEP, as operator of Springerville and Sundt, and the operators of Navajo and Four Corners received extensions until April 2016 to comply with the MATS rules.
In June 2015, the D.C. Circuit Court of Appeals remanded the MATS rules to the EPA for further consideration. Despite the June 2015 ruling, TEP proceeded with its planned MATS compliance activity at each generation facilities.
In March 2016, the installation of mercury control systems was completed at Navajo. TEP’s share of the installation costs were approximately $1 million. In addition, TEP completed the installation of mercury control systems on Units 1 and 2 at Springerville in March 2016. TEP’s share of the installation costs were approximately $3 million. At this time, all generation facilities TEP operates or is a participant in are in compliance with the MATS rules.

31



Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as Best Alternative 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 costs to comply with the BART rule, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of Navajo and Four Corners or for individual owners to continue to participate in these generation facilities. 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 timeframes, 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.
TEP's estimated NOx emissions control costs to comply with the rules include the following:
(in mill