10-K 1 tep10k12312018.htm 10-K Document


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, 2018
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, No 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. Yes o 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 Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filero
Accelerated Filero
Non-Accelerated Filerx
Smaller Reporting Companyo
Emerging Growth Companyo

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
State the aggregate market value of the voting and non-voting common equity held by non-affiliates: None
As of February 14, 2019, 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 2018 Form 10-K are defined below:
2010 Reimbursement Agreement
 
Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2017 Rate Order
 
A rate order issued by the ACC resulting in a new rate structure for TEP, effective on February 27, 2017
ABR
 
Alternate Base Rate
ACC
 
Arizona Corporation Commission
ACC Refund Order
 
An order issued by the ACC approving TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability that reflects the deferral of the return of a portion of the savings to be returned to customers in TEP's next rate case
AFUDC
 
Allowance for Funds Used During Construction
AMT
 
Alternative Minimum Tax
AOCI
 
Accumulated Other Comprehensive Income
APS
 
Arizona Public Service Company
ARO
 
Asset Retirement Obligation
BART
 
Best Available Retrofit Technology
BBtu
 
Billion British thermal unit(s)
DG
 
Distributed Generation
DSM
 
Demand Side Management
ECA
 
Environmental Compliance Adjustor
EDIT
 
Excess Deferred Income Taxes
EE Standards
 
Energy Efficiency Standards
EPA
 
Environmental Protection Agency
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
FERC Refund Order
 
An order issued by the FERC directing TEP to either: (i) submit proposed revisions to its stated transmission rates or stated transmission revenue requirements to reflect the change in the federal corporate income tax rate as a result of the TCJA; or (ii) show cause why it should not be required to do so
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 Acquisition
 
SRP entered into an agreement to acquire Gila River Units 1 and 2 from third-parties
Gila River
 
Gila River Generating Station
GWh
 
Gigawatt-hour(s)
IRS
 
Internal Revenue Service
kWh
 
Kilowatt-hour(s)
LFCR
 
Lost Fixed Cost Recovery
LIBOR
 
London Interbank Offered Rate
LOC
 
Letter(s) of Credit
Luna
 
Luna Generating Station
MMBtu
 
Million Metric British thermal units
MW
 
Megawatt(s)
MWh
 
Megawatt-hour(s)
Navajo
 
Navajo Generating Station

v


NBV
 
Net Book Value
NOPR
 
Notice of Proposed Rulemaking
PBI
 
Performance-Based Incentive
PDEQ Application
 
In 2017, TEP submitted an Air Quality Permit Application to the Pima County Department of Environmental Quality related to a generation modernization project at Sundt
Phase 2
 
Second phase of TEP's rate case proceedings originally filed November 2015
Phase 2 Order
 
ACC order establishing, among other things, an export rate that replaced net metering for excess solar generation
PNM
 
Public Service Company of New Mexico
PPA
 
Power Purchase Agreement
PPFAC
 
Purchased Power and Fuel Adjustment Clause
PV
 
Photovoltaic
REC
 
Renewable Energy Credit
Regional Haze
 
Regional Haze Regulation promulgated by the EPA to improve visibility at national parks and wilderness areas
RES
 
Renewable Energy Standard
Retail Rates
 
Rates designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment
RICE
 
Reciprocating Internal Combustion Engine
San Juan
 
San Juan Generating Station
SEC
 
Securities and Exchange Commission
SERP
 
Supplemental Executive Retirement Plan
SES
 
Southwest Energy Solutions, Inc.
SJCC
 
San Juan Coal Company
Springerville
 
Springerville Generating Station
SRP
 
Salt River Project Agricultural Improvement and Power District
Sundt
 
H. Wilson Sundt Generating Station
TCJA
 
On December 22, 2017, the Tax Cuts and Jobs Act was signed into law enacting significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017
TEP
 
Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Third-Party Owners
 
Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
Tolling PPA
 
A 20-year tolling PPA that TEP entered into in 2017 with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which includes a three-year option to purchase the unit

Tri-State
 
Tri-State Generation and Transmission Association, Inc.
TSA
 
Transmission Service Agreement
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
VEBA
 
Voluntary Employee Beneficiary Association
VIE
 
Variable Interest Entity
WCC
 
Westmoreland Coal Company


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 economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, 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: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax and energy policies; changes in, and compliance with, environmental laws and regulatory 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; our forecasts of peak demand and whether existing generation capacity and Power Purchase Agreements (PPA) are sufficient to meet the expected demand and reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and the related contribution requirements and expenses; 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 (DG) 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; the performance of TEP's generation facilities; and the impact of the Tax Cuts and Jobs Act (TCJA) on our financial condition and results of operations, including the assumptions we make relating thereto.


vii


PART I
ITEM 1. BUSINESS
OVERVIEW OF BUSINESS
General
TEP and its predecessor companies have served the greater Tucson metropolitan area for 126 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 425,000 retail customers. TEP’s service territory covers 1,155 square miles and includes a population of over one million people in Pima County, as well as parts of Cochise County. TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP 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. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis) which is a leader in the North American electric and gas utility business.
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. The ACC establishes rates that are designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates).
Customers
Electricity sold to retail 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)
2018
 
2017
 
2016
Electric Sales
 
 
 
 
 
 
 
 
 
 
 
Residential
3,766
 
24
%
 
3,786

 
28
%
 
3,724

 
29
%
Commercial
2,136
 
14
%
 
2,192

 
17
%
 
2,139

 
17
%
Industrial, non-Mining
1,949
 
12
%
 
1,939

 
15
%
 
2,006

 
16
%
Industrial, Mining
1,033
 
7
%
 
991

 
8
%
 
997

 
8
%
Other
16
 
—
%
 
18

 
—
%
 
30

 
—
%
Total Retail Sales by Customer Class
8,900
 
57
%
 
8,926

 
68
%
 
8,896

 
70
%
Wholesale Sales, Long-Term
424
 
3
%
 
587

 
4
%
 
463

 
4
%
Wholesale Sales, Short-Term
6,279
 
40
%
 
3,630

 
28
%
 
3,308

 
26
%
Total Electric Sales
15,603
 
100
%
 
13,143

 
100
%
 
12,667

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average Number of Retail Customers
 
 
 
 
 
 
 
 
 
 
 
Residential
384,021
 
90
%
 
381,399

 
90
%
 
378,991

 
90
%
Commercial
38,642
 
9
%
 
38,564

 
9
%
 
38,403

 
9
%
Industrial, non-Mining
504
 
—
%
 
520

 
—
%
 
580

 
—
%
Industrial, Mining
4
 
—
%
 
4

 
—
%
 
4

 
—
%
Other
1,873
 
1
%
 
1,879

 
1
%
 
1,866

 
1
%
Total Retail Customers
425,044
 
100
%
 
422,366

 
100
%
 
419,844

 
100
%

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Retail Customers
TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, healthcare, education, military bases, and 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 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 2019 based on the estimated population growth in its service territory.
TEP’s retail sales volume in 2018 was 8,900 gigawatt-hours (GWh), which is a decrease of 3% from 2014 levels. During the past five years, mining load reductions and state requirements to promote energy efficiency and DG have resulted in lower sales volumes.
TEP’s mining customers make up 7% of total retail sales. TEP’s GWh sales to mining customers depend on a variety of factors, including commodity prices, electricity prices, and the mines' development of self-generation resources. TEP’s GWh sales to mining customers have decreased by 9% from 2014 levels as a result of the decline in commodity prices causing the mines to curtail production starting in 2016. TEP cannot predict future commodity prices or the impact they will have on mining production and TEP’s sales to 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 power 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 primary long-term wholesale sale contracts are presented in the table below:
Counterparty
 
Contracts Expire December 31,
Navajo Tribal Utility Authority
 
2022
TRICO Electric Cooperative
 
2024
Navopache Electric Cooperative
 
2041
Short-Term Wholesale Sales
Certain contracts for short-term wholesale sales cover periods of less than one year and obligate TEP to sell capacity or power at a fixed price. 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 are passed through to TEP’s retail customers offsetting fuel and purchased power costs. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices. Short-term wholesale sales increased in 2018 due to the increase in generation capacity related to Gila River Generating Station (Gila River) Unit 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. In August 2018, the ACC opened a docket to evaluate several energy policies including retail competition for generation services. A workshop was held related to retail competition in

2

December 2018. TEP cannot predict what additional steps, if any, the ACC may take to further evaluate retail competition in this docket.
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, 2018, TEP had 3,076 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 alternating current (AC).
 
 
Unit
 
 
 
Date
 
Capacity
 
Operating
 
TEP’s Share
Generation Source
 
No.
 
Location
 
In Service
 
(MW)
 
Agent
 
%
 
(MW)
Coal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Springerville
 
1
 
Springerville, AZ
 
1985
 
387
 
TEP
 
100
 
387

Springerville (1)
 
2
 
Springerville, AZ
 
1990
 
406
 
TEP
 
100
 
406

San Juan
 
1
 
Farmington, NM
 
1976
 
340
 
PNM
 
50.0
 
170

Navajo (2)
 
1
 
Page, AZ
 
1974
 
750
 
SRP
 
7.5
 
56

Navajo (2)
 
2
 
Page, AZ
 
1975
 
750
 
SRP
 
7.5
 
56

Navajo (2)
 
3
 
Page, AZ
 
1976
 
750
 
SRP
 
7.5
 
56

Four Corners
 
4
 
Farmington, NM
 
1969
 
785
 
APS
 
7.0
 
55

Four Corners
 
5
 
Farmington, NM
 
1970
 
785
 
APS
 
7.0
 
55

Natural Gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gila River (3)
 
2
 
Gila Bend, AZ
 
2003
 
550
 
SRP
 
100
 
550

Gila River
 
3
 
Gila Bend, AZ
 
2003
 
550
 
SRP
 
75.0
 
413

Luna
 
1
 
Deming, NM
 
2006
 
555
 
PNM
 
33.3
 
185

Sundt (4)
 
1
 
Tucson, AZ
 
1958
 
81
 
TEP
 
100
 
81

Sundt (4)
 
2
 
Tucson, AZ
 
1960
 
81
 
TEP
 
100
 
81

Sundt
 
3
 
Tucson, AZ
 
1962
 
104
 
TEP
 
100
 
104

Sundt
 
4
 
Tucson, AZ
 
1967
 
156
 
TEP
 
100
 
156

Sundt Internal Combustion Turbines
 
 
 
Tucson, AZ
 
1972-1973
 
50
 
TEP
 
100
 
50

DeMoss Petrie
 
 
 
Tucson, AZ
 
2001
 
75
 
TEP
 
100
 
75

North Loop
 
 
 
Tucson, AZ
 
2001
 
94
 
TEP
 
100
 
94

Solar
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility-Scale Renewables
 
 
 
Various
 
2002-2017
 
46
 
TEP
 
100
 
46

Total Capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
3,076

(1) 
Springerville Generating Station (Springerville) Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.
(2) 
TEP, along with the other participants at the Navajo Generating Station (Navajo), plans to discontinue operations of Navajo by the end of 2019.
(3) 
In 2017, TEP entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which includes a three-year option to purchase the unit (Tolling PPA).
(4) 
TEP plans to discontinue operations of H. Wilson Sundt Generating Station (Sundt) Units 1 & 2 by the end of 2020.
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. Tri-State Generation and Transmission Association, Inc. (Tri-State), 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.

3

Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, owns 17.05% of the Springerville Coal Handling Facilities and pays TEP for a portion of the fixed costs allocated for the common facilities.
Renewable Energy Resources
The ACC’s Renewable Energy Standard (RES) requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG.
In 2018, the percentage of retail kilowatt-hour (kWh) sales attributable to the RES was approximately 14%, exceeding the 2018 requirement of 8%. The ACC approved a waiver of the 2018 DG requirement.
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 Utility-Scale Renewable Resources
As of December 31, 2018, TEP owned 46 MW of photovoltaic (PV) solar generation capacity, measured in AC. The following table presents TEP's owned utility-scale renewable generation resources:
Generation Source
 
Location
 
Date
in Service
 
Capacity (MW)
Solar
 
 
 
 
 
 
Fort Huachuca Phase I & II (1)
 
Sierra Vista, AZ
 
2014-2017
 
18

Springerville
 
Springerville, AZ
 
2004-2014
 
13

UASTP Phase I & II (2)
 
Tucson, AZ
 
2010-2011
 
5

Sundt Areva Solar Thermal
 
Tucson, AZ
 
2014
 
5

Solon Prairie Fire (2)
 
Tucson, AZ
 
2012
 
4

Small PV (<5MW)
 
Various
 
Various
 
1

Total Capacity
 
 
 
 
 
46

(1) 
TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.
(2) 
The University of Arizona Science and Technology Park (UASTP) I & II and Solon Prairie Fire are located on properties held under land easements and leases.

4

Renewable Power Purchase Agreements
As of December 31, 2018, TEP had renewable PPAs for 159 MW from solar resources, 80 MW from wind resources, and 4 MW associated with the purchase of landfill gas as presented in the table below. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date. The following table's capacity is measured in AC.
Generation Source
 
Location
 
Date/Projected Date
in Service
 
In Service
Capacity (MW)
 
Under Development
Capacity (MW)
Solar
 
 
 
 
 
 
 
 
Red Horse
 
Willcox, AZ
 
2015
 
41

 
 
Avalon I
 
Sahuarita, AZ
 
2014
 
28

 
 
Avra Valley
 
Marana, AZ
 
2012
 
25

 
 
Picture Rocks
 
Marana, AZ
 
2012
 
20

 
 
Avalon II
 
Sahuarita, AZ
 
2016
 
17

 
 
Valencia
 
Tucson, AZ
 
2013
 
10

 
 
E.On Tech Park
 
Tucson, AZ
 
2012
 
5

 
 
Gato Montes
 
Tucson, AZ
 
2012
 
5

 
 
Small PPAs (<5MW)
 
Various
 
Various
 
8

 
 
Wilmot Solar
 
Tucson, AZ
 
2021
 
 
 
100

Wind
 
 
 
 
 
 
 
 
Macho Springs
 
Deming, NM
 
2011
 
50

 
 
Red Horse Wind
 
Willcox, AZ
 
2015
 
30

 
 
Borderlands Wind
 
Catron County, NM
 
2020
 
 
 
99

Biogas
 
 
 
 
 
 
 
 
Sundt, Los Reales (1)
 
Tucson, AZ
 
1998
 
4

 
 
Total Capacity
 
 
 
 
 
243

 
199

(1) 
Purchase of landfill gas for use at Sundt.
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 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K related to purchased power commitments.
TEP typically uses its generation, supplemented by purchased power, to meet the summer peak demands of its retail customers. TEP hedges a portion of its total energy price exposure with forward priced contracts. Certain of these contracts are at a fixed price per megawatt-hour (MWh) and others are indexed to natural gas prices. TEP also purchases power in the daily and hourly markets to meet higher than anticipated demands, to cover generation outages, or when doing so is more economical than generating its own power.
TEP is a member of a regional reserve-sharing organization and has reliability and power-sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as facility outages and system disturbances, and reduce the amount of reserves TEP is required to carry.
Peak Demand and Future Resources
Peak Demand
(in MW)
2018
 
2017
 
2016
 
2015
 
2014
Retail Customers
2,413

 
2,415

 
2,278

 
2,222

 
2,218

In 2018, 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).

5

Peak demand occurs during the summer months due to the cooling requirements of retail customers in TEP’s service territory. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. Retail peak demand in 2018 was comparable to 2017 but significantly higher than peak demand in 2014 through 2016 primarily due to warmer than normal summer temperatures.
Forecasted retail peak demand for 2019 is 2,305 MW compared with actual peak demand of 2,413 MW in 2018. TEP’s 2019 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 2019.
Future Resources
As of December 31, 2018, approximately 40% of TEP's generation capacity, including owned and leased resources, was from coal-fired generation. TEP is executing strategies and evaluating additional steps to reduce its dependency on coal-fired generation while still meeting its peak load requirements and maintaining affordable Retail Rates. TEP's five-year capital expenditure forecast includes investments related to natural gas Reciprocating Internal Combustion Engine (RICE) units to be placed in service at Sundt and the planned purchase of Gila River Unit 2. These anticipated investments will provide replacement capacity for the planned early retirements of coal-fired and other generation resources.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information regarding TEP's generation resources planned retirements and additions.
Fuel Supply
A summary of Fuel and Purchased Power resource information is provided below:
 
Average Cost (cents per kWh)
 
Percentage of Total kWh Resources
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Coal
2.44

 
2.41

 
2.30

 
44
%
 
54
%
 
62
%
Natural Gas
2.54

 
3.06

 
2.84

 
42
%
 
23
%
 
25
%
Purchased Power, Non-Renewable
4.32

 
3.78

 
3.43

 
10
%
 
18
%
 
8
%
Purchased Power, Renewable
9.41

 
9.49

 
9.37

 
4
%
 
5
%
 
5
%
 
 
 
 
 
 
 
100
%
 
100
%
 
100
%
Coal Supply
The coal used for 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 $2.33 in 2018, $2.29 in 2017, and $2.21 in 2016.
Station
 
Coal Supplier
 
2018 Coal Consumption (tons in 000s)
 
Contract Expiration Date
 
Average Sulfur Content
 
Coal Obtained From
Springerville
 
Peabody CoalSales
 
2,946
 
2020
 
1.0%
 
Lee Ranch Mine/El Segundo Mine
Four Corners
 
NTEC
 
299
 
2031
 
0.7%
 
Navajo Mine
San Juan
 
San Juan Coal Co.(1)
 
410
 
2022
 
0.8%
 
San Juan Mine
Navajo
 
Peabody CoalSales
 
386
 
2019
 
0.6%
 
Kayenta Mine
(1) 
In October 2018, Westmoreland Coal Company (WCC), the owner of San Juan Coal Company (SJCC), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. TEP believes it has adequate resource capacity to meet its near-term load obligations in the event WCC’s operations at the San Juan Mine are curtailed. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding WCC's bankruptcy.
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.

6

Coal-Fired Generation Facilities Operated by Others
TEP also participates in jointly-owned coal-fired generation facilities at Four Corners Generating Station (Four Corners), Navajo, and 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 railroad delivery system. 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
The table below provides information on the natural gas transportation agreements that deliver our natural gas to the generation stations. The average cost of natural gas per MMBtu, including transportation, was $2.92 in 2018, $3.58 in 2017, and $3.14 in 2016.
Station
 
Natural Gas Transportation Counterparty
 
Contract Expiration Date(s)
Gila
 
Transwestern Pipeline Co./El Paso Natural Gas Company, LLC
 
2019-2040
Luna
 
El Paso Natural Gas Company, LLC
 
2022
Sundt
 
El Paso Natural Gas Company, LLC
 
2023-2040
DeMoss Petrie
 
Southwest Gas Corporation
 
Retail Tariff
North Loop
 
Southwest Gas Corporation
 
Retail Tariff
Transmission and Distribution
Transmission facilities owned by TEP and third parties are located in Arizona and New Mexico and transmit the output from TEP’s electric generation facilities to the Tucson area. 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. TEP's transmission and distribution systems included approximately 2,189 miles of transmission lines and 7,680 miles of distribution lines as of December 31, 2018.
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 TEP's 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 Form 10-K for additional information that relates to rates and regulation that affect TEP.
TEP Rate Case
The ACC issued orders in the rate case filed by TEP in November 2015, which was based on a test year ended June 30, 2015, in two phases. Provisions of the first phase authorized an annual increase in TEP's non-fuel revenue requirement of $81.5 million, effective February 27, 2017 (2017 Rate Order). The ACC deferred matters related to net metering and rate design for new DG customers to a second phase of TEP's rate case proceedings (Phase 2).
In 2018, the ACC issued an order establishing an export rate that replaced net metering for excess solar generation, effective October 1, 2018 (Phase 2 Order). Residential and small commercial customers who apply to interconnect their solar generation systems to TEP's distribution system after the date of the order will no longer qualify for net metering.
Purchased Power and Fuel Adjustment Clause
The Purchased Power and Fuel Adjustment Clause (PPFAC) allows TEP recovery of its fuel, transmission, purchased power, and other similar costs allowed by the ACC to serve its retail load. The rate is adjusted annually each April 1st for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs

7

established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.
As of December 31, 2018, TEP had an over-collected PPFAC balance of $17 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. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism.
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. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism. As of December 31, 2018, TEP’s cumulative annual energy savings was approximately 16%.
FERC Compliance
In 2016, the FERC issued orders relating to certain late-filed Transmission Service Agreements (TSA), which resulted in TEP recording a liability and paying time-value refunds to the counterparties under these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to FERC compliance associated with these transmission contracts.
ENVIRONMENTAL MATTERS
The Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2), particulate matter, mercury, and other by-products produced by generation facilities. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its generation facilities. Environmental laws and regulations are subject to a 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 the recovery of 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 an area does not meet the standard, the area is designated as a “non-attainment” and needs to develop a plan to bring the air-shed into compliance. A “non-attainment” designation may slow economic growth in the region and impact TEP's ability to site new local generation. Arizona submitted recommendations for area designations (attainment, non-attainment, or unclassified) to the EPA in September 2016. The EPA completed all area designations as of July 2018. The majority of Arizona counties, including Pima, were designated as "attainment" or "unclassified" except for portions of Gila, Maricopa, Pinal, and Yuma counties.
In 2018, Pima County exceeded the 2015 NAAQS standard for O3 at one monitoring location. If the county continues to exceed the standard, the state could recommend an O3 non-attainment designation for Pima County during the next review period.
Effluent Limitation Guidelines
In 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 wastewater discharges. The ELG rule establishes new or additional requirements for wastewater streams associated with fly ash, bottom ash, flue gas desulfurization, flue gas mercury control, and gasification of fuels such as coal and petroleum coke. In August 2017, in response to legal challenges, the EPA announced it began rulemaking proceedings to potentially revise the 2015 ELGs. In September 2017, the EPA postponed the earliest ELG compliance date for these waste streams from November 1, 2018 until November 1, 2020.
With the exception of Four Corners, none of TEP's owned steam electric generation facilities are subject to the ELG standards. With regard to Four Corners, until the EPA indicates how it intends to change the ELG for bottom ash transport water, it is unclear how the reconsideration will affect this waste stream, and what controls may be required.

8

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, Liquidity and Capital Resources of this Form 10-K for additional information related to environmental laws and regulations as well as environmental compliance capital expenditures.
EMPLOYEES
As of December 31, 2018, TEP had 1,528 employees, of which approximately 634 are represented by the International Brotherhood of Electrical Workers Local No. 1116 (IBEW). The current collective bargaining agreements between the IBEW and TEP expire in July 2022 with wages in effect through December 2022.
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 1, 2019, are as follows:
Name
 
Age
 
Position(s) Held
 
Executive Officer Since
David G. Hutchens (1)
 
52
 
President and Chief Executive Officer
 
2007
Frank P. Marino (1)
 
54
 
Senior Vice President and Chief Financial Officer
 
2013
Susan M. Gray
 
46
 
Senior Vice President and Chief Operating Officer
 
2015
Erik B. Bakken
 
46
 
Vice President, System Operations and Environmental
 
2018
Dallas J. Dukes
 
51
 
Vice President, Energy Programs and Pricing
 
2019
Todd C. Hixon (1)
 
52
 
Vice President, General Counsel and Chief Compliance Officer
 
2011
Mark C. Mansfield
 
63
 
Vice President, Energy Resources
 
2012
Catherine E. Ries
 
59
 
Vice President, Customer and Human Resources
 
2007
Mary Jo Smith
 
61
 
Vice President, Public Policy
 
2015
Morgan C. Stoll
 
48
 
Vice President and Chief Information Officer
 
2016
Martha B. Pritz 
 
57
 
Treasurer
 
2017
Herlinda H. Kennedy
 
57
 
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.
SEC REPORTS AVAILABLE
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). The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. TEP's reports are also available free of charge through TEP’s website address at www.tep.com/about/investors/.
TEP is providing the address of TEP’s website solely for the information of investors and does not intend for the address to be an active link. The information contained on TEP’s website is not a part of, or incorporated by reference into, any report or other filing filed with the SEC by TEP.


9

ITEM 1A. 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 negatively impact TEP’s business and financial results.
REVENUES
A significant decrease in the demand for electricity in TEP's service area would negatively impact retail sales and adversely affect results of operations, net income, and cash flows at TEP.
National and local economic conditions have a significant impact on customer growth and overall retail sales in TEP’s service area. TEP anticipates an annual customer growth rate of 1% for the next five years.
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 continue to have a negative impact on TEP’s use per customer and overall retail sales. TEP's use per customer declined by an average of 1% per year from 2014 through 2018.
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, first quarter net income is typically limited by relatively mild winter weather in TEP's 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 results of operations, net income, and cash flows at TEP.
TEP’s ten largest customers represented 11% of total revenues in 2018. 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 the Company's results of operations, net income, and cash flows.
REGULATORY
TEP's business is significantly impacted by government legislation, regulation and oversight. Changes made to legislation and regulation could negatively affect the Company’s results of operations, net income, and cash flows.
TEP's financial condition is influenced by how regulatory authorities, including the ACC and FERC, establish the rates TEP can charge customers and authorize rates of return, common equity levels, and the amount of costs that may be recovered from customers. The Company's ability to timely obtain rate adjustments that provide TEP with the opportunity to earn authorized rates of return depends upon timely regulatory action under applicable statutes and regulations, and cannot be guaranteed.
•
ACC—The ACC is a constitutionally created body composed of five elected commissioners that has jurisdiction over rates for retail customers. Commissioners are elected state-wide for staggered four-year terms and are limited to serving two consecutive terms. As a result, the composition of the commission, and therefore its policies, are subject to change every two years.
•
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.
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.

10


In addition, TEP incurs costs to comply with legislative and regulatory requirements and initiatives, such as those relating to clean energy requirements, the deployment of distributed energy resources, and implementation of demand response and customer energy efficiency programs. New initiatives or changes to existing requirements could arise in the future through legislative, regulatory, or other initiatives (including ballot initiatives) on either a federal or state level. Any such initiatives or changes could accelerate the Company's long-term resource diversification strategy and significantly increase capital expenditures and operating expenses. TEP would seek to recover the costs associated with any such requirements through rates. TEP's ability to recover costs, including its investments, associated with these and other legislative and regulatory initiatives will, in large part, depend on the final form of legislative or regulatory requirements, and whether the associated ratemaking mechanisms can be adjusted in a timely manner. Further, increases to rates could negatively affect the affordability of the rates charged to customers, which may negatively affect TEP’s results of operations, net income, and cash flows.
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.
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 coal 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 the Company's 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 Regulations (Regional Haze) 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 facilities. Additionally, these regulations may jeopardize continued generation facility operations or the ability of individual participants to meet their obligations and willingness to continue their participation in these facilities potentially resulting in an increased operational cost for the remaining participants.
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.
Regulations limiting greenhouse gas emissions may be enacted, which would require an accelerated shift from fossil fuel-based generation to renewable generation that 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 fuel-based generation facilities. In its current form, the CPP requires a shift in generation that could lead to the early retirement of coal-fired generation in Arizona and New Mexico. In 2017, the EPA issued a proposal to repeal the CPP and in 2018 published the proposed Affordable Clean Energy rule that is meant to replace the CPP. The EPA anticipates finalizing the rule in early 2019. Under the proposed rule, the EPA would set emission guidelines for Greenhouse Gas (GHG) emissions. The states would then use these emission guidelines to establish standards of performance within their jurisdictions considering source specific factors such as the remaining useful life of an individual unit. TEP will continue to work with other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies. TEP is unable to determine the impact the final rule will have on its facilities until all legal challenges have been resolved and the required state compliance plans are

11


developed and approved by the EPA. The proposed rule and any other regulations that result in costs associated with an accelerated shift from fossil fuel-based generation towards renewable generation could increase the Company's costs of operations.
FINANCIAL
Early closure of TEP's coal-fired generation facilities could result in TEP recognizing regulatory impairments or increased cost of operations if recovery of TEP's remaining investments in such facilities and the costs associated with early closures are not permitted through rates charged to customers.
Some of TEP's coal-fired generation facilities will be closed before the end of their useful lives in response to economic conditions and/or recent or future changes in environmental regulation, including potential regulation relating to greenhouse gas emissions. If any of the coal-fired generation facilities from which TEP obtains power are closed prior to the end of their useful life, TEP may need to seek recovery of the remaining net book value (NBV) and could incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation and cancellation of long-term coal contracts of such generation facilities. As of December 31, 2018, TEP's regulatory assets balance related to its planned early generation retirement costs was $72 million.
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 or bank 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 bank markets and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flows from TEP's operations. Market disruptions such as those experienced in 2008 and 2009 in the United States and abroad may increase the Company's cost of borrowing or negatively affect TEP's ability to access sources of liquidity needed to finance the Company's operations and satisfy its 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, and general economic downturns in TEP's utility service territories. If TEP is unable to access credit at reasonable rates, or if the Company's borrowing costs dramatically increase, TEP's ability to finance its operations, meet debt obligations, and execute its financial strategy could be negatively affected.
Increases in short-term interest rates would increase the cost of borrowings under TEP's credit facility. In addition, changing market conditions could negatively affect the market value of assets held in its pension and other postretirement defined benefit 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, which 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, 2018, there were outstanding approximately $272 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 early redemption by TEP. The bonds have early redemption dates or final maturities ranging from 2019 to 2022.
In addition, as of December 31, 2018, there were outstanding approximately $207 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. The bonds have early redemption dates ranging from 2020 to 2023.

12


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 the Company's business and can cause damage to its reputation. If TEP’s generation facilities or transmission and distribution systems operate below expectations, TEP’s operating results could be negatively affected or TEP's capital spending could be increased.
TEP receives power from certain generation facilities that are jointly-owned with, or 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 operated by, third parties. TEP does not have the sole discretion 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 such generation facilities. Further, TEP may have limited ability to determine how best to manage the changing economic conditions or environmental requirements that 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.
The effects of climate change may create operational and financial risks for TEP that, if realized, could negatively affect TEP's results of operations, net income, and cash flows.
Climate change may impact regional and global weather conditions and result in extreme weather events, including high temperatures, severe thunderstorms, drought, and wildfires. Changes in weather conditions or extreme weather events in TEP’s service territory or affecting TEP's remote generation facilities or transmission system may lead to service outages and business interruptions, which could result in an increase in capital expenditures and operating expenses. Any increases in severity and frequency of weather-related system outages could affect TEP's operations and system reliability. Although physical utility assets have been constructed and are operated and maintained to withstand severe weather, there can be no assurance that they will successfully do so in all circumstances. In addition, changes in weather conditions or extreme weather events outside of TEP's service territory could result in higher wholesale energy prices, insurance premiums, and other costs, which could negatively impact TEP's business and operations. Any of these situations could have a negative impact on TEP's results of operations, net income, and cash flows.
TEP is 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 is facing a heightened risk of physical attacks on the Company's electric systems. The Company's 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 TEP's security measures, a significant physical attack occurred, the Company could have: (i) operations disrupted and/or property damaged; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations.
TEP is subject to cyber-attacks which could have a negative impact on the Company's business and results of operations.
TEP is facing 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: (i) operations disrupted, property damaged, and customer information stolen; (ii) experience loss of revenues, response costs, and other

13


financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 2. PROPERTIES
The principal owned and leased generation, distribution, and transmission facilities of TEP are described in Part I, Item 1. Business, Overview of Business and such descriptions are incorporated herein by reference.
TEP's generation facilities (except as noted below), administrative headquarters, warehouses and service centers are located on land owned by TEP. TEP owned distribution and transmission facilities are located: (i) on property owned by TEP; (ii) under or over streets, alleys, highways, and other places in the public domain, as well as in national forests and state lands, under franchises, land easements, or other rights-of-way, which generally are subject to termination; (iii) under or over private property as a result of land easements obtained primarily from the record holder of title; or (iv) over tribal lands under the grant of easement by the Secretary of the Interior or leased from Indian Nations.
TEP has land easements for transmission facilities related to San Juan, Four Corners, and Navajo located on tribal lands of the Zuni, Navajo, and Tohono O’odham Nations. Four Corners and Navajo are located on properties held under land easements from the United States and under leases from the Navajo Nation. TEP, individually and in conjunction with PNM, acquired land rights, land easements, and leases for San Juan's generation facilities, transmission lines, and water diversion facility located on land owned by the Navajo Nation. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna Generating Station (Luna) is located.
TEP’s rights under various land easements and leases may be subject to defects such as:
•
possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs and the Indian Nations;
•
possible inability of TEP to legally enforce its rights against adverse claims and the Indian Nations without Congressional consent; or
•
failure or inability of the Indian Nations to protect TEP’s interests in the land easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claims.
These possible defects have not interfered, and are not expected to materially interfere, with TEP’s interest in and operation of its facilities.

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 operations or 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 8 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.

14


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.

ITEM 6. SELECTED FINANCIAL DATA
The following table provides selected financial data for the years 2014 through 2018:
(in thousands)
2018
 
2017
 
2016
 
2015
 
2014
Income Statement Data
 
 
 
 
 
 
 
 
 
Operating Revenues
$
1,432,618

 
$
1,340,935

 
$
1,234,995

 
$
1,306,544

 
$
1,269,901

Net Income
188,323

 
176,668

 
124,438

 
127,794

 
102,338

Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total Utility Plant, Net
$
4,160,640

 
$
3,768,702

 
$
3,782,806

 
$
3,558,229

 
$
3,425,190

Total Assets
5,159,207

 
4,590,249

 
4,449,989

 
4,249,478

 
4,119,830

Long-Term Debt, Net
1,615,252

 
1,354,423

 
1,453,072

 
1,451,720

 
1,361,828

Non-Current Capital Lease Obligations
19,773

 
28,519

 
39,267

 
55,324

 
69,438



15


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 financial condition, and the outlook for TEP. It includes the following:
•
outlook and strategies;
•
results of operations for 2018 compared with 2017, and 2017 compared with 2016;
•
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
•
new accounting standards issued and not yet adopted.
Management’s Discussion and Analysis includes financial information prepared in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America.
Management’s Discussion and Analysis should be read in conjunction with Part II, 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: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory and legislative actions. Our plans and strategies include the following:
•
Achieving constructive outcomes in our regulatory proceedings that will provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe and reliable service.
•
Continuing to focus on our long-term resource diversification strategy, including transitioning from carbon intensive sources to a more sustainable energy portfolio, 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. This resource strategy may be impacted by various energy policy proposals currently under consideration in Arizona.
•
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
For 2018, Management's Discussion and Analysis includes the following notable items:
•
The ACC Refund Order, reflecting the lower federal income tax rate, was approved and resulted in a total customer refund of $33 million in 2018. The refund was returned to customers through a bill credit effective May 1, 2018. TEP will continue to return savings to customers through a combination of a bill credit and a regulatory liability in 2019 and through the completion of our next rate case, which is expected to be filed in April 2019.
•
We responded to the FERC Refund Order with a proposed overall transmission rate reduction, reflecting the lower federal income tax rate. The FERC approved our proposal effective March 21, 2018. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
•
As a result of SRP completing the Gila Acquisition, TEP had $164 million recorded in Capital Lease Obligations and Utility Plant Under Capital Leases on the Consolidated Balance Sheets as of December 31, 2018, related to the 20-

16


year Tolling PPA. The amount represents the fair value of the unit, which was determined based on SRP's purchase price. The additional 550 MW of capacity, power, and ancillary services will allow us to continue to move toward our long-term goal of resource diversification.
•
The ACC issued the Phase 2 Order. The order established, among other things, an initial export rate that replaced net metering for excess solar generation for customers who applied for interconnection to TEP's distribution system after the date of the order. The new rate went into effect October 1, 2018.
•
TEP issued and sold $300 million aggregate principal amount of senior unsecured notes and redeemed $137 million of variable rate tax-exempt bonds. As of December 31, 2018, all of TEP's debt was unsecured.
RESULTS OF OPERATIONS
Weather and other factors cause seasonal fluctuations in the sales of power. TEP's summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during such period. By contrast, lower sales of power occur during the first quarter of the year, due to mild winter weather in our retail service territory. Seasonal fluctuations affect the comparability of our results of operations across quarters.

The following provides a discussion of the significant items that affected TEP's results of operations in years ended December 31, 2018, 2017, and 2016, presented on an after-tax basis.
2018 compared with 2017
TEP reported net income of $188 million in 2018 compared with $177 million in 2017. The increase of $11 million, or 6%, was primarily due to:
•
$41 million in lower income tax expense due to the reduction of the federal effective income tax rate primarily related to the enactment of the TCJA. See Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA;
•
$12 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017; and
•
$3 million in higher Allowance for Funds Used During Construction (AFUDC) related to the increase in construction projects.
The increase was partially offset by:
•
$27 million in lower retail revenue associated with the ACC Refund Order to return savings related to the TCJA to customers. The order was effective May 1, 2018. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the ACC Refund Order;
•
$8 million in lower income from a settlement agreement and reversal of accrued refunds related with late-filed TSAs in 2017. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs;
•
$8 million in higher depreciation and amortization expenses; and
•
$7 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense related to planned generation outages in 2018 and an increase in employee wages and benefits expense.
2017 compared with 2016
TEP reported net income of $177 million in 2017 compared with $124 million in 2016. The increase of $53 million, or 43%, was primarily due to:
•
$52 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017, and favorable weather;
•
$21 million in higher net income due to time-value FERC ordered refunds incurred in 2016 and the reversal of accrued refunds in 2017 related to late-filed TSAs. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs; and

17

•
$6 million in higher wholesale revenue primarily due to favorable pricing on wholesale contracts in 2017.
The increase was partially offset by:
•
$8 million in lower revenues related to the Springerville Unit 1 settlement in 2016. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the settlement;
•
$7 million in higher income tax expense primarily due to the enactment of the TCJA in 2017 as well as changes to our valuation allowance for deferred tax assets in 2016. See Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA on our financial results;
•
$6 million in higher depreciation and amortization expenses; and
•
$4 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense due to planned generation outages in 2017 and employee wages and benefits.
Retail Revenues and Key Statistics
The following table provides key statistics impacting operating revenues:
 
Years Ended
December 31,
 
Increase (Decrease)
 
Year Ended
December 31,
 
Increase (Decrease)
($ and kWh in millions)
2018
 
2017
 
Percent
 
2016
 
Percent
Operating Revenues
$
1,433

 
$
1,341

 
6.9
 %
 
$
1,235

 
8.6
 %
 
 
 
 
 
 
 
 
 
 
Electric Sales (kWh)
 
 
 
 
 
 
 
 
 
Residential
3,766

 
3,786

 
(0.5
)%
 
3,724

 
1.7
 %
Commercial
2,136

 
2,192

 
(2.6
)%
 
2,139

 
2.5
 %
Industrial
1,949

 
1,939

 
0.5
 %
 
2,006

 
(3.3
)%
Mining
1,033

 
991

 
4.2
 %
 
997

 
(0.6
)%
Public Authorities
16

 
18

 
(11.1
)%
 
30

 
(40.0
)%
Total Retail Sales
8,900

 
8,926

 
(0.3
)%
 
8,896

 
0.3
 %
Wholesale Sales, Long-Term
424

 
587

 
(27.8
)%
 
463

 
26.8
 %
Wholesale Sales, Short-Term
6,279

 
3,630

 
73.0
 %
 
3,308

 
9.7
 %
Total Electric Sales
15,603

 
13,143

 
18.7
 %
 
12,667

 
3.8
 %
 
 
 
 
 
 
 
 
 
 
Average Revenue per kWh (Cents/kWh)
 
 
 
 
 
 
 
 
 
Retail
11.48

 
11.39

 
0.8
 %
 
10.92

 
4.3
 %
Wholesale
3.46

 
3.21

 
7.8
 %
 
2.80

 
14.6
 %
 
 
 
 
 


 
 
 
 
Total Retail Customers
425,044

 
422,366

 
0.6
 %
 
419,844

 
0.6
 %
Operating Revenues increased in 2018 compared with 2017 primarily due to: (i) an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2; (ii) an increase in revenue from fuel and purchased power recoveries as a result of higher PPFAC rates; and (iii) higher retail revenues related to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017. The increase was partially offset by: (i) the return of savings related to the TCJA to customers; (ii) a 2017 reversal of an accrual related to the FERC ordered refunds for late-filed TSAs; and (iii) a decrease in billings to third-party participants in Springerville Units 3 and 4 primarily related to planned generation outages of Unit 4 in 2017.
Operating Revenues increased in 2017 compared with 2016 primarily due to: (i) higher retail revenues related to an increase in rates as approved in the 2017 Rate Order and an increase in usage due to favorable weather in 2017; (ii) time-value FERC ordered refunds incurred in 2016 and the reversal of accrued refunds in 2017 related to late-filed TSAs; (iii) an increase in short-term wholesale sales resulting from favorable commodity pricing on the wholesale market; and (iv) a new long-term wholesale contract that commenced in 2017. The increase was partially offset by a decrease in revenue from fuel and purchased power recoveries as a result of lower PPFAC rates.

18

Short-term wholesale revenues are primarily related to the ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC. Revenues related to Springerville Units 3 and 4 are primarily reimbursements by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with the corresponding expense recorded in Operating Expenses on the Consolidated Statements of Income.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the PPFAC mechanism.
Operating Expenses
Fuel and Purchased Power Expense
Fuel and Purchased Power Expense, which includes the PPFAC recovery treatment, increased by $118 million, or 28%, in 2018 compared with 2017 primarily due to an increase in: (i) generation output; (ii) recovery of PPFAC costs as a result of changes in the PPFAC rate; and (iii) the average cost of Purchased Power, Non-Renewables. The increase was partially offset by a decrease in: (i) Purchased Power, Non-Renewable volumes; and (ii) the average cost of Natural Gas.
Fuel and Purchased Power Expense, which includes the PPFAC recovery treatment, increased by $5 million, or 1%, in 2017 compared with 2016 primarily due to an increase in: (i) Purchased Power, Non-Renewables volumes that replaced lower Coal-Fired Generation output; and (ii) average fuel cost per kWh. The increase was partially offset by reduced recovery of the PPFAC costs as a result of changes in the PPFAC rate.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the PPFAC mechanism.
The following table presents TEP's sources of energy and average cost of power by type:
 
Years Ended December 31,
 
Increase (Decrease)
 
Year Ended December 31,
 
Increase (Decrease)
(kWh in millions)
2018
 
2017
 
Percent
 
2016
 
Percent
Sources of Energy
 
 
 
 
 
 
 
 
 
Coal-Fired Generation
7,208

 
7,530

 
(4.3
)%
 
8,310

 
(9.4
)%
Gas-Fired Generation
6,738

 
3,237

 
108.2
 %
 
3,283

 
(1.4
)%
Utility-Owned Renewable Generation
82

 
83

 
(1.2
)%
 
68

 
22.1
 %
Total Generation
14,028

 
10,850

 
29.3
 %
 
11,661

 
(7.0
)%
Purchased Power, Non-Renewable
1,624

 
2,471

 
(34.3
)%
 
1,126

 
119.4
 %
Purchased Power, Renewable
652

 
646

 
0.9
 %
 
666

 
(3.0
)%
Total Generation and Purchased Power
16,304

 
13,967

 
16.7
 %
 
13,453

 
3.8
 %
(cents per kWh)
 
 
 
 
 
 
 
 
 
Average Fuel Cost of Generated Power
 
 
 
 
 
 
 
 
 
Coal
2.44

 
2.41

 
1.2
 %
 
2.30

 
4.8
 %
Natural Gas
2.54

 
3.06

 
(17.0
)%
 
2.84

 
7.7
 %
Average Cost of Purchased Power
 
 
 
 
 
 
 
 
 
Purchased Power, Non-Renewable
4.32

 
3.78

 
14.3
 %
 
3.43

 
10.2
 %
Purchased Power, Renewable
9.41

 
9.49

 
(0.8
)%
 
9.37

 
1.3
 %
Operations and Maintenance Expense
Operations and Maintenance Expense increased by $2 million, or less than 1%, in 2018 compared with 2017 primarily due to: (i) an increase in maintenance expense related to planned generation outages; (ii) an increase in employee wages and benefits expense; and (iii) a sales tax refund that occurred in 2017. The increase was partially offset by a decrease in: (i) maintenance expense at Springerville Units 3 and 4; (ii) RES and DSM program expenses; and (iii) other general expenses.
Operations and Maintenance Expense increased by $6 million, or 2%, in 2017 compared with 2016 primarily due to an increase in: (i) maintenance expense related to planned generation outages; and (ii) employee wages and benefits expense. The increase was partially offset by a decrease in RES and DSM program expenses.

19

Operations and Maintenance Expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with corresponding amounts recorded in Operating Revenues on the Consolidated Statements of Income. Expenses related to RES and DSM programs are collected from customers with corresponding amounts recorded in Operating Revenues on the Consolidated Statements of Income.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on RES and DSM.
Depreciation and Amortization Expense
Depreciation and Amortization Expense increased by $9 million, or 5%, in 2018 compared with 2017 primarily due to an increase in asset base.
Depreciation and Amortization Expense increased by $7 million, or 4%, in 2017 compared with 2016 primarily due to an increase in capital expenditures and other impacts as a result of the 2017 Rate Order.
Other Income (Expense)
Other Income (Expense) decreased by $8 million, or 16%, in 2018 compared with 2017 primarily due to proceeds received from a settlement agreement related to late-filed TSAs in 2017.
Other Income (Expense) increased by $10 million, or 18%, in 2017 compared with 2016 primarily due to proceeds received from a settlement agreement related to late-filed TSAs in 2017.
See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to late-filed TSAs.
Income Tax Expense
Income Tax Expense decreased by $58 million, or 57%, in 2018 compared with 2017 primarily due to: (i) the reduction of the federal corporate income tax rate related to the enactment of the TCJA; and (ii) a decrease in earnings before tax expense.
Income Tax Expense increased by $41 million, or 70%, in 2017 compared with 2016 primarily due to: (i) the increase in earnings before tax expense; (ii) the enactment of the TCJA in December 2017; and (iii) a reduction in the valuation allowance for deferred tax assets in 2016.
See Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to impacts of the TCJA on our financial results.
FACTORS AFFECTING RESULTS OF OPERATIONS
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters.
TEP Rate Case
Provisions of the 2017 Rate Order, which were effective February 27, 2017, include, but are not limited to:
•
a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and a cost of debt component of 4.32%; and
•
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2.
Phase 2 Order
On September 20, 2018, the ACC issued an order related to the Phase 2 proceedings. The Phase 2 Order established, among other things, an export rate that replaced net metering for excess solar generation. Residential and small commercial customers who applied to interconnect their solar generating systems to TEP's distribution system after the date of the order no longer qualify for net metering. Customers who applied before the date of the order, and complete interconnection within a specified

20

time frame, were grandfathered under previous net metering rules for a period of 20 years from the date of interconnection of their solar generation systems. Provisions of the Phase 2 Order for new DG customers include:
•
an option to select from existing Time-of-Use rate schedules;
•
a monthly bill credit for customer solar generation exported to TEP's grid calculated using an export rate approved by the ACC; and
•
an annual update to the export rate based on TEP's actual solar PPA and generation facilities costs, which are expected to decline. The export rate at the time of customers' applications to interconnect will be locked for 10 years. The initial export rate was set at 9.64 cents per kWh.
The new DG customers will receive bill credits for their solar generation exported into our grid. These bill credits will be calculated using the export rate approved by the ACC and will be recorded in Purchased Power on the Consolidated Statements of Income. We expect to recover these costs through the PPFAC up to an amount equal to market prices with any remaining cost being recovered through the RES surcharge. In addition, TEP's power sales to the new DG customers will be calculated based on the respective Time-of-Use rate and will be recorded in Operating Revenues on the Consolidated Statements of Income. DG customers grandfathered under the net metering rules will continue to have their solar generation netted against the kWhs they consume. The net sales are recorded in Operating Revenues on the Consolidated Statements of Income.
TEP does not expect the change resulting from the replacement of net metering to have a material impact on the Company's results of operations in the near term. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the Phase 2 Order.
Federal Income Tax Legislation
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved the ACC Refund Order effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of Excess Deferred Income Taxes (EDIT) amortization trued up annually for actuals. For 2018, the refund amount, after the EDIT amortization true-up, totaled $33 million. The 2018 bill credit was designed to return the refund amount to customers based on forecasted kWh sales. Any over or under collected amounts are deferred to a regulatory asset or liability and will be used to adjust the 2019 bill credit amounts.
Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP filed an application with the ACC to establish the 2019 customer refund of $34 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019. TEP is allowed to defer 25% of the 2019 refund into a regulatory liability and 50% of any additional refunds in future years until the refunds are incorporated into its next rate case. TEP plans to file its next rate case in April 2019.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 and Liquidity and Capital Resources, Income Tax Position of this Form 10-K for additional information regarding the ACC Refund Order.
Federal Energy Regulatory Commission
In 2018, the FERC issued orders directing TEP to either: (i) submit proposed revisions to its stated transmission rates or stated transmission revenue requirements to reflect the change in the federal corporate income tax rate as a result of the TCJA; or (ii) show cause why it should not be required to do so (FERC Refund Order). In May 2018, TEP responded to the order and the FERC approved TEP's proposal of an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, to be effective March 21, 2018. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
Also in 2018, the FERC issued a Notice of Proposed Rulemaking (NOPR) regarding the effect of the TCJA and related EDIT amortization. TEP cannot predict the final outcome of the NOPR or the impact on TEP's financial statements.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the FERC Refund Order and the NOPR.

21

Generation Resources
TEP’s long-term strategy is to shift to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. TEP's existing coal-fired generation fleet faces a number of uncertainties impacting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.
As of December 31, 2018, approximately 40% of our generation capacity, including owned and leased resources, was from coal-fired generation.
See Part I, Item 1. Business, Overview of Business and Liquidity and Capital Resources, Environmental Matters of this Form 10-K for additional information regarding generation facility operations.
Arizona Energy Policy
In August 2018, the ACC opened a rulemaking docket to evaluate several energy policies. The docket will review possible modifications to existing renewable energy, energy efficiency requirements, and retail competition for generation services. The adoption of new policies would be subject to rulemaking proceedings at the ACC. We would seek the ACC's approval to recover any costs related to any new energy policies or requirements. TEP cannot predict the outcome of this matter or the impact on the Company's financial position or results of operations.
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. We are currently recovering Navajo capital and operating costs in base rates using a useful life through 2030. We plan to seek recovery of all unrecovered costs in our next ACC rate case, which is expected to be filed in April 2019.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the planned early retirement of Navajo.
Sundt Generating Station
In 2017, TEP submitted an Air Quality Permit Application to the Pima County Department of Environmental Quality related to a generation modernization project at Sundt (PDEQ Application). Under the project, TEP will place in service 10 natural gas RICE units with a total nominal generation capacity of 190 MW. The final permit was issued in December 2018. Construction is underway with the RICE units scheduled for commercial operation by the end of the first quarter of 2020.
The RICE units will balance the variability of intermittent renewable energy resources and will replace 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which are less efficient and lack the quick start, fast ramp capabilities of the RICE units. TEP will discontinue operation of Sundt Units 1 and 2 prior to start-up of the first RICE unit. We plan to seek recovery of all unrecovered costs for Sundt Units 1 and 2 in our next ACC rate case.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the planned early retirement of Sundt Units 1 and 2.
Gila River Generating Station
In 2017, TEP entered into the Tolling PPA, which includes a three-year option to purchase Gila River Unit 2. TEP’s obligations under the agreement were contingent upon SRP's completion of acquisition of Gila River Units 1 and 2 from third-parties (Gila Acquisition). SRP completed the Gila Acquisition in May 2018. As a result, TEP had $164 million recorded in both Capital Lease Obligations and Utility Plant Under Capital Leases on the Consolidated Balance Sheets as of December 31, 2018. The amount reflects the fair value of the unit, which was determined based on SRP's purchase price. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $164 million. Over the expected 20-month lease term, TEP will pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2. TEP recovers the monthly capacity charge and operating fee through the PPFAC.

22

The additional 550 MW of capacity, power, and ancillary services from the Tolling PPA will allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduled for early retirement. TEP sells the capacity from the Tolling PPA into the wholesale market on a short-term basis with the associated revenues credited to the PPFAC.
See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the Tolling PPA.
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 being typically the lowest in the first quarter of the year and highest in the third quarter due to TEP’s summer peaking load. We use our revolving credit facility as needed to assist in funding our 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 we have access to external financing depends on a variety of factors, including our credit ratings and conditions in the overall capital markets.
Available Liquidity
(in millions)
December 31, 2018
Cash and Cash Equivalents
$
138

Amount Available under Revolving Credit Facility (1)
250

Total Liquidity
$
388

(1) 
TEP's revolving credit facility provides for $250 million of revolving credit commitments with a Letter of Credit (LOC) sublimit of $50 million and a maturity date of October 2022.
Future Liquidity Requirements
We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to: (i) dividend payments; (ii) debt maturities; and (iii) obligations included in the Contractual Obligations and forecasted Capital Expenditures tables below.
See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk for additional information regarding TEP's market risks and Note 7 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)
2018
 
2017
 
Percent
 
2016
 
Percent
Operating Activities
$
457

 
$
448

 
2.0
%
 
$
425

 
5.4
 %
Investing Activities
(433
)
 
(392
)
 
10.5
%
 
(373
)
 
5.1
 %
Financing Activities
79

 
(50
)
 
258.0
%
 
(69
)
 
(27.5
)%
Net Increase (Decrease)
103

 
6

 
*

 
(17
)
 
*

Beginning of Period
50

 
43

 
16.3
%
 
60

 
(28.3
)%
End of Period (1)
$
153

 
$
49

 
212.2
%
 
$
43

 
14.0
 %
* Not meaningful
(1) 
Calculated on rounded data and may not correspond exactly to amounts on the Consolidated Statements of Cash Flows.

23

Operating Activities
2018 compared with 2017
Net cash flows provided by operating activities increased by $9 million compared with 2017 primarily due to: (i) higher retail revenues related to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017; (ii) an increase in cost recovery as a result of higher PPFAC rates; and (iii) changes in working capital related to the timing of billing collections and payments. The increase was partially offset by: (i) the return of savings related to the TCJA to customers; and (ii) $8 million in cash proceeds received from a settlement agreement associated with late-filed TSAs in January 2017.
2017 compared with 2016
Net cash flows provided by operating activities increased by $23 million compared with 2016 primarily due to: (i) higher retail revenue related to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017, and favorable weather; and (ii) $8 million in cash proceeds received from a settlement agreement associated with late-filed TSAs in January 2017. The increase was partially offset by: (i) an ACC approved PPFAC credit that began returning an over-collected PPFAC balance to customers in February 2017; (ii) $12.5 million received in September 2016 related to a settlement for operating costs of Springerville Unit 1; and (iii) changes in working capital related to the timing of billing collections and payments.
See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the 2017 Rate Order, the ACC Refund Order, and cost recovery mechanisms and Note 8, for additional information regarding Springerville Unit 1 and late-filed TSAs.
Investing Activities
2018 compared with 2017
Net cash flows used for investing activities increased by $41 million compared with 2017 primarily due to an increase in cash paid for capital expenditures.
2017 compared with 2016
Net cash flows used for investing activities increased by $19 million compared with 2016 primarily due to an increase in cash paid for: (i) capital expenditures; and (ii) the purchase of RECs.
Financing Activities
2018 compared with 2017
Net cash flows from financing activities increased by $129 million compared with 2017 primarily due to an increase in: (i) proceeds received from the issuance of long-term debt net of repayments; and (ii) equity contributions from UNS Energy. The increase was partially offset by an increase in: (i) repayments, net of proceeds borrowed, under our revolving credit facility; and (ii) dividends paid to UNS Energy.
2017 compared with 2016
Net cash flows from financing activities decreased by $19 million compared with 2016 primarily due to an increase in proceeds borrowed, net of repayments, under our revolving credit facility. The decrease was partially offset by an increase in dividends paid to UNS Energy.
See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, Debt Issuance and Redemption for additional information.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of December 31, 2018, TEP's short-term investments included highly-rated and liquid money market funds, certificates of deposit, and insured cash sweep accounts.

24

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 facility 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, 2018, there was $250 million available under the revolving credit commitments and the LOC facility.
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 credit facility.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.
In 2016, the ACC issued an order granting TEP financing authority. The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority.
In November 2018, we issued and sold $300 million aggregate principal amount of senior unsecured notes to repay: (i) borrowings under our revolving credit facility which had provided funds for the redemption, in November 2018, of $100 million of tax-exempt local furnishing bonds maturing in 2032; (ii) $37 million of tax-exempt pollution control bonds maturing in 2032, which were backed by a LOC expiring in February 2019; and (iii) other amounts outstanding under our revolving credit facility, with any remaining balance to be used for general corporate purposes.
In connection with the December 2018 redemption of $37 million of tax-exempt pollution control bonds, the related LOC and 2010 Reimbursement Agreement were terminated.
TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, we 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, 2018, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- and A3, respectively.
Our 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.
Certain of TEP's debt agreements contain pricing based on our credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings, and the amount of fees we pay for LOCs and unused commitments.
Debt Covenants
Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of December 31, 2018, TEP was in compliance with these covenants.
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
UNS Energy made an equity contribution to TEP of $50 million in 2018. The proceeds provided additional liquidity to TEP. We received no equity contributions in 2017 or 2016.
Dividends Paid to Parent
TEP declared and paid $85 million in dividends to UNS Energy in 2018, $70 million in 2017, and $50 million in 2016.

25

Master Trading Agreements
TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or LOCs 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, 2018, TEP had posted no cash or LOCs as credit enhancements with its counterparties.
Capital Expenditures
Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In 2018, total capital expenditures of $393 million, included investments in generation assets and an enhanced metering and distribution network. In 2017, total capital expenditures of $346 million included the purchase of an additional 17.8% undivided interest in Springerville Common Facilities. In 2016, total capital expenditures of $335 million included the purchase of the remaining ownership interest in Springerville Unit 1.
Our forecasted capital expenditures presented below for years ended December 31 exclude amounts for AFUDC and other non-cash items:
(in millions)
2019
 
2020
 
2021
 
2022
 
2023
Generation Facilities:
 
 
 
 
 
 
 
 
 
Renewable Energy(1)
$
62

 
$
309

 
$
9

 
$
—

 
$
11

Other Generation Facilities (2)
262

 
76

 
122

 
56

 
54

Total Generation Facilities
324

 
385

 
131

 
56

 
65

Transmission and Distribution (3)
343

 
321

 
194

 
176

 
170

General and Other (4)
87

 
61

 
53

 
64

 
82

Total Capital Expenditures
$
754

 
$
767

 
$
378

 
$
296

 
$
317

(1) 
Includes investments in renewable energy that will allow us to continue to move toward our long-term strategy of shifting to a more diverse, sustainable energy portfolio.
(2) 
TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019.
(3) 
Includes investments in transmission capacity and system reinforcements.
(4) 
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, new or changing commitments, 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, other borrowings, or equity contributions.

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Contractual Obligations
The following table summarizes our material contractual obligations as of December 31, 2018:
 
 
 
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)
$
1,629

 
$
—

 
$
330

 
$
150

 
$
1,149

Interest (2)
1,026

 
72

 
140

 
108

 
706

Capital Lease Obligations (3)
207

 
187

 
20

 
—

 
—

Operating Leases (4)
10

 
1

 
2

 
2

 
5

Land Easements and Rights-of-Way (5)
86

 
1

 
3

 
2

 
80

Purchase Obligations:

 
 
 
 
 
 
 
 
Fuel, Including Transportation (6)
424

 
85

 
119

 
45

 
175

Purchased Power
20

 
20

 
—

 
—

 
—

Transmission
48

 
19

 
14

 
6

 
9

Renewable Power Purchase Agreements (7)
921

 
64

 
126

 
126

 
605

RES Performance-Based Incentives (8)
76

 
8

 
15

 
14

 
39

Acquisition of Springerville Common Facilities (9)
68

 
—

 
68

 
—

 
—

Other Long-Term Liabilities: (10) (11)

 
 
 
 
 
 
 
 
Restricted and Performance-Based Stock Units
9

 
3

 
6

 
—

 
—

Pension and Other Postretirement Benefits (12)
75

 
17

 
12

 
13

 
33

Total Contractual Obligations
$
4,599

 
$
477

 
$
855

 
$
466

 
$
2,801

(1) 
Total long-term debt is not reduced by $11 million of related unamortized debt issuance costs or $3 million of unamortized original issue discount.
(2) 
Excludes interest on revolving credit facilities.
(3) 
Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP began reimbursing TEP for various operating costs related to the common facilities on an ongoing basis. The common facilities include assets leased by TEP at Springerville. TEP was reimbursed for $6 million of operating costs in 2018 by SRP and Tri-State and does not expect any material changes to the reimbursement amount in 2019. Capital Lease Obligations does not reflect any reduction associated with this reimbursement. The balance of Capital Lease Obligations declines over time as scheduled capital lease payments are made. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Capital Lease Obligations.
(4) 
Primarily represents leases for land, rail cars, and communication towers with varying terms, provisions, and expiration dates through 2041.
(5) 
Have varying terms and provisions and reflect expiration dates through 2054. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Land Easements and Rights-of-Way.
(6) 
Excludes TEP’s liability for final mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate as the timing of payments has not been determined. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP’s share of reclamation costs.
(7) 
TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities' output once commercial operation status is achieved. While TEP is not required to make payments under these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PPAs.
(8) 
TEP has entered into REC agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBI) and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PBIs.

27

(9) 
Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021, subject to optional renewal periods of two or more years. TEP may renew the two leases or exercise its remaining fixed-price purchase options. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding Springerville Common Facilities Leases.
(10) 
Excludes Asset Retirement Obligations (ARO) of $72 million expected to occur through 2048.
(11) 
Excludes unrecognized tax benefits of $16 million. At this time, we are unable to make a reasonably reliable estimate of the timing of payments in individual years in connection with these tax liabilities.
(12) 
Represents TEP’s expected contributions to pension plans in 2019, expected benefit payments for its unfunded Supplemental Executive Retirement Plan (SERP), and expected other postretirement benefit costs to cover medical and life insurance claims as determined by the plans’ actuaries. Due to the significant impact that returns on plan assets and changes in discount rates might have on payment obligation amounts, other contributions beyond 2019 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
Tax legislation previously in effect included provisions that made qualified property placed in service before 2018 eligible for bonus depreciation for tax purposes. In addition, the Internal Revenue Service (IRS) had issued guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions were an acceleration of tax benefits we otherwise would have received over 20 years and created net operating loss carryforwards that are used to offset future taxable income. As a result, we did not pay any federal or state income taxes in 2018. We offset net operating loss carryforwards against taxable income and do not expect to make federal or state income tax payments for the next several years.
Under the TCJA, Alternative Minimum Tax (AMT) credit carryforwards will be refunded if not used to offset federal income tax liabilities. TEP expects to receive refunds of approximately $14 million in 2019, $7 million in 2020, and $3 million in 2021 and 2022.
In 2018, the ACC Refund Order was approved effective May 1, 2018. The refund amount, after the EDIT amortization true-up, totaled $33 million, which was passed back to customers through a bill credit in 2018. Customer bill credits are trued-up annually to reflect actual kWh sales and EDIT amortization. We filed an application with the ACC to establish the 2019 customer refund of $34 million. We will continue to return savings to customers through a combination of a bill credit and a regulatory liability. The customer bill credit will account for 75% of the returned savings in 2019, and 50% of the returned savings in 2020 and through the completion of our next rate case. The portion of savings not returned through a bill credit will be deferred as a regulatory liability and returned to customers through our next rate case, which is expected to be filed in April 2019.
See Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the TCJA.

Environmental Matters
The EPA regulates the amount of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs.
We capitalized $9 million in 2018, $33 million in 2017, and $40 million in 2016 in costs incurred to comply with environmental rules and regulations. In addition, we recorded environmental compliance related operations and maintenance expenses of $6 million in 2018, $5 million in 2017 and $6 million in 2016. We expect environmental compliance related capital expenditures of $2 million in 2019 and 2020 and do not expect material environmental compliance related capital expenditures in years 2021 through 2023. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.

28

Regional Haze Regulations
The EPA's Regional Haze require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these generation facilities.
In the western United States, Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). The BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s, after the time frame as designated by the rules. Other provisions of Regional Haze requiring further emission reductions are not likely to impact Springerville operations until after 2021. In December 2016, the EPA signed a final rule, entitled "Protection of Visibility: Amendments to Requirements for State Plans." Among other things, the rule changes the date for submittal of the next Regional Haze implementation plan from 2018 to 2021. Based on recent Regional Haze requirement time frames, TEP anticipates that impacts, if any, to Springerville will likely occur three to five years after the 2021 plan submittal date. TEP cannot predict the ultimate outcome of these matters.
Four Corners Generating Station
In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy. As a result, APS closed Units 1, 2, and 3 in December 2013 and agreed to install SCR on Units 4 and 5. TEP owns 7% of Four Corners Units 4 and 5. APS completed the installation of SCR in July 2018. TEP's share of installation costs was approximately $47 million in capital expenditures and $2 million in annual operations and maintenance expenses.
Navajo Generating Station
In August 2014, the EPA published a final Federal Implementation Plan (FIP) which provides that: (i) one unit at Navajo will be shut down by 2020; (ii) SCR, or the equivalent, will be installed on the remaining two units by 2030; and (iii) conventional coal-fired generation will cease by December 2044. The final BART rule includes options that accommodate potential ownership changes at the facility. The facility had until December 2019 to notify the EPA of how it will comply with the FIP. As a result of the planned early retirement of Navajo, TEP and the co-owners will no longer be responsible for implementing the FIP. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the early retirement of Navajo.
Greenhouse Gas Regulation
In August 2015, the EPA issued the CPP limiting CO2 emissions from existing and new fossil fuel-based generation facilities. The CPP establishes state-level CO2 emission rates and mass-based goals that apply to fossil fuel-based generation. The plan targets CO2 emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.
In October 2017, the EPA issued a proposal to repeal the CPP and in December 2017, the EPA issued an Advance Notice of Proposed Rulemaking soliciting information about the intent to replace the CPP with a rule establishing new emissions guidelines.
In August 2018, the EPA published the proposed Affordable Clean Energy (ACE) rule. The proposed rule is meant to replace the CPP and proposes to rebalance the roles between the states and the EPA. Under the proposed rule, the EPA would set emission guidelines based on the Best System of Emission Reduction (BSER) for GHG emissions. The states would then use these emission guidelines to establish standards of performance consistent with the BSER within their jurisdictions considering source specific factors such as the remaining useful life of an individual unit. The proposed ACE rule also includes New Source Review (NSR) reform to incentivize heat-rate improvements that could reduce GHG emissions without triggering costly NSR permit requirements. Only projects that increase a generation facility’s hourly rate of pollutant emissions would be required to undergo a full NSR analysis.
Upon publication of the final rule, the states will have three years to submit plans establishing standards of performance. The EPA has 12 months to act on a complete state submittal. If a state plan is not approved, or a state fails to submit a plan within the allotted three years, the EPA would have two years to issue a federal plan. The public comment period closed October 31, 2018. The EPA anticipates finalizing the rule in early 2019.
TEP will continue to work with other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed. TEP is unable to determine the impact to its facilities until all legal challenges have been resolved and any new regulations have been promulgated.

29

Coal Combustion Residuals Regulation
In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA Subtitle D) for disposal in landfills and/or surface impoundments. Our share of costs to comply with the rule at Springerville was $2 million. The majority was spent through 2016 on capital expenditures associated with site preparation and installation of the groundwater monitoring well system. We continue to incur additional operating costs for on-going groundwater monitoring and eventual site closure activities. Similarly, we currently estimate our share of costs to be $3 million at Four Corners and $3 million at Navajo. San Juan does not operate any landfills or surface impoundments. San Juan currently disposes of CCR in the surface mine pits of San Juan Mine, adjacent to the plant.
In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act which authorizes the States to establish permit programs under RCRA for implementing regulation for CCR. In response to the WIIN Act and RCRA rulemaking petitions, the EPA has indicated that it intends to conduct two phases of CCR rule revisions. In July 2018, the EPA signed a Phase 1, Part 1 final rule which: (i) revised groundwater protection standards for rule-specific constituents without maximum containment levels; (ii) incorporated risk-based changes under an EPA-approved state permit program or an EPA permit program; and (iii) extended certain closure deadlines. TEP does not anticipate a material impact on operations or financial results from the first phase, part 1 final rule. The EPA anticipates finalizing the first phase, part 2 in 2019. The second phase is also anticipated to be finalized in 2019.
TEP is currently working with other affected utilities and the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires management to apply accounting policies and to make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on TEP’s other significant accounting policies can be found in Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
Accounting for Regulated Operations
We account for our regulated electric operations in accordance with accounting standards that allow the actions of our regulators, the ACC and the FERC, to be reflected in our financial statements. Regulator actions may cause us to capitalize certain costs that would be included as an expense, or in Accumulated Other Comprehensive Income (AOCI), in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. We evaluate regulatory assets and liabilities each period and believe future recovery or settlement is probable. Our assessment includes consideration of recent rate orders, historical regulatory treatment of similar costs, and changes in the regulatory and political environment. If management's assessment is ultimately different than actual regulatory outcomes, the impact on our results of operations, financial position, and future cash flows could be material.
As of December 31, 2018, regulatory liabilities net of regulatory assets on the balance sheet totaled $208 million. There are no current or expected proposals or changes in the regulatory environment that impact our ability to apply accounting guidance for regulated operations. If we conclude, in a future period, that our operations no longer meet the criteria in this guidance, we would reflect our pension and other postretirement plan regulatory assets or liabilities in AOCI and recognize the impact of other regulatory assets and liabilities in the income statement, both of which would be material to our financial statements. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding regulatory matters.
Revenue Recognition
TEP’s retail revenues, which are recognized in the period that electricity is delivered and consumed by customers, include unbilled revenue based on an estimate of kWh delivered at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment, including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated kWh delivered to the kWh billed to our retail customers. The excess of estimated kWh delivered over kWh billed is allocated to the retail customer classes based on estimated usage by each

30

customer class. We then record revenue for each customer class based on the various Retail Rates for each customer class. Due to the seasonal fluctuations of TEP’s actual load, unbilled revenues increase during the spring and summer and decrease during the fall and winter. A provision for uncollectible accounts, associated with retail revenues, is recorded as a component of operations and maintenance expense.
Income Taxes
Due to the differences between GAAP and income tax laws, many transactions are treated differently for income tax purposes than they are in the financial statements. We account for this difference by recording deferred income tax assets and liabilities using the effective income tax rate as of our balance sheet date. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS, Inc., a Fortis intermediate holding company (FortisUS).
A valuation allowance is established against deferred tax assets for which management believes it is more likely than not that the deferred asset will not be realized. In making this judgment, management evaluates all available evidence and gives more weight to objective verifiable evidence. TEP recorded no valuation allowance as of December 31, 2018. See Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding income taxes.
Plant Asset Depreciable Lives
TEP has significant investments in electric generation assets and electric transmission and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and expected net removal costs. The useful lives of plant assets are further detailed in Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded in the income statement. The ACC approves depreciation rates for all generation and distribution assets. Depreciation rates for such assets cannot be changed without the ACC's approval. TEP's transmission assets are subject to the jurisdiction of the FERC. See Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding depreciation rates.
Accounting for Asset Retirement Obligations
GAAP requires us to record the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. We incur legal obligations as a result of environmental regulations imposed by State and Federal regulators, contractual agreements, and other factors. To estimate the liability, management must use judgment and assumptions in: (i) determining whether a legal obligation exists to remove assets; (ii) estimating the probability of a future event for a conditional obligation; (iii) estimating the fair value of the cost of removal; estimating when final removal will occur; and (iv) estimating the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for AROs. TEP primarily defers costs associated with its legal AROs as regulatory assets because these costs are included in depreciation rates approved for recovery by the ACC. Deferred costs are amortized over the life of the underlying asset.
TEP identified legal obligations to retire generation facilities specified in land leases for its jointly-owned Navajo and Four Corners facilities. These stations reside on land leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at expiration of the leases. TEP also has certain environmental obligations at Gila River, Luna, San Juan, Sundt and Springerville. TEP estimates that its share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt, Gila River, and Springerville environmental and contractual obligations will be approximately $343 million at the retirement dates. Additionally, TEP entered into land lease agreements or land easement agreements with certain land owners for the installation of PV assets. The provisions of the PV land leases or land easements require TEP to remove the PV facilities upon expiration of the agreements. In addition, TEP is required to dispose or recycle the PV assets under the Resource Conservation and Recovery Act. TEP's ARO related to the PV assets is estimated to be approximately $19 million at the retirement dates. No other legal obligations to retire generation plant assets have been identified.
TEP has various transmission and distribution lines that operate under land easements and rights-of-way that contain end dates and may contain site restoration clauses. TEP operates transmission and distribution lines as if they will be operated in perpetuity and will continue to be used or sold without land remediation. As such, there are no AROs for these assets.
The total net present value of TEP's ARO liability was $72 million as of December 31, 2018. ARO liabilities are reported in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.

31

Additionally, the authorized depreciation rates for TEP include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances as of December 31, 2018, represent non-legal ARO accruals, less actual removal costs incurred, net of salvage proceeds realized, and are recorded as a regulatory liability on the balance sheet. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding future cost of removal.
Pension and Other Postretirement Benefit Plan Assumptions
TEP records the underfunded amount for its pension and other postretirement obligations as a liability. Amounts not yet recognized in the income statement are recorded as a regulatory asset or liability to reflect expected recovery or refund of pension and other postretirement obligations through rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability may vary significantly in future years. Key assumptions used include:
•
discount rates used to determine obligations;
•
expected returns on plan assets;
•
compensation increases;
•
mortality assumptions; and
•
healthcare cost trend rates.
Discount Rates
As of December 31, 2018, TEP discounted its future pension plan obligations at 4.5% and its other postretirement plan obligations at a rate of 4.3%. The discount rate for future pension plan and other postretirement plan obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments.
Expected Returns on Plan Assets
To establish the expected return on assets assumption, TEP reviews the asset allocation and develops return assumptions for each asset class based on advice from an investment consultant and the pension’s actuary that includes both historical performance analysis and forward-looking views of the financial markets. As of December 31, 2018, TEP assumed that its pension plans’ assets would generate a long-term rate of return of 7%.
Compensation Increases
As of December 31, 2018, TEP used a rate of compensation increase of 2.8% to measure pension obligations.
Mortality
The RP-2014 mortality table projected with improvement scale MP-2018 with 15-year convergence and a 0.75% long-term rate was utilized to measure the December 31, 2018 pension obligations, whereas improvement scales MP-2017 was utilized for the December 31, 2017 measurement.
Healthcare Cost Trend Rates
TEP used a current year healthcare cost trend rate range between 6.5% and 7.8% in valuing its other postretirement benefit obligation as of December 31, 2018. This rate reflects both market conditions and historical experience.

32

Sensitivity Analysis
The table below shows the effect on TEP's 2018 expense and obligation of a 100 basis point change to its assumptions:
 
Effect on Expense
 
Effect on Obligation
 
Increase
 
Decrease
 
Increase
 
Decrease
(in millions)
December 31, 2018
Change to Pension
 
 
 
 
 
 
 
Discount Rate
$
(7
)
 
$
8

 
$
(56
)
 
$
71

Long-Term Rate of Return on Plan Assets
(4
)
 
4

 
N/A

 
N/A

Change to Other Postretirement Benefits
 
 
 
 
 
 
 
Discount Rate
—

 
1

 
(7
)
 
9

Long-Term Rate of Return on Plan Assets
—

 
—

 
N/A

 
N/A

Healthcare Cost Trend Rate
1

 
(1
)
 
7

 
(6
)
In 2019, TEP will incur pension costs of approximately $13 million and other postretirement benefit costs of approximately $5 million. TEP expects to charge approximately $14 million of these costs to operations and maintenance expense, $3 million to capital, and $1 million to other expense. TEP expects to make pension plan contributions of $11 million in 2019. In 2019, TEP expects to make benefit payments to retirees under the retiree benefit plan of approximately $5 million and contributions to the Voluntary Employee Beneficiary Association (VEBA) trust of approximately $1 million, net of distributions.
See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension plan and other postretirement benefit plan expenses and obligations.
Accounting for Derivative Instruments and Hedging Activities
Commodity Derivative Contracts
TEP enters into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, or one year, within established limits to meet forecasted load requirements or to take advantage of favorable market opportunities. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it will have excess supply and the market price of energy exceeds its marginal cost. TEP enters into forward gas commodity price swap agreements to lock in fixed prices on a portion of forecasted gas purchases and to hedge the price risk associated with forward PPAs that are indexed to natural gas prices.
For all commodity derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the balance sheet and measure those instruments at fair value. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or liability on the balance sheet based on our ability to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC mechanism.
The market prices used to determine fair values for TEP’s derivative instruments as of December 31, 2018, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.
Interest Rate Swaps
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates tied to the London Interbank Offered Rate (LIBOR) on the Springerville Common Facilities lease. As of December 31, 2018, approximately $12 million of variable rate lease debt for the Springerville Common Facilities lease had been hedged through an amortizing interest rate swap expiring in January 2020.

33

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP’s financial statements are exposed to certain market risks that can affect asset and liability fair value, results of operations, and cash flows. TEP's significant market risks are primarily associated with interest rates, commodity and coal prices, and extension of credit to counterparties. TEP may enter into interest rate swaps and financing transactions to manage changes in interest rates. TEP has a Risk Management Committee responsible for the oversight of commodity price risk and credit risk related to wholesale energy marketing and power procurement activities. To limit TEP’s exposure to commodity price risk, the Risk Management Committee sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP’s exposure to credit risk, the Risk Management Committee reviews counterparty credit exposure as well as credit policies and limits on a regular basis.
Interest Rate Risk
Long-Term Debt
TEP is exposed to interest rate risk resulting from changes in interest rates on certain variable rate debt obligations. TEP has $14 million of variable rate debt outstanding related to the Springerville Common Facilities capital lease obligation as of December 31, 2018. TEP has a fixed-for-floating interest rate swap in place to hedge the floating interest rate risk associated with a portion of the capital lease obligation. The notional amount of the swap was $12 million as of December 31, 2018.
Interest Rate Swap
To adjust the value of TEP’s interest rate swap, classified as a cash flow hedge, to fair value in other comprehensive income (loss), TEP recorded the following net unrealized gains:
(in millions)
2018
 
2017
 
2016
Net Unrealized Gains
$
—

 
$
1

 
$
1

Credit Facilities
TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under its credit agreement. The interest rate paid on borrowings is variable. Revolving credit borrowings are made on either the basis of a spread over LIBOR or an Alternate Base Rate (ABR). As a result, TEP may experience significant volatility in the rates paid on LIBOR borrowings under its revolving credit facilities.
Commodity and Coal Price Risk
TEP is exposed to market fluctuations in electricity, natural gas and coal prices as a result of its obligation to serve retail customer load in its regulated service territory and long-term wholesale contracts. TEP's load and generating facilities represent substantial underlying commodity positions. Exposure to commodity prices consist primarily of variations in the price of fuel required to generate electricity that is purchased and sold in the retail and wholesale markets. Commodity and coal prices may be subject to significant price changes as supply and demand are impacted by, among other unpredictable factors, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Under the guidance of the Risk Management Committee, TEP mitigates a portion of its commodity price risk through the use of commodity contracts, which include forwards, options, swaps and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. TEP's exposure to commodity and coal price risk is limited by its ability to include these costs in regulated rates through its PPFAC mechanism, which is subject to review by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.

34

Certain commodity contracts qualify as derivatives and are recorded at fair value. The changes in fair value of such contracts have a high correlation to price changes in the hedged commodities. The following table shows the changes in fair value of our derivative positions:
(in millions)
2018
 
2017
 
2016
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities
$
(9
)
 
$
(18
)
 
$
12

TEP's derivative contracts mature on various dates through 2029. The table below displays the valuation methodologies and maturities of derivative contracts by source of fair value:
 
Unrealized Gain (Loss) of TEP’s Hedging Activities
 
Maturity 0 – 6 months
 
Maturity 6 – 12 months
 
Maturity over 1 yr.
 
Total Unrealized Gain (Loss)
(in millions)
December 31, 2018
Prices Actively Quoted
$
(6
)
 
$
(8
)
 
$
(11
)
 
$
(25
)
Sensitivity Analysis of Derivatives
TEP uses sensitivity analysis to measure the potential impact of favorable and unfavorable changes in market prices on the fair value of its derivative contracts. TEP records unrealized gains and losses as either a regulatory asset or liability. As contracts settle, the unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. For TEP's derivatives related to the purchase and sale of electricity, a 10% change in the market price of purchased power would affect unrealized positions reported as a regulatory asset or liability by approximately $1 million; for derivatives related to the natural gas price hedges, a 10% change in the market price of energy would affect unrealized positions reported as a regulatory asset or liability by approximately $33 million.
Coal Supply Agreements
TEP is subject to fuel price risk from changes in the price of coal used to fuel its coal-fired generation facilities. This risk is mitigated through the use of long-term coal supply agreements with limited price movement. Coal agreements expire from 2019 through 2031. TEP expects coal reserves from the supplying mines to be sufficient to fulfill the estimated requirements for each coal-fired generation facility's estimated remaining life. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
Credit Risk
TEP is exposed to credit risk in its energy-related marketing activities related to potential non-performance by counterparties. TEP manages the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. Counterparty credit exposure is calculated by adding any outstanding receivable (net of amounts payable if a netting agreement exists) to the mark-to-market value of any forward contracts. If exposure exceeds credit limits or contractual collateral thresholds, we may request that a counterparty provide credit enhancement in the form of cash collateral or an LOC.
TEP has entered into short-term and long-term transactions related to its wholesale marketing and gas hedging activities with various counterparties. As of December 31, 2018, TEP’s total credit exposure was approximately $23 million. TEP had approximately $3 million of exposure to non-investment grade counterparties.
As of December 31, 2018, TEP had posted no cash collateral nor LOCs as credit enhancements with its counterparties, and held approximately $7 million in collateral from its wholesale counterparties.

35


ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm
To the Stockholder and the Board of Directors of
Tucson Electric Power Company
Tucson, Arizona

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Tucson Electric Power Company and subsidiaries (the "Company") as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, changes in stockholder’s equity, and cash flows, for each of the two years in the period ended December 31, 2018, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 14, 2019
We have served as the Company's auditor since 2017.

36


Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Tucson Electric Power Company:
We have audited the accompanying consolidated statements of income, comprehensive income, changes in stockholder’s equity and cash flows of Tucson Electric Power Company for the year ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provided a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Tucson Electric Power Company for the year ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP
Ernst & Young LLP
Calgary, Canada
February 16, 2017


37

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands)
 
Years Ended December 31,
 
2018
 
2017
 
2016
Operating Revenues
$
1,432,618

 
$
1,340,935

 
$
1,234,995

 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
Fuel
351,749

 
285,551

 
289,862

Purchased Power
134,914

 
136,425

 
85,354

Transmission and Other PPFAC Recoverable Costs
46,595

 
36,239

 
23,781

Increase (Decrease) to Reflect PPFAC Recovery Treatment
9,885

 
(32,660
)
 
21,064

Total Fuel and Purchased Power
543,143

 
425,555

 
420,061

Operations and Maintenance
361,963

 
360,302

 
353,905

Depreciation
158,310

 
152,874

 
146,097

Amortization
26,052

 
22,255

 
22,498

Taxes Other Than Income Taxes
55,006

 
53,623

 
49,303

Total Operating Expenses
1,144,474

 
1,014,609

 
991,864

 
 
 
 
 
 
Operating Income
288,144

 
326,326

 
243,131

 
 
 
 
 
 
Other Income (Expense)
 
 
 
 
 
Interest Expense
(67,620
)
 
(65,290
)
 
(65,902
)
Allowance For Borrowed Funds
3,151

 
2,078

 
1,710

Allowance For Equity Funds
8,117

 
5,322

 
4,522

Other, Net
(487
)
 
8,995

 
353

Total Other Income (Expense)
(56,839
)
 
(48,895
)
 
(59,317
)
 
 
 
 
 
 
Income Before Income Tax Expense
231,305

 
277,431

 
183,814

Income Tax Expense
42,982

 
100,763

 
59,376

Net Income
$
188,323

 
$
176,668

 
$
124,438

The accompanying notes are an integral part of these financial statements.


38


TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in thousands)
 
Years Ended December 31,
 
2018
 
2017
 
2016
Comprehensive Income
 
 
 
 
 
Net Income
$
188,323

 
$
176,668

 
$
124,438

Other Comprehensive Income (Loss)
 
 
 
 
 
Net Changes in Fair Value of Cash Flow Hedges:
 
 
 
 
 
Net of Income Tax (Expense) Benefit of $(121), $(305), and $(420)
364

 
485

 
652

Supplemental Executive Retirement Plan Adjustments:
 
 
 
 
 
Net of Income Tax (Expense) Benefit of $(747), $637, and $399
2,026

 
(2,156
)
 
(643
)
Total Other Comprehensive Income (Loss), Net of Tax
2,390

 
(1,671
)
 
9

Total Comprehensive Income
$
190,713

 
$
174,997

 
$
124,447

The accompanying notes are an integral part of these financial statements.


39

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
 
Years Ended December 31,
 
2018
 
2017
 
2016
Cash Flows from Operating Activities
 
 
 
 
 
Net Income
$
188,323

 
$
176,668

 
$
124,438

Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities:
 
 
 
 
 
Depreciation Expense
158,310

 
152,874

 
146,097

Amortization Expense
26,052

 
22,255

 
22,498

Amortization of Debt Issuance Costs
2,339

 
2,349

 
2,853

Use of Renewable Energy Credits for Compliance
32,350

 
25,453

 
17,618

Deferred Income Taxes
56,066

 
100,762

 
59,367

Pension and Other Postretirement Benefits Expense
15,303

 
16,039

 
15,338

Pension and Other Postretirement Benefits Funding
(26,673
)
 
(14,430
)
 
(13,459
)
Allowance for Equity Funds Used During Construction
(8,117
)
 
(5,322
)
 
(4,522
)
FERC Transmission Refund Payable
—

 
(4,878
)
 
4,878

Changes in Current Assets and Current Liabilities:
 
 
 
 
 
Accounts Receivable
(26,729
)
 
(13,219
)
 
7,809

Materials, Supplies, and Fuel Inventory
(2,357
)
 
175

 
7,627

Regulatory Assets
(4,080
)
 
(3,942
)
 
(12,147
)
Accounts Payable and Accrued Charges
33,536

 
9,790

 
14,284

Income Taxes Receivable
(13,004
)
 
—

 
—

Regulatory Liabilities
14,028

 
(20,227
)
 
18,012

Other, Net
11,879

 
3,977

 
14,777

Net Cash Flows—Operating Activities
457,226

 
448,324

 
425,468

Cash Flows from Investing Activities
 
 
 
 
 
Capital Expenditures
(392,522
)
 
(345,617
)
 
(250,360
)
Purchase, Springerville Unit 1 Assets
—

 
—

 
(85,000
)
Purchase Intangibles, Renewable Energy Credits
(51,327
)
 
(51,179
)
 
(40,949
)
Contributions in Aid of Construction
10,817

 
4,983

 
3,432

Net Cash Flows—Investing Activities
(433,032
)
 
(391,813
)
 
(372,877
)
Cash Flows from Financing Activities
 
 
 
 
 
Proceeds from Borrowings, Revolving Credit Facility
171,000

 
70,000

 
—

Repayments of Borrowings, Revolving Credit Facility
(206,000
)
 
(35,000
)
 
—

Proceeds from Issuance, Long-Term Debt—Net of Discount
298,869

 
—

 
—

Repayments, Long-Term Debt
(136,700
)
 
—

 
—

Dividends Paid to Parent
(85,000
)
 
(70,000
)
 
(50,000
)
Payments of Capital Lease Obligations
(10,930
)
 
(15,571
)
 
(14,079
)
Payment of Debt Issuance Costs
(3,265
)
 
(245
)
 
(183
)
Contribution from Parent
50,000

 
—

 
—

Other, Net
1,078

 
481

 
(4,871
)
Net Cash Flows—Financing Activities
79,052

 
(50,335
)
 
(69,133
)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash
103,246

 
6,176

 
(16,542
)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period
49,501

 
43,325

 
59,867

Cash, Cash Equivalents, and Restricted Cash, End of Period
$
152,747

 
$
49,501

 
$
43,325

The accompanying notes are an integral part of these financial statements.

40

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
 
December 31,
 
2018
 
2017
ASSETS
 
 
 
Utility Plant
 
 
 
Plant in Service
$
6,020,469

 
$
5,780,805

Utility Plant Under Capital Leases
248,635

 
84,870

Construction Work in Progress
258,965

 
160,288

Total Utility Plant
6,528,069

 
6,025,963

Accumulated Depreciation and Amortization
(2,293,783
)
 
(2,193,656
)
Accumulated Amortization of Capital Lease Assets
(73,646
)
 
(63,605
)
Total Utility Plant, Net
4,160,640

 
3,768,702

 
 
 
 
Investments and Other Property
50,952

 
51,260

 
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents
138,114

 
37,701

Accounts Receivable, Net
172,367

 
137,932

Fuel Inventory
22,783

 
25,059

Materials and Supplies
107,990

 
103,981

Regulatory Assets
106,725

 
93,960

Derivative Instruments
3,929

 
3,187

Other
25,571

 
10,777

Total Current Assets
577,479

 
412,597

Regulatory and Other Assets
 
 
 
Regulatory Assets
293,078

 
293,551

Derivative Instruments
8,402

 
8,826

Other
68,656

 
55,313

Total Regulatory and Other Assets
370,136

 
357,690

Total Assets
$
5,159,207

 
$
4,590,249

The accompanying notes are an integral part of these financial statements.

(Continued)

41

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share data)
 
December 31,
 
2018
 
2017
CAPITALIZATION AND OTHER LIABILITIES
 
 
 
Capitalization
 
 
 
Common Stock Equity:
 
 
 
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2018 and 2017)
$
1,346,539

 
$
1,296,539

Capital Stock Expense
(6,357
)
 
(6,357
)
Retained Earnings
484,277

 
380,076

Accumulated Other Comprehensive Loss
(4,714
)
 
(6,226
)
Total Common Stock Equity
1,819,745

 
1,664,032

Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2018 and 2017)
—

 
—

Capital Lease Obligations
19,773

 
28,519

Long-Term Debt, Net
1,615,252

 
1,354,423

Total Capitalization
3,454,770

 
3,046,974

Current Liabilities
 
 
 
Current Maturities of Long-Term Debt
—

 
100,000

Borrowings Under Revolving Credit Facility
—

 
35,000

Capital Lease Obligations
172,510

 
10,749

Accounts Payable
133,012

 
97,367

Accrued Taxes Other than Income Taxes
41,686

 
40,706

Accrued Employee Expenses
34,339

 
30,929

Accrued Interest
17,927

 
14,750

Regulatory Liabilities
95,094

 
89,024

Customer Deposits
27,650

 
24,865

Derivative Instruments
18,137

 
10,667

Other
21,555

 
18,119

Total Current Liabilities
561,910

 
472,176

Regulatory and Other Liabilities
 
 
 
Deferred Income Taxes, Net
369,705

 
300,258

Regulatory Liabilities
512,425

 
516,438

Pension and Other Postretirement Benefits
117,472

 
133,799

Derivative Instruments
19,361

 
17,907

Other
123,564

 
102,697

Total Regulatory and Other Liabilities
1,142,527

 
1,071,099

 
 
 
 
Commitments and Contingencies

 

 
 
 
 
Total Capitalization and Other Liabilities
$
5,159,207

 
$
4,590,249

The accompanying notes are an integral part of these financial statements.

(Concluded)

42

TUCSON ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
(Amounts in thousands)
 
Common Stock
 
Capital Stock Expense
 
Retained Earnings
 
Accumulated Other Comprehensive Loss
 
Total Stockholder's Equity
Balances as of December 31, 2015
$
1,296,539

 
$
(6,357
)
 
$
189,317

 
$
(4,564
)
 
$
1,474,935

Net Income
 
 
 
 
124,438

 
 
 
124,438

Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
9

 
9

Dividends Declared to Parent
 
 
 
 
(50,000
)
 
 
 
(50,000
)
Adoption of ASU, Cumulative Effect Adjustment
 
 
 
 
9,653

 
 
 
9,653

Balances as of December 31, 2016
1,296,539

 
(6,357
)
 
273,408

 
(4,555
)
 
1,559,035

Net Income
 
 
 
 
176,668

 
 
 
176,668

Other Comprehensive Loss, Net of Tax
 
 
 
 
 
 
(1,671
)
 
(1,671
)
Dividends Declared to Parent
 
 
 
 
(70,000
)
 
 
 
(70,000
)
Balances as of December 31, 2017
1,296,539

 
(6,357
)
 
380,076

 
(6,226
)
 
1,664,032

Net Income
 
 
 
 
188,323

 
 
 
188,323

Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
2,390

 
2,390

Dividends Declared to Parent
 
 
 
 
(85,000
)
 
 
 
(85,000
)
Contribution from Parent
50,000

 
 
 
 
 
 
 
50,000

Adoption of ASU, Cumulative Effect Adjustment
 
 
 
 
878

 
(878
)
 
—

Balances as of December 31, 2018
$
1,346,539

 
$
(6,357
)
 
$
484,277

 
$
(4,714
)
 
$
1,819,745

The accompanying notes are an integral part of these financial statements.


43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 425,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis.
BASIS OF PRESENTATION
TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly-owned facilities is recorded in Utility Plant on the Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included in the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant.
Certain amounts from prior periods have been reclassified to conform to the current year presentation. Most notably, TEP combined captions on the Consolidated Statements of Income by reclassifying similar line items into a single line item as follows:
 
As Filed
 
Amount Reclassified
 
As Reclassified
 
As Filed
 
Amount Reclassified
 
As Reclassified
(in thousands)
Year Ended December 31, 2017
 
Year Ended December 31, 2016
Other Income (Deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest Income
$
742

 
$
(742
)
 
$
—

 
$
111

 
$
(111
)
 
$
—

Other Income
14,128

 
(14,128
)
 
—

 
5,636

 
(5,636
)
 
—

Other Expense
(3,344
)
 
3,344

 
—

 
(3,019
)
 
3,019

 
—

Appreciation in Value of Investments
2,791

 
(2,791
)
 
—

 
2,147

 
(2,147
)
 
—

Allowance For Equity Funds
—

 
5,322

 
5,322

 
—

 
4,522

 
4,522

Other, Net
—

 
8,995

 
8,995

 
—

 
353

 
353

 
 
 
 
 
 
 
 
 
 
 
 
Interest Expense
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt
62,018

 
(62,018
)
 
—

 
62,015

 
(62,015
)
 
—

Capital Leases
2,554

 
(2,554
)
 
—

 
3,356

 
(3,356
)
 
—

Other Interest Expense
718

 
(718
)
 
—

 
531

 
(531
)
 
—

Interest Capitalized
(2,078
)
 
2,078

 
—

 
(1,710
)
 
1,710

 
—

Allowance For Borrowed Funds
—

 
(2,078
)
 
(2,078
)
 
—

 
(1,710
)
 
(1,710
)
Interest Expense
—

 
65,290

 
65,290

 
—

 
65,902

 
65,902

Accounting for Regulated Operations
TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters.

44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



TEP applies regulatory accounting as the following conditions exist:
•
An independent regulator sets rates;
•
The regulator sets the rates to recover the specific enterprise’s costs of providing service; and
•
Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers.
Variable Interest Entities
TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.
TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of the VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.
As of December 31, 2018, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED
The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) has been adopted as of January 1, 2018. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
Revenue from Contracts with Customers
TEP adopted accounting guidance that requires recognition of revenue when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the company expects to be entitled. The Company continues to recognize revenue for tariff-based sales to retail and wholesale customers, which represent TEP’s primary source of revenue, as power is delivered. TEP adopted the new guidance using the modified retrospective approach. There was no adjustment identified or recorded to the opening balance of retained earnings on adoption. The Company applied the new revenue guidance to contracts with customers that were not completed at the date of initial application, January 1, 2018. The new guidance requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for additional disclosure related to TEP's operating revenues.
Compensation—Retirement Benefits
TEP adopted accounting guidance that requires an employer to disaggregate the service cost component from the other components of net periodic benefit cost. TEP no longer capitalizes the non-service cost components of net periodic benefit cost as part of inventory or plant in service and presents non-service costs in Other, Net on the Consolidated Statements of Income.
Derivatives and Hedging
TEP early adopted accounting guidance that simplifies the application of hedge accounting through changes to both the designation and measurement guidance and is intended to enable the Company to better portray the economics of its risk management activities in its financial statements.
Reclassification of Certain Tax Effects
TEP early adopted accounting guidance that permits reclassification of certain tax effects resulting from the TCJA from AOCI to retained earnings. TEP applied the guidance as of the beginning of the period of adoption. On adoption, TEP recorded a one-time reclassification of $1 million from Accumulated Other Comprehensive Loss to Retained Earnings on the Consolidated

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Balance Sheets as a result of income tax effects due to the reduction in the U.S. federal statutory tax rate. See Note 13 for additional disclosure related to the TCJA.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected in TEP’s financial statements as of December 31, 2018. Unless otherwise indicated, TEP is currently assessing the impacts such guidance may have (which could be material) on TEP’s financial position, results of operations, cash flows, and disclosures, as well as the potential to early adopt where applicable. Updates not listed below were assessed and either determined to not be applicable or are expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
Leases
In February 2016, the FASB issued an ASU that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. The standard was effective for periods beginning January 1, 2019, and may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as an adjustment to retained earnings as of the date of initial application. TEP adopted this ASU on January 1, 2019, applied the transition provisions of the new standard as of the adoption date, and will not retrospectively adjust prior periods.
TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. In addition, TEP elected a practical expedient that permitted entities to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance will be applied on a prospective basis to all new or modified land easements after January 1, 2019. Finally, TEP utilized the hindsight practical expedient in transition to determine the lease term.
TEP’s leasing activities accounted for as operating leases primarily relate to rail cars, land, and communication towers. Adoption of the ASU resulted in recognition of additional right-of-use assets and lease liabilities of approximately $8 million. The Company does not expect the new ASU to affect its results of operations or cash flows.
During the implementation process, TEP planned modifications to its processes and control activities related to gathering contracts and contract review requirements associated with accounting for leases.
Internal-Use Software
In August 2018, the FASB issued an ASU that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The ASU also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. The standard is effective for periods beginning January 1, 2020, and should be applied either retrospectively or prospectively after the date of adoption. TEP early adopted this ASU prospectively effective January 1, 2019.
USE OF ACCOUNTING ESTIMATES
Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect:
•
assets and liabilities in the balance sheet at the dates of the financial statements;
•
disclosures about contingent assets and liabilities at the dates of the financial statements; and
•
revenues and expenses in the income statement during the periods presented.
Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates.
Asset Retirement Obligations
TEP has identified legal AROs related to the retirement of certain generation assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset or liability account based on the ACC approval of these costs in its depreciation rates.
Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities.
Contingencies
Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
CASH AND CASH EQUIVALENTS
TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
RESTRICTED CASH
Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Cash and Cash Equivalents
$
138

 
$
38

 
$
36

Restricted Cash included in:
 
 
 
 
 
Investments and Other Property
14

 
11

 
7

Current Assets, Other
1

 
1

 
—

Total Cash, Cash Equivalents, and Restricted Cash
$
153

 
$
50

 
$
43

Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Beginning of Period
$
5

 
$
5

 
$
27

Additions Charged to Cost and Expense
3

 
3

 
4

Write-offs
(3
)
 
(3
)
 
(3
)
Provision for Springerville Unit 1, Third-Party Owners
—

 
—

 
(23
)
End of Period
$
5

 
$
5

 
$
5


47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The allowance for doubtful accounts decreased in 2016 due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 8 for additional information regarding the settlement of the Third-Party Owners' claims.
INVENTORY
TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.
UTILITY PLANT
Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction.
The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred.
When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement.
AFUDC and Capitalized Interest
AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.
The average AFUDC rates on regulated construction expenditures are included in the table below:
 
2018
 
2017
 
2016
Average AFUDC Rates
7.12
%
 
7.31
%
 
7.47
%
Depreciation
Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs.
Below are the summarized average annual depreciation rates for all utility plant:
 
2018
 
2017
 
2016
Average Annual Depreciation Rates
3.13
%
 
2.97
%
 
2.85
%
Utility Plant Under Capital Leases
TEP finances a portion of the Springerville Common Facilities with capital leases. In addition, TEP has a Tolling PPA related to Gila River Unit 2 that is accounted for as a capital lease. Capital lease expense related to Gila River Unit 2 is recorded in Purchased Energy on the Consolidated Statements of Income. Capital lease expense related to Springerville Common Facilities is recorded in Amortization Expense and Interest Expense on the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant and Note 7 for additional information related to the terms of these transactions.
Computer Software and Cloud Computing Costs
Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense on the income statement.

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



EVALUATION OF ASSETS FOR IMPAIRMENT
Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time.
DEFERRED FINANCING COSTS
Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.
TEP accounts for debt issuance costs related to credit facility arrangements as an asset.
The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt.
OPERATING REVENUES
TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date delinquent and charges the customer a late payment fee. No component of the transaction price is allocated to unsatisfied performance obligations.
TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP's variable consideration includes revenues that are subject to refund. TEP estimates variable consideration at the most likely amount to which the Company expects to be entitled and recognizes a refund liability until TEP is certain that the Company will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods. See Note 4 for the disaggregation of TEP's Operating Revenues.
PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE
TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters.
RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS
The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the LFCR mechanism.
TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs. The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism.

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Operating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures.
RENEWABLE ENERGY CREDITS
The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism.
When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. See Note 2 for additional information regarding regulatory matters. The table below does not include PBI activity and summarizes the balance of TEP's RECs which are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets:
 
December 31,
(in millions)
2018
 
2017
Beginning of Period
$
42

 
$
24

Purchased
45

 
43

Used for Compliance
(32
)
 
(25
)
End of Period
$
55

 
$
42

TAXES OTHER THAN INCOME TAXES
TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
INCOME TAXES
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized.
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income.
TEP accounts for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. TEP had $6 million and $7 million in federal energy credits as of December 31, 2018 and 2017, respectively. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises.
TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS.

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



PENSION AND OTHER POSTRETIREMENT BENEFITS
TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees.
The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees.
Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 9 for additional information regarding the employee benefit plans.
FAIR VALUE
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 12 for additional information regarding fair value.
DERIVATIVE INSTRUMENTS
The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; (ii) reduce exposure to energy commodity price volatility; and (iii) hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities on the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity on the income statement.
For derivatives designated as hedging contracts, TEP formally assesses, at inception, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy.
For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 12 for additional information regarding derivative instruments.


51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 2. REGULATORY MATTERS
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 the Company's business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
TEP RATE CASE
Provisions of the 2017 Rate Order, which were effective February 27, 2017, included, but are not limited to:
•
a non-fuel base rate increase of $81.5 million; and
•
adoption of TEP's proposed depreciation and amortization rates, which included a reduction in the depreciable life for San Juan Unit 1.
The ACC deferred matters related to net metering and rate design for new DG customers to a second phase of TEP's rate case (Phase 2).
Phase 2 Order
On September 20, 2018, the ACC issued an order related to Phase 2 proceedings. The Phase 2 Order established, among other things, an export rate that replaced net metering. Residential and small commercial customers who apply to interconnect their solar generation systems to TEP's distribution system after the date of the order will no longer qualify for net metering. Customers who applied before the date of the order, and complete interconnection within a specified time frame, were grandfathered under previous net metering rules for a period of 20 years from the date of interconnection of their solar generation system.
Provisions of the Phase 2 Order for new DG customers include:
•
an option to select from existing Time-of-Use rate schedules;
•
a monthly bill credit for customer excess solar generation exported to TEP's grid calculated using an export rate approved by the ACC; and
•
an annual update to the export rate based on TEP's actual solar PPA and generation facilities costs, which are expected to decline. The export rate at the time of customers' applications to interconnect will be locked for 10 years. The initial export rate was set at 9.64 cents per kWh.
FEDERAL TAX LEGISLATION
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved the ACC Refund Order effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization trued up annually for actuals. The refund amount, after the EDIT amortization true-up, totaled $33 million. The 2018 bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year 2018. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the 2019 bill credit amounts.
The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:
 
Year Ended December 31,
(in millions)
2018
Beginning of Period
$
—

ACC Approved Refund (Reduction in Operating Revenues)
(33
)
Amount Returned to Customers Through Bill Credits
37

End of Period
$
4


52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Customer bill credits are trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP filed an application with the ACC to establish the 2019 customer refund of $34 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019.
See Note 13 for additional information regarding the TCJA.
Federal Energy Regulatory Commission
In 2018, the FERC issued the FERC Refund Order. TEP submitted a proposal for an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, effective March 21, 2018 which was approved by the FERC. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018.
In addition, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization. TEP cannot predict the final outcome of the NOPR or the impact on TEP's financial statements.
See Note 13 for additional information regarding the TCJA.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is adjusted annually each April 1st for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.
The table below summarizes the PPFAC regulatory asset (liability) balance:
 
Years Ended December 31,
(in millions)
2018
 
2017
Beginning of Period
$
(9
)
 
$
(38
)
Deferred Fuel and Purchased Power Costs
2

 
14

PPFAC Refunds (Recoveries) (1)
(10
)
 
15

End of Period
$
(17
)
 
$
(9
)
(1) 
The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018.
Environmental Compliance Adjustor
The Environmental Compliance Adjustor (ECA) allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided that they are not already recovered in base rates or recovered through another commission-approved mechanism.
The eligible costs for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. The Company recognized $3 million in 2018 and $1 million in both 2017 and 2016 related to the return on company-owned environmental investments included in Operating Revenues on the Consolidated Statements of Income.
Renewable Energy Standard
The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC.
In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. In 2018, TEP recognized $1 million of revenue as a return on company-owned solar projects. The return on company-owned solar projects is included in Operating Revenues on the Consolidated Statements of Income. TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism

53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



and plans to request recovery of these types of costs through its rate case process. As part of the Phase 2 Order, the ACC approved a separate residential community solar program for TEP.
In July 2018, TEP submitted its application for approval of the 2019 RES implementation plan with a budget amount of $55 million. The Company cannot predict when the ACC will consider its 2019 RES implementation plan.
In 2018, the percentage of TEP's retail kWh sales attributable to the RES was approximately 14%, exceeding the overall 2018 RES requirement of 8%. The ACC approved a waiver of the 2018 DG requirement.
Energy Efficiency Standards
Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of December 31, 2018, TEP’s cumulative annual energy savings were approximately 16%.
TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in each of 2018, 2017, and 2016 related to the performance incentive in Operating Revenues on the Consolidated Statements of Income.
TEP is currently operating under the ACC approved 2016 energy efficiency implementation plan. On February 6, 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which will be collected through the DSM surcharge.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.
TEP recorded regulatory assets and recognized LFCR revenues of $26 million in 2018, $22 million in 2017, and $18 million in 2016. LFCR revenues are included in Operating Revenues on the Consolidated Statements of Income.

54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below:
 
Remaining Recovery Period (years)
 
December 31,
($ in millions)
 
2018
 
2017
Regulatory Assets
 
 
 
 
 
Pension and Other Postretirement Benefits (Note 9)
Various
 
$
126

 
$
126

Early Generation Retirement Costs (1)
Various
 
72

 
84

Income Taxes Recoverable through Future Rates (2)
Various
 
47

 
40

Lost Fixed Cost Recovery
2
 
35

 
29

Final Mine Reclamation and Retiree Healthcare Costs (3)
20
 
29

 
31

Derivatives (Note 12)
11
 
27

 
18

Property Tax Deferrals (4)
1
 
23

 
24

Springerville Unit 1 Leasehold Improvements (5)
5
 
11

 
14

Other Regulatory Assets
Various
 
30

 
22

Total Regulatory Assets
 
 
400

 
388

Less Current Portion
1
 
107

 
94

Total Non-Current Regulatory Assets
 
 
$
293

 
$
294

Regulatory Liabilities
 
 
 
 
 
Income Taxes Payable through Future Rates (2)
Various
 
$
354

 
$
353

Net Cost of Removal (6)
Various
 
171

 
180

Renewable Energy Standard
Various
 
52

 
44

Purchased Power and Fuel Adjustment Clause
1
 
17

 
9

Deferred Investment Tax Credits (7)
Various
 
7

 
14

Other Regulatory Liabilities
Various
 
6

 
5

Total Regulatory Liabilities
 
 
607

 
605

Less Current Portion
1
 
95

 
89

Total Non-Current Regulatory Liabilities
 
 
$
512

 
$
516

(1) 
Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Consolidated Balance Sheets due to the planned early retirement of the facilities. As of December 31, 2018, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 3 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2.
(2) 
Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA. See Note 1 and Note 13 for additional information regarding income taxes.
(3) 
Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038.
(4) 
Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.
(5) 
Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year amortization period.
(6) 
Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.
(7) 
Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates related to the EDIT balances, TEP does not pay a return on regulatory liabilities.
FERC COMPLIANCE
In 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 8 for additional information related to FERC compliance associated with these transmission contracts.
IMPACTS OF REGULATORY ACCOUNTING
If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.

NOTE 3. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
UTILITY PLANT
The following table shows Plant in Service on the Consolidated Balance Sheets by major class:
 
Annual Depreciation Rate (4)
 
Average Remaining Life in Years (4)
 
December 31,
($ in millions)
 
 
2018
 
2017
Plant in Service
 
 
 
 
 
 
 
Generation Plant
3.19%
 
24
 
$
2,667

 
$
2,548

Transmission Plant
1.48%
 
31
 
1,010

 
1,001

Distribution Plant
1.56%
 
35
 
1,692

 
1,632

General Plant
5.89%
 
11
 
409

 
389

Intangible Plant, Software Costs, and Other (1)
Various
 
Various
 
239

 
207

Plant Held for Future Use
—
 
—
 
3

 
4

Total Plant in Service (2)
 
 
 
 
$
6,020

 
$
5,781

 
 
 
 
 
 
 
 
Utility Plant Under Capital Leases (3)
 
 
 
 
$
249

 
$
85

(1) 
Primarily represents computer software. Unamortized computer software costs were $73 million and $59 million as of December 31, 2018 and 2017, respectively. The amortization of computer software costs was $24 million in 2018, $19 million in 2017, and $17 million in 2016. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of three years for large enterprise software.
(2) 
Includes plant acquisition adjustments of $(134) million as of December 31, 2018 and 2017.
(3) 
In May 2018, TEP recorded capital lease obligations related to the Tolling PPA. See Note 7 for additional information regarding the Tolling PPA and Springerville leases.
(4) 
Represents a composite of the depreciation rates of assets within each major class of utility plant and is based on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order.

56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Utility Plant Under Capital Leases
All assets included in Utility Plant Under Capital Leases are used in generation operations and amortized over the primary lease term. The following table shows the amount of lease expense incurred for capital leases:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Lease Expense
 
 
 
 
 
Interest Expense included in:
 
 
 
 
 
Interest Expense, Capital Leases
$
2

 
$
3

 
$
3

Operating Expenses, Fuel
8

 
—

 
—

Amortization of Capital Lease Assets included in:
 
 
 
 
 
Operating Expenses, Amortization
6

 
6

 
5

Total Lease Expense
$
16

 
$
9

 
$
8

Springerville Acquisition
In December 2017, TEP purchased an undivided interest in the Springerville Common Facilities. As of December 31, 2018, Utility Plant Under Capital Leases represented 32.2% undivided interests in certain Springerville Common Facilities. See Note 7 for additional information regarding the Springerville capital lease purchases.
JOINTLY-OWNED FACILITIES
As of December 31, 2018, TEP was a participant in the following jointly-owned generation facilities and transmission systems:
(in millions)
Ownership Percentage (1)
 
Plant in Service
 
Construction Work in Progress
 
Accumulated Depreciation
 
Net Book Value
San Juan Unit 1
50.0%
 
$
290

 
$
1

 
$
134

 
$
157

Four Corners Units 4 and 5
7.0%
 
173

 
2

 
76

 
99

Luna
33.3%
 
58

 
—

 
4

 
54

Gila River Unit 3
75.0%
 
204

 
4

 
67

 
141

Gila River Common Facilities
18.8%
 
25

 
—

 
9

 
16

Springerville Coal Handling Facilities
83.0%
 
208

 
—

 
86

 
122

Transmission Facilities
Various
 
532

 
13

 
290

 
255

Total
 
 
$
1,490

 
$
20

 
$
666

 
$
844

(1) 
TEP also has a 7.5% ownership interest in Navajo. Navajo's NBV is classified as a regulatory asset. See Note 2 for additional information related to Navajo's NBV.
As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
RETIREMENTS
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. See Note 2 for additional information related to the planned early retirement of Navajo.
Sundt Generating Station
In 2018, TEP's PDEQ Application was approved. Under the project outlined in the PDEQ Application, TEP will place in service 10 natural gas RICE units with a total nominal generation capacity of 190 MW. The RICE units are scheduled for commercial operation by the end of the first quarter of 2020.

57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Consistent with the approved PDEQ Application, TEP plans to early retire Sundt Units 1 and 2 prior to start-up of the first RICE unit. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively.
ASSET RETIREMENT OBLIGATIONS
The accrual of AROs is primarily related to generation and PV assets and is included in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets:
 
December 31,
(in millions)
2018
 
2017
Beginning of Period
$
46

 
$
33

Liabilities Incurred (1)
10

 
3

Liabilities Settled
—

 
(1
)
Regulatory Deferral/Accretion Expense
3

 
2

Revisions to the Present Value of Estimated Cash Flows (2)
13

 
9

End of Period
$
72

 
$
46

(1) 
Primarily related to closure of the ash landfill at Springerville.
(2) 
Primarily related to changes in expected cost estimates for certain generation facilities.

NOTE 4. REVENUE
TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration. As of December 31, 2018, TEP's variable consideration included revenues that are subject to refund.
DISAGGREGATION OF REVENUES
The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Retail
$
1,022

 
$
1,017

 
$
969

Wholesale
238

 
152

 
106

Other Services
100

 
103

 
109

Revenues from Contracts with Customers
1,360

 
1,272

 
1,184

Alternative Revenues
28

 
24

 
20

Other
45

 
45

 
31

Total Operating Revenues
$
1,433

 
$
1,341

 
$
1,235

Retail Revenues
TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail Revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Once the usage is estimated, TEP applies the anticipated rate and records revenue. Unbilled revenues increase during the spring and summer months and decrease during the fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and

58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



cash collections results in billed and unbilled accounts receivable balances on the balance sheet. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.
In January 2018, TEP began to recognize a provision for revenues subject to refund, which reduced operating revenues, and a current regulatory liability for savings expected to be returned to customers from the Company’s federal income tax reduction under the TCJA. In April 2018, the ACC approved the ACC Refund Order effective May 1, 2018. As a result of the ACC Refund Order, the Company returned savings to customers through a bill credit. See Note 2 for more information regarding the ACC Refund Order.
Wholesale Revenues
TEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand (for capacity) or the reading of meters (for power). For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income.
In March 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the FERC Refund Order and proposed an overall transmission rate reduction. As a result, TEP began accruing a current regulatory liability and reduction in wholesale revenues. In November 2018, the FERC approved TEP's proposed revisions to its stated transmission rates. The related revenue subject to refund recorded did not have a material impact on TEP's financial position or results of operations. See Note 2 for more information regarding the FERC Refund Order.
Other Services Revenues
Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, miscellaneous service-related revenues, and reimbursement of various operating expenses for the use of the Springerville Common Facilities by Springerville Units 3 and 4 and the Springerville Coal Handling Facilities by Springerville Unit 3. As the operating agent for Springerville Units 3 and 4, TEP may be required to refund its monthly fee based on unit availability. When TEP recognizes revenue for reimbursement of Springerville Common Facilities and Springerville Coal Handling Facilities' operating expenses, the associated expenses are recorded in their respective line items on the income statement based on the nature of services provided.
Alternative Revenues
Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of applicable retail revenues of 2%. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding these cost recovery mechanisms.
Other Revenues
Other Revenues include gains and losses on derivative contracts, late and returned payment finance charges, and lease income. See Note 12 for information regarding derivative instruments.


59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 5. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:
 
December 31,
(in millions)
2018
 
2017
Customer (1) (2)
$
99

 
$
81

Customer, Unbilled
45

 
39

Due from Affiliates (Note 6)
8

 
7

Other
25

 
16

Allowance for Doubtful Accounts
(5
)
 
(5
)
Accounts Receivable, Net
$
172

 
$
138

(1) 
Includes $8 million and $9 million as of December 31, 2018 and 2017, respectively, of receivables related to revenue from derivative instruments.
(2) 
In 2018, Customer Accounts Receivable increased due to higher wholesale sales as a result of the increase in available system capacity related to Gila River Unit 2.

NOTE 6. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy Affiliates). These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor related services.
The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets:
 
December 31,
(in millions)
2018
 
2017
Receivables from Related Parties
 
 
 
UNS Electric
$
7

 
$
5

UNS Gas
1

 
2

Total Due from Related Parties
$
8

 
$
7

 
 
 
 
Payables to Related Parties
 
 
 
SES
$
2

 
$
3

UNS Electric
1

 
—

UNS Gas
1

 
—

UNS Energy
1

 
1

Total Due to Related Parties
$
5

 
$
4


60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The following table presents the components of related party transactions included in the Consolidated Statements of Income:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Goods and Services Provided by TEP to Affiliates
 
 
 
 
 
Transmission Revenues, UNS Electric (1) 
$
6

 
$
7

 
$
7

Wholesale Revenues, UNS Electric (1)
1

 
—

 
—

Control Area Services, UNS Electric (2)
3

 
3

 
2

Common Costs, UNS Energy Affiliates (3)
18

 
16

 
14

Corporate Services, Fortis Affiliates (4)
—

 
2

 
—

 
 
 
 
 
 
Goods and Services Provided by Affiliates to TEP
 
 
 
 
 
Wholesale Revenues, UNS Electric (1)
—

 
—

 
1

Supplemental Workforce, SES (5)
15

 
15

 
14

Corporate Services, UNS Energy (6)
6

 
5

 
7

Corporate Services, UNS Energy Affiliates (7)
7

 
5

 
4

Capacity Charges, UNS Gas (8)
1

 
—

 
—

(1) 
TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates through the applicable Open Access Transmission Tariff.
(2) 
TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.
(3) 
Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.
(4) 
TEP provides non-tariffed goods and services to Fortis affiliate companies at the higher of fully burdened cost or fair market value.
(5) 
SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.
(6) 
Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis Management fees. TEP's share of Fortis' management fees were $5 million in 2018 and $6 million in 2017 and 2016.
(7) 
Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
(8) 
UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.


61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 7. DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS
DEBT
Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets:
 
 
 
Maturity Date
 
December 31,
($ in millions)
Interest Rate
 
 
2018
 
2017
Notes
 
 
 
 
 
 
 
2011 Notes
5.15%
 
2021
 
$
250

 
$
250

2012 Notes
3.85%
 
2023
 
150

 
150

2014 Notes
5.00%
 
2044
 
150

 
150

2015 Notes
3.05%
 
2025
 
300

 
300

2018 Notes
4.85%
 
2048
 
300

 
—

Tax-Exempt Local Furnishings Bonds
 
 
 
 
 
 
 
2010 Pima A
5.25%
 
2040
 
100

 
100

2012 Pima A
4.50%
 
2030
 
16

 
16

2013 Pima A
4.00%
 
2029
 
91

 
91

2013 Apache A (1)
2.42%
 
2032
 
—

 
100

Tax-Exempt Pollution Control Bonds
 
 
 
 
 
 
 
2009 Pima A
4.95%
 
2020
 
80

 
80

2009 Coconino A
5.13%
 
2032
 
15

 
15

2010 Coconino A (2)
2.34%
 
2032
 
—

 
37

2012 Apache A
4.50%
 
2030
 
177

 
177

Total Long-Term Debt (3)
 
 
 
 
1,629

 
1,466

Less Unamortized Discount and Debt Issuance Costs
 
 
 
 
14

 
12

Less Current Maturities of Long-Term Debt
 
 
 
 
—

 
100

Total Long-Term Debt, Net
 
 
 
 
$
1,615

 
$
1,354

(1) 
Variable rate debt for which rates were reset monthly. The weighted average interest rate was calculated based on a percentage of an index equal to one-month LIBOR plus a credit spread. The interest rate for 2018 was calculated through the redemption date.
(2) 
Variable rate debt for which rates were reset weekly. The weighted average interest rate was calculated using a weighted average and includes LOC fees and remarketing fees. The interest rate for 2018 was calculated through the redemption date.
(3) 
As of December 31, 2018, all of TEP's debt is unsecured.
Debt Issuances and Redemptions
Fixed Rate Debt
In November 2018, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to June 1, 2048, with a make-whole premium plus accrued interest. On or after June 1, 2048, TEP may redeem the notes at par plus accrued interest.
Variable Rate Debt
In December 2018, TEP redeemed at par a series of variable rate tax-exempt bonds with an aggregate principal amount of $37 million prior to the maturity of the bonds. The bonds were backed by an LOC issued pursuant to the 2010 Reimbursement Agreement which was scheduled to expire in February 2019. In connection with the redemption of the related bonds, the $37 million LOC and the associated 2010 Reimbursement Agreement were terminated.
In November 2018, TEP redeemed at par a series of variable rate tax-exempt bonds with an aggregate principal amount of $100 million prior to the maturity of the bonds. The bonds were subject to mandatory tender for purchase in November 2018.

62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



CREDIT FACILITY
TEP's unsecured credit agreement with a maturity date of October 2022 included in Current Liabilities on the Consolidated Balance Sheets consists of the following:
 
Capacity
 
Sub-Limit LOC
 
Borrowed
 
Available
 
Weighted Average Interest Rate
 
Pricing (1)
(in millions)
December 31, 2018
Credit Facility
$
250

 
$
50

 
$
—

 
$
250

 
—
%
 
LIBOR + 1.000
%
or ABR + 0.00%
(in millions)
December 31, 2017
Credit Facility
$
250

 
$
50

 
$
35

 
$
215

 
2.56
%
 
LIBOR + 1.000
%
or ABR + 0.00%
(1) 
Interest rates and fees under the credit facility are based on a pricing grid tied to TEP's credit rating.
TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes. TEP will issue LOCs from time to time to support energy procurement and hedging transactions. As of February 14, 2019, there was $250 million available under the revolving credit commitments and LOC facilities.
CAPITAL LEASE OBLIGATIONS
The following table details Capital Lease Obligations on the Consolidated Balance Sheets:
 
December 31,
(in millions)
2018
 
2017
Gila River Unit 2
$
164

 
$
—

Springerville Common Facilities
29

 
39

Total Capital Lease Obligations
193

 
39

Less Current Portion
173

 
11

Total Capital Lease Obligations, Non-Current
$
20

 
$
28

Gila River Unit 2
In 2017, TEP entered into the Tolling PPA agreement, which includes a three-year option to purchase Gila River Unit 2. TEP’s obligations under the agreement were contingent upon the Gila Acquisition, which SRP completed in May 2018. As a result, TEP recorded an increase to both capital lease obligations and utility plant. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $164 million, the fair value of the unit as determined based on SRP's purchase price. Over the expected 20-month lease term, TEP will pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2. TEP recovers the monthly demand charge through the PPFAC.
Utility Plant Under Capital Leases on the Consolidated Balance Sheets reflects a balance related to the Tolling PPA of $164 million as of December 31, 2018.
Springerville Unit 1 Capital Lease Purchase
In September 2016, TEP purchased an undivided interest in Springerville Unit 1 for $85 million, bringing its total ownership of the assets to 100% for a total generation capacity of 387 MW. See Note 8 for more information regarding the settlement agreement relating to Springerville Unit 1.
Springerville Common Facilities Leases
As of December 31, 2018, the Springerville Common Facilities Leases include two leases with initial terms ending January 2021 and fixed price purchase options totaling $68 million. Under the two leases, TEP has options to: (i) renew the leases for periods of two or more years at fair market value; or (ii) exercise the fixed price purchase options under these contracts. In addition, TEP entered into agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions that become effective if the Common Facilities Leases are not renewed: (i) TEP will exercise the purchase options under these contracts; (ii) SRP will be obligated to buy a 14% undivided interest in the facilities; and (iii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make

63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



payments to TEP for the use of these facilities. If renewed, Tri-State and SRP will each pay 14% of the new fair market value rent.
In December 2017, TEP purchased a 17.8% undivided interest in the Springerville Common Facilities for $38 million, bringing its total ownership of the assets to 67.8%. Upon purchase of the leased interest, TEP reduced Current Lease Obligations on the Consolidated Balance Sheets by $36 million.
Springerville Common Facilities Lease Interest Rate Swap
TEP entered into an interest rate swap agreement in 2006 that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. The swap has the effect of fixing the benchmark LIBOR rate on a portion of the amortizing principal balance. The swap matures in January 2020 with interest on the lease debt payable at a swapped rate of 5.77% plus an applicable margin per the lease agreement. The lease debt outstanding as of December 31, 2018, consisted of a notional amount of $12 million on which interest was fixed by the swap and a notional amount of $2 million of debt that was not hedged. The applicable margin was 2.00% and 1.88% as of December 31, 2018 and 2017, respectively.
TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 12 for additional information.
DEBT MATURITIES
Long-term debt, including revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:
(in millions)
Long-Term Debt(1)
 
Capital Lease Obligations
 
Total Debt Maturities
2019
$
—

 
$
187

 
$
187

2020
80

 
20

 
100

2021
250

 
—

 
250

2022
—

 
—

 
—

2023
150

 
—

 
150

Total 2019 - 2023
480

 
207

 
687

Thereafter
1,149

 
—

 
1,149

Less: Imputed Interest
—

 
14

 
14

Total
$
1,629

 
$
193

 
$
1,822

(1) 
Total long-term debt excludes $11 million of related unamortized debt issuance costs and $3 million of unamortized original issue discount.

64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 8. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As of December 31, 2018, TEP had the following unconditional, minimum purchase obligations and operating leases:
(in millions)
2019
 
2020
 
2021
 
2022
 
2023
 
Thereafter
 
Total
Fuel, Including Transportation
$
85

 
$
74

 
$
45

 
$
26

 
$
19

 
$
175

 
$
424

Purchased Power
20

 
—

 
—

 
—

 
—

 
—

 
20

Transmission
19

 
9

 
5

 
3

 
3

 
9

 
48

Renewable Power Purchase Agreements
64

 
63

 
63

 
63

 
63

 
605

 
921

RES Performance-Based Incentives
8

 
8

 
7

 
7

 
7

 
39

 
76

Operating Leases (1)
1

 
1

 
1

 
1

 
1

 
5

 
10

Land Easements and Rights-of-Way (2)
1

 
1

 
2

 
1

 
1

 
80

 
86

Total Purchase Commitments
$
198

 
$
156

 
$
123

 
$
101

 
$
94

 
$
913

 
$
1,585

(1) 
Primarily represents leases for land, rail cars, and communication towers with varying terms, provisions, and expiration dates through 2041. TEP's operating lease expense totaled $1 million in 2018 and 2017 and $2 million in 2016.
(2) 
Land easements and rights-of-way have varying terms and provisions and reflect expiration dates through 2054.
Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.
Fuel, Including Transportation
TEP has long-term agreements for the purchase and delivery of coal with various expiration dates between 2019 and 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs.
In October 2018, Westmoreland Coal Company (WCC), the owner of San Juan Coal Company (SJCC), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. PNM, the operator of San Juan, has an existing Coal Supply Agreement (CSA) with WCC to supply coal to San Juan. TEP is not a party to the CSA, but has minimum purchase obligations under a joint participation agreement. WCC is expected to provide adequate liquidity to support continued operations at the San Juan Mine throughout the restructuring process. TEP believes it has adequate resource capacity to meet its near-term load obligations in the event WCC’s operations at the San Juan Mine are curtailed. TEP cannot currently predict the outcome of this matter or the long-term impacts on operations at San Juan.
TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2019 and 2040.
Purchased Power
TEP has contracts with utilities and other energy suppliers for purchased power to: (i) meet system load and energy requirements; (ii) replace generation from company-owned units under maintenance and during outages; and (iii) meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the second quarter of 2019. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2018.
Transmission
TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2019 and 2030.
Renewable Power Purchase Agreements
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 the

65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2036.
RES Performance-Based Incentives
TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2020 and 2034.
CONTINGENCIES
Legal Matters
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or 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 and are disclosed below.
Claims Related to Springerville Generating Station Unit 1
In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions and purchased the Third-Party Owners’ undivided interest in Springerville Unit 1 for $85 million. As also provided for in the Agreement, TEP received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues on the Consolidated Statements of Income. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice.
Claims Related to San Juan Generating Station
WildEarth Guardians
In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining (OSM) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to SJCC 's San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSM, including: (i) failure to provide requisite public notice and participation; and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM may prepare a new environmental impact statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the Court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSM’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. In May 2018, the OSM released a draft EIS for public comment which was open through July 2018. TEP cannot currently predict the outcome of this matter or the range of its potential impact.
Mine Reclamation at Generation Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $66 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The Consolidated Balance Sheets reflect a total liability related to mine reclamation of $36 million and $34 million as of December 31, 2018 and 2017, respectively.
Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
FERC Compliance
In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. In 2016, as a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements. In 2016, Operating Revenues on the Consolidated Statements of Income reflected a $22 million reduction in revenues, and, as of December 31, 2016, Current Liabilities—Other on the Consolidated Balance Sheets reflected $5 million related to the time-value refunds.
In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In January 2017, in accordance with the agreement, the counterparty paid TEP $8 million, which TEP recorded in Other Income on the Consolidated Statements of Income and dismissed the appeal with prejudice.
In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Consolidated Balance Sheets, offsetting Operating Revenues on the Consolidated Statements of Income.
Performance Guarantees
TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of December 31, 2018, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046.

NOTE 9. EMPLOYEE BENEFIT PLANS
PENSION BENEFIT PLANS
TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under IRS regulations. TEP also maintains a SERP for executive management.
OTHER POSTRETIREMENT BENEFITS PLAN
TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.
TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $3 million in 2018 and 2017 and $2 million in 2016 to the VEBA. Other postretirement benefits for unclassified employees are self-funded.
REGULATORY RECOVERY
TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income (Loss) since SERP expense is not currently recoverable in rates.

67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the balance sheet:
 
Pension Benefits
 
Other Postretirement Benefits
 
December 31,
(in millions)
2018
 
2017
 
2018
 
2017
Regulatory Assets
$
126

 
$
121

 
$
—

 
$
5

Regulatory Liabilities
—

 
—

 
(3
)
 
—

Accrued Employee Expenses
(1
)
 
(1
)
 
(3
)
 
(2
)
Pension and Other Postretirement Benefits
(63
)
 
(71
)
 
(54
)
 
(63
)
Accumulated Other Comprehensive Loss, SERP
6

 
9

 
—

 
—

Net Amount Recognized
$
68

 
$
58

 
$
(60
)
 
$
(60
)
OBLIGATIONS AND FUNDED STATUS
The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2018 and 2017. The table below presents the status of all of TEP’s pension and other postretirement benefit plans. All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented:
 
Pension Benefits
 
Other Postretirement Benefits
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2018
 
2017
Change in Benefit Obligation
 
 
 
 
 
 
 
Beginning of Period
$
475

 
$
424

 
$
82

 
$
79

Actuarial (Gain) Loss
(42
)
 
42

 
(8
)
 
1

Interest Cost
16

 
15

 
2

 
2

Service Cost
15

 
13

 
5

 
4

Benefits Paid
(23
)
 
(19
)
 
(5
)
 
(4
)
Plan Amendments
(1
)
 
—

 
(2
)
 
—

End of Period
440

 
475

 
74

 
82

Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
Beginning of Period
403

 
354

 
17

 
14

Actual Return on Plan Assets
(25
)
 
59

 
(1
)
 
2

Benefits Paid
(23
)
 
(19
)
 
(5
)
 
(4
)
Employer Contributions (1)
21

 
9

 
6

 
5

End of Period
376

 
403

 
17

 
17

Funded Status at End of Period
$
(64
)
 
$
(72
)
 
$
(57
)
 
$
(65
)
(1) 
TEP expects to contribute $11 million to the pension plans in 2019.
The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:
 
Pension Benefits
 
Other Postretirement Benefits
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2018
 
2017
Net (Gain) Loss
$
133

 
$
129

 
$
(1
)
 
$
5

Prior Service Cost (Benefit)
—

 
1

 
(2
)
 
(1
)

68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The accumulated benefit obligation aggregated for all pension plans was $402 million and $428 million as of December 31, 2018 and 2017, respectively. Two of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2018 and December 31, 2017. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:
 
December 31,
(in millions)
2018
 
2017
Accumulated Benefit Obligation
$
230

 
$
237

Fair Value of Plan Assets
202

 
206

The Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components:
 
Pension Benefits
 
Other Postretirement Benefits
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Service Cost
$
15

 
$
13

 
$
12

 
$
5

 
$
4

 
$
4

Interest Cost
16

 
15

 
15

 
2

 
2

 
2

Expected Return on Plan Assets
(28
)
 
(25
)
 
(23
)
 
(1
)
 
(1
)
 
(1
)
Amortization of Net Loss
7

 
8

 
7

 
—

 
—

 
—

Net Periodic Benefit Cost
$
10

 
$
11

 
$
11

 
$
6

 
$
5

 
$
5

The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. Approximately 19% of the 2018 service cost and approximately 18% of the 2017 net periodic benefit cost was capitalized as a cost of construction.
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows:
 
Pension Benefits
 
Other Postretirement Benefits
 
Regulatory Asset
 
AOCI
 
Regulatory Asset
(in millions)
2018
 
2017
 
2016
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Current Year Actuarial (Gain) Loss
$
12

 
$
5

 
$
15

 
$
(1
)
 
$
3

 
$
1

 
$
(6
)
 
$
(1
)
 
$
—

Amortization of Net Loss
(7
)
 
(7
)
 
(7
)
 
—

 
—

 
—

 
—

 
—

 
—

Prior Service Credit
—

 
—

 
—

 
(1
)
 
—

 
—

 
(2
)
 
—

 
—

Total Recognized (Gain) Loss
$
5

 
$
(2
)
 
$
8

 
$
(2
)
 
$
3

 
$
1

 
$
(8
)
 
$
(1
)
 
$
—

For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Estimated amortization from regulatory assets into net periodic benefit cost in 2019 includes the following:
(in millions)
Pension Benefits
 
Other Postretirement Benefits
Net Loss
$
8

 
$
—

Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.
TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes.

69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The following table includes the weighted average assumptions used to determine benefit obligations:
 
Pension Benefits
 
Other Postretirement Benefits
 
2018
 
2017
 
2018
 
2017
Discount Rate
4.5%
 
3.7%
 
4.3%
 
3.6%
Rate of Compensation Increase
2.8%
 
2.8%
 
N/A
 
N/A
The following table includes the weighted average assumptions used to determine net periodic benefit costs:
 
Pension Benefits
 
Other Postretirement Benefits
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Discount Rate, Service Cost
3.8%
 
4.4%
 
4.8%
 
3.8%
 
4.3%
 
4.6%
Discount Rate, Interest Cost
3.4%
 
3.7%
 
3.9%
 
3.2%
 
3.3%
 
3.4%
Rate of Compensation Increase
2.8%
 
2.8%
 
3.0%
 
N/A
 
N/A
 
N/A
Expected Return on Plan Assets
7.0%
 
7.0%
 
7.0%
 
7.0%
 
7.0%
 
7.0%
Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:
 
December 31,
 
2018
 
2017
Next Year (Pre-65)
6.5%
 
6.5%
Next Year (Post-65)
7.8%
 
7.6%
Ultimate Rate Assumed (Pre-65 and Post-65)
4.5%
 
4.5%
Year Ultimate Rate is Reached (Pre-65)
2037
 
2037
Year Ultimate Rate is Reached (Post-65)
2037
 
2036
Assumed healthcare cost trend rates significantly affect the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost trend rates would have the following effects on the amounts:
 
One-Percentage-
Point Increase
 
One-Percentage-
Point Decrease
(in millions)
December 31, 2018
Total Service and Interest Cost Components Increase (Decrease)
$
1

 
$
(1
)
Other Postretirement Benefits Obligation Increase (Decrease)
7

 
(6
)
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS
TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows:
 
Pension
 
Other Postretirement Benefits
 
2018
 
2017
 
2018
 
2017
Asset Category
 
 
 
 
 
Equity Securities
45
%
 
46
%
 
60
%
 
63
%
Fixed Income Securities
45
%
 
45
%
 
38
%
 
35
%
Real Estate
8
%
 
7
%
 
—
%
 
—
%
Other
2
%
 
2
%
 
2
%
 
2
%
Total
100
%
 
100
%
 
100
%
 
100
%
As of December 31, 2018, the fair value of VEBA trust assets was $17 million, of which $7 million were fixed income investments and $10 million were equities. As of December 31, 2017, the fair value of VEBA trust assets was $17 million, of which $6 million were fixed income investments and $11 million were equities. The VEBA trust assets are primarily Level 2 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust.

70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy:
 
Level 1
 
Level 2
 
Level 3
 
Total
(in millions)
December 31, 2018
Asset Category
 
 
 
 
 
 
 
Cash Equivalents
$
1

 
$
—

 
$
—

 
$
1

Equity Securities:
 
 
 
 
 
 
 
United States Large Cap
—

 
45

 
—

 
45

United States Small Cap
—

 
17

 
—

 
17

Non-United States
—

 
67

 
—

 
67

Global
—

 
42

 
—

 
42

Fixed Income
—

 
167

 
—

 
167

Real Estate
—

 
9

 
22

 
31

Private Equity
—

 
—

 
6

 
6

Total
$
1

 
$
347

 
$
28

 
$
376

 
 
 
 
 
 
 
 
(in millions)
December 31, 2017
Asset Category
 
 
 
 
 
 
 
Cash Equivalents
$
1

 
$
—

 
$
—

 
$
1

Equity Securities:
 
 
 
 
 
 


United States Large Cap
—

 
66

 
—

 
66

United States Small Cap
—

 
19

 
—

 
19

Non-United States
—

 
72

 
—

 
72

Global
—

 
30

 
—

 
30

Fixed Income
—

 
179

 
—

 
179

Real Estate
—

 
9

 
21

 
30

Private Equity
—

 
—

 
6

 
6

Total
$
1

 
$
375

 
$
27

 
$
403

•
Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit.
•
Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
•
Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties.
•
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.

71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
(in millions)
Private Equity
 
Real Estate
 
Total
Balance as of December 31, 2016
$
7

 
$
19

 
$
26

Actual Return on Plan Assets:
 
 
 
 


Assets Held at Reporting Date
1

 
2

 
3

Purchases, Sales, and Settlements
(2
)
 
—

 
(2
)
Balance as of December 31, 2017
6

 
21

 
27

Actual Return on Plan Assets:
 
 
 
 
 
Assets Held at Reporting Date
2

 
1

 
3

Purchases, Sales, and Settlements
(2
)
 
—

 
(2
)
Balance as of December 31, 2018
$
6

 
$
22

 
$
28

Pension Plan Investments
Investment Goals
Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.
Risk Management
TEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
Relationship between Plan Assets and Benefit Obligations
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation.

72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Target Allocation Percentages
The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced.
 
Pension
 
Other Postretirement Benefits
 
December 31, 2018
Cash/Treasury Bills
—%
 
2%
Equity Securities:
 
 
 
United States Large Cap
12%
 
39%
United States Small Cap
5%
 
5%
Non-United States Developed
—%
 
7%
Non-United States Emerging
—%
 
9%
Global Equity
26%
 
—%
Global Infrastructure
3%
 
—%
Fixed Income
45%
 
38%
Real Estate
8%
 
—%
Private Equity
1%
 
—%
Total
100%
 
100%
Pension Fund Descriptions
For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds.
ESTIMATED FUTURE BENEFIT PAYMENTS
TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate.
(in millions)
2019
 
2020
 
2021
 
2022
 
2023
 
2024-2028
Pension Benefits
$
22

 
$
23

 
$
24

 
$
25

 
$
26

 
$
139

Other Postretirement Benefits
5

 
5

 
5

 
6

 
6

 
28

DEFINED CONTRIBUTION PLAN
TEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $7 million in 2018, $6 million in 2017, and $5 million in 2016.

NOTE 10. SHARE-BASED COMPENSATION
2015 SHARE UNIT PLAN
The Human Resources and Governance Committee (Committee) of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (Plan) effective January 2015. Under the Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of performance-based share units (PSU) and time-based restricted share units (RSU) annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula.

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The following table represents PSUs and RSUs awarded by UNS Energy:
 
2018
 
2017
 
2016
PSUs
54,426

 
68,126

 
66,974

RSUs
27,213

 
34,063

 
33,488

The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $9 million as of December 31, 2018 and 2017.
TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $2 million in 2018, $4 million in 2017, and $2 million in 2016 based on its share of UNS Energy's compensation expense.

NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION
CASH TRANSACTIONS
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Interest, Net of Amounts Capitalized
$
67

 
$
61

 
$
61

Income Taxes (1)
—

 
—

 
—

(1) 
TEP did not pay federal or state income taxes due to net operating loss carryforwards offsetting taxable income.
NON-CASH TRANSACTIONS
Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Gila River Unit 2, Capital Lease
$
164

 
$
—

 
$
—

Accrued Capital Expenditures
31

 
24

 
29

Asset Retirement Obligations Increase (Decrease) (1)
20

 
10

 
(1
)
Renewable Energy Credits
3

 
2

 
2

Commitment to Purchase Capital Lease Interests
—

 
—

 
36

Net Cost of Removal Increase (Decrease) (2)
(4
)
 
(88
)
 
8

(1) 
The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future AROs.
(2) 
Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. As approved in the 2017 TEP Rate Order, TEP implemented new depreciation reserves and rates effective March 1, 2018. See Note 2 for additional information.

NOTE 12. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:
 
Level 1
 
Level 2
 
Level 3
 
Total
(in millions)
December 31, 2018
Assets
 
Cash Equivalents(1)
$
125

 
$
—

 
$
—

 
$
125

Restricted Cash(1)
15

 
—

 
—

 
15

Energy Derivative Contracts, Regulatory Recovery(2)
—

 
10

 
—

 
10

Energy Derivative Contracts, No Regulatory Recovery(2)
—

 
—

 
2

 
2

Total Assets
140

 
10

 
2

 
152

Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts, Regulatory Recovery(2)
—

 
(35
)
 
(2
)
 
(37
)
Total Liabilities
—

 
(35
)
 
(2
)
 
(37
)
Total Assets (Liabilities), Net
$
140

 
$
(25
)
 
$
—

 
$
115

(in millions)
December 31, 2017
Assets
 
Cash Equivalents(1)
$
30

 
$
—

 
$
—

 
$
30

Restricted Cash(1)
12

 
—

 
—

 
12

Energy Derivative Contracts, Regulatory Recovery(2)
—

 
9

 
—

 
9

Energy Derivative Contracts, No Regulatory Recovery(2)
—

 
—

 
3

 
3

Total Assets
42

 
9

 
3

 
54

Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts, Regulatory Recovery(2)
—

 
(26
)
 
—

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

 
—

 
(1
)
 
(1
)
Interest Rate Swap(3)
—

 
(1
)
 
—

 
(1
)
Total Liabilities
—

 
(27
)
 
(1
)
 
(28
)
Total Assets (Liabilities), Net
$
42

 
$
(18
)
 
$
2

 
$
26

(1) 
Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Consolidated Balance Sheets.
(2) 
Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets.
(3) 
The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Consolidated Balance Sheets.

75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.
 
Gross Amount Recognized in the Balance Sheets
 
Gross Amount Not Offset in the Balance Sheets
 
Net Amount
 
 
Counterparty Netting of Energy Contracts
 
Cash Collateral Received/Posted
 
(in millions)
December 31, 2018
Derivative Assets
 
 
 
 
 
 
 
Energy Derivative Contracts
$
12

 
$
11

 
$
—

 
$
1

Derivative Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts
(37
)
 
(11
)
 
—

 
(26
)
(in millions)
December 31, 2017
Derivative Assets
 
 
 
 
 
 
 
Energy Derivative Contracts
$
12

 
$
10

 
$
—

 
$
2

Derivative Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts
(27
)
 
(10
)
 
—

 
(17
)
Interest Rate Swap
(1
)
 
—

 
—

 
(1
)
DERIVATIVE INSTRUMENTS
TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism.
The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Cash Flow Hedges
To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires in January 2020. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months is not material to TEP's financial position or results of operations.

76
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



The table below presents realized losses recorded to Interest Expense as well as total Interest Expense on the Consolidated Statements of Income:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Realized Loss From Cash Flow Hedge
$
—

 
$
1

 
$
1

Interest Expense
68

 
65

 
66

As of December 31, 2018, the total notional amount of the interest rate swap was $12 million.
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Unrealized Net Gain (Loss)
$
(9
)
 
$
(18
)
 
$
12

Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Operating Revenues
$
5

 
$
5

 
$
4

Derivative Volumes
As of December 31, 2018, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:
 
December 31,
 
2018
 
2017
Power Contracts GWh
1,743

 
2,589

Gas Contracts BBtu
146,933

 
137,952

Level 3 Fair Value Measurements
The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
 
Valuation
 
Fair Value of
 
 
 
Range of
 
Approach
 
Assets
 
Liabilities
 
Unobservable Inputs
 
Unobservable Input
(in millions)
December 31, 2018
Forward Power Contracts
Market approach
 
$
3

 
$
(2
)
 
Market price per MWh
 
$
16.80

 
$
47.05

 
December 31, 2017
Forward Power Contracts
Market approach
 
$
3

 
$
(1
)
 
Market price per MWh
 
$
17.65

 
$
34.60

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a

77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



regulatory asset or regulatory liability, or as a component of other comprehensive income (loss), rather than in the income statement.
The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:
 
Years Ended December 31,
(in millions)
2018
 
2017
Beginning of Period
$
2

 
$
1

Gains (Losses) Recorded
 
 
 
Regulatory Assets or Liabilities, Derivative Instruments
(4
)
 
1

Operating Revenues
5

 
4

Settlements
(2
)
 
(4
)
End of Period
$
1

 
$
2

 
 
 
 
Gains (Losses), Assets (Liabilities) Still Held
$
1

 
$
2

CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.
TEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOC, or other acceptable security to collateralize exposure beyond the allowed amounts.
TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.
The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $41 million as of December 31, 2018, compared with $27 million as of December 31, 2017. As of December 31, 2018, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on December 31, 2018, TEP would have been required to post an additional $41 million of collateral of which $16 million relates to outstanding net payable balances for settled positions.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt:
 
Fair Value Hierarchy
 
Face Value
 
Fair Value
 
 
 
December 31,
(in millions)
 
 
2018
 
2017
 
2018
 
2017
Liabilities
 
 
 
 
 
 
 
 
 
Long-Term Debt, including Current Maturities
Level 2
 
$
1,629

 
$
1,466

 
$
1,672

 
$
1,547


78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 13. INCOME TAXES
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 to pre-tax income due to the following:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Federal Income Tax Expense at Statutory Rate
$
49

 
$
97

 
$
64

State Income Tax Expense, Net of Federal Deduction
9

 
9

 
6

Federal/State Tax Credits
(10
)
 
(9
)
 
(8
)
Allowance for Equity Funds Used During Construction
(1
)
 
(2
)
 
(1
)
Deferred Tax Asset Valuation Allowance
—

 
—

 
(2
)
Impact of Enactment, TCJA
—

 
7

 
—

Excess Deferred Income Taxes
(6
)
 
—

 
—

Impact of AMT Sequestration
2


—


—

Other
—

 
(1
)
 
—

Total Federal and State Income Tax Expense
$
43

 
$
101

 
$
59

Income Tax Expense included on the Consolidated Income Statement consists of the following:
 
Years Ended December 31,
(in millions)
2018
 
2017
 
2016
Current Income Tax Expense
 
 
 
 
 
Federal
$
(13
)
 
$
—

 
$
—

State
—

 
—

 
—

Total Current Income Tax Expense
(13
)
 
—

 
—

Deferred Income Tax Expense
 
 
 
 
 
Federal
53

 
98

 
60

Federal Investment Tax Credits
(6
)
 
(6
)
 
(6
)
State
9

 
9

 
5

Total Deferred Income Tax Expense
56

 
101

 
59

Total Federal and State Income Tax Expense
$
43

 
$
101

 
$
59

On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. In addition, the TCJA provided modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities.
As a result of the TCJA, the Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment. This resulted in a net decrease to deferred income tax liabilities. Since the Company believes it is probable that a significant portion of the decrease will be returned to customers through future rates, a regulatory liability was established. TEP is amortizing the EDIT balance in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining life of the related plant.
In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $6 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2018. See Note 2 for additional information regarding the ACC Refund Order and the FERC NOPR.
Under the TCJA, AMT credit carryforwards will be refunded if not used to offset federal income tax liabilities. As of December 31, 2018, TEP had a receivable of $13 million related to the AMT credit carryforwards in Current Assets—Other on the Consolidated Balance Sheets.
In 2018, the Company recorded $2 million of income tax expense related to the estimated impact of sequestration on future AMT credit refunds. In January 2019, the IRS revised its previously-issued guidance on this matter and announced that future

79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



AMT credit refunds will no longer be subject to sequestration. As a result, the Company anticipates receiving additional AMT credit refunds of $2 million in future periods.
In August 2018, the IRS proposed regulations on bonus depreciation. Based on the proposed regulation, the Company adjusted its estimated provision for its 2017 tax year and the results of such adjustment did not have a material impact on TEP's financial position or results of operations. TEP's accounting for the income tax effects of the bonus depreciation provisions included in the TCJA has been completed as of December 31, 2018.
The significant components of deferred income tax assets and liabilities consist of the following:
 
December 31,
(in millions)
2018
 
2017
Gross Deferred Income Tax Assets
 
 
 
Capital Lease Obligations
$
48

 
$
10

Operating Loss Carryforwards, Net
23

 
56

Customer Advances and Contributions in Aid of Construction
16

 
14

Alternative Minimum Tax Credit
13

 
26

Other Postretirement Benefits
15

 
15

Investment Tax Credit Carryforward
34

 
34

Income Taxes Recoverable Through Future Rates
87

 
88

Other
60

 
50

Total Gross Deferred Income Tax Assets
296

 
293

Deferred Tax Assets Valuation Allowance
—

 
—

Gross Deferred Income Tax Liabilities
 
 
 
Plant, Net
(552
)
 
(518
)
Plant Abandonments
(18
)
 
(21
)
Capital Lease Assets, Net
(44
)
 
(5
)
Pensions
(19
)
 
(16
)
Income Taxes Payable Through Future Rates
(12
)
 
(10
)
Other
(21
)
 
(23
)
Total Gross Deferred Income Tax Liabilities
(666
)
 
(593
)
Deferred Income Taxes, Net
$
(370
)
 
$
(300
)
TEP recorded no valuation allowance against credit and net operating loss carryforward deferred income tax assets as of December 31, 2018 and 2017. Management believes TEP will produce sufficient taxable income in the future to realize credit and net operating loss carryforwards before they expire.
As of December 31, 2018, TEP had the following carryforward amounts:
(in millions)
Amount
 
Expiring Year
Federal Net Operating Loss
$
108

 
2033-35
State Credits
9

 
2021-29
Alternative Minimum Tax Credit
13

 
None
Investment Tax Credits
34

 
2031-37

80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Uncertain Tax Positions
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
 
December 31,
(in millions)
2018
 
2017
Beginning of Period
$
13

 
$
12

Additions Based on Tax Positions Taken in the Current Year
3

 
7

Reduction to Positions, TCJA
—

 
(6
)
End of Period
$
16

 
$
13

Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 2018 and 2017.
TEP recorded no interest expense during 2018 and 2017 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2018 and 2017.
TEP has been audited by the IRS through tax year 2010. TEP's 2011 to 2018 tax years are open for audit by federal and state tax agencies.
The balance in unrecognized tax benefits could change in the next 12 months as a result of the IRS audit, but the Company is unable to determine the amount of change.


81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED)
TEP's quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. TEP's utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
(in millions)
2018
Operating Revenue
$
275

 
$
354

 
$
460

 
$
344

Operating Income
43

 
83

 
126

 
36

Net Income
24

 
58

 
95

 
11

 
 
 
 
 
 
 
 
 
2017
Operating Revenue
$
268

 
$
352

 
$
417

 
$
304

Operating Income
37

 
107

 
138

 
44

Net Income
21

 
61

 
82

 
13


82

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

ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures are effective as of December 31, 2018.
Management’s Report on Internal Control Over Financial Reporting
TEP’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of TEP’s internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations Internal Control – Integrated Framework.
Based on management’s assessment using those criteria, management has concluded that, as of December 31, 2018, TEP’s internal control over financial reporting was effective.
Changes in Internal Control Over Financial Reporting
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during the fourth quarter of 2018 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting. During 2018, we designed modifications to our internal control over financial reporting related to gathering contracts and contract review requirements associated with accounting for leases.

ITEM 9B. OTHER INFORMATION
None.


83

PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Pre-Approved Policies and Procedures
Rules adopted by the SEC in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. UNS Energy’s Audit and Risk Committee has adopted a policy pursuant to which audit, audit-related, tax, and other services are pre-approved by category of service. Recognizing that situations may arise where it is in the Company’s best interest for the auditor to perform services in addition to the annual audit of the Company’s financial statements, the policy sets forth guidelines and procedures with respect to approval of the four categories of service designed to achieve the continued independence of the auditor when it is retained to perform such services for UNS Energy. The policy requires the Audit and Risk Committee to be informed of each service and does not include any delegation of the Audit and Risk Committee’s responsibilities to management. The Audit and Risk Committee may delegate to the Chair of the Audit and Risk Committee the authority to grant pre-approvals of audit and non-audit services requiring Audit and Risk Committee approval where the Audit and Risk Committee Chair believes it is desirable to pre-approve such services prior to the next regularly scheduled Audit and Risk Committee meeting. The decisions of the Audit and Risk Committee Chair to pre-approve any such services from one regularly scheduled Audit Committee meeting to the next shall be reported to the Audit and Risk Committee.
Fees
The Audit and Risk Committee has considered whether the provision of services to TEP by Deloitte & Touche LLP (Deloitte), beyond those rendered in connection with their audit and review of TEP’s financial statements, is compatible with maintaining their independence as auditor.
The following table details principal accountant fees paid to Deloitte for professional services:
(in thousands)
2018
 
2017
Audit Fees
$
1,302

 
$
1,108

Audit-Related Fees
115

 
17

Tax Fees
—

 
68

All Other Fees
—

 
24

Total
$
1,417

 
$
1,217

Audit Fees includes fees for audit services for TEP's consolidated financial statements included in its Annual Report on Form 10-K and review services of TEP's consolidated financial statements included in its Quarterly Reports on Form 10-Q. Audit

84

Fees also includes services provided in connection with comfort letters, consents, and other services related to SEC matters, financing transactions, and statutory and regulatory audits.
Audit-Related Fees includes fees for consulting services with respect to the TCJA and valuation procedures in 2018 and ASC 606 Revenue Recognition in 2017.
Tax Fees includes fees for research and development services with respect to tax credits in 2017.
All Other Fees includes fees for consulting services with respect to regulatory filings in 2017.
All services performed by our principal accountant are approved in advance by the Audit and Risk Committee in accordance with the Audit and Risk Committee’s pre-approval policy for services provided by the Independent Registered Public Accounting Firm.


85

PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
 
 
Page
(a)
(1)
Consolidated Financial Statements as of December 31, 2018 and 2017, and for each of the three years in the period ended December 31, 2018:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(2)
Financial Statement Schedule
 
 
 
All schedules have been omitted because they are either not applicable, not required, or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.
 
 
 
 
 
 
(3)
Exhibits
 
 
 
Reference is made to the Exhibit Index commencing on page 87.
 

ITEM 16. FORM 10-K SUMMARY
Not Applicable.


86


Exhibit Index
Exhibit No.
 
Description
 
Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for the year ended December 31, 1996, File No. 1-05924 - Exhibit No 3(a)).
 
 
 
 
TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-05924 - Exhibit 3(a)).
 
 
 
 
Bylaws of TEP, as amended as of August 12, 2015 (Form 10-Q for the quarter ended September 30, 2015, File No. 1-05924 - Exhibit 3).
 
 
 
 
Amendment to Articles of Incorporation of UNS Energy Corporation, creating series of Limited Voting Junior Preferred Stock (Form 8-K dated August 12, 2015, File No. 1-05924 - Exhibit 3.2).
 
 
 
 
Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(A)).
 
 
 
 
Loan Agreement, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company San Juan Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(B)).
 
 
 
 
Indenture of Trust, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(C)).
 
 
 
 
Loan Agreement, dated as of October 1, 2009, between Coconino County, Arizona Pollution Control Corporation and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(D)).
 
 
 
 
Indenture of Trust, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-05924 Exhibit 4(a)).
 
 
 
 
Loan Agreement, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-05924 - Exhibit 4(b)).
 
 
 
 
Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(a)).
 
 
 
 
Loan Agreement, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(b)).
 
 
 
 
Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(a)).
 
 
 
 
Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(b)).
 
 
 

87


 
Indenture of Trust, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(a)).
 
 
 
 
Loan Agreement, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(b)).
 
 
 
 
Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank National Association, as trustee, authorizing unsecured Notes (Form 8-K dated November 8, 2011, File 1-05924 - Exhibit 4.1).
 
 
 
 
Officers Certificate, dated November 8, 2011, authorizing 5.15% Notes due 2021 (Form 8-K dated November 8, 2011, File No. 1-05924 - Exhibit 4.2).
 
 
 
 
Officers Certificate, dated September 14, 2012, authorizing 3.85% Notes due 2023 (Form 8-K dated September 14, 2012, File No. 1-05924 - Exhibit 4.1).
 
 
 
 
Officer's Certificate, dated March 10, 2014, authorizing 5.00% Senior Notes due 2044 (Form 8-K dated March 10, 2014, File No. 1-05924 - Exhibit 4.1).
 
 
 
 
Officer's Certificate, dated February 27, 2015, authorizing 3.05% Senior Notes due 2025 (Form 8-K dated February 27, 2015, File No. 1-05924 - Exhibit 4(a)).
 
 
 
 
Officer's Certificate, dated November 29, 2018, authorizing 4.85% Senior Notes due 2048.
 
 
 
 
Credit Agreement, dated as of October 15, 2015, among Tucson Electric Power Company, MUFG Union Bank, N.A. as Administrative Agent, and a group of lenders (Form 8-K dated October 15, 2015, File No. 1-05924 - Exhibit 4.1).
 
 
 
 
Power of Attorney.
 
 
 
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens.
 
 
 
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino.
 
 
 
 
Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
 
 
 
101.INS
 
XBRL Instance Document.
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document.
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
*
 
Previously filed as indicated and incorporated herein by reference.
**
 
Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

88



SIGNATURES
Pursuant to the requirements of section 13 or 15(b) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
TUCSON ELECTRIC POWER COMPANY
 
 
 
(Registrant)
 
 
 
 
Date:
February 14, 2019
 
/s/ Frank P. Marino
 
 
 
Frank P. Marino
 
 
 
Sr. Vice President, Chief Financial Officer, and Director
 
 
 
(Principal Financial Officer and Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
 
 
 
Date:
February 14, 2019
 
*
 
 
 
David G. Hutchens
 
 
 
President, Chief Executive Officer, and Director
 
 
 
(Principal Executive Officer)
 
 
 
Date:
February 14, 2019
 
/s/ Frank P. Marino
 
 
 
Frank P. Marino
 
 
 
Sr. Vice President, Chief Financial Officer, and Director
 
 
 
(Principal Financial Officer and Principal Accounting Officer)
 
 
 
Date:
February 14, 2019
 
*
 
 
 
Todd C. Hixon
 
 
 
Director
 
 
 
 
 
*By:
/s/ Frank P. Marino
 
 
 
Frank P. Marino
 
 
 
Attorney-in-fact


89