10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2019

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	86-0062700
(State or other jurisdiction of incorporation or organization)	(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 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 Filer o Accelerated Filer o Non-Accelerated Filer ☒ Smaller Reporting Company ☐ Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

i

State the aggregate market value of the voting and non-voting common equity held by non-affiliates: None

As of February 12, 2020, 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.

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Table of Contents

Definitions	v
Forward-Looking Information	viii
PART I
Item 1. Business	1
Overview of Business	1
Environmental Matters	8
Employees	8
Information about our Executive Officers	9
SEC Reports Available	9
Item 1A. Risk Factors	10
Item 1B. Unresolved Staff Comments	14
Item 2. Properties	14
Item 3. Legal Proceedings	15
Item 4. Mine Safety Disclosures	15
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	16
Item 6. Selected Financial Data	16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Critical Accounting Policies and Estimates	30
New Accounting Standards Issued and Not Yet Adopted	33
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	33
Item 8. Consolidated Financial Statements and Supplementary Data	35
Report of Independent Registered Public Accounting Firm	35
Consolidated Statements of Income	36
Consolidated Statements of Comprehensive Income	37
Consolidated Statements of Cash Flows	38
Consolidated Balance Sheets	39
Consolidated Statements of Changes in Stockholder's Equity	41
Notes to Consolidated Financial Statements	42
Note 1. Nature of Operations and Summary of Significant Accounting Policies	42
Note 2. Regulatory Matters	48
Note 3. Utility Plant and Jointly-Owned Facilities	53
Note 4. Revenue	55
Note 5. Accounts Receivable	56
Note 6. Related Party Transactions	57
Note 7. Debt and Credit Agreements	58
Note 8. Leases	60
Note 9. Commitments and Contingencies	63
Note 10. Employee Benefit Plans	65
Note 11. Share-Based Compensation	71
Note 12. Supplemental Cash Flow Information	72
Note 13. Fair Value Measurements and Derivative Instruments	73
Note 14. Income Taxes	77
Note 15. Quarterly Financial Data (Unaudited)	80

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	81
Item 9A. Controls and Procedures	81
Item 9B. Other Information	81
PART III
Item 10. Directors, Executive Officers, and Corporate Governance	82
Item 11. Executive Compensation	82
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	82
Item 13. Certain Relationships and Related Transactions and Director Independence	82
Item 14. Principal Accountant Fees and Services	82
PART IV
Item 15. Exhibits and Financial Statement Schedules	84
Item 16. Form 10-K Summary	84
Exhibits	85
Signatures	87

iv

DEFINITIONS

The abbreviations and acronyms used in the 2019 Form 10-K are defined below:

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

2010 Reimbursement Agreement	Reimbursement Agreement, dated December 14, 2010 between TEP, as borrower, and a financial institution
2015 Credit Agreement	The 2015 Credit Agreement provides for a $250 million revolving credit and letter of credit facilities with a sublimit of $50 million; the credit agreement matures in 2020
2019 Credit Agreement	The 2019 Credit Agreement provides for up to $225 million in term loans; the credit agreement matures in 2020
2019 Rate Case	A pending general rate case filed with the ACC by TEP in April 2019 requesting new rates be implemented in May 2020
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, effective May 1, 2018
ACE	Affordable Clean Energy
ADEQ	Arizona Department of Environmental Quality
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
AMT	Alternative Minimum Tax
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
CCR	Coal Combustion Residuals
DG	Distributed Generation
DSM	Demand Side Management
ECA	Environmental Compliance Adjustor
EDIT	Excess Deferred Income Taxes
EE Standards	Energy Efficiency Standards
EIM	Energy Imbalance Market
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FERC Refund Order	An order issued by the FERC approving TEP's proposal of an overall transmission rate reduction reflecting the lower federal tax rate, effective March 21, 2018
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
LFCR	Lost Fixed Cost Recovery
LIBOR	London Interbank Offered Rate
LOC	Letter(s) of Credit
NERC	North American Electric Reliability Corporation
NOPR	Notice of Proposed Rulemaking
OATT	Open Access Transmission Tariff
PBI	Performance Based Incentives
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
PSU	Performance-Based Share Units

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PURPA	Public Utility Regulatory Policies Act
PV	Photovoltaic
RCRA	Resource Conservation and Recovery Act
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 costs of providing services and an opportunity to earn a reasonable return on its investment
RICE	Reciprocating Internal Combustion Engine
RMC	Risk Management Committee
RSU	Restricted Share Units
SERP	Supplemental Executive Retirement Plan
TCA	Transmission Cost Adjustor
TCJA	Tax Cuts and Jobs Act
TEAM	Tax Expense Adjustor Mechanism
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 included a three-year option to purchase the unit
VEBA	Voluntary Employee Beneficiary Association
VIE	Variable Interest Entity

ENTITIES AND GENERATING STATIONS

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
FortisUS	Fortis intermediate holding company
Four Corners	Four Corners Generating Station
Gila River	Gila River Generating Station
Luna	Luna Generating Station
Navajo	Navajo Generating Station
Oso Grande	A 250 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico
PNM	Public Service Company of New Mexico
San Juan	San Juan Generating Station
SES	Southwest Energy Solutions, Inc.
SJCC	San Juan Coal Company
Springerville	Springerville Generating Station
Springerville Common Facilities	Portion of the facilities at Springerville used in common with Springerville Unit 1 and Unit 2
SRP	Salt River Project Agricultural Improvement and Power District
Sundt	H. Wilson Sundt Generating Station
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Tri-State	Tri-State Generation and Transmission Association, Inc.
UASTP	University of Arizona Science and Technology Park
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

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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 Corporation

UNITS OF MEASURE

AC	Alternating Current
BBtu	Billion British thermal unit(s)
GWh	Gigawatt-hour(s)
kWh	Kilowatt-hour(s)
MMBtu	Million Metric British thermal units
MW	Megawatt(s)
MWh	Megawatt-hour(s)

vii

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. 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 and any change in the structure of utility service in Arizona resulting from the ACC's examination of the state's 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; the outcome of the general rate case filed with the ACC in April 2019; the outcome of the proposal filed with the FERC in May 2019 requesting revisions to TEP's OATT; regional economic and market conditions that 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 PPAs are sufficient to meet the expected demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital and use the proceeds from any capital that we do raise as originally intended; 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 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; the development of our wind powered electric generation facility in southeastern New Mexico; participation in the EIM; and the impact of the TCJA on our financial condition and results of operations, including the assumptions we make relating thereto.

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PART I

ITEM 1. BUSINESS

OVERVIEW OF BUSINESS

General

TEP and its predecessor companies have served the greater Tucson metropolitan area for 127 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 429,000 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, a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis which is a leader in the North American electric and gas utility business.

Regulated Utility Operations

TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for coal, natural gas, wind, and solar generation resources to provide electricity. This electricity, together with electricity purchased in 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 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)	2019			2018			2017			2016			2015
Electric Sales
Residential	3,698	22	%	3,766	24	%	3,786	29	%	3,724	29	%	3,724	28	%
Commercial	2,077	13	%	2,136	14	%	2,192	17	%	2,139	17	%	2,124	15	%
Industrial, non-Mining	1,896	11	%	1,949	12	%	1,939	15	%	2,006	16	%	2,063	15	%
Industrial, Mining	1,057	6	%	1,033	7	%	991	8	%	997	8	%	1,109	8	%
Other	16	—	%	16	—	%	18	—	%	30	—	%	33	—	%
Total Retail Sales by Customer Class	8,744	53	%	8,900	57	%	8,926	68	%	8,896	70	%	9,053	66	%
Wholesale Sales, Long-Term	490	3	%	424	3	%	587	4	%	463	4	%	750	5	%
Wholesale Sales, Short-Term(1)	7,257	44	%	6,279	40	%	3,630	28	%	3,308	26	%	3,928	29	%
Total Electric Sales	16,491	100	%	15,603	100	%	13,143	100	%	12,667	100	%	13,731	100	%
Average Number of Retail Customers
Residential	387,409	90	%	384,021	90	%	381,399	90	%	378,991	90	%	376,439	90	%
Commercial	38,838	9	%	38,642	9	%	38,564	9	%	38,403	9	%	38,253	9	%
Industrial, non-Mining	503	—	%	504	—	%	520	—	%	580	—	%	588	—	%
Industrial, Mining	4	—	%	4	—	%	4	—	%	4	—	%	4	—	%
Other	1,872	1	%	1,873	1	%	1,879	1	%	1,866	1	%	1,857	1	%
Total Retail Customers	428,626	100	%	425,044	100	%	422,366	100	%	419,844	100	%	417,141	100	%

⁽¹⁾  Short-term wholesale sales increased due to the increase in generation capacity related to Gila River Unit 2.

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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, 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 2020 based on the estimated population growth in its service territory.

TEP’s retail sales volume in 2019 was 8,744 GWh, which is a decrease of 3% from 2015 levels. During the past five years, mining load reductions and state requirements to promote energy efficiency and DG have resulted in lower sales volumes.

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.

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.

Energy Imbalance Market

In May 2019, TEP signed an agreement with the California Independent System Operator indicating its intent to begin participating in the Energy Imbalance Market (EIM) by spring of 2022. Participation in the EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the EIM, TEP must demonstrate resource adequacy through a combination of owned or contracted resources. TEP's participation in the EIM is expected to: (i) reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance reliability through improved system utilization and responsiveness.

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 2018, the ACC opened a docket to evaluate several energy policies including retail competition for generation services. In 2019, the ACC staff prepared a draft of retail electric competition rules and workshops have been held on the subject. Such

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rules have not been officially proposed and no changes have been made. The adoption of new policies or rules would be subject to rulemaking proceedings at the ACC. TEP cannot predict what additional steps, if any, the ACC may take to further evaluate retail competition in this docket.

Wholesale Customers

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, 2019, TEP had 2,841 MW of nominal generation capacity, as set forth in the following table. Nominal rating is based on current unit design basis net output, measured in 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
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 (2)	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	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
Sundt Reciprocating Internal Combustion Engine	6-10	Tucson, AZ	2019	94	TEP	100	94
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	47	TEP	100	47
Total Capacity (3)							2,841

⁽¹⁾  Springerville Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.

⁽²⁾  TEP purchased Gila River Unit 2 in December 2019.

⁽³⁾  In November 2019, Navajo was removed from service. TEP held a 7.5% share in Navajo Units 1, 2, and 3 with a total nominal capacity of 168 MW. In December 2019, Sundt Units 1 and 2 were removed from service. Sundt Units 1 and 2 had a total nominal capacity of 162 MW.

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, 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. 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 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

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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 2019, the percentage of retail kWh sales attributable to the RES was approximately 16%, exceeding the 2019 requirement of 9%. The ACC approved a waiver of the 2019 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, 2019, TEP owned 47 MW of PV solar generation capacity, measured in AC. The following table presents TEP's owned utility-scale renewable generation resources:

Generation Source	Location	Date/Projected Date in Service	In Service Capacity (MW)	Under Development Capacity (MW)
Solar
Fort Huachuca Phase I & II (1)	Sierra Vista, AZ	2014-2017	18
Springerville	Springerville, AZ	2004-2014	14
UASTP Phase I & II (2)	Tucson, AZ	2010-2011	6
Sundt Areva Solar Thermal	Tucson, AZ	2014	5
Solon Prairie Fire (2)	Tucson, AZ	2012	4
Raptor Ridge	Tucson, AZ	2021		10
Wind
Oso Grande Wind Project	Chaves County, NM	2020		250
Total Capacity			47	260

⁽¹⁾  TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.

⁽²⁾  The UASTP I & II and Solon Prairie Fire are located on properties held under land easements and leases.

Renewable Power Purchase Agreements

As of December 31, 2019, TEP had renewable PPAs for 156 MW from solar resources and 80 MW from wind resources 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	29
Avra Valley	Marana, AZ	2012	25
Picture Rocks	Marana, AZ	2012	20
Avalon II	Sahuarita, AZ	2016	16
Valencia	Tucson, AZ	2013	10
E.On Tech Park	Tucson, AZ	2012	5
Gato Montes	Tucson, AZ	2012	5
Small PPAs (<5MW)	Various	Various	5
Wilmot Solar (1)	Sahuarita, AZ	2020		100
Wind
Macho Springs	Deming, NM	2011	50
Red Horse Wind	Willcox, AZ	2015	30
Borderlands Wind	Catron County, NM	2021		99
Total Capacity			236	199

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⁽¹⁾  Wilmot Solar will be accompanied by 30 MW of energy storage.

ACC PURPA Ruling

On December 17, 2019, the ACC issued a decision related to contract terms for qualifying facilities under PURPA. Congress enacted PURPA in 1978 in response to a national energy crisis. The FERC prescribes rules for the implementation of PURPA and state regulatory agencies implement PURPA. PURPA requires, among other things, that electric utilities enter into contracts to purchase power from facilities that qualify under PURPA at a price equivalent to the utility's avoided cost. The ACC's 2019 decision requires, among other things, that TEP's contracts to purchase power from qualifying facilities with renewable nameplate capacity over 100 kW include certain terms and conditions, including a minimum 18-year contract length and pricing based on TEP's long-term avoided cost. The Company cannot predict the impact of the ACC's ruling at this time.

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 9 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 MWh and others are indexed to natural gas prices. TEP also purchases power in the daily and hourly markets: (i) to meet higher than anticipated demands; (ii) during periods of generation outages; or (iii) 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 generation facility outages and system disturbances, which reduces the amount of reserves TEP is required to carry.

Peak Demand and Future Resources

Peak Demand

(in MW)	2019	2018	2017	2016	2015
Retail Customers	2,367	2,413	2,415	2,278	2,222

In 2019, 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 entity with delegated authority from NERC.

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 2019, 2018, and 2017 was higher than in 2016 and 2015 primarily due to warmer than normal summer temperatures.

Forecasted retail peak demand for 2020 is 2,325 MW compared with actual peak demand of 2,367 MW in 2019. TEP’s 2020 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 2020.

Future Resources

As of December 31, 2019, approximately 38% of TEP's generation capacity 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.

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.

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Fuel Supply

A summary of Fuel and Purchased Power resource information is provided below:

	Average Cost (cents per kWh)			Percentage of Total kWh Resources
	2019	2018	2017	2019		2018		2017
Coal	2.46	2.44	2.41	41	%	44	%	54	%
Natural Gas	2.33	2.54	3.06	45	%	42	%	23	%
Purchased Power, Non-Renewable	4.09	4.32	3.78	10	%	10	%	18	%
Purchased Power, Renewable	9.43	9.41	9.49	4	%	4	%	5	%
				100	%	100	%	100	%

Coal Supply

The coal used for generation is low-sulfur, bituminous or sub-bituminous coal sourced 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 MMBtu, including transportation, was $2.37 in 2019, $2.33 in 2018, and $2.29 in 2017.

Station	Coal Supplier	2019 Coal Consumption (tons in 000s)	Contract Expiration Date	Average Sulfur Content	Coal Obtained From
Springerville (1)	Peabody CoalSales	2,693	2020	1.0%	Lee Ranch Mine/El Segundo Mine
Four Corners	NTEC	315	2031	0.7%	Navajo Mine
San Juan	San Juan Coal Co.	588	2022	0.8%	San Juan Mine

⁽¹⁾  An extension to the coal supply agreement is currently under negotiation.

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 from the supplying mines to be sufficient to fulfill the estimated requirements for each of the Springerville units' estimated remaining life.

Coal-Fired Generation Facilities Operated by Others

TEP also participates in jointly-owned coal-fired generation facilities at Four Corners and San Juan. Four Corners, which is operated by APS, and San Juan, which is operated by PNM, are mine-mouth generation facilities located adjacent to the coal reserves. TEP expects coal reserves available to these two 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 $2.20 in 2019, $2.92 in 2018, and $3.58 in 2017.

Station	Natural Gas Transportation Counterparty	Contract Expiration Date(s)
Gila	Transwestern Pipeline Co./El Paso Natural Gas Company, LLC	2022-2040
Luna	El Paso Natural Gas Company, LLC	2022
Sundt/RICE	El Paso Natural Gas Company, LLC	2023-2040
DeMoss Petrie	Southwest Gas Corporation	Retail Tariff
North Loop	Southwest Gas Corporation	Retail Tariff

Sundt Generating Station

TEP placed in service five natural gas RICE units in December 2019, with the remaining five units scheduled to be placed in service in the first quarter of 2020, and retired Sundt Units 1 and 2 in November 2019. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the RICE units.

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Transmission and Distribution

TEP's distribution and transmission facilities are located in Arizona and New Mexico. These facilities are located on property owned by: (i) TEP; (ii) public entities; (iii) private entities; and (iv) Indian Nations. TEP's transmission and distribution systems included approximately 2,189 miles of transmission lines and 7,740 miles of distribution lines as of December 31, 2019.

TEP's transmission facilities transmit the output from TEP’s electric generation facilities to the Tucson area and power markets. The 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 systems, enables TEP to integrate and access generation resources to meet its customer load requirements.

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 rates and services for electric transmission and wholesale power sales in interstate commerce.

ACC Regulation

Renewable Energy Standard

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.

Energy Efficiency Standard

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, 2019, TEP’s cumulative annual energy savings was approximately 19%.

ACC Rates

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 are generally established in rate case proceedings. TEP's last rate case proceeding was finalized in 2017. TEP is currently in a new rate case proceeding which began in 2019 and is expected to be finalized in 2020.

As a result of past regulatory decisions, TEP has cost recovery mechanisms that allow for more timely recovery of certain costs between rate case proceedings. These mechanisms are generally reset annually through separate filings with the ACC. TEP's cost recovery mechanisms include:

• PPFAC — a usage-based charge or credit that reflects changes in energy costs that are not recovered through base rates established in a rate case.

• REST — a usage-based charge that recovers the cost of complying with the RES.

• DSM — a usage-based charge that recovers the cost of energy efficiency programs that are designed to help TEP comply with the EE Standards.

• LFCR — a usage-based charge that partially offsets the revenue TEP loses when customers reduce their bills as a result of energy efficiency programs and DG system installations.

• ECA — a usage-based charge that recovers certain costs incurred at TEP's generation stations to comply with environmental regulations.

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 on TEP's current rate case proceeding and cost recovery mechanisms.

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ENVIRONMENTAL MATTERS

The EPA regulates the amount of sulfur dioxide (SO₂), nitrogen oxide (NO_x), 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.

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. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.

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. In November 2019, the EPA published a proposed ELG rule revision in the Federal Register.

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 finalizes the proposed rule revisions, it is unclear how the revision will affect this facility.

EMPLOYEES

As of December 31, 2019, TEP had 1,587 employees, of which approximately 675 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.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

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, 2020, are as follows:

Name	Age	Position(s) Held	Executive Officer Since
David G. Hutchens	53	Chief Executive Officer	2007
Susan M. Gray (1)	47	President and Chief Operating Officer	2015
Frank P. Marino (1)	55	Senior Vice President and Chief Financial Officer	2013
Todd C. Hixon (1)	53	Senior Vice President, General Counsel, Corporate Secretary, and Chief Compliance Officer	2011
Erik B. Bakken	47	Vice President, System Operations and Environmental	2018
Dallas J. Dukes	52	Vice President, Energy Programs and Pricing	2019
Cynthia A. Garcia	52	Vice President, Energy Delivery	2020
Mark C. Mansfield	64	Vice President, Energy Resources	2012
Catherine E. Ries	60	Vice President, Customer and Human Resources	2007
Michael E. Sheehan	52	Vice President, Resource Planning, Fuels, and Wholesale Marketing	2020
Mary Jo Smith	62	Vice President, Public Policy	2015
Morgan C. Stoll	49	Vice President and Chief Information Officer	2016
Martha B. Pritz	58	Treasurer	2017

⁽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 SEC. The SEC maintains a website at https://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 at https://www.tep.com/investor-information/.

TEP is providing the address of its 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 by TEP filed with the SEC.

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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 2% per year from 2015 through 2019.

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 10% of total revenues in 2019. 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 DG; 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. TEP's inability to recover its costs, earn a reasonable return on its investments, or comply with current regulations would negatively affect its 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 reliability standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new reliability standards may

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subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory reliability standards could subject TEP to sanctions, including substantial monetary penalties.

Changes made to legislation, regulation, or regulatory structure could negatively affect TEP's results of operations, net income, and cash flows.

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 programs for demand response, customer energy efficiency, and electric vehicles. 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.

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various state energy policies, including renewable energy goals and retail competition for generation services. In 2019, the ACC staff prepared a draft of rules that, if adopted, would change the renewable energy goals requiring Arizona regulated utilities to acquire 45% of the retail energy it sells from renewable generation by 2035. Increases to the renewable energy goals could accelerate the Company's long-term resource diversification strategy and increase capital expenditures and operating expenses. 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. 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. In addition, the ACC staff and two commissioners have prepared different drafts of retail competition rules for utilities in Arizona. These rules have not been officially proposed, but if such rules were adopted, retail competition could have a negative impact on the Company's retail sales. TEP cannot predict the final outcome of these proposals. The adoption of any new policies or rules would be subject to rulemaking proceedings at the ACC.

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.

Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions of conventional pollutants and greenhouse gases, water use, wastewater discharges, solid waste, hazardous waste, and management of CCR.

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 timely and fully recoverable from TEP customers. TEP’s obligation to comply with these laws and regulations as a participant or owner in regulated facilities like Springerville, San Juan, and Four Corners, 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.

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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 GHG 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 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, 2019, TEP's regulatory assets balance related to its early generation retirement costs was $68 million. In 2019, TEP filed a general rate case with the ACC which includes a request to recover certain early retirement costs related to Navajo and Sundt Units 1 and 2.

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 facilities. 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, 2019, there were outstanding approximately $257 million aggregate principal amount of tax-exempt bonds that financed pollution control expenditures at TEP’s generation facilities. In October 2020, $80 million aggregate principal amount of bonds mature. The remaining bonds may be redeemed at par commencing in the first quarter of 2022. The bonds would be subject to early redemption should certain generating facilities be retired and dismantled prior to maturity or the first redemption date.

In addition, as of December 31, 2019, 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. TEP has $100 million in aggregate principal bonds that may be redeemed at par on or after October 2020. The remaining bonds may be redeemed at par commencing on dates ranging from first quarter of 2022 to first quarter of 2023.

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OPERATIONAL

The operation of 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 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.

In addition, as coal-fired generation facilities are closed, the economic viability of coal mines and coal suppliers may be jeopardized. To date, several coal suppliers have declared bankruptcy and coal mines have been closed. As additional coal-fired generation facilities are closed, the availability of sufficient coal supplies could decrease and prices may increase, which could, in turn, negatively affect the viability of our remaining coal-fired generation facilities.

The operation of generation facilities and transmission systems on Indian lands may create operational and financial risks for TEP that, if realized, could negatively affect TEP’s results of operations, net income, and cash flows.

Certain jointly-owned facilities and portions of TEP's transmission lines are located on Indian lands pursuant to leases, land easements, or other rights-of-way that are effective for specified periods. TEP is unable to predict the final outcomes of pending and future approvals by the applicable sovereign governing bodies with respect to the cost of renewals and continued access to these leases, land easements and rights-of-way. If pending and future approvals are not obtained and if continued access to the facilities is not granted, it could negatively affect TEP's results of operations, net income, and cash flows.

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.

TEP’s generation, transmission, and distribution facilities are critical to the provision of electric service to our customers and provide the framework for our service 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 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. The Company relies on the continued operation of its network infrastructure, which is part of an interconnected regional grid. Any significant interruption of these assets could prevent the Company from fulfilling its critical business

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functions including delivering energy to customers. Security threats continue to evolve and adapt. TEP and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to disrupt operations. Despite implementation of security measures, there can be no assurance that the Company will be able to prevent the disruption of our operations.

If, despite TEP's security measures, a significant physical attack occurred, the Company could: (i) have 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.

Cybercrime, which includes the use of malware, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years. The Company relies on the continued operation of sophisticated digital information technology systems and network infrastructure, which are part of an interconnected regional grid. TEP's operations technology systems face a heightened risk of cyber-attack due to the critical nature of the infrastructure, the Company's connectivity to the Internet, and inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, and other types of data security breaches.

TEP's information technology systems and network infrastructure have been subject, and will likely continue to be subject, to cyber-attacks from foreign or domestic sources attempting to gain unauthorized access to information and/or information systems or to disrupt utility operations through computer viruses and phishing attempts either directly or indirectly through its material vendors or related third parties. Furthermore, 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: (i) have operations disrupted, customer information stolen, and general business system and process interruption or compromise, including preventing TEP from servicing customers, collecting revenues or the recording, processing and/or reporting financial information correctly; (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. To date we have not experienced any material breaches or disruptions to our network, information systems, or our service operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

TEP's corporate headquarters is owned by TEP and located in Tucson, Arizona. Operational support facilities for Tucson operations are owned by TEP and located in Tucson, Arizona.

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 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.

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

TEP's rights under land easements expire at various times in the future and renewal action by the applicable tribe or federal agencies will be required. The ultimate cost of renewal for certain of the rights-of-way for the Company's transmission lines is uncertain. 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.

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 9 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.

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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 2015 through 2019:

(in thousands)	2019		2018		2017		2016		2015
Income Statement Data
Operating Revenues	$	1,418,338	$	1,432,618	$	1,340,935	$	1,234,995	$	1,306,544
Net Income	186,515		188,323		176,668		124,438		127,794
Balance Sheet Data
Total Utility Plant, Net	$	4,534,896	$	4,160,640	$	3,768,702	$	3,782,806	$	3,558,229
Total Assets	5,489,157		5,159,207		4,590,249		4,449,989		4,249,478
Long-Term Debt, Net	1,522,087		1,615,252		1,354,423		1,453,072		1,451,720
Non-Current Finance Lease Obligations	67,316		19,773		28,519		39,267		55,324

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

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

• overview and strategies;

• factors affecting our results of operations;

• results of operations;

• liquidity and capital resources, including: (i) capital expenditures; (ii) contractual obligations; and (iii) 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 GAAP.

This section of this Form 10-K primarily discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 activity and year-to-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in Part II, Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations of our 2018 Annual Report on Form 10-K.

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 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.

OVERVIEW

Outlook and Strategies

TEP's financial performance 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:

• 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, affordable, 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 reliability and 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 achieving 30% of our customers’ energy needs with non-carbon emitting resources eight years ahead of our 2030 goal. We are currently working on new long-term goals based on carbon emission reductions as part of our integrated resource plan which we plan to file with the ACC during 2020. 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.

Performance - 2019 Compared with 2018

TEP reported net income of $187 million in 2019 compared with $188 million in 2018. The decrease of $1 million, or 1%, was primarily due to:

• $11 million in higher depreciation and amortization expense due to an increase in asset base;

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• $10 million in higher interest expense related to a debt issuance in November 2018; and

• $8 million due to lower retail revenue primarily due to a decrease in usage related to unfavorable weather.

The decrease was partially offset by:

• $8 million in higher AFUDC due to an increase in construction projects;

• $7 million in lower income tax expense primarily due to EDIT amortization true-ups related to the TCJA and the recognition of additional AMT credits related to a revision in tax law guidance;

• $7 million increase in value of company-owned life insurance as a result of favorable market conditions; and

• $6 million in lower operations and maintenance expense related to planned generation outages in 2018 not recurring in 2019.

FACTORS AFFECTING RESULTS OF OPERATIONS

Several factors affect our current and future results of operations. The most significant factors are related to regulatory matters, generation resource diversification, and weather patterns.

Regulatory Matters

TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters.

2019 ACC Rate Case

In April 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018, to provide TEP with an opportunity to recover its full cost of service, including an appropriate return on its rate base investments, and enable TEP to continue to provide safe and reliable service.

TEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019 include:

• a non-fuel retail revenue increase of $99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $60 million over test year retail revenues;

• a 7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.00% and an average cost of debt of 4.65%;

• a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;

• a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

• a TEAM that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and

• a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

Hearings before an ALJ were held in January and February 2020. The hearing will resume in April 2020. TEP requested new rates to be implemented by May 1, 2020. We cannot predict the timing or outcome of the proceeding.

2019 FERC Rate Case

In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund.

Provisions of the order include, but are not limited to:

• replacing TEP's stated transmission rates with a forward-looking formula rate;

• a 10.4% return on equity; and

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• elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.

The requested forward-looking formula rate is intended to allow for more timely recovery of transmission-related costs. If this request is approved, transmission revenues would increase by $7 million. As part of the order, the FERC established hearing and settlement procedures, and all revisions to the OATT in the FERC order are subject to refund. As of December 31, 2019, TEP had reserved $4 million of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as a result of the FERC proceedings. We cannot predict the outcome of the proceeding.

Abandoned Plant Costs

Also in May 2019, TEP filed with the FERC a request to recover through its OATT abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that we incurred in developing the transmission line. The filing requested that the abandoned plant costs be included in TEP's transmission rate. On September 19, 2019, the FERC issued an order allowing TEP to recover 50% of its costs in its formula rate and established hearing and settlement procedures. TEP incorporated the abandoned plant costs into our formula rate effective January 1, 2020, subject to refund. On September 26, 2019, the FERC issued an order consolidating the 2019 FERC Rate Case and Abandoned Plant Costs proceedings. TEP previously wrote off a portion of the deferred costs related to the Nogales transmission line. As of December 31, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets.

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 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 customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018 (ACC Refund Order). The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The refund amounts totaled $33 million in both 2019 and 2018. TEP filed an information filing with the ACC to establish a 2020 customer refund of $35 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our next rate case. TEP has proposed a TEAM to return the remaining deferred balance.

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 NOPR regarding the effect of the TCJA and related EDIT amortization. In November 2019, the FERC issued a final rule on the NOPR, which did not require TEP to update its stated transmission rates to deduct or include EDIT in its rate base. As required by the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.

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.

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Arizona Energy Policy

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy goals, integrated resource planning, and retail competition for generation services. In 2019 and 2020, the ACC staff and two commissioners prepared different drafts of retail electric competition rules. The ACC is expected to discuss those draft rules during upcoming workshops, but such rules have not been officially proposed and no changes have been made. We anticipate that the ACC will hold additional workshops in 2020 related to retail electric competition and other energy-related policies. The adoption of new policies or rules would be subject to rulemaking proceedings at the ACC. We would seek the ACC's approval to recover any costs related to new energy policies or requirements. TEP cannot predict the outcome of these matters or its impact on the Company's financial position or results of operations.

Generation Resource Diversification

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, 2019, approximately 38% of our generation capacity 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.

Navajo Generating Station

TEP and the co-owners of Navajo retired the generation station in November 2019 and began decommissioning activities. TEP expects the majority of decommissioning activities to be completed by 2024 with monitoring activities continuing through 2054. TEP is currently recovering the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. As of December 31, 2019, the net book value of Navajo was $42 million, with estimated other related costs of $4 million.

See Note 2 and Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the early retirement of Navajo.

Sundt Generating Station

In 2018, the Pima County Department of Environmental Quality approved TEP's air permit. Under the air permit, TEP is allowed to place in service 10 RICE units. TEP placed in service five of the RICE units in December 2019, and the remaining five are scheduled to be placed in service in the first quarter of 2020. In addition, TEP was required to retire Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 of Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. As of December 31, 2019, the net book value of Sundt Units 1 and 2 was $26 million, with estimated other related costs of $1 million.

The RICE units are expected to balance the variability of intermittent renewable energy resources and replace 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which were less efficient and lacked the quick start, fast ramp capabilities of the RICE units.

See Note 2 and Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the early retirement of Sundt Units 1 and 2.

Gila River Generating Station

In 2017, TEP entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three-year option to purchase the unit (Tolling PPA). TEP completed the purchase of Gila River Unit 2 in December 2019 for $165 million. We have requested recovery of the Gila River Unit 2 purchase in the 2019 Rate Case.

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We expect the additional 550 MW of capacity, power, and ancillary services to allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation lost due to early retirements.

See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K, for additional information regarding the Tolling PPA.

Weather Patterns

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.

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.

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RESULTS OF OPERATIONS

Significant drivers of TEP's results of operations that do not have a significant impact on net income include:

• Cost Recovery Mechanisms — TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, REST and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on cost recovery mechanisms.

• Short-Term Wholesale Sales — Revenues related to short-term wholesale sales are primarily related to 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 cost recovery mechanism.

• Springerville Units 3 and 4 — 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, through participant billings recorded in Operating Revenues on the Consolidated Statements of Income.

The following discussion provides the significant drivers that affected TEP's results of operations for the year ended 2019 compared to 2018 presented on a pre-tax basis.

Operating Revenues

TEP reported operating revenues of $1,418 million in 2019 compared with $1,433 million in 2018. The decrease of $15 million, or 1%, was primarily due to:

• $37 million in lower fuel and purchase power recoveries as a result of lower PPFAC rates; and

• $11 million in lower retail revenue primarily due to a decrease in customer usage related to unfavorable weather.

The decrease was partially offset by:

• $24 million in higher participant billings related to Springerville Units 3 & 4;

• $6 million in higher RES and DSM cost recoveries as a result of higher program expenses; and

• $3 million in higher short-term wholesale sales.

The following table provides key statistics impacting operating revenues:

	Years Ended December 31,		Increase (Decrease)		Year Ended December 31,	Increase (Decrease)
(kWh in millions)	2019	2018	Percent		2017	Percent
Electric Sales (kWh)
Retail Sales	8,744	8,900	(1.8	)%	8,926	(0.3	)%
Wholesale Sales, Long-Term	490	424	15.6	%	587	(27.8	)%
Wholesale Sales, Short-Term	7,257	6,279	15.6	%	3,630	73.0	%
Total Electric Sales	16,491	15,603	5.7	%	13,143	18.7	%
Average Revenue per kWh (Cents/kWh)
Retail	11.12	11.48	(3.1	)%	11.39	0.8	%
Wholesale	3.13	3.46	(9.5	)%	3.21	7.8	%
Total Retail Customers	428,626	425,044	0.8	%	422,366	0.6	%

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Operating Expenses

Fuel and Purchased Power Expense

TEP reported fuel and purchased power expense of $506 million in 2019 compared with $543 million in 2018. The decrease of $37 million, or 7%, was primarily due to:

• $53 million in lower PPFAC recoveries primarily due to changes in the PPFAC rate and an increase in deferral of eligible costs.

The decrease was partially offset by:

• $6 million in higher fuel expense primarily due to realized losses on hedging contracts resulting from lower natural gas prices;

• $5 million in higher transmission costs primarily due to an increase in transmission purchases and increased transmission rates; and

• $3 million in higher purchased power primarily due to an increase in volume.

The following table provides key statistics impacting fuel and purchase power:

	Years Ended December 31,		Increase (Decrease)		Year Ended December 31,	Increase (Decrease)
(kWh in millions)	2019	2018	Percent		2017	Percent
Sources of Energy
Coal-Fired Generation	7,046	7,208	(2.2	)%	7,530	(4.3	)%
Gas-Fired Generation	7,714	6,738	14.5	%	3,237	108.2	%
Utility-Owned Renewable Generation	75	82	(8.5	)%	83	(1.2	)%
Total Generation	14,835	14,028	5.8	%	10,850	29.3	%
Purchased Power, Non-Renewable	1,709	1,624	5.2	%	2,471	(34.3	)%
Purchased Power, Renewable	643	652	(1.4	)%	646	0.9	%
Total Generation and Purchased Power	17,187	16,304	5.4	%	13,967	16.7	%
(cents per kWh)
Average Fuel Cost of Generated Power
Coal	2.46	2.44	0.8	%	2.41	1.2	%
Natural Gas (1)	2.33	2.54	(8.3	)%	3.06	(17.0	)%
Average Cost of Purchased Power
Purchased Power, Non-Renewable	4.09	4.32	(5.3	)%	3.78	14.3	%
Purchased Power, Renewable	9.43	9.41	0.2	%	9.49	(0.8	)%

⁽¹⁾  Includes realized gains and losses from hedging activity.

Operations and Maintenance Expense

TEP reported operations and maintenance expense of $378 million in 2019 compared with $362 million in 2018. The increase of $16 million, or 4%, in 2019 was primarily due to:

• $22 million in higher reimbursable maintenance expense related to Springerville Units 3 and 4; and

• $3 million in higher expenses related to an increase in employee wages and benefits and outside services.

The increase was partially offset by $8 million in lower expense related to planned generation outages in 2018 not recurring in 2019.

Depreciation and Amortization Expense

Depreciation and amortization expense increased by $12 million, or 7%, in 2019 compared with 2018 primarily due to an increase in asset base.

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Other Income (Expense)

TEP reported other expense of $62 million in 2019 compared with $57 million in 2018. The increase of $5 million, or 9%, in 2019 compared with 2018 was primarily due to:

• $11 million in higher Gila River Unit 2 demand charges, which are recovered through the PPFAC and accounted for as finance lease interest expense; and

• $10 million in higher interest expense related to debt issued in November 2018.

The increase was partially offset by:

• $10 million in higher AFUDC due to an increase in construction projects; and

• $8 million increase in the value of company-owned life insurance as a result of favorable market conditions.

Income Tax Expense

TEP reported income tax expense of $34 million in 2019 compared with $43 million in 2018. The decrease of $9 million, or 21%, in 2019 compared with 2018 was primarily due to:

• $3 million in lower tax expense due to EDIT amortization true-ups related to the TCJA;

• $3 million in AMT credits recognized in the first quarter of 2019 related to a revision in tax law guidance; and

• $3 million in lower tax expense due to a decrease in 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 credit agreements as needed to fund our business activities. We believe that we have sufficient liquidity under our credit agreements 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 bank and capital markets.

Available Liquidity

(in millions)	December 31, 2019
Cash and Cash Equivalents	$	10
Amount Available under Credit Agreements (1)	310
Total Liquidity	$	320

⁽¹⁾  The 2015 Credit Agreement provides for $250 million of revolving credit commitments and a LOC sublimit of $50 million with a maturity date of October 2022. The 2019 Credit Agreement provides for a $225 million term loan with a maturity date of December 2020.

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.

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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)	2019			2018			Percent		2017			Percent
Operating Activities	$	414		$	457		(9.4	)%	$	448		2.0	%
Investing Activities	(654		)	(433		)	51.0	%	(392		)	10.5	%
Financing Activities	115			79			45.6	%	(50		)	258.0	%
Net Increase (Decrease)	(125		)	103			*		6			*
Beginning of Period	153			50			206.0	%	43			16.3	%
End of Period (1)	$	28		$	153		(81.7	)%	$	49		212.2	%

* Not meaningful

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

Operating Activities

Net cash flows provided by operating activities decreased by $43 million in 2019 compared with 2018 primarily due to: (i) a decrease in recovery of PPFAC costs as a result of changes in the PPFAC rate; (ii) a settlement payment for final mine reclamation settlement associated with the early retirement of Navajo; (iii) lower retail sales primarily due to a decrease in usage related to unfavorable weather; and (iv) changes in working capital related to the timing of billing collections and payments.

The decrease was partially offset by: (i) a decrease in cash paid for pension funding as a result of favorable market conditions; and (ii) a decrease in amounts returned to customers through bill credits related to the TCJA.

Investing Activities

Net cash flows used for investing activities increased by $221 million in 2019 compared with 2018 primarily due to: (i) the purchase of Gila River Unit 2 in December 2019; and (ii) payments for the Oso Grande project in 2019.

Financing Activities

Net cash flows provided by financing activities increased by $36 million in 2019 compared with 2018 primarily due to: (i) higher proceeds from credit facility borrowings, net of repayments; and (ii) a decrease in cash dividend payments to UNS Energy. The increase was partially offset by lower proceeds from issuance of long-term debt, net of long-term repayments.

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, 2019, TEP had no short-term investments.

Access to Credit Agreements

We have access to working capital through our credit agreements.

Amounts borrowed from the 2019 Credit Agreement were used (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. As of December 31, 2019, there was $60 million available under the 2019 Credit Agreement. As of February 12, 2020, there were no amounts available under the 2019 Credit Agreement. Prepaid amounts under the 2019 Credit Agreement may not be reborrowed.

Amounts borrowed from the 2015 Credit Agreement will be used for working capital and other general corporate purposes and LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of December 31, 2019, there was $250 million available under the 2015 Credit Agreement. In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 12, 2020, there was $173 million available under the 2015 Credit Agreement.

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We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding our credit agreements.

Debt Financing

We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings.

In 2016, the ACC issued an order granting TEP financing authority (2016 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. As of February 12, 2020, our long-term debt was $1,614 million.

TEP will be submitting an application for a new financing authority with the ACC in the first quarter of 2020.

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.

In November 2019, TEP redeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of $15 million prior to the maturity of the bonds.

We anticipate issuing long-term debt in 2020 to: (i) refinance the borrowings under the 2019 Credit Agreement; (ii) redeem tax-exempt bonds; (iii) make payments for the construction of the Oso Grande project; and (iv) for general corporate purposes.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2019, 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, 2019, 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.

Contributions from Parent

UNS Energy made equity contributions to TEP of $50 million in 2019 and 2018. The proceeds provided additional liquidity to TEP. In January 2020, UNS Energy made an equity contribution to TEP of $125 million. The proceeds were used in part for the construction of the Oso Grande project.

In 2020, we expect to receive additional equity contributions from UNS Energy. The proceeds are expected to be used for: (i) investments in generation, transmission, and distribution assets; and (ii) general corporate purposes.

Dividends Paid to Parent

TEP declared and paid $75 million in dividends to UNS Energy in 2019 and $85 million in 2018.

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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, 2019, TEP had posted $2 million cash as a credit enhancement with one of its counterparties. As of February 12, 2020, there was no collateral posted.

Capital Expenditures

TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In 2019, total capital expenditures of $608 million included: (i) the purchase of Gila River Unit 2 in December 2019; (ii) payments for Oso Grande; and (iii) other investments in generation, transmission, and distribution assets. In 2018, total capital expenditures of $393 million included investments in generation assets and an enhanced metering and distribution network.

Our forecasted capital expenditures presented below for years ended December 31 exclude amounts for AFUDC and other non-cash items:

(in millions)	2020		2021		2022		2023		2024
Generation Facilities:
Renewable Energy (1)	$	346	$	31	$	—	$	—	$	—
Other Generation Facilities (2)	198		64		38		63		47
Total Generation Facilities	544		95		38		63		47
Transmission and Distribution (3)	291		356		319		270		145
General and Other (4)	138		122		60		53		49
Total Capital Expenditures	$	973	$	573	$	417	$	386	$	241

⁽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. In January 2020, TEP made a payment of $226 million for Oso Grande under the build-transfer agreement.

⁽²⁾  Includes the commitment to purchase Springerville Common Facilities.

⁽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, 2019:

			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)	$	1,614	$	80	$	250	$	150	$	1,134
Interest (2)	943		71		122		100		650
Leases (3)(4)	86		18		68		—		—
Purchase Obligations:
Fuel, Including Transportation (5)	455		94		101		66		194
Purchased Power	8		8		—		—		—
Transmission	63		21		30		6		6
Renewable Power Purchase Agreements (6)	857		63		126		125		543
RES Performance-Based Incentives (7)	69		8		14		14		33
Land Easements and Rights-of-Way (8)	87		1		3		4		79
Build-Transfer Agreement (9)	338		338		—		—		—
Other Long-Term Liabilities: (10)(11)
RSU and PSU	12		5		7		—		—
Pension and Other Postretirement Benefits (12)	74		19		12		12		31
Total Contractual Obligations	$	4,606	$	726	$	733	$	477	$	2,670

⁽¹⁾  Total long-term debt is not reduced by $10 million of related unamortized debt issuance costs or $2 million of unamortized original issue discount.

⁽²⁾  Excludes interest on credit agreements.

⁽³⁾  TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms up to 22 years. In December 2019, TEP exercised its option to purchase the interests in the Springerville Common Facilities by January 2021, the expiration date of the leases, for $68 million. See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding our leases.

⁽⁴⁾  Effective with commercial operation of Springerville Unit 3 in July 2006 and Unit 4 in December 2009, Tri-State and SRP reimburse TEP for various operating costs related to the Springerville Common Facilities, on an ongoing basis. TEP was reimbursed $6 million of operating costs in 2019 by SRP and Tri-State related to the Springerville Common Facilities and does not expect any material changes to the reimbursement amount in 2020. The obligation balance does not reflect any reduction associated with the reimbursement.

⁽⁵⁾  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 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding TEP’s share of reclamation costs.

⁽⁶⁾  TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities' output once commercial operation status is achieved. While TEP is not required to make payments under these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PPAs.

⁽⁷⁾  TEP has entered into REC agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBI and are paid in contractually agreed upon intervals (usually quarterly) based on metered renewable energy production. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding PBIs.

⁽⁸⁾  Have varying terms and provisions and reflect expiration dates through 2054. See Note 9 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.

⁽⁹⁾  TEP entered into an agreement to develop a wind-powered electric generation facility with costs of $384 million. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the Build-Transfer Agreement.

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⁽¹⁰⁾  Excludes AROs of $107 million expected to occur through 2048.

⁽¹¹⁾  Excludes unrecognized tax benefits of $18 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 2020, expected benefit payments for its unfunded 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 2020 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

TEP did not make any U.S. federal or Arizona state income tax payments during 2019 due to existing net operating loss and tax credit carryforwards in those jurisdictions. Based on its remaining tax carryforward balances, the Company does not anticipate making U.S. federal or state income tax payments of a material nature for the next several years.

Under the TCJA, AMT credit carryforwards will either be refunded or TEP will use them to offset U.S. federal income tax liabilities through the Company's 2021 tax year. TEP received an AMT credit refund of $14 million in 2019, and will receive $7 million in 2020, and $3 million each in 2021 and 2022. Alternatively, TEP will utilize those amounts to offset U.S. federal tax liabilities that would otherwise result through the Company's 2021 tax year.

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 $33 million, of which 75% was passed back to customers through a bill credit in 2019. TEP filed an application with the ACC to establish a 2020 customer refund of $35 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 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 was filed in April 2019.

See Note 14 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, NO_x, 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. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on the Broadway-Pantano site.

We capitalized $4 million in 2019 and $9 million in 2018 in costs incurred to comply with environmental rules and regulations. In addition, we recorded environmental compliance related operations and maintenance expenses of $5 million in 2019, $6 million in 2018, and $5 million in 2017. We expect environmental compliance related capital expenditures of $3 million in 2020, $1 million in years 2021 through 2023, and $2 million in 2024. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.

Regional Haze Regulations

The EPA's Regional Haze rule requires emission reductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a State Implementation Plan (SIP), and must review and submit revisions to the SIP on a periodic basis.

In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The ADEQ began to develop a control strategy with a focus on making reasonable progress

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toward the national visibility goal. In July 2019, the ADEQ notified TEP that Springerville and Sundt had been selected for potential emissions controls evaluation.

TEP will work with the ADEQ to prepare and submit the evaluations. Based on current Regional Haze requirement time-frames, TEP anticipates that impacts, if any, to the facilities will likely occur three to five years after the 2021 SIP submittal date. TEP cannot predict the ultimate outcome of these matters at this time.

Greenhouse Gas Regulation

In August 2015, the EPA issued the Clean Power Plan (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 June 2019, the EPA repealed the CPP, and replaced it with the ACE rule, establishing new emissions guidelines. The new rule rebalances the roles between the states and the EPA. Under the new rule, the EPA would set emission guidelines based on the Best System of Emission Reduction (BSER) for GHG emissions. The BSER for GHG emissions from existing coal-fired generation facilities is defined as heat-rate (efficiency) improvements that can be applied at the source. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the remaining useful life of an individual unit.

Effective September 2019, states will have three years to submit plans to the EPA establishing performance standards. 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.

Legal challenges to the rule could delay the effectiveness and implementation of the new rule. TEP does not anticipate a material impact to its generation facilities at this time as a result of the rule. TEP will continue to work with other Arizona utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed.

Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring disposal of coal ash and other CCR to be managed as a solid waste under Subtitle D of the RCRA for disposal in landfills and/or surface impoundments. Our share of costs to comply at Four Corners is estimated to be $3 million, the majority of which is expected to be capital expenditures associated with site preparation and installation of the groundwater monitoring well system. TEP and the co-owners of Navajo retired the generation station in November 2019.

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. In response to challenges to this rule, the EPA filed a motion to voluntarily remand the rule but not vacate it. On March 13, 2019, the U.S. Court of Appeals for the D.C. Circuit Court issued an order granting the EPA's motion, allowing the EPA nine months to undertake new rulemaking. In August 2019, the EPA issued the Phase 2 rule revision proposal. TEP does not anticipate a material impact on operations or financial results from the anticipated proposed rule revisions.

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 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, 2019, regulatory liabilities net of regulatory assets in the balance sheet totaled $108 million. There are no current or expected 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. The impact of this change 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 customer class. We then record revenue for each customer class based on the 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.

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, 2019. See Note 14 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

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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 determining or estimating: (i) whether a legal obligation exists to remove assets; (ii) the probability of a future event for a conditional obligation; (iii) the fair value of the cost of removal; (iv) when final removal will occur; and (v) the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to our judgment and assumptions will change amounts recorded in the future as expense for AROs. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset and subsequently amortized over the life of the underlying asset. Accretion of the liability and amortization of the associated asset are deferred as regulatory assets because these costs are expected to be recovered through depreciation rates.

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 $220 million at the retirement dates. Additionally, TEP entered into land lease agreements or land easement agreements with certain landowners 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 properly dispose or recycle the PV assets under RCRA. We estimated our ARO related to the PV assets to be approximately $19 million at the retirement dates. We have identified no other legal obligations to retire generation plant assets.

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 our ARO liability recorded in Other on the Consolidated Balance Sheets was $107 million as of December 31, 2019. See Note 3 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.

Additionally, ACC approved 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 are recorded as a regulatory liability and represent non-legal estimated cost of removal accruals, less actual removal costs incurred, net of salvage proceeds realized. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding future net 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.

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Discount Rates

As of December 31, 2019, TEP discounted its future pension plan obligations at 3.6% and its other postretirement plan obligations at a rate of 3.3%. 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 60^th and 90^th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments.

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, 2019, TEP assumed that its pension plans’ assets would generate a long-term rate of return of 6.75%.

Compensation Increases

As of December 31, 2019, TEP used a rate of compensation increase of 2.8% to measure pension obligations.

Mortality

The PRI-2012 mortality table projected with improvement scale MP-2019 with 15-year convergence and a 0.75% long-term rate was utilized to measure the December 31, 2019 pension obligations, whereas RP-2014 mortality table projected with improvement scale MP-2018 was utilized for the December 31, 2018 measurement.

Healthcare Cost Trend Rates

TEP used a current year healthcare cost trend rate range between 6.3% and 7.5% in valuing its other postretirement benefit obligation as of December 31, 2019. This rate reflects both market conditions and historical experience.

Sensitivity Analysis

The table below shows the effect on TEP's expense and obligation of a 100 basis point change to its assumptions as of December 31, 2019:

	Effect on Expense						Effect on Obligation
(in millions)	Increase			Decrease			Increase			Decrease
Change to Pension
Discount Rate	$	(6	)	$	7		$	(71	)	$	89
Long-Term Rate of Return on Plan Assets	(4		)	4			N/A			N/A
Change to Other Postretirement Benefits
Discount Rate	—			—			(8		)	10
Long-Term Rate of Return on Plan Assets	—			—			N/A			N/A
Healthcare Cost Trend Rate	1			(1		)	7			(6		)

In 2020, TEP will incur pension costs of $11 million and other postretirement benefit costs of $4 million. TEP expects to record: (i) $16 million to operations and maintenance expense; (ii) $4 million to capital; and (iii) $5 million to other income. In 2020, TEP expects to make: (i) pension plan contributions of $11 million; (ii) benefit payments to retirees under the retiree benefit plan of $5 million; and (iii) contributions to the VEBA trust of $1 million, net of distributions.

See Note 10 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, one year, or three years, 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

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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 natural 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 in 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 in 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, 2019, 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.

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 RMC 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 RMC 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 RMC reviews counterparty credit exposure as well as credit policies and limits on a regular basis.

Interest Rate Risk

Credit Agreements

TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under its credit agreements. The interest rate paid on borrowings is variable. Amounts borrowed under the credit agreements are made on either the basis of a spread over LIBOR or an ABR. As a result, TEP may experience significant volatility in the rates paid on LIBOR borrowings under its credit agreements.

The 2019 Credit Agreement is a 364-day credit agreement that provides for up to $225 million in term loans, which could be drawn in up to two drawings. As of December 31, 2019, TEP had borrowed $165 million under the 2019 Credit Agreement. As of February 12, 2020, TEP had borrowed $225 million under the 2019 Credit Agreement.

The 2015 Credit Agreement is scheduled to mature in October 2022 and provides for up to $250 million in credit borrowings. As of December 31, 2019, TEP had no revolving credit borrowings under the 2015 Credit Agreement. In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 12, 2020, there was $173 million available under the 2015 Credit Agreement.

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 generation 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 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, generation facility availability, customer usage, storage, and transmission and transportation constraints. Under the guidance of the Risk Management Committee (RMC), TEP mitigates a portion of its commodity price risk through the use of commodity contracts, which include forwards, financial 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 annually by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.

Certain commodity contracts qualify as derivatives and 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)	2019			2018			2017
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$	(45	)	$	(9	)	$	(18	)

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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, 2019
Prices Actively Quoted	$	(11	)	$	(13	)	$	(46	)	$	(70	)

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 power, a 10% change in the market price of purchased power would affect unrealized positions reported as a regulatory asset or liability by approximately $7 million. For derivatives related to 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 $25 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. TEP's coal supply agreements expire from 2020 through 2031. TEP is currently negotiating its coal supply agreement scheduled to expire in 2020. 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 9 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, TEP 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, 2019, TEP’s total credit exposure was approximately $10 million. TEP had approximately $4 million of exposure to non-investment grade counterparties.

As of December 31, 2019, TEP had $2 million of cash posted as collateral to provide credit enhancement to a counterparty. As of February 12, 2020, there was no collateral posted. As of December 31, 2019, TEP held approximately $4 million in collateral from its wholesale counterparties.

34

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, 2019 and 2018, the related consolidated statements of income, comprehensive income, changes in stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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 12, 2020

We have served as the Company's auditor since 2017.

35

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Amounts in thousands)

	Years Ended December 31,
	2019			2018			2017
Operating Revenues	$	1,418,338		$	1,432,618		$	1,340,935
Operating Expenses
Fuel	358,394			351,749			285,551
Purchased Power	137,977			134,914			136,425
Transmission and Other PPFAC Recoverable Costs	52,261			46,595			36,239
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(42,836		)	9,885			(32,660		)
Total Fuel and Purchased Power	505,796			543,143			425,555
Operations and Maintenance	377,563			361,963			360,302
Depreciation	169,042			158,310			152,874
Amortization	27,706			26,052			22,255
Taxes Other Than Income Taxes	55,642			55,006			53,623
Total Operating Expenses	1,135,749			1,144,474			1,014,609
Operating Income	282,589			288,144			326,326
Other Income (Expense)
Interest Expense	(88,511		)	(67,620		)	(65,290		)
Allowance For Borrowed Funds	5,744			3,151			2,078
Allowance For Equity Funds	15,222			8,117			5,322
Other, Net	5,524			(487		)	8,995
Total Other Income (Expense)	(62,021		)	(56,839		)	(48,895		)
Income Before Income Tax Expense	220,568			231,305			277,431
Income Tax Expense	34,053			42,982			100,763
Net Income	$	186,515		$	188,323		$	176,668

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

36

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in thousands)

	Years Ended December 31,
	2019			2018		2017
Comprehensive Income
Net Income	$	186,515		$	188,323	$	176,668
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax (Expense) Benefit of $(44), $(121), and $(305)	133			364		485
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax (Expense) Benefit of $1,059, $(747), and $637	(3,190		)	2,026		(2,156		)
Total Other Comprehensive Income (Loss), Net of Tax	(3,057		)	2,390		(1,671		)
Total Comprehensive Income	$	183,458		$	190,713	$	174,997

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

37

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Years Ended December 31,
	2019			2018			2017
Cash Flows from Operating Activities
Net Income	$	186,515		$	188,323		$	176,668
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	169,042			158,310			152,874
Amortization Expense	27,706			26,052			22,255
Amortization of Debt Issuance Costs	2,326			2,339			2,349
Use of Renewable Energy Credits for Compliance	37,141			32,350			25,453
Deferred Income Taxes	41,614			56,066			100,762
Pension and Other Postretirement Benefits Expense	17,762			15,303			16,039
Pension and Other Postretirement Benefits Funding	(16,749		)	(26,673		)	(14,430		)
Allowance for Equity Funds Used During Construction	(15,222		)	(8,117		)	(5,322		)
FERC Transmission Refund Payable	—			—			(4,878		)
Regulatory Deferral, ACC Refund Order	7,705			(1,562		)	—
Changes in Current Assets and Current Liabilities:
Accounts Receivable	9,238			(26,729		)	(13,219		)
Materials, Supplies, and Fuel Inventory	(16,236		)	(2,357		)	175
Regulatory Assets	(20,934		)	(4,080		)	(3,942		)
Other Current Assets	(475		)	(1,746		)	(751		)
Accounts Payable and Accrued Charges	(27,776		)	33,536			9,790
Income Taxes Receivable	6,072			(13,004		)	—
Regulatory Liabilities	(1,626		)	14,028			(20,227		)
Other, Net	8,140			15,187			4,728
Net Cash Flows—Operating Activities	414,243			457,226			448,324
Cash Flows from Investing Activities
Capital Expenditures	(607,593		)	(392,522		)	(345,617		)
Purchase Intangibles, Renewable Energy Credits	(51,699		)	(51,327		)	(51,179		)
Contributions in Aid of Construction	6,607			10,817			4,983
Note Receivable	(1,000		)	—			—
Net Cash Flows—Investing Activities	(653,685		)	(433,032		)	(391,813		)
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 Borrowings, Term Loan	165,000			—			—
Proceeds from Issuance, Long-Term Debt—Net of Discount	—			298,869			—
Repayments of Long-Term Debt	(14,700		)	(136,700		)	—
Dividends Paid to Parent	(75,000		)	(85,000		)	(70,000		)
Payments of Finance Lease Obligations	(10,890		)	(10,930		)	(15,571		)
Payment of Debt Issuance Costs	(757		)	(3,265		)	(245		)
Contribution from Parent	50,000			50,000			—
Other, Net	1,514			1,078			481
Net Cash Flows—Financing Activities	115,167			79,052			(50,335		)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(124,275		)	103,246			6,176
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	152,747			49,501			43,325
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	28,472		$	152,747		$	49,501

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

38

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)

	December 31,
	2019			2018
ASSETS
Utility Plant
Plant in Service	$	6,663,912		$	6,020,469
Utility Plant Under Finance Leases	151,467			248,635
Construction Work in Progress	303,488			258,965
Total Utility Plant	7,118,867			6,528,069
Accumulated Depreciation and Amortization	(2,506,686		)	(2,293,783		)
Accumulated Amortization of Finance Lease Assets	(77,285		)	(73,646		)
Total Utility Plant, Net	4,534,896			4,160,640
Investments and Other Property	62,136			50,952
Current Assets
Cash and Cash Equivalents	9,762			138,114
Accounts Receivable, Net	154,847			172,367
Fuel Inventory	23,731			22,783
Materials and Supplies	121,542			107,990
Regulatory Assets	138,412			106,725
Derivative Instruments	3,596			3,929
Other	21,416			25,571
Total Current Assets	473,306			577,479
Regulatory and Other Assets
Regulatory Assets	326,860			293,078
Derivative Instruments	2,763			8,402
Other	89,196			68,656
Total Regulatory and Other Assets	418,819			370,136
Total Assets	$	5,489,157		$	5,159,207

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

(Continued)

39

TUCSON ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share data)

	December 31,
	2019			2018
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, 2019 and 2018)	$	1,396,539		$	1,346,539
Capital Stock Expense	(6,357		)	(6,357		)
Retained Earnings	595,792			484,277
Accumulated Other Comprehensive Loss	(7,771		)	(4,714		)
Total Common Stock Equity	1,978,203			1,819,745
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2019 and 2018)	—			—
Finance Lease Obligations	67,316			19,773
Long-Term Debt, Net	1,522,087			1,615,252
Total Capitalization	3,567,606			3,454,770
Current Liabilities
Current Maturities of Long-Term Debt	80,330			—
Borrowings Under Credit Agreements	165,000			—
Finance Lease Obligations	17,086			172,510
Accounts Payable	136,465			133,012
Accrued Taxes Other than Income Taxes	42,741			41,686
Accrued Employee Expenses	32,567			34,339
Accrued Interest	16,700			17,927
Regulatory Liabilities	96,017			95,094
Customer Deposits	24,568			27,650
Derivative Instruments	27,615			18,137
Other	23,678			21,555
Total Current Liabilities	662,767			561,910
Regulatory and Other Liabilities
Deferred Income Taxes, Net	432,484			369,705
Regulatory Liabilities	477,495			512,425
Pension and Other Postretirement Benefits	133,452			117,472
Derivative Instruments	48,697			19,361
Other	166,656			123,564
Total Regulatory and Other Liabilities	1,258,784			1,142,527
Commitments and Contingencies
Total Capitalization and Other Liabilities	$	5,489,157		$	5,159,207

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

(Concluded)

40

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, 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
Net Income						186,515						186,515
Other Comprehensive Loss, Net of Tax									(3,057		)	(3,057		)
Dividends Declared to Parent						(75,000		)				(75,000		)
Contribution from Parent	50,000											50,000
Balances as of December 31, 2019	$	1,396,539	$	(6,357	)	$	595,792		$	(7,771	)	$	1,978,203

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

41

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 429,000 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. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities 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.

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.

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 VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it 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 has entered 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 these 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, 2019, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent 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.

42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. 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.

Leases

TEP adopted accounting guidance 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. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, 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. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 8 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance 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 guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

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 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.

43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 with respect to 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 in the balance sheet and reconciles their sum to the cash flow statement:

	Years Ended December 31,
(in millions)	2019		2018		2017
Cash and Cash Equivalents	$	10	$	138	$	38
Restricted Cash included in:
Investments and Other Property	16		14		11
Current Assets—Other	2		1		1
Total Cash, Cash Equivalents, and Restricted Cash	$	28	$	153	$	50

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 and various contractual agreements. 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)	2019			2018			2017
Beginning of Period	$	5		$	5		$	5
Additions Charged to Cost and Expense	4			3			3
Write-offs	(3		)	(3		)	(3		)
End of Period	$	6		$	5		$	5

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.

44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. 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:

	2019		2018		2017
Average AFUDC Rates	7.86	%	7.12	%	7.31	%

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:

	2019		2018		2017
Average Annual Depreciation Rates	3.08	%	3.13	%	2.97	%

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. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense in the income statement.

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.

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet.

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 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.

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.

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Beginning of Period	$	55		$	42
Purchased	45			45
Used for Compliance	(37		)	(32		)
End of Period	$	63		$	55

TEP expenses the cost of internally developed RECs, including PBI activity that is not included in the table above and recoverable through the RES surcharge.

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 in 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 2013 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. TEP had an aggregate liability balance of $6 million and $7 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million and $6 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. 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. 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.

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

47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 10 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 13 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 in 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 in 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 13 for additional information regarding derivative instruments.

NOTE 2. REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

2019 ACC RATE CASE

In April 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018.

TEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019 include:

• a non-fuel retail revenue increase of $99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $60 million over test year retail revenues;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

• a 7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.00% and an average cost of debt of 4.65%;

• a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

• a TEAM that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and

• a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

Hearings before an ALJ were held in January and February 2020. The hearing will resume in April 2020. TEP requested new rates to be implemented by May 1, 2020.

TEP cannot predict the timing or outcome of the proceeding.

2019 FERC RATE CASE

In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund.

Provisions of the order include, but are not limited to:

• replacing TEP's stated transmission rates with a forward-looking formula rate;

• a 10.4% return on equity; and

• elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.

The requested forward-looking formula rate is intended to allow for more timely recovery of transmission related costs. As part of the order, the FERC established hearing and settlement procedures, and all revisions to the OATT in the FERC order are subject to refund. As of December 31, 2019, TEP had reserved $4 million of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as a result of the FERC proceedings. TEP cannot predict the outcome of the proceeding.

Abandoned Plant Costs

Also in May 2019, TEP filed with the FERC a request to recover through its OATT abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. On September 19, 2019, the FERC issued an order allowing TEP to recover 50% of its costs in its formula rate and established hearing and settlement procedures. TEP plans to incorporate the abandoned plant costs into its formula rate effective January 1, 2020, subject to refund. On September 26, 2019, the FERC issued an order consolidating the 2019 FERC Rate Case and Abandoned Plant Costs proceedings. In 2012, TEP wrote-off a portion of the deferred costs related to the Nogales transmission line. As of December 31, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets.

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 issued the ACC Refund Order. The ACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. TEP filed an information filing with the ACC to establish a 2020 customer refund of $35 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our next rate case.

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:

	Years Ended December 31,
(in millions)	2019			2018
Beginning of Period	$	4		$	—
ACC Approved Refund (Reduction in Operating Revenues)	(34		)	(33		)
Amount Returned to Customers Through Bill Credits	22			37
Regulatory Deferral	8			—
End of Period	$	—		$	4

See Note 14 for additional information regarding the TCJA.

Federal Energy Regulatory Commission

In 2018, the FERC issued the 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 NOPR regarding the effect of the TCJA and related EDIT amortization on rates. In November 2019, the FERC issued a final rule on the NOPR which required TEP to address the effect of the TCJA and related EDIT amortization in its next FERC rate case. As required by the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.

See Note 14 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 and goes into effect for the subsequent 12-month period unless the schedule is 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)	2019			2018
Beginning of Period	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs	31			2
PPFAC Refunds (Recoveries) (1)	22			(10		)
End of Period	$	36		$	(17	)

⁽¹⁾  In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Environmental Compliance Adjustor

The 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 $2 million in 2019, $3 million in 2018, and $1 million in 2017 related to the return on company-owned environmental investments included in Operating Revenues on the Consolidated Statements of Income.

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million. The recovery funds the following: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. The Company recognized less than $1 million in 2019, and $1 million in 2018 and 2017 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 and requests recovery of these types of costs through its rate case process.

In 2019, the percentage of TEP's retail kWh sales attributable to the RES was approximately 16%, exceeding the overall 2019 RES requirement of 9%. The ACC approved the waiver of the 2019 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, 2019, TEP's cumulative annual energy savings was approximately 19%.

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 2019, 2018, and 2017 related to performance in Operating Revenues on the Consolidated Statements of Income.

In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is 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 LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.

The table below summarizes the LFCR revenues recognized in Operating Revenues on the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
LFCR Revenues	$	33	$	26	$	22

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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)		2019		2018
Regulatory Assets
Pension and Other Postretirement Benefits (Note 10)	Various	$	135	$	126
Derivatives (Note 13)	10	72		27
Early Generation Retirement Costs	Various	68		72
Lost Fixed Cost Recovery	2	46		35
Income Taxes Recoverable through Future Rates (1)	Various	38		47
Under Recovered Purchased Energy Costs	1	36		—
Property Tax Deferrals (2)	1	24		23
Final Mine Reclamation and Retiree Healthcare Costs (3)	19	19		29
Springerville Unit 1 Leasehold Improvements (4)	4	9		11
Other Regulatory Assets	Various	18		30
Total Regulatory Assets		465		400
Less Current Portion	1	138		107
Total Non-Current Regulatory Assets		$	327	$	293

Regulatory Liabilities
Income Taxes Payable through Future Rates (1)	Various	$	327	$	354
Net Cost of Removal (5)	Various	164		171
Renewable Energy Standard	Various	59		52
Deferred Investment Tax Credits (6)	Various	3		7
Over Recovered Purchased Energy Costs	Various	—		17
Other Regulatory Liabilities	Various	20		6
Total Regulatory Liabilities		573		607
Less Current Portion	1	96		95
Total Non-Current Regulatory Liabilities		$	477	$	512

⁽¹⁾  Amortized over the life of the assets. See Note 14 for additional information regarding income taxes.

⁽²⁾  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.

⁽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⁾  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 period.

⁽⁵⁾  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.

⁽⁶⁾  Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Early Generation Retirement Costs

Navajo Generating Station

In 2017, the Navajo Nation approved a land lease extension allowing TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the co-owners of Navajo retired the generation station in November 2019, with related decommissioning activities continuing through 2054. TEP is currently recovering the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case.

Sundt Generating Station

In 2018, the Pima County Department of Environmental Quality approved TEP's air permit application. Under the project outlined in the application, TEP is placing in service 10 RICE units and was required to retire Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 for Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. See Note 3 for additional information on the RICE units.

Regulatory Assets and Liabilities

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, TEP does not pay a return on regulatory liabilities.

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 (3)	Average Remaining Life in Years (3)	December 31,
($ in millions)			2019		2018
Plant in Service
Generation Plant	3.19%	20	$	3,065	$	2,667
Transmission Plant	1.69%	37	1,060		1,010
Distribution Plant	1.56%	31	1,784		1,692
General Plant	5.89%	20	477		409
Intangible Plant, Software Costs, and Other (1)	Various	Various	271		239
Plant Held for Future Use	—	—	7		3
Total Plant in Service (2)			$	6,664	$	6,020

⁽¹⁾  Primarily represents computer software. Unamortized computer software costs were $78 million and $73 million as of December 31, 2019 and 2018, respectively. Amortized computer software costs were $26 million in 2019, $24 million in 2018, and $19 million in 2017. 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 $(211) million and $(134) million as of December 31, 2019 and 2018, respectively.

⁽³⁾  Based on the 2015 depreciation study available for the major classes of Plant in Service, effective March 1, 2017, as approved by the ACC as part of the 2017 TEP Rate Order. TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 2019 FERC Rate Case.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Gila River Unit 2

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 included a three-year option to purchase the unit. The Tolling PPA was accounted for as a finance lease. See Note 8 for additional information regarding TEP's leases. In December 2019, TEP completed its purchase of Gila River Unit 2 for $165 million. The purchase increased Plant in Service and Material and Supplies and decreased Utility Plant Under Finance Leases on the Consolidated Balance Sheets as of December 31, 2019.

RICE Units

Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed in service five natural gas RICE units in December 2019. As a result, Plant in Service on the Consolidated Balance Sheets increased by $82 million. An additional five units are scheduled to be placed in service in the first quarter of 2020. The 10 units have a planned total nominal generation capacity of 188 MW.

JOINTLY-OWNED FACILITIES

As of December 31, 2019, TEP was a participant in the following jointly-owned generation facilities and transmission systems:

(in millions)	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation			Net Book Value
San Juan Unit 1	50.0%	$	289	$	1	$	(193	)	$	97
Four Corners Units 4 and 5	7.0%	175		5		(77		)	103
Luna	33.3%	57		—		(1		)	56
Gila River Unit 3	75.0%	200		2		(61		)	141
Gila River Common Facilities	43.8%	71		—		(23		)	48
Springerville Coal Handling Facilities	83.0%	208		—		(90		)	118
Transmission Facilities	Various	545		5		(295		)	255
Total		$	1,545	$	13	$	(740	)	$	818

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.

ASSET RETIREMENT OBLIGATIONS

The liability accrual of AROs is primarily related to generation and PV assets and is included in 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)	2019			2018
Beginning of Period	$	72		$	46
Liabilities Incurred	—			10
Liabilities Settled (1)	(2		)	—
Regulatory Deferral/Accretion Expense	2			3
Revisions to the Present Value of Estimated Cash Flows (2)	35			13
End of Period	$	107		$	72

⁽¹⁾  Primarily related to the retirement of Navajo.

⁽²⁾  Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of certain generation facilities.

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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)	2019		2018		2017
Retail	$	972	$	1,022	$	1,017
Wholesale	247		238		152
Other Services	124		100		103
Revenues from Contracts with Customers	1,343		1,360		1,272
Alternative Revenues	35		28		24
Other	40		45		45
Total Operating Revenues	$	1,418	$	1,433	$	1,341

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. Unbilled revenues primarily 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 cash collections results in billed and unbilled accounts receivable balances in the balance sheet. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.

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 May 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing proposed replacing TEP's stated transmission rates with a forward-looking formula rate. Effective August 2019, the FERC authorized TEP to bill the proposed rate revisions, subject to refund. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the FERC rate case.

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. 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 in the income statement based on the nature of services provided.

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 13 for information regarding derivative instruments and Note 8 for information regarding lease income.

NOTE 5. ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Customer (1)	$	92		$	99
Customer, Unbilled	42			45
Due from Affiliates (Note 6)	8			8
Other	19			25
Allowance for Doubtful Accounts	(6		)	(5		)
Accounts Receivable, Net	$	155		$	172

⁽¹⁾  Includes $5 million and $8 million as of December 31, 2019 and 2018, respectively, of receivables related to revenue from derivative instruments.

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 6. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and the 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)	2019		2018
Receivables from Related Parties
UNS Electric	$	6	$	7
UNS Gas	2		1
Total Due from Related Parties	$	8	$	8
Payables to Related Parties
SES	$	2	$	2
UNS Electric	1		1
UNS Gas	—		1
UNS Energy	1		1
Total Due to Related Parties	$	4	$	5

The following table presents the components of related party transactions included in the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	7	$	6	$	7
Wholesale Revenues, UNS Electric (1)	1		1		—
Control Area Services, UNS Electric (2)	4		3		3
Common Costs, UNS Energy Affiliates (3)	19		18		16
Corporate Services, Fortis Affiliates (4)	—		—		2
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (5)	15		15		15
Corporate Services, UNS Energy (6)	6		6		5
Corporate Services, UNS Energy Affiliates (7)	4		7		5
Capacity Charges, UNS Gas (8)	1		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 OATT.

⁽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 83% of UNS Energy's allocated costs.

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $6 million in 2019, $5 million in 2018, and $6 million in 2017.

⁽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.

CONTRIBUTIONS FROM PARENT

In January 2020, an equity contribution of $125 million was received by TEP from UNS Energy.

NOTE 7. DEBT AND CREDIT AGREEMENTS

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:

			December 31,
($ in millions)	Interest Rate	Maturity Date	2019		2018
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		300
Tax-Exempt Local Furnishings Bonds (1)
2010 Pima A	5.25%	2040	100		100
2012 Pima A	4.50%	2030	16		16
2013 Pima A	4.00%	2029	91		91
Tax-Exempt Pollution Control Bonds (2)
2009 Pima A	4.95%	2020	80		80
2009 Coconino A	5.13%	2032	—		15
2012 Apache A	4.50%	2030	177		177
Total Long-Term Debt (3)			1,614		1,629
Less Unamortized Discount and Debt Issuance Costs			12		14
Less Current Maturities of Long-Term Debt			80		—
Total Long-Term Debt, Net			$	1,522	$	1,615

⁽¹⁾  The 2010 Pima A bonds can be redeemed at par on or after October 2020. TEP has the option to redeem the remaining bonds at par on dates ranging from first quarter of 2022 to first quarter of 2023.

⁽²⁾  The 2009 Pima A bonds mature in October 2020. The 2012 Apache A bonds may be redeemed at par in the first quarter of 2022.

⁽³⁾  As of December 31, 2019, all of TEP's debt is unsecured.

Issuances and Redemptions

Fixed Rate Debt

In November 2019, TEP redeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of $15 million prior to the maturity of the bonds.

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 expired 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.

Maturities

Long-term debt matures on the following dates:

(in millions)	Long-Term Debt (1)
2020	$	80
2021	250
2022	—
2023	150
2024	—
Thereafter	1,134
Total	$	1,614

⁽¹⁾  Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount.

CREDIT AGREEMENTS

Amounts borrowed under credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets.

2019 Credit Agreement

In December 2019, TEP entered into an unsecured credit agreement with a maturity date of December 2020 that provides for term loans. Terms are as follows:

							Weighted Average Interest Rate
	Capacity		Borrowed (1)		Available				Pricing
(in millions)	December 31, 2019
Term Loan	$	225	$	165	$	60	4.75	%	LIBOR + 0.550%	or ABR + 0.00%

⁽¹⁾  All amounts borrowed will be due and payable by December 2020.

The 2019 Credit Agreement is intended to supplement TEP's liquidity during a period of increased capital spending and to provide funds: (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. Amounts paid or repaid may not be reborrowed. As of February 12, 2020, no amount was available as the term loan had been fully drawn. See Note 3 and Note 9 for additional information on the purchase of Gila River Unit 2 and Oso Grande, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2015 Credit Agreement

In October 2015, TEP entered into an unsecured credit agreement with a maturity date of October 2022 that provides for revolving credit commitments and LOC facilities. Terms are as follows:

	Capacity		Sub-Limit LOC		Borrowed		Available		Weighted Average Interest Rate		Pricing (1)
(in millions)	December 31, 2019
Revolver and LOC	$	250	$	50	$	—	$	250	—	%	LIBOR + 1.000%	or ABR + 0.00%

(in millions)	December 31, 2018
Revolver and LOC	$	250	$	50	$	—	$	250	—	%	LIBOR + 1.000%	or ABR + 0.00%

⁽¹⁾  Interest rates and fees are based on a pricing grid tied to TEP's credit rating.

Amounts borrowed under the 2015 Credit Agreement will be used for working capital and other general corporate purposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities.

In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 12, 2020, there was $173 million available under the revolving credit commitments and LOC facilities.

NOTE 8. LEASES

TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s leases are included in the balance sheet as follows:

(in millions)	Lease Type	December 31, 2019
Lease Assets
Utility Plant Under Finance Leases	Finance	$	151
Accumulated Amortization of Finance Lease Assets	Finance	(77		)
Regulatory and Other Assets, Other	Operating	8
Lease Liabilities
Current Liabilities, Finance Lease Obligations	Finance	17
Finance Lease Obligations	Finance	67
Current Liabilities, Other	Operating	1
Regulatory and Other Liabilities, Other	Operating	6

Springerville Common Facilities Leases

TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019, TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million. The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities.

Gila River Unit 2

In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20-year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Tolling PPA included a three-year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed.

The following table presents the components of TEP’s lease cost:

	Year Ended
(in millions)	December 31, 2019
Finance
Amortization of Leased Assets (1)	$	13
Interest on Lease Liabilities (2)	13
Operating	1
Variable	16
Short Term	1
Total Lease Cost	$	44

⁽¹⁾  TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment.

⁽²⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019. TEP purchased Gila River Unit 2 in December 2019.

TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.

As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:

(in millions)	Finance Leases		Operating Leases		Total
2020	$	18	$	1	$	19
2021	68		1		69
2022	—		1		1
2023	—		1		1
2024	—		1		1
Thereafter	—		4		4
Total Lease Payments	86		9		95
Less Imputed Interest	2		2		4
Total Lease Obligations	84		7		91
Less Current Portion	17		1		18
Total Non-Current Lease Obligations	$	67	$	6	$	73

The following table presents TEP's lease terms and discount rate related to its leases:

	December 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	2.2	%
Operating Leases	4.1	%

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents TEP's cash flow information related to its leases:

	Year Ended
(in millions)	December 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	13
Operating Cash Flows used for Operating Leases	1
Financing Cash Flows used for Finance Leases	11
Investing Cash Flows used for Finance Leases	164

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years.

Operating lease income for the year ended December 31, 2019, was $1 million. TEP's expected operating lease payments to be received as of December 31, 2019, are $1 million in each of 2020 through 2024 and thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

TEP's operating lease cost was $1 million for the year ended December 31, 2018.

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 9. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

Unconditional Purchase Obligations

As of December 31, 2019, TEP had the following unconditional minimum purchase obligations:

(in millions)	2020		2021		2022		2023		2024		Thereafter		Total
Fuel, Including Transportation	$	94	$	61	$	40	$	33	$	33	$	194	$	455
Purchased Power	8		—		—		—		—		—		8
Transmission	21		16		14		3		3		6		63
Renewable Power Purchase Agreements	63		63		63		63		62		543		857
RES Performance-Based Incentives	8		7		7		7		7		33		69
Land Easements and Rights-of-Way (1)	1		2		1		1		3		79		87
Total Purchase Commitments	$	195	$	149	$	125	$	107	$	108	$	855	$	1,539

⁽¹⁾  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 2020 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.

TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2022 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 2020. 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, 2019.

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 2020 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Build-Transfer Agreement

In March 2019, TEP entered into a build-transfer agreement to develop a 250 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico (Oso Grande) with estimated costs of approximately $384 million. In January 2020, TEP took ownership of Oso Grande. Construction commenced in the third quarter of 2019 and is expected to be completed for operation by December 2020. TEP made payments under the build-transfer agreement of $47 million in 2019 and $226 million in January 2020.

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 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 Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to SJCC) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, 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 OSMRE so the OSMRE 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 2019. The order provides that: (i) the OSMRE’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 2019, then the approved mine plan will immediately be vacated, absent further court order. On April 30, 2019, the OSMRE issued a final Record of Decision (ROD) on the Final EIS released March 15, 2019. The Final EIS contemplates continued mining at the San Juan Mine in annual quantities similar to those currently being provided through 2033. The Assistant Secretary for Land and Minerals Management approved the mining plan outlined in the ROD in August 2019. TEP is not a party in this matter but does own 50% of Unit 1 at San Juan. San Juan is scheduled for early retirement in 2022. TEP does not anticipate any significant impact on the cost of coal at San Juan related to this matter.

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. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing 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’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP defers these expenses until recovered from rate payers 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 out.

San Juan and Four Corners

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of mine reclamation costs at both mines is $57 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $36 million and $31 million as of December 31, 2019 and 2018, respectively, was recorded in Other on the Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Navajo

In December 2019, TEP entered into an agreement with the owner and operator of the Kayenta Mine and the third-party owners of Navajo for the settlement and release of asserted claims associated with the early retirement of Navajo. During 2019, TEP paid $17 million related to the retirement of Navajo which includes $8 million paid for final mine reclamation costs as a result of the settlement. As of December 31, 2019, TEP had no liability balance related to Navajo final mine reclamation. A liability balance related to Navajo final mine reclamation of $5 million as of December 31, 2018, was recorded in Current Liabilities—Other on the Consolidated Balance Sheets.

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, 2019, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generating station. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046.

Environmental Matters

TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.

Broadway-Pantano Site

The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop substation and a portion of a related transmission line are located on two parcel adjacent to these landfills. On November 8, 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements, however, the overall investigation and remediation plan have not been finalized.

NOTE 10. 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.

65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $1 million in 2019 and $3 million in 2018 and 2017 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.

The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet:

	Pension Benefits						Other Postretirement Benefits
	December 31,
(in millions)	2019			2018			2019			2018
Regulatory Assets	$	135		$	126		$	—		$	—
Regulatory Liabilities	—			—			(1		)	(3		)
Accrued Employee Expenses	(2		)	(1		)	(2		)	(3		)
Pension and Other Postretirement Benefits	(77		)	(63		)	(56		)	(54		)
Accumulated Other Comprehensive Loss, SERP	10			6			—			—
Net Amount Recognized	$	66		$	68		$	(59	)	$	(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, 2019 and 2018. 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)	2019			2018			2019			2018
Change in Benefit Obligation
Beginning of Period	$	440		$	475		$	74		$	82
Actuarial (Gain) Loss	76			(42		)	4			(8		)
Interest Cost	18			16			3			2
Service Cost	13			15			4			5
Benefits Paid	(23		)	(23		)	(6		)	(5		)
Plan Amendments	1			(1		)	—			(2		)
End of Period	525			440			79			74
Change in Fair Value of Plan Assets
Beginning of Period	376			403			17			17
Actual Return on Plan Assets	81			(25		)	4			(1		)
Benefits Paid	(22		)	(23		)	(6		)	(5		)
Employer Contributions (1)	11			21			6			6
End of Period	446			376			21			17
Funded Status at End of Period	$	(79	)	$	(64	)	$	(58	)	$	(57	)

⁽¹⁾  TEP expects to contribute $11 million to the pension plans and $1 million to the VEBA trust in 2020.

The $85 million increase in the pension benefit obligation was driven by a significant decrease in discount rates as a result of a decrease in interest rates. The $70 million increase in the pension plan assets was due to positive equity returns and fixed income returns as a result of a decline in interest rates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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)	2019		2018		2019			2018
Net (Gain) Loss	$	145	$	133	$	1		$	(1	)
Prior Service Cost (Benefit)	—		—		(2		)	(2		)

The accumulated benefit obligation aggregated for all pension plans was $476 million and $402 million as of December 31, 2019 and 2018, respectively. All of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2019 and 2018. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:

	December 31,
(in millions)	2019		2018
Accumulated Benefit Obligation	$	476	$	230
Fair Value of Plan Assets	446		202

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)	2019			2018			2017			2019			2018			2017
Service Cost	$	13		$	15		$	13		$	4		$	5		$	4
Non-Service Cost
Interest Cost	18			16			15			3			2			2
Expected Return on Plan Assets	(26		)	(28		)	(25		)	(2		)	(1		)	(1		)
Amortization of Net (Gain) Loss	8			7			8			—			—			—
Net Periodic Benefit Cost	$	13		$	10		$	11		$	5		$	6		$	5

The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. In 2019 and 2018, TEP capitalized 21% and 19% of service cost, respectively, 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)	2019			2018			2017			2019			2018			2017		2019		2018			2017
Current Year Actuarial (Gain) Loss	$	16		$	12		$	5		$	4		$	(1	)	$	3	$	1	$	(6	)	$	(1	)
Amortization of Net Loss	(8		)	(7		)	(7		)	(1		)	—			—		—		—			—
Prior Service Credit (Cost)	—			—			—			1			(1		)	—		—		(2		)	—
Total Recognized (Gain) Loss	$	8		$	5		$	(2	)	$	4		$	(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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table includes the weighted average assumptions used to determine benefit obligations:

	Pension Benefits		Other Postretirement Benefits
	2019	2018	2019	2018
Discount Rate	3.6%	4.5%	3.3%	4.3%
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
	2019	2018	2017	2019	2018	2017
Discount Rate, Service Cost	4.7%	3.8%	4.4%	4.5%	3.8%	4.3%
Discount Rate, Interest Cost	4.2%	3.4%	3.7%	4.0%	3.2%	3.3%
Rate of Compensation Increase	2.8%	2.8%	2.8%	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,
	2019	2018
Next Year (Pre-65)	6.3%	6.5%
Next Year (Post-65)	7.5%	7.8%
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	2037

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
	2019		2018		2019		2018
Asset Category
Equity Securities	46	%	45	%	65	%	60	%
Fixed Income Securities	45	%	45	%	33	%	38	%
Real Estate	8	%	8	%	—	%	—	%
Other	1	%	2	%	2	%	2	%
Total	100	%	100	%	100	%	100	%

As of December 31, 2019, the fair value of VEBA trust assets was $21 million, of which $7 million were fixed income investments and $14 million were equities. 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. 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.

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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, 2019
Asset Category
Cash Equivalents	$	2	$	—	$	—	$	2
Equity Securities:
United States Large Cap	—		55		—		55
United States Small Cap	—		21		—		21
Non-United States	—		80		—		80
Global	—		51		—		51
Fixed Income	—		199		—		199
Real Estate	—		10		23		33
Private Equity	—		—		5		5
Total	$	2	$	416	$	28	$	446

	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

• 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.

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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, 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
Actual Return on Plan Assets:
Assets Held at Reporting Date	1			1		2
Purchases, Sales, and Settlements	(2		)	—		(2		)
Balance as of December 31, 2019	$	5		$	23	$	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.

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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, 2019
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)	2020		2021		2022		2023		2024		2025-2029
Pension Benefits	$	26	$	26	$	26	$	27	$	28	$	147
Other Postretirement Benefits	5		5		5		5		5		25

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 $6 million in 2019, $7 million in 2018, and $6 million in 2017.

NOTE 11. SHARE-BASED COMPENSATION

2015 SHARE UNIT PLAN

The Human Resources and Governance 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 PSUs and RSUs annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table represents PSUs and RSUs awarded by UNS Energy:

	2019	2018	2017
PSUs	66,978	54,426	68,126
RSUs	33,489	27,213	34,063

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 $12 million and $9 million as of December 31, 2019 and 2018, respectively.

TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2019, $2 million in 2018, and $4 million in 2017 based on its share of UNS Energy's compensation expense.

NOTE 12. SUPPLEMENTAL CASH FLOW INFORMATION

CASH TRANSACTIONS

	Years Ended December 31,
(in millions)	2019			2018		2017
Interest Paid, Net of Amounts Capitalized	$	80		$	67	$	61
Income Tax Refunds (1)	(14		)	—		—

⁽¹⁾  TEP received a refund of AMT credit carryforwards in 2019. See Note 14 for additional information regarding AMT.

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
(in millions)	2019			2018			2017
Finance Leases	$	67		$	164		$	—
Accrued Capital Expenditures	40			31			24
Asset Retirement Obligations Increase (Decrease) (1)	26			20			10
Operating Leases (2)	8			—			—
Renewable Energy Credits	3			3			2
Net Cost of Removal Increase (Decrease) (3)	(10		)	(4		)	(88		)

⁽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 expected future AROs.

⁽²⁾  On January 1 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods.

⁽³⁾  Represents an accrual for future cost of retirement net of salvage values that does not impact earnings.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 13. 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.

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 through net income 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, 2019
Assets
Restricted Cash (1)	$	18	$	—		$	—	$	18
Energy Derivative Contracts, Regulatory Recovery (2)	—		3			—		3
Energy Derivative Contracts, No Regulatory Recovery (2)	—		3			—		3
Total Assets	18		6			—		24
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(76		)	—		(76		)
Total Liabilities	—		(76		)	—		(76		)
Total Assets (Liabilities), Net	$	18	$	(70	)	$	—	$	(52	)

(in millions)	December 31, 2018
Assets
Cash Equivalents (1)	$	55	$	—		$	—		$	55
Restricted Cash (1)	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery (2)	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			2			2
Total Assets	70		10			2			82
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	70	$	(25	)	$	—		$	45

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit, 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 2 as of December 31, 2019 and Level 3 as of December 31, 2018) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to decreases in forward market prices of natural gas and increases in volume.

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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, 2019
Derivative Assets
Energy Derivative Contracts	$	6		$	4		$	—		$	2
Derivative Liabilities
Energy Derivative Contracts	(76		)	(4		)	(2		)	(70		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

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. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.

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 had an interest rate swap agreement that expired in January 2020. As of December 31, 2019, the total notional amount of the interest rate swap was $6 million. No notional amount remained as of February 12, 2020. The after-tax unrealized gains and losses on cash flow hedge activities were reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense on the Consolidated Statements of Income are not material to TEP's financial position or results of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 in the balance sheet:

	Years Ended December 31,
(in millions)	2019			2018			2017
Unrealized Net Loss (1)	$	(45	)	$	(9	)	$	(18	)

⁽¹⁾  In 2019, unrealized net loss on regulatory recoverable derivative contracts increased primarily due to decreases in forward market prices of natural gas and increases in volume.

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)	2019		2018		2017
Operating Revenues	$	6	$	5	$	5

Derivative Volumes

As of December 31, 2019, 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,
	2019	2018
Power Contracts GWh	4,740	1,743
Gas Contracts BBtu	122,779	146,933

Level 3 Fair Value Measurements

As of December 31, 2019, TEP does not have any Level 3 assets and liabilities balances remaining. The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:

	Valuation Approach	Fair Value of					Unobservable Inputs	Range of Unobservable Inputs
		Assets		Liabilities
(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

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 regulatory asset or regulatory liability, or as a component of other comprehensive income (loss), rather than in the income statement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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)	2019			2018
Beginning of Period	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(12		)	(4		)
Operating Revenues	5			5
Settlements	1			(2		)
Transfers Out of Level 3 (1)	5			—
End of Period	$	—		$	1
Gains (Losses), Assets (Liabilities) Still Held	$	—		$	1

⁽¹⁾  Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities.

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, LOCs, 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 $100 million as of December 31, 2019, compared with $41 million as of December 31, 2018. As of December 31, 2019, TEP had $2 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets—Other on the Consolidated Balance Sheets. As of February 12, 2020, there was no collateral posted. If the credit risk contingent features were triggered on December 31, 2019, TEP would have been required to post an additional $98 million of collateral of which $19 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.

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt:

		Net Carrying Value				Fair Value
	Fair Value Hierarchy	December 31,
(in millions)		2019		2018		2019		2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,602	$	1,615	$	1,755	$	1,672

NOTE 14. 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 2019 and 2018 and 35% in 2017 to pre-tax income due to the following:

	Years Ended December 31,
(in millions)	2019			2018			2017
Federal Income Tax Expense at Statutory Rate	$	46		$	49		$	97
State Income Tax Expense, Net of Federal Deduction	9			9			9
Federal/State Tax Credits	(6		)	(10		)	(9		)
Allowance for Equity Funds Used During Construction	(3		)	(1		)	(2		)
Impact of Enactment, TCJA	—			—			7
Excess Deferred Income Taxes	(9		)	(6		)	—
Impact of AMT Sequestration	(2		)	2			—
Other	(1		)	—			(1		)
Total Federal and State Income Tax Expense	$	34		$	43		$	101

Income Tax Expense included on the Consolidated Statements of Income consists of the following:

	Years Ended December 31,
(in millions)	2019			2018			2017
Current Income Tax Expense
Federal	$	(8	)	$	(13	)	$	—
State	—			—			—
Total Current Income Tax Expense	(8		)	(13		)	—
Deferred Income Tax Expense
Federal	41			53			98
Federal Investment Tax Credits	(4		)	(6		)	(6		)
State	5			9			9
Total Deferred Income Tax Expense	42			56			101
Total Federal and State Income Tax Expense	$	34		$	43		$	101

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 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $9 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019. 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, 2019, TEP had a receivable of $7 million related to the AMT credit carryforwards in Current Assets—Other on the Consolidated Balance Sheets.

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In 2018, the Company recorded $2 million of income tax expense related to the estimated impact of sequestration on future AMT credit refunds. In 2019, TEP reversed the $2 million in income tax expense, as the AMT credit refunds were no longer subject to sequestration due to the IRS revising previously issued guidance.

The significant components of deferred income tax assets and liabilities consist of the following:

	December 31,
(in millions)	2019			2018
Gross Deferred Income Tax Assets
Finance Lease Obligations	$	21		$	48
Operating Loss Carryforwards, Net	3			23
Customer Advances and Contributions in Aid of Construction	19			16
AMT Credit	7			13
Other Postretirement Benefits	15			15
Investment Tax Credit Carryforward	34			34
Income Taxes Recoverable Through Future Rates	81			87
Other	79			60
Total Gross Deferred Income Tax Assets	259			296
Deferred Tax Assets Valuation Allowance	—			—
Gross Deferred Income Tax Liabilities
Plant, Net	(602		)	(552		)
Plant Abandonments	(17		)	(18		)
Finance Lease Assets, Net	(18		)	(44		)
Pensions	(17		)	(19		)
Income Taxes Payable Through Future Rates	(9		)	(12		)
Other	(28		)	(21		)
Total Gross Deferred Income Tax Liabilities	(691		)	(666		)
Deferred Income Taxes, Net	$	(432	)	$	(370	)

TEP recorded no valuation allowance against credit and net operating loss carryforward deferred income tax assets as of December 31, 2019 and 2018. 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, 2019, TEP had the following carryforward amounts:

(in millions)	Amount		Expiring Year
Federal Net Operating Loss	$	17	2034 - 35
State Credits	9		2022 - 29
AMT Credit	7		None
Investment Tax Credits	34		2031 - 37

UNCERTAIN TAX POSITIONS

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	December 31,
(in millions)	2019		2018
Beginning of Period	$	16	$	13
Additions Based on Tax Positions Taken in the Current Year	2		3
End of Period	$	18	$	16

Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 2019 and 2018.

78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP recorded no interest expense during 2019 and 2018 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2019 and 2018.

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.

A decrease of $17 million in the Company's uncertain tax position obligations could occur within the next twelve months pending the outcome of an application for change in accounting method filed with the IRS.

TAX SHARING AGREEMENT

Under the terms of the tax sharing agreement with UNS Energy, TEP received $14 million in 2019 related to the 2018 Federal income tax returns and no payments in 2018 related to the 2017 Federal income tax returns.

79

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 15. 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)	2019
Operating Revenue	$	333	$	326	$	441	$	318
Operating Income	43		67		134		39
Net Income	26		42		98		21
	2018
Operating Revenue	$	275	$	354	$	460	$	344
Operating Income	43		83		126		36
Net Income	24		58		95		11

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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) and 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 were effective as of December 31, 2019.

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, 2019. 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, 2019, TEP’s internal control over financial reporting was effective.

Changes in Internal Control Over Financial Reporting

There has been no change in TEP’s internal control over financial reporting during the fourth quarter of 2019 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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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)	2019		2018
Audit Fees (1)	$	924	$	1,268
Audit-Related Fees (2)	100		140
Tax Fees (3)	25		—
Total	$	1,049	$	1,408

⁽¹⁾  Audit Fees includes fees billed, or expected to be billed, by Deloitte, for professional services for the financial statement audits of 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 Fees also includes services provided by Deloitte in

82

connection with comfort letters, consents, and other services related to SEC matters, financing transactions, and statutory and regulatory audits.

⁽²⁾  Audit-Related Fees are fees billed, or expected to be billed, by Deloitte for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above. The fees are for additional procedures for nonrecurring material transactions in 2019 and 2018.

⁽³⁾  Tax Fees are fees billed by Deloitte for professional services related to tax planning and tax strategy.

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.

83

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

			Page
(a)	(1)	Consolidated Financial Statements as of December 31, 2019 and 2018, and for each of the three years in the period ended December 31, 2019:
		Report of Independent Registered Public Accounting Firm	35
		Consolidated Statements of Income	36
		Consolidated Statements of Comprehensive Income	37
		Consolidated Statements of Cash Flows	38
		Consolidated Balance Sheets	39
		Consolidated Statement of Changes in Stockholder’s Equity	41
		Notes to Consolidated Financial Statements	42
	(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 85.

ITEM 16. FORM 10-K SUMMARY

Not Applicable.

84

Exhibit Index
Exhibit No.	Description
*3(a)	Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for the year ended December 31, 1996, File No. 1-05924 - Exhibit No 3(a)).
*3(a)(1)	TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-05924 - Exhibit 3(a)).
*3(b)	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).
*3(c)	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).
*4(a)(1)	Indenture of Trust, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association authorizing Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company Navajo Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(A)).
*4(a)(2)	Loan Agreement, dated as of October 1, 2009, between The Industrial Development Authority of the County of Pima and TEP relating to Pollution Control Revenue Bonds, 2009 Series A (Tucson Electric Power Company San Juan Project). (Form 8-K dated October 13, 2009, File No. 1-05924 - Exhibit 4(B)).
*4(b)(1)	Indenture of Trust, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-05924 Exhibit 4(a)).
*4(b)(2)	Loan Agreement, dated as of October 1, 2010, between the Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2010 Series A (Tucson Electric Power Company Project). (Form 8-K dated October 8, 2010, File No. 1-05924 - Exhibit 4(b)).
*4(c)(1)	Indenture of Trust, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and U.S. Bank Trust National Association, authorizing Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(a)).
*4(c)(2)	Loan Agreement, dated as of March 1, 2012, between The Industrial Development Authority of the County of Apache and TEP, relating to Pollution Control Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 21, 2012, File No. 1-05924 - Exhibit 4(b)).
*4(d)(1)	Indenture of Trust, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(a)).
*4(d)(2)	Loan Agreement, dated as of June 1, 2012, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2012 Series A (Tucson Electric Power Company Project). (Form 8-K dated June 21, 2012, File No. 1-05924 - Exhibit 4(b)).
*4(e)(1)	Indenture of Trust, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and U.S. Bank Trust National Association, authorizing Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(a)).
*4(e)(2)	Loan Agreement, dated as of March 1, 2013, between The Industrial Development Authority of the County of Pima and TEP, relating to Industrial Development Revenue Bonds, 2013 Series A (Tucson Electric Power Company Project). (Form 8-K dated March 14, 2013, File No. 1-05924 - Exhibit 4(b)).

85

*4(f)(1)	Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank National Association, as trustee, authorizing unsecured Notes (Form 8-K dated November 8, 2011, File 1-05924 - Exhibit 4.1).
*4(f)(2)	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).
*4(f)(3)	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).
*4(f)(4)	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).
*4(f)(5)	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)).
*4(f)(6)	Officer's Certificate, dated November 29, 2018, authorizing 4.85% Senior Notes due 2048.
*4(g)	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).
*4(h)	Credit Agreement, dated as of December 11, 2019, among Tucson Electric Power Company, Truist Bank, as Administrative Agent, and a group of lenders (Form 8-K dated December 11, 2019, File No. 1-05924 - Exhibit 4.1).
23	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm.
24	Power of Attorney.
31(a)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens.
31(b)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino.
**32	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.
104	The cover page from the Company's Annual Report on Form 10-K for the year ended December 31, 2019, formatted in Inline XBRL and contained in Exhibit 101
*	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.

86

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 12, 2020	/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 12, 2020		*
			David G. Hutchens
			Chief Executive Officer
			(Principal Executive Officer)
Date:	February 12, 2020		/s/ Frank P. Marino
			Frank P. Marino
			Sr. Vice President, Chief Financial Officer, and Director
			(Principal Financial Officer and Principal Accounting Officer)
Date:	February 12, 2020		*
			Susan M. Gray
			President, Chief Operating Officer, and Director
Date:	February 12, 2020		*
			Todd C. Hixon
			Director
		*By:	/s/ Frank P. Marino
			Frank P. Marino
			Attorney-in-fact

87

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-231982 on Form S-3 of our report dated February 12, 2020, relating to the consolidated financial statements of Tucson Electric Power Company and subsidiaries, appearing in this Annual Report on Form 10-K of Tucson Electric Power Company for the year ended December 31, 2019.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP

Phoenix, Arizona

February 12, 2020

EX-24

Exhibit 24

Power of Attorney

KNOW ALL BY THESE PRESENTS, that the undersigned Principal Executive Officer, Principal Financial Officer, Principal Accounting Officer, officers and/or directors of Tucson Electric Power Company, an Arizona corporation, which corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 2019, under the Securities Exchange Act of 1934, as amended, does each for himself or herself and not for one another, hereby constitute and appoint Frank P. Marino and Todd C. Hixon and each of them, his or her true and lawful attorneys, in his or her name, place and stead, to sign his or her name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said attorneys, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and each of the undersigned for himself or herself hereby ratifies and confirms all that said attorneys, or any one of them, shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 12th day of February, 2020.

/s/ David G. Hutchens

David G. Hutchens

Chief Executive Officer

(Principal Executive Officer)

/s/ Frank P. Marino

Frank P. Marino

Sr. Vice President, Chief Financial Officer, and Director

(Principal Financial Officer and Principal Accounting Officer)

/s/ Susan M. Gray

Susan M. Gray

President, Chief Operating Officer, and Director

/s/ Todd C. Hixon

Todd C. Hixon

Director

EX-31.A

Exhibit 31(a)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, David G. Hutchens, certify that: 

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2019, of Tucson Electric Power Company; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 12, 2020	/s/ David G. Hutchens
		David G. Hutchens
		Chief Executive Officer
		(Principal Executive Officer)

EX-31.B

Exhibit 31(b)

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act

I, Frank P. Marino, certify that: 

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2019, of Tucson Electric Power Company; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): 

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and     

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 12, 2020	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)

EX-32

Exhibit 32

STATEMENTS OF CORPORATE OFFICERS

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Each of the undersigned, David G. Hutchens, Chief Executive Officer of Tucson Electric Power Company (the “Company”), and Frank P. Marino, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 12, 2020	/s/ David G. Hutchens
		David G. Hutchens
		Chief Executive Officer
		(Principal Executive Officer)
Date:	February 12, 2020	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)

XML

LEASES (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) option	Dec. 31, 2018 USD ($)	Dec. 31, 2017 MWh	Jan. 31, 2021	May 31, 2018
Lessee, Lease, Description [Line Items]
Renewal term	15 years
Number of renewal options | option	1
Operating lease income	$ 1
Operating lease cost	1	$ 1
Lessor, Operating Lease, Payments, Fiscal Year Maturity
2020	1
2021	1
2022	1
2023	1
2024	1
Thereafter	$ 1
Tolling PPA
Lessee, Lease, Description [Line Items]
Term of contract					20 years
Generating capacity (MW) | MWh			550
Option to purchase unit, term			3 years
Energy Storage
Lessee, Lease, Description [Line Items]
Lease not yet commenced, term of contract	20 years
Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Remaining lease term	3 years
Springerville Common Facilities
Lessee, Lease, Description [Line Items]
Commitment to purchase finance lease interest	$ 68
Springerville Common Facilities | Forecast
Lessee, Lease, Description [Line Items]
Percentage of interest to be purchased (in percentage)				32.20%
Springerville Common Facilities | Tri-State
Lessee, Lease, Description [Line Items]
Percentage of interest to be purchased (in percentage)	14.00%
Springerville Common Facilities | SRP
Lessee, Lease, Description [Line Items]
Percentage of interest to be purchased (in percentage)	14.00%
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Minimum | Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Renewal term	4 years
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	22 years
Maximum | Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Remaining lease term	13 years

XML

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Percent of gains shared with ratepayers									10.00%
Operating Revenues	$ 318,000	$ 441,000	$ 326,000	$ 333,000	$ 344,000	$ 460,000	$ 354,000	$ 275,000	$ 1,418,338	$ 1,432,618	$ 1,340,935
Energy Derivative | Not Designated
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Loss									(45,000)	(9,000)	(18,000)
Operating Revenues									$ 6,000	$ 5,000	$ 5,000

XML

SUPPLEMENTAL CASH FLOW INFORMATION (Cash Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Interest Paid, Net of Amounts Capitalized	$ 80	$ 67	$ 61
Income Tax Refunds	$ (14)	$ 0	$ 0

XML

DEBT AND CREDIT AGREEMENTS (Long-term Debt) (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total Long-Term Debt	$ 1,614,000	$ 1,629,000
Less Unamortized Discount and Debt Issuance Costs	12,000	14,000
Current Maturities of Long-Term Debt	80,000	0
Total Long-Term Debt, Net	$ 1,522,087	1,615,252
2011 Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	5.15%
Total Long-Term Debt	$ 250,000	250,000
2012 Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	3.85%
Total Long-Term Debt	$ 150,000	150,000
2014 Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	5.00%
Total Long-Term Debt	$ 150,000	150,000
2015 Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	3.05%
Total Long-Term Debt	$ 300,000	300,000
2018 Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.85%
Total Long-Term Debt	$ 300,000	300,000
2010 Pima A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	5.25%
Total Long-Term Debt	$ 100,000	100,000
2012 Pima A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.50%
Total Long-Term Debt	$ 16,000	16,000
2013 Pima A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.00%
Total Long-Term Debt	$ 91,000	91,000
2009 Pima A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.95%
Total Long-Term Debt	$ 80,000	80,000
2009 Coconino A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	5.13%
Total Long-Term Debt	$ 0	15,000
2012 Apache A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.50%
Total Long-Term Debt	$ 177,000	$ 177,000

XML

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Feb. 12, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
FV of derivative instruments in net liability positions with credit risk related features, including normal purchase normal sale		$ 100,000,000	$ 41,000,000
Collateral posted		2,000,000
Additional collateral to post if credit-risk contingent features are triggered		98,000,000
Outstanding Net Payable Balances for Settled Positions
Derivative [Line Items]
Additional collateral to post if credit-risk contingent features are triggered		19,000,000
Interest Rate Swap
Derivative [Line Items]
Derivative liability, notional amount		$ 6,000,000
Interest Rate Swap | Subsequent Event
Derivative [Line Items]
Derivative liability, notional amount	$ 0

XML

LEASES (Term and Rate) (Details)	Dec. 31, 2019
Weighted-Average Remaining Lease Term (years)
Weighted-Average Remaining Lease Term (years), Finance Lease	1 year
Weighted-Average Remaining Lease Term (years), Operating Lease	12 years
Weighted-Average Discount Rate
Weighted-Average Discount Rate, Finance Lease	2.20%
Weighted-Average Discount Rate, Operating Lease	4.10%

XML

INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Gross Deferred Income Tax Assets
Finance Lease Obligations	$ 21,000,000
Finance Lease Obligations		$ 48,000,000
Operating Loss Carryforwards, Net	3,000,000	23,000,000
Customer Advances and Contributions in Aid of Construction	19,000,000	16,000,000
AMT Credit	7,000,000	13,000,000
Other Postretirement Benefits	15,000,000	15,000,000
Investment Tax Credit Carryforward	34,000,000	34,000,000
Income Taxes Recoverable Through Future Rates	81,000,000	87,000,000
Other	79,000,000	60,000,000
Total Gross Deferred Income Tax Assets	259,000,000	296,000,000
Deferred Tax Assets Valuation Allowance	0	0
Gross Deferred Income Tax Liabilities
Plant, Net	(602,000,000)	(552,000,000)
Plant Abandonments	(17,000,000)	(18,000,000)
Finance Lease Assets, Net	(18,000,000)	(44,000,000)
Pensions	(17,000,000)	(19,000,000)
Income Taxes Payable Through Future Rates	(9,000,000)	(12,000,000)
Other	(28,000,000)	(21,000,000)
Total Gross Deferred Income Tax Liabilities	(691,000,000)	(666,000,000)
Deferred Income Taxes, Net	$ (432,000,000)	$ (370,000,000)

XML

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Net Carrying Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 1,602	$ 1,615
Fair Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 1,755	$ 1,672

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average AFUDC Rates	7.86%	7.12%	7.31%

XML

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Income Tax) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 573	$ 607
Federal energy credits | Prior to 2013
Regulatory Liabilities [Line Items]
Regulatory liabilities	6	7
Federal energy credits | Since 2013
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 2	$ 6

XML

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Public utility PPE

The following table shows Plant in Service on the Consolidated Balance Sheets by major class:

	Annual Depreciation Rate (3)	Average Remaining Life in Years (3)	December 31,
($ in millions)			2019		2018
Plant in Service
Generation Plant	3.19%	20	$	3,065	$	2,667
Transmission Plant	1.69%	37	1,060		1,010
Distribution Plant	1.56%	31	1,784		1,692
General Plant	5.89%	20	477		409
Intangible Plant, Software Costs, and Other (1)	Various	Various	271		239
Plant Held for Future Use	—	—	7		3
Total Plant in Service (2)			$	6,664	$	6,020

⁽¹⁾  Primarily represents computer software. Unamortized computer software costs were $78 million and $73 million as of December 31, 2019 and 2018, respectively. Amortized computer software costs were $26 million in 2019, $24 million in 2018, and $19 million in 2017. 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 $(211) million and $(134) million as of December 31, 2019 and 2018, respectively.

⁽³⁾ 

Based on the 2015 depreciation study available for the major classes of Plant in Service, effective March 1, 2017, as approved by the ACC as part of the 2017 TEP Rate Order. TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 2019 FERC Rate Case.

Schedule of jointly owned utility plants

As of December 31, 2019, TEP was a participant in the following jointly-owned generation facilities and transmission systems:

(in millions)	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation			Net Book Value
San Juan Unit 1	50.0%	$	289	$	1	$	(193	)	$	97
Four Corners Units 4 and 5	7.0%	175		5		(77		)	103
Luna	33.3%	57		—		(1		)	56
Gila River Unit 3	75.0%	200		2		(61		)	141
Gila River Common Facilities	43.8%	71		—		(23		)	48
Springerville Coal Handling Facilities	83.0%	208		—		(90		)	118
Transmission Facilities	Various	545		5		(295		)	255
Total		$	1,545	$	13	$	(740	)	$	818

Schedule of asset retirement obligations

The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Beginning of Period	$	72		$	46
Liabilities Incurred	—			10
Liabilities Settled (1)	(2		)	—
Regulatory Deferral/Accretion Expense	2			3
Revisions to the Present Value of Estimated Cash Flows (2)	35			13
End of Period	$	107		$	72

⁽¹⁾  Primarily related to the retirement of Navajo.

⁽²⁾ 

Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of certain generation facilities.

XML

QUARTERLY FINANCIAL DATA (UNAUDITED)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL DATA (UNAUDITED)

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)	2019
Operating Revenue	$	333	$	326	$	441	$	318
Operating Income	43		67		134		39
Net Income	26		42		98		21
	2018
Operating Revenue	$	275	$	354	$	460	$	344
Operating Income	43		83		126		36
Net Income	24		58		95		11

XML

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 12, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-5924
Entity Registrant Name	TUCSON ELECTRIC POWER CO
Entity Incorporation, State or Country Code	AZ
Entity Tax Identification Number	86-0062700
Entity Address, Address Line One	88 East Broadway Boulevard
Entity Address, City or Town	Tucson
Entity Address, State or Province	AZ
Entity Address, Postal Zip Code	85701
City Area Code	520
Local Phone Number	571-4000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		32,139,434
Documents Incorporated by Reference	None
Entity Central Index Key	0000100122
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0

XML

LEASES (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Assets And Liabilities, Lessee

TEP’s leases are included in the balance sheet as follows:

(in millions)	Lease Type	December 31, 2019
Lease Assets
Utility Plant Under Finance Leases	Finance	$	151
Accumulated Amortization of Finance Lease Assets	Finance	(77		)
Regulatory and Other Assets, Other	Operating	8
Lease Liabilities
Current Liabilities, Finance Lease Obligations	Finance	17
Finance Lease Obligations	Finance	67
Current Liabilities, Other	Operating	1
Regulatory and Other Liabilities, Other	Operating	6

Lease, Cost

The following table presents TEP's cash flow information related to its leases:

	Year Ended
(in millions)	December 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	13
Operating Cash Flows used for Operating Leases	1
Financing Cash Flows used for Finance Leases	11
Investing Cash Flows used for Finance Leases	164

The following table presents the components of TEP’s lease cost:

	Year Ended
(in millions)	December 31, 2019
Finance
Amortization of Leased Assets (1)	$	13
Interest on Lease Liabilities (2)	13
Operating	1
Variable	16
Short Term	1
Total Lease Cost	$	44

⁽¹⁾  TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment.

⁽²⁾ 

Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019. TEP purchased Gila River Unit 2 in December 2019.

Lessee, Operating Lease, Liability, Maturity

As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:

(in millions)	Finance Leases		Operating Leases		Total
2020	$	18	$	1	$	19
2021	68		1		69
2022	—		1		1
2023	—		1		1
2024	—		1		1
Thereafter	—		4		4
Total Lease Payments	86		9		95
Less Imputed Interest	2		2		4
Total Lease Obligations	84		7		91
Less Current Portion	17		1		18
Total Non-Current Lease Obligations	$	67	$	6	$	73

Finance Lease, Liability, Maturity

As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:

(in millions)	Finance Leases		Operating Leases		Total
2020	$	18	$	1	$	19
2021	68		1		69
2022	—		1		1
2023	—		1		1
2024	—		1		1
Thereafter	—		4		4
Total Lease Payments	86		9		95
Less Imputed Interest	2		2		4
Total Lease Obligations	84		7		91
Less Current Portion	17		1		18
Total Non-Current Lease Obligations	$	67	$	6	$	73

Schedule of Lease Term and Discount Rate

The following table presents TEP's lease terms and discount rate related to its leases:

	December 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	2.2	%
Operating Leases	4.1	%

Schedule of Future Minimum Rental Payments for Operating Leases

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

Schedule of Future Minimum Lease Payments for Capital Leases

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

XML

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

CASH TRANSACTIONS

	Years Ended December 31,
(in millions)	2019			2018		2017
Interest Paid, Net of Amounts Capitalized	$	80		$	67	$	61
Income Tax Refunds (1)	(14		)	—		—

⁽¹⁾  TEP received a refund of AMT credit carryforwards in 2019. See Note 14 for additional information regarding AMT.

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
(in millions)	2019			2018			2017
Finance Leases	$	67		$	164		$	—
Accrued Capital Expenditures	40			31			24
Asset Retirement Obligations Increase (Decrease) (1)	26			20			10
Operating Leases (2)	8			—			—
Renewable Energy Credits	3			3			2
Net Cost of Removal Increase (Decrease) (3)	(10		)	(4		)	(88		)

⁽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 expected future AROs.

⁽²⁾  On January 1 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods.

⁽³⁾ 

Represents an accrual for future cost of retirement net of salvage values that does not impact earnings.

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Flows from Operating Activities
Net Income	$ 186,515	$ 188,323	$ 176,668
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	169,042	158,310	152,874
Amortization Expense	27,706	26,052	22,255
Amortization of Debt Issuance Costs	2,326	2,339	2,349
Use of Renewable Energy Credits for Compliance	37,141	32,350	25,453
Deferred Income Taxes	41,614	56,066	100,762
Pension and Other Postretirement Benefits Expense	17,762	15,303	16,039
Pension and Other Postretirement Benefits Funding	(16,749)	(26,673)	(14,430)
Allowance for Equity Funds Used During Construction	(15,222)	(8,117)	(5,322)
FERC Transmission Refund Payable	0	0	(4,878)
Regulatory Deferral, ACC Refund Order	7,705	(1,562)	0
Changes in Current Assets and Current Liabilities:
Accounts Receivable	9,238	(26,729)	(13,219)
Materials, Supplies, and Fuel Inventory	(16,236)	(2,357)	175
Regulatory Assets	(20,934)	(4,080)	(3,942)
Other Current Assets	(475)	(1,746)	(751)
Accounts Payable and Accrued Charges	(27,776)	33,536	9,790
Income Taxes Receivable	6,072	(13,004)	0
Regulatory Liabilities	(1,626)	14,028	(20,227)
Other, Net	8,140	15,187	4,728
Net Cash Flows—Operating Activities	414,243	457,226	448,324
Cash Flows from Investing Activities
Capital Expenditures	(607,593)	(392,522)	(345,617)
Purchase Intangibles, Renewable Energy Credits	(51,699)	(51,327)	(51,179)
Contributions in Aid of Construction	6,607	10,817	4,983
Note Receivable	(1,000)	0	0
Net Cash Flows—Investing Activities	(653,685)	(433,032)	(391,813)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	0	171,000	70,000
Repayments of Borrowings, Revolving Credit Facility	0	(206,000)	(35,000)
Proceeds from Borrowings, Term Loan	165,000	0	0
Proceeds from Issuance, Long-Term Debt—Net of Discount	0	298,869	0
Repayments of Long-Term Debt	(14,700)	(136,700)	0
Dividends Paid to Parent	(75,000)	(85,000)	(70,000)
Payments of Finance Lease Obligations	(10,890)
Payments of Finance Lease Obligations		(10,930)	(15,571)
Payment of Debt Issuance Costs	(757)	(3,265)	(245)
Contribution from Parent	50,000	50,000	0
Other, Net	1,514	1,078	481
Net Cash Flows—Financing Activities	115,167	79,052	(50,335)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(124,275)	103,246	6,176
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	152,747	49,501	43,325
Cash, Cash Equivalents, and Restricted Cash, End of Period	$ 28,472	$ 152,747	$ 49,501

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 429,000 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. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities 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.

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.

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 VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it 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 has entered 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 these 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, 2019, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent 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 FASB has been adopted as of January 1, 2019. 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.

Leases

TEP adopted accounting guidance 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. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, 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. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 8 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance 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 guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

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 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 with respect to 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 in the balance sheet and reconciles their sum to the cash flow statement:

	Years Ended December 31,
(in millions)	2019		2018		2017
Cash and Cash Equivalents	$	10	$	138	$	38
Restricted Cash included in:
Investments and Other Property	16		14		11
Current Assets—Other	2		1		1
Total Cash, Cash Equivalents, and Restricted Cash	$	28	$	153	$	50

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 and various contractual agreements. 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)	2019			2018			2017
Beginning of Period	$	5		$	5		$	5
Additions Charged to Cost and Expense	4			3			3
Write-offs	(3		)	(3		)	(3		)
End of Period	$	6		$	5		$	5

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 determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. 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:

	2019		2018		2017
Average AFUDC Rates	7.86	%	7.12	%	7.31	%

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:

	2019		2018		2017
Average Annual Depreciation Rates	3.08	%	3.13	%	2.97	%

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. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense in the income statement.

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.

LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet.

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 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.

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 summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Beginning of Period	$	55		$	42
Purchased	45			45
Used for Compliance	(37		)	(32		)
End of Period	$	63		$	55

TEP expenses the cost of internally developed RECs, including PBI activity that is not included in the table above and recoverable through the RES surcharge.

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 in 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 2013 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. TEP had an aggregate liability balance of $6 million and $7 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million and $6 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. 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. 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.

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 10 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 13 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 in 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 in 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 13 for additional information regarding derivative instruments.

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DEBT AND CREDIT AGREEMENTS

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

DEBT AND CREDIT AGREEMENTS

DEBT AND CREDIT AGREEMENTS

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:

			December 31,
($ in millions)	Interest Rate	Maturity Date	2019		2018
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		300
Tax-Exempt Local Furnishings Bonds (1)
2010 Pima A	5.25%	2040	100		100
2012 Pima A	4.50%	2030	16		16
2013 Pima A	4.00%	2029	91		91
Tax-Exempt Pollution Control Bonds (2)
2009 Pima A	4.95%	2020	80		80
2009 Coconino A	5.13%	2032	—		15
2012 Apache A	4.50%	2030	177		177
Total Long-Term Debt (3)			1,614		1,629
Less Unamortized Discount and Debt Issuance Costs			12		14
Less Current Maturities of Long-Term Debt			80		—
Total Long-Term Debt, Net			$	1,522	$	1,615

⁽¹⁾  The 2010 Pima A bonds can be redeemed at par on or after October 2020. TEP has the option to redeem the remaining bonds at par on dates ranging from first quarter of 2022 to first quarter of 2023.

⁽²⁾  The 2009 Pima A bonds mature in October 2020. The 2012 Apache A bonds may be redeemed at par in the first quarter of 2022.

⁽³⁾  As of December 31, 2019, all of TEP's debt is unsecured.

Issuances and Redemptions

Fixed Rate Debt

In November 2019, TEP redeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of $15 million prior to the maturity of the bonds.

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 expired 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.

Maturities

Long-term debt matures on the following dates:

(in millions)	Long-Term Debt (1)
2020	$	80
2021	250
2022	—
2023	150
2024	—
Thereafter	1,134
Total	$	1,614

⁽¹⁾  Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount.

CREDIT AGREEMENTS

Amounts borrowed under credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets.

2019 Credit Agreement

In December 2019, TEP entered into an unsecured credit agreement with a maturity date of December 2020 that provides for term loans. Terms are as follows:

							Weighted Average Interest Rate
	Capacity		Borrowed (1)		Available				Pricing
(in millions)	December 31, 2019
Term Loan	$	225	$	165	$	60	4.75	%	LIBOR + 0.550%	or ABR + 0.00%

⁽¹⁾  All amounts borrowed will be due and payable by December 2020.

The 2019 Credit Agreement is intended to supplement TEP's liquidity during a period of increased capital spending and to provide funds: (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. Amounts paid or repaid may not be reborrowed. As of February 12, 2020, no amount was available as the term loan had been fully drawn. See Note 3 and Note 9 for additional information on the purchase of Gila River Unit 2 and Oso Grande, respectively.

2015 Credit Agreement

In October 2015, TEP entered into an unsecured credit agreement with a maturity date of October 2022 that provides for revolving credit commitments and LOC facilities. Terms are as follows:

	Capacity		Sub-Limit LOC		Borrowed		Available		Weighted Average Interest Rate		Pricing (1)
(in millions)	December 31, 2019
Revolver and LOC	$	250	$	50	$	—	$	250	—	%	LIBOR + 1.000%	or ABR + 0.00%

(in millions)	December 31, 2018
Revolver and LOC	$	250	$	50	$	—	$	250	—	%	LIBOR + 1.000%	or ABR + 0.00%

⁽¹⁾  Interest rates and fees are based on a pricing grid tied to TEP's credit rating.

Amounts borrowed under the 2015 Credit Agreement will be used for working capital and other general corporate purposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities.

In January 2020, TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 12, 2020, there was $173 million available under the revolving credit commitments and LOC facilities.

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UTILITY PLANT AND JOINTLY-OWNED FACILITIES

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

UTILITY PLANT AND JOINTLY-OWNED FACILITIES

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 (3)	Average Remaining Life in Years (3)	December 31,
($ in millions)			2019		2018
Plant in Service
Generation Plant	3.19%	20	$	3,065	$	2,667
Transmission Plant	1.69%	37	1,060		1,010
Distribution Plant	1.56%	31	1,784		1,692
General Plant	5.89%	20	477		409
Intangible Plant, Software Costs, and Other (1)	Various	Various	271		239
Plant Held for Future Use	—	—	7		3
Total Plant in Service (2)			$	6,664	$	6,020

⁽¹⁾  Primarily represents computer software. Unamortized computer software costs were $78 million and $73 million as of December 31, 2019 and 2018, respectively. Amortized computer software costs were $26 million in 2019, $24 million in 2018, and $19 million in 2017. 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 $(211) million and $(134) million as of December 31, 2019 and 2018, respectively.

⁽³⁾  Based on the 2015 depreciation study available for the major classes of Plant in Service, effective March 1, 2017, as approved by the ACC as part of the 2017 TEP Rate Order. TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 2019 FERC Rate Case.

Gila River Unit 2

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 included a three-year option to purchase the unit. The Tolling PPA was accounted for as a finance lease. See Note 8 for additional information regarding TEP's leases. In December 2019, TEP completed its purchase of Gila River Unit 2 for $165 million. The purchase increased Plant in Service and Material and Supplies and decreased Utility Plant Under Finance Leases on the Consolidated Balance Sheets as of December 31, 2019.

RICE Units

Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed in service five natural gas RICE units in December 2019. As a result, Plant in Service on the Consolidated Balance Sheets increased by $82 million. An additional five units are scheduled to be placed in service in the first quarter of 2020. The 10 units have a planned total nominal generation capacity of 188 MW.

JOINTLY-OWNED FACILITIES

As of December 31, 2019, TEP was a participant in the following jointly-owned generation facilities and transmission systems:

(in millions)	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation			Net Book Value
San Juan Unit 1	50.0%	$	289	$	1	$	(193	)	$	97
Four Corners Units 4 and 5	7.0%	175		5		(77		)	103
Luna	33.3%	57		—		(1		)	56
Gila River Unit 3	75.0%	200		2		(61		)	141
Gila River Common Facilities	43.8%	71		—		(23		)	48
Springerville Coal Handling Facilities	83.0%	208		—		(90		)	118
Transmission Facilities	Various	545		5		(295		)	255
Total		$	1,545	$	13	$	(740	)	$	818

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.

ASSET RETIREMENT OBLIGATIONS

The liability accrual of AROs is primarily related to generation and PV assets and is included in 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)	2019			2018
Beginning of Period	$	72		$	46
Liabilities Incurred	—			10
Liabilities Settled (1)	(2		)	—
Regulatory Deferral/Accretion Expense	2			3
Revisions to the Present Value of Estimated Cash Flows (2)	35			13
End of Period	$	107		$	72

⁽¹⁾  Primarily related to the retirement of Navajo.

⁽²⁾ 

Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of certain generation facilities.

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SHARE-BASED COMPENSATION

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION

2015 SHARE UNIT PLAN

The Human Resources and Governance 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 PSUs and RSUs annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur.

The following table represents PSUs and RSUs awarded by UNS Energy:

	2019	2018	2017
PSUs	66,978	54,426	68,126
RSUs	33,489	27,213	34,063

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 $12 million and $9 million as of December 31, 2019 and 2018, respectively.

TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2019, $2 million in 2018, and $4 million in 2017 based on its share of UNS Energy's compensation expense.

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EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Net (Gain) Loss	$ 145	$ 133
Prior Service Cost (Benefit)	0	0
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Net (Gain) Loss	1	(1)
Prior Service Cost (Benefit)	$ (2)	$ (2)

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EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Details)	Dec. 31, 2019
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	100.00%
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	100.00%
Cash/Treasury Bills | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Cash/Treasury Bills | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	2.00%
United States Large Cap | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	12.00%
United States Large Cap | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	39.00%
United States Small Cap | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	5.00%
United States Small Cap | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	5.00%
Non-United States Developed | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Non-United States Developed | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	7.00%
Non-United States Emerging | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Non-United States Emerging | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	9.00%
Global Equity | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	26.00%
Global Equity | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Global Infrastructure | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	3.00%
Global Infrastructure | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Fixed Income Securities | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	45.00%
Fixed Income Securities | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	38.00%
Real Estate | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	8.00%
Real Estate | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Private Equity | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	1.00%
Private Equity | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%

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LEASES (Cash Flows) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$ 13,000
Operating Cash Flows used for Operating Leases	1,000
Financing Cash Flows used for Finance Leases	10,890
Investing Cash Flows used for Finance Leases	$ 164,000

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EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 13	$ 15	$ 13
Non-Service Cost
Interest Cost	18	16	15
Expected Return on Plan Assets	(26)	(28)	(25)
Amortization of Net (Gain) Loss	8	7	8
Net Periodic Benefit Cost	13	10	11
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	5	4
Non-Service Cost
Interest Cost	3	2	2
Expected Return on Plan Assets	(2)	(1)	(1)
Amortization of Net (Gain) Loss	0	0	0
Net Periodic Benefit Cost	$ 5	$ 6	$ 5

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EMPLOYEE BENEFIT PLANS(Assumed Health Care Cost Trend Rates) (Details)	Dec. 31, 2019	Dec. 31, 2018
Retirement Benefits [Abstract]
Next Year (Pre-65) (in percentage)	6.30%	6.50%
Next Year (Post-65) (in percentage)	7.50%	7.80%
Ultimate Rate Assumed (Pre-65 and Post-65) (in percentage)	4.50%	4.50%

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COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee	Dec. 31, 2019 USD ($)
Guarantor Obligations [Line Items]
Current carrying value	$ 0
Navajo, San Juan, Luna
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	0
Four Corner
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	$ 250,000,000

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UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of Period	$ 72	$ 46
Liabilities Incurred	0	10
Liabilities Settled	(2)	0
Regulatory Deferral/Accretion Expense	2	3
Revisions to the Present Value of Estimated Cash Flows	35	13
End of Period	$ 107	$ 72

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REGULATORY MATTERS (Early Generation Retirement Costs) (Details)	12 Months Ended
	Dec. 31, 2019
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Navajo
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	10 years
Sundt Units 1 and 2
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	10 years

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Capital Stock Expense	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2016	$ 1,559,035	$ 1,296,539	$ (6,357)	$ 273,408	$ (4,555)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	176,668			176,668
Other Comprehensive (Loss) Income, Net of Tax	(1,671)				(1,671)
Dividends Declared to Parent	(70,000)			(70,000)
Ending Balances at Dec. 31, 2017	1,664,032	1,296,539	(6,357)	380,076	(6,226)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	188,323			188,323
Other Comprehensive (Loss) 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	0			878	(878)
Ending Balances at Dec. 31, 2018	1,819,745	1,346,539	(6,357)	484,277	(4,714)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	186,515			186,515
Other Comprehensive (Loss) Income, Net of Tax	(3,057)				(3,057)
Dividends Declared to Parent	(75,000)			(75,000)
Contribution from Parent	50,000	50,000
Ending Balances at Dec. 31, 2019	$ 1,978,203	$ 1,396,539	$ (6,357)	$ 595,792	$ (7,771)

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments

As of December 31, 2019, TEP had the following unconditional minimum purchase obligations:

(in millions)	2020		2021		2022		2023		2024		Thereafter		Total
Fuel, Including Transportation	$	94	$	61	$	40	$	33	$	33	$	194	$	455
Purchased Power	8		—		—		—		—		—		8
Transmission	21		16		14		3		3		6		63
Renewable Power Purchase Agreements	63		63		63		63		62		543		857
RES Performance-Based Incentives	8		7		7		7		7		33		69
Land Easements and Rights-of-Way (1)	1		2		1		1		3		79		87
Total Purchase Commitments	$	195	$	149	$	125	$	107	$	108	$	855	$	1,539

⁽¹⁾  Land easements and rights-of-way have varying terms and provisions and reflect expiration dates through 2054.

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

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 through net income 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, 2019
Assets
Restricted Cash (1)	$	18	$	—		$	—	$	18
Energy Derivative Contracts, Regulatory Recovery (2)	—		3			—		3
Energy Derivative Contracts, No Regulatory Recovery (2)	—		3			—		3
Total Assets	18		6			—		24
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(76		)	—		(76		)
Total Liabilities	—		(76		)	—		(76		)
Total Assets (Liabilities), Net	$	18	$	(70	)	$	—	$	(52	)

(in millions)	December 31, 2018
Assets
Cash Equivalents (1)	$	55	$	—		$	—		$	55
Restricted Cash (1)	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery (2)	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			2			2
Total Assets	70		10			2			82
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	70	$	(25	)	$	—		$	45

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit, 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 2 as of December 31, 2019 and Level 3 as of December 31, 2018) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to decreases in forward market prices of natural gas and increases in volume.

Potential offset of assets by counterparty netting and cash collateral

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, 2019
Derivative Assets
Energy Derivative Contracts	$	6		$	4		$	—		$	2
Derivative Liabilities
Energy Derivative Contracts	(76		)	(4		)	(2		)	(70		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

Potential offset of liabilities by counterparty netting and cash collateral

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, 2019
Derivative Assets
Energy Derivative Contracts	$	6		$	4		$	—		$	2
Derivative Liabilities
Energy Derivative Contracts	(76		)	(4		)	(2		)	(70		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

Financial impact of energy contracts

The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
Operating Revenues	$	6	$	5	$	5

The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability in the balance sheet:

	Years Ended December 31,
(in millions)	2019			2018			2017
Unrealized Net Loss (1)	$	(45	)	$	(9	)	$	(18	)

⁽¹⁾  In 2019, unrealized net loss on regulatory recoverable derivative contracts increased primarily due to decreases in forward market prices of natural gas and increases in volume.

Derivative volumes

The following table presents volumes associated with the energy contracts:

	December 31,
	2019	2018
Power Contracts GWh	4,740	1,743
Gas Contracts BBtu	122,779	146,933

Following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements

The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:

	Valuation Approach	Fair Value of					Unobservable Inputs	Range of Unobservable Inputs
		Assets		Liabilities
(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

Schedule of reconciliation of changes in the fair value of net assets and liabilities

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)	2019			2018
Beginning of Period	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(12		)	(4		)
Operating Revenues	5			5
Settlements	1			(2		)
Transfers Out of Level 3 (1)	5			—
End of Period	$	—		$	1
Gains (Losses), Assets (Liabilities) Still Held	$	—		$	1

⁽¹⁾  Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities.

Schedule of different estimation methods and/or market assumptions may yield different estimated fair value amounts

The following table includes the net carrying value and estimated fair value of TEP's long-term debt:

		Net Carrying Value				Fair Value
	Fair Value Hierarchy	December 31,
(in millions)		2019		2018		2019		2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,602	$	1,615	$	1,755	$	1,672

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net changes in fair value of cash flow hedges, tax	$ (44)	$ (121)	$ (305)
Supplemental executive retirement plan adjustments, tax	$ 1,059	$ (747)	$ 637

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

EMPLOYEE BENEFIT PLANS

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 $1 million in 2019 and $3 million in 2018 and 2017 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.

The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet:

	Pension Benefits						Other Postretirement Benefits
	December 31,
(in millions)	2019			2018			2019			2018
Regulatory Assets	$	135		$	126		$	—		$	—
Regulatory Liabilities	—			—			(1		)	(3		)
Accrued Employee Expenses	(2		)	(1		)	(2		)	(3		)
Pension and Other Postretirement Benefits	(77		)	(63		)	(56		)	(54		)
Accumulated Other Comprehensive Loss, SERP	10			6			—			—
Net Amount Recognized	$	66		$	68		$	(59	)	$	(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, 2019 and 2018. 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)	2019			2018			2019			2018
Change in Benefit Obligation
Beginning of Period	$	440		$	475		$	74		$	82
Actuarial (Gain) Loss	76			(42		)	4			(8		)
Interest Cost	18			16			3			2
Service Cost	13			15			4			5
Benefits Paid	(23		)	(23		)	(6		)	(5		)
Plan Amendments	1			(1		)	—			(2		)
End of Period	525			440			79			74
Change in Fair Value of Plan Assets
Beginning of Period	376			403			17			17
Actual Return on Plan Assets	81			(25		)	4			(1		)
Benefits Paid	(22		)	(23		)	(6		)	(5		)
Employer Contributions (1)	11			21			6			6
End of Period	446			376			21			17
Funded Status at End of Period	$	(79	)	$	(64	)	$	(58	)	$	(57	)

⁽¹⁾  TEP expects to contribute $11 million to the pension plans and $1 million to the VEBA trust in 2020.

The $85 million increase in the pension benefit obligation was driven by a significant decrease in discount rates as a result of a decrease in interest rates. The $70 million increase in the pension plan assets was due to positive equity returns and fixed income returns as a result of a decline in interest rates.

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)	2019		2018		2019			2018
Net (Gain) Loss	$	145	$	133	$	1		$	(1	)
Prior Service Cost (Benefit)	—		—		(2		)	(2		)

The accumulated benefit obligation aggregated for all pension plans was $476 million and $402 million as of December 31, 2019 and 2018, respectively. All of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2019 and 2018. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:

	December 31,
(in millions)	2019		2018
Accumulated Benefit Obligation	$	476	$	230
Fair Value of Plan Assets	446		202

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)	2019			2018			2017			2019			2018			2017
Service Cost	$	13		$	15		$	13		$	4		$	5		$	4
Non-Service Cost
Interest Cost	18			16			15			3			2			2
Expected Return on Plan Assets	(26		)	(28		)	(25		)	(2		)	(1		)	(1		)
Amortization of Net (Gain) Loss	8			7			8			—			—			—
Net Periodic Benefit Cost	$	13		$	10		$	11		$	5		$	6		$	5

The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. In 2019 and 2018, TEP capitalized 21% and 19% of service cost, respectively, 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)	2019			2018			2017			2019			2018			2017		2019		2018			2017
Current Year Actuarial (Gain) Loss	$	16		$	12		$	5		$	4		$	(1	)	$	3	$	1	$	(6	)	$	(1	)
Amortization of Net Loss	(8		)	(7		)	(7		)	(1		)	—			—		—		—			—
Prior Service Credit (Cost)	—			—			—			1			(1		)	—		—		(2		)	—
Total Recognized (Gain) Loss	$	8		$	5		$	(2	)	$	4		$	(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.

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

The following table includes the weighted average assumptions used to determine benefit obligations:

	Pension Benefits		Other Postretirement Benefits
	2019	2018	2019	2018
Discount Rate	3.6%	4.5%	3.3%	4.3%
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
	2019	2018	2017	2019	2018	2017
Discount Rate, Service Cost	4.7%	3.8%	4.4%	4.5%	3.8%	4.3%
Discount Rate, Interest Cost	4.2%	3.4%	3.7%	4.0%	3.2%	3.3%
Rate of Compensation Increase	2.8%	2.8%	2.8%	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,
	2019	2018
Next Year (Pre-65)	6.3%	6.5%
Next Year (Post-65)	7.5%	7.8%
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	2037

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
	2019		2018		2019		2018
Asset Category
Equity Securities	46	%	45	%	65	%	60	%
Fixed Income Securities	45	%	45	%	33	%	38	%
Real Estate	8	%	8	%	—	%	—	%
Other	1	%	2	%	2	%	2	%
Total	100	%	100	%	100	%	100	%

As of December 31, 2019, the fair value of VEBA trust assets was $21 million, of which $7 million were fixed income investments and $14 million were equities. 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. 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.

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, 2019
Asset Category
Cash Equivalents	$	2	$	—	$	—	$	2
Equity Securities:
United States Large Cap	—		55		—		55
United States Small Cap	—		21		—		21
Non-United States	—		80		—		80
Global	—		51		—		51
Fixed Income	—		199		—		199
Real Estate	—		10		23		33
Private Equity	—		—		5		5
Total	$	2	$	416	$	28	$	446

	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

• 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.

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, 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
Actual Return on Plan Assets:
Assets Held at Reporting Date	1			1		2
Purchases, Sales, and Settlements	(2		)	—		(2		)
Balance as of December 31, 2019	$	5		$	23	$	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.

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, 2019
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)	2020		2021		2022		2023		2024		2025-2029
Pension Benefits	$	26	$	26	$	26	$	27	$	28	$	147
Other Postretirement Benefits	5		5		5		5		5		25

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 $6 million in 2019, $7 million in 2018, and $6 million in 2017.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and the 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)	2019		2018
Receivables from Related Parties
UNS Electric	$	6	$	7
UNS Gas	2		1
Total Due from Related Parties	$	8	$	8
Payables to Related Parties
SES	$	2	$	2
UNS Electric	1		1
UNS Gas	—		1
UNS Energy	1		1
Total Due to Related Parties	$	4	$	5

The following table presents the components of related party transactions included in the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	7	$	6	$	7
Wholesale Revenues, UNS Electric (1)	1		1		—
Control Area Services, UNS Electric (2)	4		3		3
Common Costs, UNS Energy Affiliates (3)	19		18		16
Corporate Services, Fortis Affiliates (4)	—		—		2
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (5)	15		15		15
Corporate Services, UNS Energy (6)	6		6		5
Corporate Services, UNS Energy Affiliates (7)	4		7		5
Capacity Charges, UNS Gas (8)	1		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 OATT.

⁽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 83% of UNS Energy's allocated costs.

Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $6 million in 2019, $5 million in 2018, and $6 million in 2017.

⁽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.

CONTRIBUTIONS FROM PARENT

In January 2020, an equity contribution of $125 million was received by TEP from UNS Energy.

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REGULATORY MATTERS

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

2019 ACC RATE CASE

In April 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018.

TEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019 include:

• a non-fuel retail revenue increase of $99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $60 million over test year retail revenues;

• a 7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.00% and an average cost of debt of 4.65%;

• a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of RICE units at Sundt;

• a TEAM that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and

• a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.

Hearings before an ALJ were held in January and February 2020. The hearing will resume in April 2020. TEP requested new rates to be implemented by May 1, 2020.

TEP cannot predict the timing or outcome of the proceeding.

2019 FERC RATE CASE

In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund.

Provisions of the order include, but are not limited to:

• replacing TEP's stated transmission rates with a forward-looking formula rate;

• a 10.4% return on equity; and

• elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.

The requested forward-looking formula rate is intended to allow for more timely recovery of transmission related costs. As part of the order, the FERC established hearing and settlement procedures, and all revisions to the OATT in the FERC order are subject to refund. As of December 31, 2019, TEP had reserved $4 million of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as a result of the FERC proceedings. TEP cannot predict the outcome of the proceeding.

Abandoned Plant Costs

Also in May 2019, TEP filed with the FERC a request to recover through its OATT abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. On September 19, 2019, the FERC issued an order allowing TEP to recover 50% of its costs in its formula rate and established hearing and settlement procedures. TEP plans to incorporate the abandoned plant costs into its formula rate effective January 1, 2020, subject to refund. On September 26, 2019, the FERC issued an order consolidating the 2019 FERC Rate Case and Abandoned Plant Costs proceedings. In 2012, TEP wrote-off a portion of the deferred costs related to the Nogales transmission line. As of December 31, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets.

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 issued the ACC Refund Order. The ACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. TEP filed an information filing with the ACC to establish a 2020 customer refund of $35 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our next rate case.

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:

	Years Ended December 31,
(in millions)	2019			2018
Beginning of Period	$	4		$	—
ACC Approved Refund (Reduction in Operating Revenues)	(34		)	(33		)
Amount Returned to Customers Through Bill Credits	22			37
Regulatory Deferral	8			—
End of Period	$	—		$	4

See Note 14 for additional information regarding the TCJA.

Federal Energy Regulatory Commission

In 2018, the FERC issued the 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 NOPR regarding the effect of the TCJA and related EDIT amortization on rates. In November 2019, the FERC issued a final rule on the NOPR which required TEP to address the effect of the TCJA and related EDIT amortization in its next FERC rate case. As required by the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization.

See Note 14 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 and goes into effect for the subsequent 12-month period unless the schedule is 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)	2019			2018
Beginning of Period	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs	31			2
PPFAC Refunds (Recoveries) (1)	22			(10		)
End of Period	$	36		$	(17	)

⁽¹⁾  In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Environmental Compliance Adjustor

The 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 $2 million in 2019, $3 million in 2018, and $1 million in 2017 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 September 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million. The recovery funds the following: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. The Company recognized less than $1 million in 2019, and $1 million in 2018 and 2017 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 and requests recovery of these types of costs through its rate case process.

In 2019, the percentage of TEP's retail kWh sales attributable to the RES was approximately 16%, exceeding the overall 2019 RES requirement of 9%. The ACC approved the waiver of the 2019 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, 2019, TEP's cumulative annual energy savings was approximately 19%.

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 2019, 2018, and 2017 related to performance in Operating Revenues on the Consolidated Statements of Income.

In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is 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 LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.

The table below summarizes the LFCR revenues recognized in Operating Revenues on the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
LFCR Revenues	$	33	$	26	$	22

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)		2019		2018
Regulatory Assets
Pension and Other Postretirement Benefits (Note 10)	Various	$	135	$	126
Derivatives (Note 13)	10	72		27
Early Generation Retirement Costs	Various	68		72
Lost Fixed Cost Recovery	2	46		35
Income Taxes Recoverable through Future Rates (1)	Various	38		47
Under Recovered Purchased Energy Costs	1	36		—
Property Tax Deferrals (2)	1	24		23
Final Mine Reclamation and Retiree Healthcare Costs (3)	19	19		29
Springerville Unit 1 Leasehold Improvements (4)	4	9		11
Other Regulatory Assets	Various	18		30
Total Regulatory Assets		465		400
Less Current Portion	1	138		107
Total Non-Current Regulatory Assets		$	327	$	293

Regulatory Liabilities
Income Taxes Payable through Future Rates (1)	Various	$	327	$	354
Net Cost of Removal (5)	Various	164		171
Renewable Energy Standard	Various	59		52
Deferred Investment Tax Credits (6)	Various	3		7
Over Recovered Purchased Energy Costs	Various	—		17
Other Regulatory Liabilities	Various	20		6
Total Regulatory Liabilities		573		607
Less Current Portion	1	96		95
Total Non-Current Regulatory Liabilities		$	477	$	512

⁽¹⁾  Amortized over the life of the assets. See Note 14 for additional information regarding income taxes.

⁽²⁾  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.

⁽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⁾  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 period.

⁽⁵⁾  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.

⁽⁶⁾  Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

Early Generation Retirement Costs

Navajo Generating Station

In 2017, the Navajo Nation approved a land lease extension allowing TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the co-owners of Navajo retired the generation station in November 2019, with related decommissioning activities continuing through 2054. TEP is currently recovering the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case.

Sundt Generating Station

In 2018, the Pima County Department of Environmental Quality approved TEP's air permit application. Under the project outlined in the application, TEP is placing in service 10 RICE units and was required to retire Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 for Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 Rate Case. See Note 3 for additional information on the RICE units.

Regulatory Assets and Liabilities

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, TEP does not pay a return on regulatory liabilities.

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.

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LEASES (Future Minimum Lease Payments) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Capital Leases
2019	$ 187,000
2020	20,000
2021	0
2022	0
2023	0
Thereafter	0
Total Lease Payments	207,000
Less: Imputed Interest	14,000
Total Lease Obligations	193,000
Less: Current Portion	172,510
Total Non-Current Lease Obligations	19,773
Operating Leases
2019	1,000
2020	1,000
2021	1,000
2022	1,000
2023	1,000
Thereafter	5,000
Total Lease Payments	$ 10,000

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EMPLOYEE BENEFIT PLANS (Changes in Regulatory Assets and Accumulated Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits | Regulatory Asset
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	$ 16	$ 12	$ 5
Amortization of Net Loss	(8)	(7)	(7)
Prior Service Credit (Cost)	0	0	0
Total Recognized (Gain) Loss	8	5	(2)
Pension Benefits | AOCI
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	4	(1)	3
Amortization of Net Loss	(1)	0	0
Prior Service Credit (Cost)	1	(1)	0
Total Recognized (Gain) Loss	4	(2)	3
Other Postretirement Benefits | Regulatory Asset
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	1	(6)	(1)
Amortization of Net Loss	0	0	0
Prior Service Credit (Cost)	0	(2)	0
Total Recognized (Gain) Loss	$ 1	$ (8)	$ (1)

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EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Details)	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	100.00%	100.00%
Pension Benefits | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	46.00%	45.00%
Pension Benefits | Fixed Income Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	45.00%	45.00%
Pension Benefits | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	8.00%	8.00%
Pension Benefits | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	1.00%	2.00%
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	100.00%	100.00%
Other Postretirement Benefits | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	65.00%	60.00%
Other Postretirement Benefits | Fixed Income Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	33.00%	38.00%
Other Postretirement Benefits | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	0.00%	0.00%
Other Postretirement Benefits | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	2.00%	2.00%

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EMPLOYEE BENEFIT PLANS (Additional Information) (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) plan	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Number of defined benefit pension plans | plan	3
Number of qualified defined benefit pension plans | plan	2
Increase in pension benefit obligation	$ 85,000,000
Increase in pension plan assets	$ 70,000,000
Percentage of service cost that was capitalized (in percentage)	21.00%	19.00%
Investment return model best-estimate range (in years)	20 years
Matching 401(k) contributions made	$ 6,000,000	$ 7,000,000	$ 6,000,000
Level 3
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	28,000,000	28,000,000	27,000,000
Other Postretirement Benefits
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employer Contribution to VEBA Trust	1,000,000	3,000,000	3,000,000
Fair value measurements of plan assets	21,000,000	17,000,000	17,000,000
Other Postretirement Benefits | Level 1 and Level 2
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	21,000,000	17,000,000
Other Postretirement Benefits | Level 3
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	0
Pension Benefits
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Accumulated benefit obligation	476,000,000	402,000,000
Fair value measurements of plan assets	446,000,000	376,000,000	$ 403,000,000
Pension Benefits | Level 3
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	28,000,000	28,000,000
Transfers	$ 0
Minimum
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used (in percentage)	25.00%
Maximum
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used (in percentage)	75.00%
Fixed Income Securities | Other Postretirement Benefits | Level 1 and Level 2
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 7,000,000	7,000,000
Equities | Other Postretirement Benefits | Level 1 and Level 2
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 14,000,000	$ 10,000,000

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EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Details) - Pension Benefits - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]
Accumulated Benefit Obligation	$ 476	$ 230
Fair Value of Plan Assets	$ 446	$ 202

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EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Details) $ in Millions	Dec. 31, 2019 USD ($)
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2020	$ 26
2021	26
2022	26
2023	27
2024	28
Years 2025-2029	147
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2020	5
2021	5
2022	5
2023	5
2024	5
Years 2025-2029	$ 25

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UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Jointly-Owned Facilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Aug. 30, 2019
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$ 1,545
Construction Work in Progress	13
Accumulated Depreciation	(740)
Net Book Value	$ 818
San Juan Unit 1
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	50.00%	50.00%
Plant in Service	$ 289
Construction Work in Progress	1
Accumulated Depreciation	(193)
Net Book Value	$ 97
Four Corners Units 4 and 5
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	7.00%
Plant in Service	$ 175
Construction Work in Progress	5
Accumulated Depreciation	(77)
Net Book Value	$ 103
Luna
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	33.30%
Plant in Service	$ 57
Construction Work in Progress	0
Accumulated Depreciation	(1)
Net Book Value	$ 56
Gila River Unit 3
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	75.00%
Plant in Service	$ 200
Construction Work in Progress	2
Accumulated Depreciation	(61)
Net Book Value	$ 141
Gila River Common Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	43.80%
Plant in Service	$ 71
Construction Work in Progress	0
Accumulated Depreciation	(23)
Net Book Value	$ 48
Springerville Coal Handling Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	83.00%
Plant in Service	$ 208
Construction Work in Progress	0
Accumulated Depreciation	(90)
Net Book Value	118
Transmission Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	545
Construction Work in Progress	5
Accumulated Depreciation	(295)
Net Book Value	$ 255

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REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 573,000	$ 607,000
Less Current Portion	96,017	95,094
Total Non-Current Regulatory Liabilities	477,495	512,425
Income Taxes Payable through Future Rates
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	327,000	354,000
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	164,000	171,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	59,000	52,000
Deferred Investment Tax Credits
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	3,000	7,000
Over Recovered Purchased Energy Costs
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	0	17,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 20,000	$ 6,000

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Roll-forward
Beginning of Period	$ 1	$ 2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(12)	(4)
Operating Revenues	5	5
Settlements	1	(2)
Transfers Out of Level 3	5	0
End of Period	0	1
Gains (Losses), Assets (Liabilities) Still Held	$ 0	$ 1

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LEASES (Lease Liability) (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Finance Leases
2020	$ 18,000
2021	68,000
2022	0
2023	0
2024	0
Thereafter	0
Total Lease Payments	86,000
Less Imputed Interest	2,000
Total Lease Obligations	84,000
Less Current Portion	17,086
Total Non-Current Lease Obligations	67,316
Operating Leases
2020	1,000
2021	1,000
2022	1,000
2023	1,000
2024	1,000
Thereafter	4,000
Total Lease Payments	9,000
Less Imputed Interest	2,000
Total Lease Obligations	7,000
Less Current Portion	1,000
Total Non-Current Lease Obligations	6,000
Total
2020	19,000
2021	69,000
2022	1,000
2023	1,000
2024	1,000
Thereafter	4,000
Total Lease Payments	95,000
Less Imputed Interest	4,000
Total Lease Obligations	91,000
Less Current Portion	18,000
Total Non-Current Lease Obligations	$ 73,000

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INCOME TAXES (Summary of Tax Carryforwards) (Details) $ in Millions	Dec. 31, 2019 USD ($)
Internal Revenue Service (IRS)
Income Tax Contingency [Line Items]
Federal Net Operating Loss	$ 17
Tax Credits	7
Investment Tax Credits	34
State Tax Jurisdiction
Income Tax Contingency [Line Items]
Tax Credits	$ 9

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INCOME TAXES (Reconciliation of Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal Income Tax Expense at Statutory Rate	$ 46,000	$ 49,000	$ 97,000
State Income Tax Expense, Net of Federal Deduction	9,000	9,000	9,000
Federal/State Tax Credits	(6,000)	(10,000)	(9,000)
Allowance for Equity Funds Used During Construction	(3,000)	(1,000)	(2,000)
Impact of Enactment, TCJA	0	0	7,000
Excess Deferred Income Taxes	(9,000)	(6,000)	0
Impact of AMT Sequestration	(2,000)	2,000	0
Other	(1,000)	0	(1,000)
Total Federal and State Income Tax Expense	$ 34,053	$ 42,982	$ 100,763

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DEBT AND CREDIT AGREEMENTS (Credit Agreement) (Details) - Line of Credit - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Feb. 12, 2020	Jan. 31, 2020
Term Loan
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 225,000,000
Borrowed	165,000,000
Available	$ 60,000,000
Weighted Average Interest Rate (in percentage)	4.75%
Term Loan | Subsequent Event
Debt Instrument [Line Items]
Available			$ 0
Term Loan | LIBOR
Debt Instrument [Line Items]
Basis of variable spread (in percentage)	0.55%
Term Loan | Base Rate
Debt Instrument [Line Items]
Basis of variable spread (in percentage)	0.00%
Revolver
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 250,000,000	$ 250,000,000
Borrowed	0	0
Available	$ 250,000,000	$ 250,000,000
Weighted Average Interest Rate (in percentage)	0.00%	0.00%
Revolver | Subsequent Event
Debt Instrument [Line Items]
Available			$ 173,000,000
Revolver | LIBOR
Debt Instrument [Line Items]
Basis of variable spread (in percentage)	1.00%	1.00%
Revolver | Base Rate
Debt Instrument [Line Items]
Basis of variable spread (in percentage)	0.00%	0.00%
Sub-Limit LOC
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 50,000,000	$ 50,000,000
Sub-Limit LOC | Subsequent Event
Debt Instrument [Line Items]
Borrowed				$ 12,000,000

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Asset [Abstract]
Derivative Asset, Gross Amount Recognized in the Balance Sheets	$ 6	$ 12
Derivative Asset, Counterparty Netting	4	11
Derivative Asset, Cash Collateral Received/Posted	0	0
Derivative Asset, Net Amount	2	1
Derivative Liability [Abstract]
Derivative Liability, Gross Amount Recognized in the Balance Sheets	(76)	(37)
Derivative Liability, Counterparty Netting	(4)	(11)
Derivative Liability, Cash Collateral Received/Posted	(2)	0
Derivative Liability, Net Amount	$ (70)	$ (26)

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SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated share of probable payout	$ 12	$ 9
Allocated share-based compensation expense	$ 4	$ 2	$ 4
2015 Share Unit Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, valuation, share equivalent, number (in shares)	1
2015 Share Unit Plan | PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options awarded during the period (in shares)	66,978	54,426	68,126
2015 Share Unit Plan | RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options awarded during the period (in shares)	33,489	27,213	34,063

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RELATED PARTY TRANSACTIONS (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) facility	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties		$ 8,000	$ 8,000
Payables to Related Parties		4,000	5,000
Supplemental Workforce, SES		505,796	543,143	$ 425,555
Transmission Revenues, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Transmission and Wholesale Revenue		7,000	6,000	7,000
Wholesale Revenues, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Transmission and Wholesale Revenue		1,000	1,000	0
Control Area Services, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Control Area Services and Corporate Services		4,000	3,000	3,000
Common Costs, UNS Energy Affiliates
Related Party Transaction, Due from (to) Related Parties [Abstract]
Common Costs, UNS Energy Affiliates		19,000	18,000	16,000
Corporate Services, Fortis Affiliates
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services		0	0	2,000
Supplemental Workforce, SES
Related Party Transaction, Due from (to) Related Parties [Abstract]
Supplemental Workforce, SES		15,000	15,000	15,000
Corporate Services, UNS Energy
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services		$ 6,000	6,000	5,000
Intercompany allocation parent to subsidiary (in percentage)		83.00%
Management fee		$ 6,000	5,000	6,000
Corporate Services, UNS Energy Affiliates
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services		4,000	7,000	5,000
Capacity Charges, UNS Gas
Related Party Transaction, Due from (to) Related Parties [Abstract]
Capacity Charges, UNS Gas		$ 1,000	1,000	$ 0
Number of generation facilities | facility		1
UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties		$ 6,000	7,000
Payables to Related Parties		1,000	1,000
UNS Gas
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties		2,000	1,000
Payables to Related Parties		0	1,000
SES
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payables to Related Parties		2,000	2,000
UNS Energy
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payables to Related Parties		$ 1,000	$ 1,000
UNS Energy | Subsequent Event
Related Party Transaction, Due from (to) Related Parties [Abstract]
Equity contributions	$ 125,000

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average Annual Depreciation Rates	3.08%	3.13%	2.97%

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REGULATORY MATTERS (2019 ACC Rate Case) (Details) - Arizona Corporation Commission $ in Millions	1 Months Ended
	Apr. 30, 2019 USD ($)
Non-fuel Component of Base Rate
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase (decrease)	$ 99
Original cost rate base (percentage)	7.49%
Original cost rate base	$ 2,700
Original cost of equity (percentage)	10.00%
Average original cost of debt (percentage)	4.65%
Fuel Component of Base Rate
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase (decrease)	$ (39)
Revenue Component of Base Rate
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase (decrease)	$ 60

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REGULATORY MATTERS (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Schedule of Regulatory Assets

The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order:

	Years Ended December 31,
(in millions)	2019			2018
Beginning of Period	$	4		$	—
ACC Approved Refund (Reduction in Operating Revenues)	(34		)	(33		)
Amount Returned to Customers Through Bill Credits	22			37
Regulatory Deferral	8			—
End of Period	$	—		$	4

Schedule of Purchased Power and Fuel Adjustment Rates

The table below summarizes the PPFAC regulatory asset (liability) balance:

	Years Ended December 31,
(in millions)	2019			2018
Beginning of Period	$	(17	)	$	(9	)
Deferred Fuel and Purchased Power Costs	31			2
PPFAC Refunds (Recoveries) (1)	22			(10		)
End of Period	$	36		$	(17	)

⁽¹⁾ 

In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request.

Schedule of Regulated Operating Revenue

The table below summarizes the LFCR revenues recognized in Operating Revenues on the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
LFCR Revenues	$	33	$	26	$	22

Schedule of 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)		2019		2018
Regulatory Assets
Pension and Other Postretirement Benefits (Note 10)	Various	$	135	$	126
Derivatives (Note 13)	10	72		27
Early Generation Retirement Costs	Various	68		72
Lost Fixed Cost Recovery	2	46		35
Income Taxes Recoverable through Future Rates (1)	Various	38		47
Under Recovered Purchased Energy Costs	1	36		—
Property Tax Deferrals (2)	1	24		23
Final Mine Reclamation and Retiree Healthcare Costs (3)	19	19		29
Springerville Unit 1 Leasehold Improvements (4)	4	9		11
Other Regulatory Assets	Various	18		30
Total Regulatory Assets		465		400
Less Current Portion	1	138		107
Total Non-Current Regulatory Assets		$	327	$	293

Regulatory Liabilities
Income Taxes Payable through Future Rates (1)	Various	$	327	$	354
Net Cost of Removal (5)	Various	164		171
Renewable Energy Standard	Various	59		52
Deferred Investment Tax Credits (6)	Various	3		7
Over Recovered Purchased Energy Costs	Various	—		17
Other Regulatory Liabilities	Various	20		6
Total Regulatory Liabilities		573		607
Less Current Portion	1	96		95
Total Non-Current Regulatory Liabilities		$	477	$	512

⁽¹⁾  Amortized over the life of the assets. See Note 14 for additional information regarding income taxes.

⁽²⁾  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.

⁽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⁾  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 period.

⁽⁵⁾  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.

⁽⁶⁾ 

Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

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INCOME TAXES

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to pre-tax income due to the following:

	Years Ended December 31,
(in millions)	2019			2018			2017
Federal Income Tax Expense at Statutory Rate	$	46		$	49		$	97
State Income Tax Expense, Net of Federal Deduction	9			9			9
Federal/State Tax Credits	(6		)	(10		)	(9		)
Allowance for Equity Funds Used During Construction	(3		)	(1		)	(2		)
Impact of Enactment, TCJA	—			—			7
Excess Deferred Income Taxes	(9		)	(6		)	—
Impact of AMT Sequestration	(2		)	2			—
Other	(1		)	—			(1		)
Total Federal and State Income Tax Expense	$	34		$	43		$	101

Income Tax Expense included on the Consolidated Statements of Income consists of the following:

	Years Ended December 31,
(in millions)	2019			2018			2017
Current Income Tax Expense
Federal	$	(8	)	$	(13	)	$	—
State	—			—			—
Total Current Income Tax Expense	(8		)	(13		)	—
Deferred Income Tax Expense
Federal	41			53			98
Federal Investment Tax Credits	(4		)	(6		)	(6		)
State	5			9			9
Total Deferred Income Tax Expense	42			56			101
Total Federal and State Income Tax Expense	$	34		$	43		$	101

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 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $9 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019. 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, 2019, TEP had a receivable of $7 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 2019, TEP reversed the $2 million in income tax expense, as the AMT credit refunds were no longer subject to sequestration due to the IRS revising previously issued guidance.

The significant components of deferred income tax assets and liabilities consist of the following:

	December 31,
(in millions)	2019			2018
Gross Deferred Income Tax Assets
Finance Lease Obligations	$	21		$	48
Operating Loss Carryforwards, Net	3			23
Customer Advances and Contributions in Aid of Construction	19			16
AMT Credit	7			13
Other Postretirement Benefits	15			15
Investment Tax Credit Carryforward	34			34
Income Taxes Recoverable Through Future Rates	81			87
Other	79			60
Total Gross Deferred Income Tax Assets	259			296
Deferred Tax Assets Valuation Allowance	—			—
Gross Deferred Income Tax Liabilities
Plant, Net	(602		)	(552		)
Plant Abandonments	(17		)	(18		)
Finance Lease Assets, Net	(18		)	(44		)
Pensions	(17		)	(19		)
Income Taxes Payable Through Future Rates	(9		)	(12		)
Other	(28		)	(21		)
Total Gross Deferred Income Tax Liabilities	(691		)	(666		)
Deferred Income Taxes, Net	$	(432	)	$	(370	)

TEP recorded no valuation allowance against credit and net operating loss carryforward deferred income tax assets as of December 31, 2019 and 2018. 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, 2019, TEP had the following carryforward amounts:

(in millions)	Amount		Expiring Year
Federal Net Operating Loss	$	17	2034 - 35
State Credits	9		2022 - 29
AMT Credit	7		None
Investment Tax Credits	34		2031 - 37

UNCERTAIN TAX POSITIONS

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	December 31,
(in millions)	2019		2018
Beginning of Period	$	16	$	13
Additions Based on Tax Positions Taken in the Current Year	2		3
End of Period	$	18	$	16

Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 2019 and 2018.

TEP recorded no interest expense during 2019 and 2018 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2019 and 2018.

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.

A decrease of $17 million in the Company's uncertain tax position obligations could occur within the next twelve months pending the outcome of an application for change in accounting method filed with the IRS.

TAX SHARING AGREEMENT

Under the terms of the tax sharing agreement with UNS Energy, TEP received $14 million in 2019 related to the 2018 Federal income tax returns and no payments in 2018 related to the 2017 Federal income tax returns.

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LEASES

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

LEASES

LEASES

TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s leases are included in the balance sheet as follows:

(in millions)	Lease Type	December 31, 2019
Lease Assets
Utility Plant Under Finance Leases	Finance	$	151
Accumulated Amortization of Finance Lease Assets	Finance	(77		)
Regulatory and Other Assets, Other	Operating	8
Lease Liabilities
Current Liabilities, Finance Lease Obligations	Finance	17
Finance Lease Obligations	Finance	67
Current Liabilities, Other	Operating	1
Regulatory and Other Liabilities, Other	Operating	6

Springerville Common Facilities Leases

TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019, TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million. The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities.

Gila River Unit 2

In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20-year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The

Tolling PPA included a three-year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed.

The following table presents the components of TEP’s lease cost:

	Year Ended
(in millions)	December 31, 2019
Finance
Amortization of Leased Assets (1)	$	13
Interest on Lease Liabilities (2)	13
Operating	1
Variable	16
Short Term	1
Total Lease Cost	$	44

⁽¹⁾  TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment.

⁽²⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019. TEP purchased Gila River Unit 2 in December 2019.

TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.

As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:

(in millions)	Finance Leases		Operating Leases		Total
2020	$	18	$	1	$	19
2021	68		1		69
2022	—		1		1
2023	—		1		1
2024	—		1		1
Thereafter	—		4		4
Total Lease Payments	86		9		95
Less Imputed Interest	2		2		4
Total Lease Obligations	84		7		91
Less Current Portion	17		1		18
Total Non-Current Lease Obligations	$	67	$	6	$	73

The following table presents TEP's lease terms and discount rate related to its leases:

	December 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	2.2	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Year Ended
(in millions)	December 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	13
Operating Cash Flows used for Operating Leases	1
Financing Cash Flows used for Finance Leases	11
Investing Cash Flows used for Finance Leases	164

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years.

Operating lease income for the year ended December 31, 2019, was $1 million. TEP's expected operating lease payments to be received as of December 31, 2019, are $1 million in each of 2020 through 2024 and thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

TEP's operating lease cost was $1 million for the year ended December 31, 2018.

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

LEASES

LEASES

TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s leases are included in the balance sheet as follows:

(in millions)	Lease Type	December 31, 2019
Lease Assets
Utility Plant Under Finance Leases	Finance	$	151
Accumulated Amortization of Finance Lease Assets	Finance	(77		)
Regulatory and Other Assets, Other	Operating	8
Lease Liabilities
Current Liabilities, Finance Lease Obligations	Finance	17
Finance Lease Obligations	Finance	67
Current Liabilities, Other	Operating	1
Regulatory and Other Liabilities, Other	Operating	6

Springerville Common Facilities Leases

TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019, TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million. The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities.

Gila River Unit 2

In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20-year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The

Tolling PPA included a three-year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed.

The following table presents the components of TEP’s lease cost:

	Year Ended
(in millions)	December 31, 2019
Finance
Amortization of Leased Assets (1)	$	13
Interest on Lease Liabilities (2)	13
Operating	1
Variable	16
Short Term	1
Total Lease Cost	$	44

⁽¹⁾  TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment.

⁽²⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019. TEP purchased Gila River Unit 2 in December 2019.

TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.

As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:

(in millions)	Finance Leases		Operating Leases		Total
2020	$	18	$	1	$	19
2021	68		1		69
2022	—		1		1
2023	—		1		1
2024	—		1		1
Thereafter	—		4		4
Total Lease Payments	86		9		95
Less Imputed Interest	2		2		4
Total Lease Obligations	84		7		91
Less Current Portion	17		1		18
Total Non-Current Lease Obligations	$	67	$	6	$	73

The following table presents TEP's lease terms and discount rate related to its leases:

	December 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	2.2	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Year Ended
(in millions)	December 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	13
Operating Cash Flows used for Operating Leases	1
Financing Cash Flows used for Finance Leases	11
Investing Cash Flows used for Finance Leases	164

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years.

Operating lease income for the year ended December 31, 2019, was $1 million. TEP's expected operating lease payments to be received as of December 31, 2019, are $1 million in each of 2020 through 2024 and thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

TEP's operating lease cost was $1 million for the year ended December 31, 2018.

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

LEASES

LEASES

TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.

TEP’s leases are included in the balance sheet as follows:

(in millions)	Lease Type	December 31, 2019
Lease Assets
Utility Plant Under Finance Leases	Finance	$	151
Accumulated Amortization of Finance Lease Assets	Finance	(77		)
Regulatory and Other Assets, Other	Operating	8
Lease Liabilities
Current Liabilities, Finance Lease Obligations	Finance	17
Finance Lease Obligations	Finance	67
Current Liabilities, Other	Operating	1
Regulatory and Other Liabilities, Other	Operating	6

Springerville Common Facilities Leases

TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019, TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million. The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities.

Gila River Unit 2

In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20-year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The

Tolling PPA included a three-year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed.

The following table presents the components of TEP’s lease cost:

	Year Ended
(in millions)	December 31, 2019
Finance
Amortization of Leased Assets (1)	$	13
Interest on Lease Liabilities (2)	13
Operating	1
Variable	16
Short Term	1
Total Lease Cost	$	44

⁽¹⁾  TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment.

⁽²⁾  Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019. TEP purchased Gila River Unit 2 in December 2019.

TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.

As of December 31, 2019, TEP had the following future minimum lease payments, excluding payments to lessors for variable costs:

(in millions)	Finance Leases		Operating Leases		Total
2020	$	18	$	1	$	19
2021	68		1		69
2022	—		1		1
2023	—		1		1
2024	—		1		1
Thereafter	—		4		4
Total Lease Payments	86		9		95
Less Imputed Interest	2		2		4
Total Lease Obligations	84		7		91
Less Current Portion	17		1		18
Total Non-Current Lease Obligations	$	67	$	6	$	73

The following table presents TEP's lease terms and discount rate related to its leases:

	December 31, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases	1
Operating Leases	12
Weighted-Average Discount Rate
Finance Leases	2.2	%
Operating Leases	4.1	%

The following table presents TEP's cash flow information related to its leases:

	Year Ended
(in millions)	December 31, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
Operating Cash Flows used for Finance Leases	$	13
Operating Cash Flows used for Operating Leases	1
Financing Cash Flows used for Finance Leases	11
Investing Cash Flows used for Finance Leases	164

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years.

Operating lease income for the year ended December 31, 2019, was $1 million. TEP's expected operating lease payments to be received as of December 31, 2019, are $1 million in each of 2020 through 2024 and thereafter.

DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD

As of December 31, 2018, future minimum lease payments were as follows:

(in millions)	Capital Leases		Operating Leases
2019	$	187	$	1
2020	20		1
2021	—		1
2022	—		1
2023	—		1
Thereafter	—		5
Total Lease Payments	207		$	10
Less: Imputed Interest	14
Total Lease Obligations	193
Less: Current Portion	173
Total Non-Current Lease Obligations	$	20

TEP's operating lease cost was $1 million for the year ended December 31, 2018.

See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities.

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REVENUE

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

REVENUE

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.

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)	2019		2018		2017
Retail	$	972	$	1,022	$	1,017
Wholesale	247		238		152
Other Services	124		100		103
Revenues from Contracts with Customers	1,343		1,360		1,272
Alternative Revenues	35		28		24
Other	40		45		45
Total Operating Revenues	$	1,418	$	1,433	$	1,341

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. Unbilled revenues primarily 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 cash collections results in billed and unbilled accounts receivable balances in the balance sheet. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.

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 May 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing proposed replacing TEP's stated transmission rates with a forward-looking formula rate. Effective August 2019, the FERC authorized TEP to bill the proposed rate revisions, subject to refund. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the FERC rate case.

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. 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 in 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 13 for information regarding derivative instruments and Note 8 for information regarding lease income.

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QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of quarterly financial information

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)	2019
Operating Revenue	$	333	$	326	$	441	$	318
Operating Income	43		67		134		39
Net Income	26		42		98		21
	2018
Operating Revenue	$	275	$	354	$	460	$	344
Operating Income	43		83		126		36
Net Income	24		58		95		11

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Operating Revenues	$ 1,418,338	$ 1,432,618	$ 1,340,935
Operating Expenses
Fuel	358,394	351,749	285,551
Purchased Power	137,977	134,914	136,425
Transmission and Other PPFAC Recoverable Costs	52,261	46,595	36,239
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(42,836)	9,885	(32,660)
Total Fuel and Purchased Power	505,796	543,143	425,555
Operations and Maintenance	377,563	361,963	360,302
Depreciation	169,042	158,310	152,874
Amortization	27,706	26,052	22,255
Taxes Other Than Income Taxes	55,642	55,006	53,623
Total Operating Expenses	1,135,749	1,144,474	1,014,609
Operating Income	282,589	288,144	326,326
Other Income (Expense)
Interest Expense	(88,511)	(67,620)	(65,290)
Allowance For Borrowed Funds	5,744	3,151	2,078
Allowance For Equity Funds	15,222	8,117	5,322
Other, Net	5,524	(487)	8,995
Total Other Income (Expense)	(62,021)	(56,839)	(48,895)
Income Before Income Tax Expense	220,568	231,305	277,431
Income Tax Expense	34,053	42,982	100,763
Net Income	$ 186,515	$ 188,323	$ 176,668

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DEBT AND CREDIT AGREEMENTS (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of long-term debt instruments

The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets:

			December 31,
($ in millions)	Interest Rate	Maturity Date	2019		2018
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		300
Tax-Exempt Local Furnishings Bonds (1)
2010 Pima A	5.25%	2040	100		100
2012 Pima A	4.50%	2030	16		16
2013 Pima A	4.00%	2029	91		91
Tax-Exempt Pollution Control Bonds (2)
2009 Pima A	4.95%	2020	80		80
2009 Coconino A	5.13%	2032	—		15
2012 Apache A	4.50%	2030	177		177
Total Long-Term Debt (3)			1,614		1,629
Less Unamortized Discount and Debt Issuance Costs			12		14
Less Current Maturities of Long-Term Debt			80		—
Total Long-Term Debt, Net			$	1,522	$	1,615

⁽¹⁾  The 2010 Pima A bonds can be redeemed at par on or after October 2020. TEP has the option to redeem the remaining bonds at par on dates ranging from first quarter of 2022 to first quarter of 2023.

⁽²⁾  The 2009 Pima A bonds mature in October 2020. The 2012 Apache A bonds may be redeemed at par in the first quarter of 2022.

⁽³⁾ 

As of December 31, 2019, all of TEP's debt is unsecured.

Schedule of maturities of long-term debt

Long-term debt matures on the following dates:

(in millions)	Long-Term Debt (1)
2020	$	80
2021	250
2022	—
2023	150
2024	—
Thereafter	1,134
Total	$	1,614

⁽¹⁾ 

Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount.

Schedule of line of credit facilities

Terms are as follows:

							Weighted Average Interest Rate
	Capacity		Borrowed (1)		Available				Pricing
(in millions)	December 31, 2019
Term Loan	$	225	$	165	$	60	4.75	%	LIBOR + 0.550%	or ABR + 0.00%

⁽¹⁾ 

All amounts borrowed will be due and payable by December 2020.

Terms are as follows:

	Capacity		Sub-Limit LOC		Borrowed		Available		Weighted Average Interest Rate		Pricing (1)
(in millions)	December 31, 2019
Revolver and LOC	$	250	$	50	$	—	$	250	—	%	LIBOR + 1.000%	or ABR + 0.00%

(in millions)	December 31, 2018
Revolver and LOC	$	250	$	50	$	—	$	250	—	%	LIBOR + 1.000%	or ABR + 0.00%

⁽¹⁾  Interest rates and fees are based on a pricing grid tied to TEP's credit rating.

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SHARE-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Schedule of represents PSUs and RSUs awarded by UNS Energy

The following table represents PSUs and RSUs awarded by UNS Energy:

	2019	2018	2017
PSUs	66,978	54,426	68,126
RSUs	33,489	27,213	34,063

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Utility Plant
Plant in Service	$ 6,663,912	$ 6,020,469
Utility Plant Under Finance Leases	151,467	248,635
Construction Work in Progress	303,488	258,965
Total Utility Plant	7,118,867	6,528,069
Accumulated Depreciation and Amortization	(2,506,686)	(2,293,783)
Accumulated Amortization of Finance Lease Assets	(77,285)	(73,646)
Total Utility Plant, Net	4,534,896	4,160,640
Investments and Other Property	62,136	50,952
Current Assets
Cash and Cash Equivalents	9,762	138,114
Accounts Receivable, Net	154,847	172,367
Fuel Inventory	23,731	22,783
Materials and Supplies	121,542	107,990
Regulatory Assets	138,412	106,725
Derivative Instruments	3,596	3,929
Other	21,416	25,571
Total Current Assets	473,306	577,479
Regulatory and Other Assets
Regulatory Assets	326,860	293,078
Derivative Instruments	2,763	8,402
Other	89,196	68,656
Total Regulatory and Other Assets	418,819	370,136
Total Assets	5,489,157	5,159,207
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2019 and 2018)	1,396,539	1,346,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	595,792	484,277
Accumulated Other Comprehensive Loss	(7,771)	(4,714)
Total Common Stock Equity	1,978,203	1,819,745
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2019 and 2018)	0	0
Finance Lease Obligations	67,316
Finance Lease Obligations		19,773
Long-Term Debt, Net	1,522,087	1,615,252
Total Capitalization	3,567,606	3,454,770
Current Liabilities
Current Maturities of Long-Term Debt	80,330	0
Borrowings Under Credit Agreements	165,000	0
Finance Lease Obligations	17,086
Finance Lease Obligations		172,510
Accounts Payable	136,465	133,012
Accrued Taxes Other than Income Taxes	42,741	41,686
Accrued Employee Expenses	32,567	34,339
Accrued Interest	16,700	17,927
Regulatory Liabilities	96,017	95,094
Customer Deposits	24,568	27,650
Derivative Instruments	27,615	18,137
Other	23,678	21,555
Total Current Liabilities	662,767	561,910
Regulatory and Other Liabilities
Deferred Income Taxes, Net	432,484	369,705
Regulatory Liabilities	477,495	512,425
Pension and Other Postretirement Benefits	133,452	117,472
Derivative Instruments	48,697	19,361
Other	166,656	123,564
Total Regulatory and Other Liabilities	1,258,784	1,142,527
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 5,489,157	$ 5,159,207

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UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Utility Plant in Service by Major Class) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	3.08%	3.13%	2.97%
Plant in Service	$ 6,663,912	$ 6,020,469
Capitalized computer software, net	78,000	73,000
Amortization of computer software costs	$ 26,000	24,000	$ 19,000
Acquired finite-lived intangible assets, weighted average useful life (in years)	3 years
Plant acquisition adjustments	$ (211,000)	(134,000)
Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Acquired finite-lived intangible assets, weighted average useful life (in years)	3 years
Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Acquired finite-lived intangible assets, weighted average useful life (in years)	5 years
Generation Plant
Public Utility, Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	3.19%
Average Remaining Life in Years	20 years
Plant in Service	$ 3,065,000	2,667,000
Transmission Plant
Public Utility, Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	1.69%
Average Remaining Life in Years	37 years
Plant in Service	$ 1,060,000	1,010,000
Distribution Plant
Public Utility, Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	1.56%
Average Remaining Life in Years	31 years
Plant in Service	$ 1,784,000	1,692,000
General Plant
Public Utility, Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	5.89%
Average Remaining Life in Years	20 years
Plant in Service	$ 477,000	409,000
Intangible Plant, Software Costs and Other
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	271,000	239,000
Plant Held for Future Use
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service	$ 7,000	$ 3,000

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REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Sep. 30, 2019	Feb. 28, 2019	Dec. 31, 2025	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Roll Forward]
Environmental compliance adjustor, as a percentage of total retail revenue					0.50%
Environmental compliance adjustor, return on environmental investments					$ 2	$ 3	$ 1
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Roll Forward]
Beginning of Period				$ 36	(17)	(9)
Deferred Fuel and Purchased Power Costs					31	2
PPFAC Refunds (Recoveries)					22	(10)
End of Period					$ 36	(17)	(9)
Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified					12 months
Renewable Energy Standard
Regulatory Liabilities [Roll Forward]
Renewable energy target percentage					9.00%
Approved spending budget	$ 55
Recovery revenue						1	1
Renewable energy actual percentage					16.00%
Renewable Energy Standard | Maximum
Regulatory Liabilities [Roll Forward]
Recovery revenue					$ 1
Renewable Energy Standard | Forecast
Regulatory Liabilities [Roll Forward]
Renewable energy target percentage			15.00%
Distributed generation requirement percent of target percentage (percentage)			30.00%
Demand Side Management
Regulatory Liabilities [Roll Forward]
Recovery revenue					$ 2	2	2
Energy Efficiency Standards
Regulatory Liabilities [Roll Forward]
Percentage of cumulative annual retail kilowatt savings, actual					19.00%
Approved recovery of spending budget		$ 23
Energy Efficiency Standards | Forecast
Regulatory Liabilities [Roll Forward]
Percentage of electric energy efficiency standards target retail savings on sales (in percentage)				22.00%
Lost Fixed Cost Recovery
Regulatory Liabilities [Roll Forward]
Recovery revenue					$ 33	$ 26	$ 22
Cap on increase in lost fixed cost recovery rate (percentage)					2.00%

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REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers									$ 1,343,000	$ 1,360,000	$ 1,272,000
Alternative Revenues									35,000	28,000	24,000
Other									40,000	45,000	45,000
Total Operating Revenues	$ 318,000	$ 441,000	$ 326,000	$ 333,000	$ 344,000	$ 460,000	$ 354,000	$ 275,000	1,418,338	1,432,618	1,340,935
Retail
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers									972,000	1,022,000	1,017,000
Wholesale
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers									247,000	238,000	152,000
Other Services
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers									$ 124,000	$ 100,000	$ 103,000
Lost Fixed Cost Recovery Mechanism
Disaggregation of Revenue [Line Items]
Cap on increase in lost fixed cost recovery rate (percentage)									2.00%

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COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Aug. 30, 2019	Dec. 31, 2018
San Juan Unit 1
Commitments And Contingencies [Line Items]
Percentage of ownership (in percentage)	50.00%	50.00%
San Juan and Four Corners
Commitments And Contingencies [Line Items]
Reclamation costs	$ 57
San Juan and Four Corners | Other Liabilities
Commitments And Contingencies [Line Items]
Reclamation costs accrued	36		$ 31
Navajo
Commitments And Contingencies [Line Items]
Reclamation costs	17
Reclamation costs accrued	0
Navajo | Other Liabilities
Commitments And Contingencies [Line Items]
Reclamation costs accrued			$ 5
Settlement paid	$ 8

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EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Rate of Compensation Increase (in percentage)	2.80%	2.80%	2.80%
Expected Return on Plan Assets (in percentage)	7.00%	7.00%	7.00%
Pension Benefits | Service cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	4.70%	3.80%	4.40%
Pension Benefits | Interest Cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	4.20%	3.40%	3.70%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected Return on Plan Assets (in percentage)	7.00%	7.00%	7.00%
Other Postretirement Benefits | Service cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	4.50%	3.80%	4.30%
Other Postretirement Benefits | Interest Cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	4.00%	3.20%	3.30%

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EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning of Period	$ 28	$ 27
Actual Return on Plan Assets:
Assets Held at Reporting Date	2	3
Purchases, Sales, and Settlements	(2)	(2)
End of Period	28	28
Private Equity
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning of Period	6	6
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	2
Purchases, Sales, and Settlements	(2)	(2)
End of Period	5	6
Real Estate
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning of Period	22	21
Actual Return on Plan Assets:
Assets Held at Reporting Date	1	1
Purchases, Sales, and Settlements	0	0
End of Period	$ 23	$ 22

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EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Change in Benefit Obligation
Beginning of Period	$ 440	$ 475
Actuarial (Gain) Loss	76	(42)
Interest Cost	18	16	$ 15
Service Cost	13	15	13
Benefits Paid	(23)	(23)
Plan Amendments	1	(1)
End of Period	525	440	475
Change in Fair Value of Plan Assets
Beginning of Period	376	403
Actual Return on Plan Assets	81	(25)
Benefits Paid	(22)	(23)
Employer Contributions	11	21
End of Period	446	376	403
Funded Status at End of Period	(79)	(64)
Expected future contribution	11
Other Postretirement Benefits
Change in Benefit Obligation
Beginning of Period	74	82
Actuarial (Gain) Loss	4	(8)
Interest Cost	3	2	2
Service Cost	4	5	4
Benefits Paid	(6)	(5)
Plan Amendments	0	(2)
End of Period	79	74	82
Change in Fair Value of Plan Assets
Beginning of Period	17	17
Actual Return on Plan Assets	4	(1)
Benefits Paid	(6)	(5)
Employer Contributions	6	6
End of Period	21	17	$ 17
Funded Status at End of Period	(58)	$ (57)
Expected future contribution	$ 1

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REGULATORY MATTERS (Federal Tax Legislation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Roll Forward]
Regulatory Deferral	$ 7,705	$ (1,562)	$ 0
Arizona Corporation Commission
Public Utilities, General Disclosures [Line Items]
Change in tax rate, refund to customers, net of amortization	$ 35,000
Change in tax rate, customers bill as percent of returned savings	50.00%
Arizona Corporation Commission | Revenue Refund
Regulatory Assets [Roll Forward]
Beginning of Period	$ 4,000	0
ACC Refund (Reduction in Operating Revenues)	(34,000)	(33,000)
Amount Returned to Customers through Bill Credits	22,000	37,000
Regulatory Deferral	8,000	0
End of Period	$ 0	4,000	$ 0
FERC
Regulatory Assets [Roll Forward]
ACC Refund (Reduction in Operating Revenues)		$ (1,000)
Regulatory commission, decrease in transmission rate		5.30%

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Allowance for Doubtful Accounts) (Details) - Allowance for Doubtful Accounts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning of Period	$ 5	$ 5	$ 5
Additions Charged to Cost and Expense	4	3	3
Write-offs	(3)	(3)	(3)
End of Period	$ 6	$ 5	$ 5

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy Credits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Renewable Energy Credits [Roll Forward]
Beginning of Period	$ 55	$ 42
Purchased	45	45
Used for Compliance	(37)	(32)
End of Period	$ 63	$ 55

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QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Operating Revenue	$ 318,000	$ 441,000	$ 326,000	$ 333,000	$ 344,000	$ 460,000	$ 354,000	$ 275,000	$ 1,418,338	$ 1,432,618	$ 1,340,935
Operating Income	39,000	134,000	67,000	43,000	36,000	126,000	83,000	43,000	282,589	288,144	326,326
Net Income	$ 21,000	$ 98,000	$ 42,000	$ 26,000	$ 11,000	$ 95,000	$ 58,000	$ 24,000	$ 186,515	$ 188,323	$ 176,668

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INCOME TAXES (Additional Information) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Increase in regulated liabilities due to change in tax rate	$ 9,000,000
Impact of AMT Sequestration	2,000,000	$ (2,000,000)	$ 0
Valuation allowance	0	0
Unrecognized tax benefits, if recognized, decrease in income tax expense (benefit)	1,000,000	1,000,000
Interest expense related to uncertain tax position	0	0
Interest payable	0	0
Penalties accrued	0	0
Decrease in uncertain tax position obligations	17,000,000
Federal tax return	8,000,000	13,000,000	$ 0
UNS Energy
Operating Loss Carryforwards [Line Items]
Federal tax return	14,000,000	$ 0
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Tax credits	$ 7,000,000

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LEASES (Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Lease Assets
Utility Plant Under Finance Leases	$ 151,467	$ 248,635
Accumulated Amortization of Finance Lease Assets	(77,285)	$ (73,646)
Regulatory and Other Assets, Other	8,000
Lease Liabilities
Current Liabilities, Finance Lease Obligations	17,086
Total Non-Current Lease Obligations	67,316
Current Liabilities, Other	1,000
Regulatory and Other Liabilities, Other	$ 6,000

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) $ in Millions, BBtu in Billions	Dec. 31, 2019 USD ($) BBtu GWh	Dec. 31, 2018 BBtu GWh
Interest Rate Swap
Derivative Instruments, Gain (Loss) [Line Items]
Derivative liability, notional amount | $	$ 6
Power Contracts GWh
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, nonmonetary notional amount | GWh	4,740	1,743
Gas Contracts BBtu
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, nonmonetary notional amount | BBtu	122,779	146,933

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SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Finance Leases	$ 67
Finance Leases		$ 164	$ 0
Accrued Capital Expenditures	40	31	24
Asset Retirement Obligations Increase (Decrease)	26	20	10
Operating Leases	8
Renewable Energy Credits	3	3	2
Net Cost of Removal Increase (Decrease)	$ (10)	$ (4)	$ (88)

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DEBT AND CREDIT AGREEMENTS (Issuances and Redemptions) (Details) - USD ($)	1 Months Ended
	Nov. 30, 2019	Dec. 31, 2018	Nov. 30, 2018
Secured Debt | Tax Exempt Variable Rate
Debt Instrument [Line Items]
Debt extinguishment		$ 37,000,000
Unsecured Debt | Tax Exempt Variable Rate
Debt Instrument [Line Items]
Debt extinguishment	$ 15,000,000		$ 100,000,000
Unsecured Debt | Notes 2018, Due June 1, 2048
Debt Instrument [Line Items]
Debt instrument, face amount			$ 300,000,000

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis Of Presentation and Accounting for Regulated Operations

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. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities 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.

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.

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 Entity

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it 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 has entered 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 these 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, 2019, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent 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.

New Accounting Standards Issued and Adopted and Not Yet Adopted

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. 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.

Leases

TEP adopted accounting guidance 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. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, 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. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 8 for additional disclosure about TEP’s leasing arrangements.

Internal-Use Software

TEP early adopted accounting guidance 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 guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

Use of Accounting Estimates

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

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 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

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

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 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 and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.

RESTRICTED CASH

Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations.

Allowance for Doubtful Accounts

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.

Inventory

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

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 determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. 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 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.

Depreciation

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.

Computer Software and Cloud Computing Costs

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. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense in the income statement.

Evaluation of Assets for Impairment

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

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.

Leases

LEASES

When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet.

Operating Revenues

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 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.

Purchased Power and Fuel Adjustment Clause

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.

Renewable Energy and Energy Efficiency Programs and Renewable Energy Credits

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.

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.

Taxes Other Than Income Taxes

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

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 in 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 2013 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. TEP had an aggregate liability balance of $6 million and $7 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million and $6 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. 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. 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.

Pension and Other Post Retirement Benefits

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.

Fair Value

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.

Derivative Instruments

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 in 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 in 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.

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SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

CASH TRANSACTIONS

	Years Ended December 31,
(in millions)	2019			2018		2017
Interest Paid, Net of Amounts Capitalized	$	80		$	67	$	61
Income Tax Refunds (1)	(14		)	—		—

⁽¹⁾  TEP received a refund of AMT credit carryforwards in 2019. See Note 14 for additional information regarding AMT.

NON-CASH TRANSACTIONS

Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:

	Years Ended December 31,
(in millions)	2019			2018			2017
Finance Leases	$	67		$	164		$	—
Accrued Capital Expenditures	40			31			24
Asset Retirement Obligations Increase (Decrease) (1)	26			20			10
Operating Leases (2)	8			—			—
Renewable Energy Credits	3			3			2
Net Cost of Removal Increase (Decrease) (3)	(10		)	(4		)	(88		)

⁽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 expected future AROs.

⁽²⁾  On January 1 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods.

⁽³⁾ 

Represents an accrual for future cost of retirement net of salvage values that does not impact earnings.

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REVENUE (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of revenue

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)	2019		2018		2017
Retail	$	972	$	1,022	$	1,017
Wholesale	247		238		152
Other Services	124		100		103
Revenues from Contracts with Customers	1,343		1,360		1,272
Alternative Revenues	35		28		24
Other	40		45		45
Total Operating Revenues	$	1,418	$	1,433	$	1,341

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Details) customer in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) mi² customer	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of retail customers | customer	429
Area in which subsidiary generates transmits and distributes electricity to retail electric customers (sq miles) | mi²	1,155
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and Cash Equivalents	$ 9,762	$ 138,114	$ 38,000
Total Cash, Cash Equivalents, and Restricted Cash	28,472	152,747	49,501	$ 43,325
Investments and Other Property
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted Cash	16,000	14,000	11,000
Current Assets—Other
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted Cash	$ 2,000	$ 1,000	$ 1,000

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy and Energy Efficiency Programs) (Details)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2020	Dec. 31, 2019
Renewable Energy Standard
Public Utilities, General Disclosures [Line Items]
Renewable energy target percentage by 2025 (in percentage)			9.00%
Forecast | Renewable Energy Standard
Public Utilities, General Disclosures [Line Items]
Renewable energy target percentage by 2025 (in percentage)	15.00%
Distributed generation requirement target percentage (in percentage)	30.00%
Forecast | Energy Efficiency Standards
Public Utilities, General Disclosures [Line Items]
Percentage of electric energy efficiency standards target retail savings on sales (in percentage)		22.00%

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REGULATORY MATTERS (2019 FERC Rate Case) (Details) - USD ($) $ in Thousands		12 Months Ended
	May 31, 2019	Dec. 31, 2019	Sep. 19, 2019	Dec. 31, 2018
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 96,017		$ 95,094
Regulatory Assets		$ 465,000		$ 400,000
FERC | Transmission Services Rate
Public Utilities, General Disclosures [Line Items]
Return on equity (percentage)		10.40%
Requested recovery in development, percentage	100.00%
Requested recovery in development	$ 9,000
Allowed cost recovery in development, percentage			50.00%
Regulatory Assets		$ 4,000
FERC | Transmission Services Rate | Revenue Subject to Refund
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 4,000

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LEASES (Lease Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Finance
Amortization of Leased Assets	$ 13
Interest on Lease Liabilities	13
Operating	1	$ 1
Variable	16
Short Term	1
Total Lease Cost	44
Gila River Unit 2
Finance
Amortization of Leased Assets	6
Interest on Lease Liabilities	$ 12

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Forward Power Contracts - Level 3 $ in Millions	Dec. 31, 2018 USD ($) $ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets | $	$ 3
Derivative Liabilities | $	$ (2)
Minimum
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / megawatt_hour	16.80
Maximum
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market Price | $ / megawatt_hour	47.05

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets
Cash Equivalents		$ 55
Restricted Cash	$ 18	15
Energy Derivative Contract, Regulatory Recovery	3	10
Energy Derivative Contract, No Regulatory Recovery	3	2
Total Assets	24	82
Liabilities
Energy Derivative Contracts, Regulatory Recovery	(76)	(37)
Total Liabilities	(76)	(37)
Total Assets (Liabilities), Net	(52)	45
Level 1
Assets
Cash Equivalents		55
Restricted Cash	18	15
Energy Derivative Contract, Regulatory Recovery	0	0
Energy Derivative Contract, No Regulatory Recovery	0	0
Total Assets	18	70
Liabilities
Energy Derivative Contracts, Regulatory Recovery	0	0
Total Liabilities	0	0
Total Assets (Liabilities), Net	18	70
Level 2
Assets
Cash Equivalents		0
Restricted Cash	0	0
Energy Derivative Contract, Regulatory Recovery	3	10
Energy Derivative Contract, No Regulatory Recovery	3	0
Total Assets	6	10
Liabilities
Energy Derivative Contracts, Regulatory Recovery	(76)	(35)
Total Liabilities	(76)	(35)
Total Assets (Liabilities), Net	(70)	(25)
Level 3
Assets
Cash Equivalents		0
Restricted Cash	0	0
Energy Derivative Contract, Regulatory Recovery	0	0
Energy Derivative Contract, No Regulatory Recovery	0	2
Total Assets	0	2
Liabilities
Energy Derivative Contracts, Regulatory Recovery	0	(2)
Total Liabilities	0	(2)
Total Assets (Liabilities), Net	$ 0	$ 0

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DEBT AND CREDIT AGREEMENTS (Maturities of Long-term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Long-Term Debt Maturities
2020	$ 80
2021	250
2022	0
2023	150
2024	0
Thereafter	1,134
Total Long-Term Debt	1,614	$ 1,629
Unamortized debt issuance expense	10
Debt discount	$ 2

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INCOME TAXES (Uncertain Tax Positions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning of Period	$ 16	$ 13
Additions Based on Tax Positions Taken in the Current Year	2	3
End of Period	$ 18	$ 16

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INCOME TAXES (Income Tax Expense Included in Income Statements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Income Tax Expense
Federal	$ (8,000)	$ (13,000)	$ 0
State	0	0	0
Total Current Income Tax Expense	(8,000)	(13,000)	0
Deferred Income Tax Expense
Federal	41,000	53,000	98,000
Federal Investment Tax Credits	(4,000)	(6,000)	(6,000)
State	5,000	9,000	9,000
Total Deferred Income Tax Expense	42,000	56,000	101,000
Total Federal and State Income Tax Expense	$ 34,053	$ 42,982	$ 100,763

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ACCOUNTS RECEIVABLE (Tables)

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

Schedule of the components of Accounts Receivable, Net

The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Customer (1)	$	92		$	99
Customer, Unbilled	42			45
Due from Affiliates (Note 6)	8			8
Other	19			25
Allowance for Doubtful Accounts	(6		)	(5		)
Accounts Receivable, Net	$	155		$	172

⁽¹⁾ 

Includes $5 million and $8 million as of December 31, 2019 and 2018, respectively, of receivables related to revenue from derivative instruments.

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NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Restrictions on cash and cash equivalents

The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to the cash flow statement:

	Years Ended December 31,
(in millions)	2019		2018		2017
Cash and Cash Equivalents	$	10	$	138	$	38
Restricted Cash included in:
Investments and Other Property	16		14		11
Current Assets—Other	2		1		1
Total Cash, Cash Equivalents, and Restricted Cash	$	28	$	153	$	50

Allowance for doubtful accounts

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)	2019			2018			2017
Beginning of Period	$	5		$	5		$	5
Additions Charged to Cost and Expense	4			3			3
Write-offs	(3		)	(3		)	(3		)
End of Period	$	6		$	5		$	5

AFUDC rates

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

	2019		2018		2017
Average AFUDC Rates	7.86	%	7.12	%	7.31	%

Summary of average annual depreciation rates for all utility plants

Below are the summarized average annual depreciation rates for all utility plant:

	2019		2018		2017
Average Annual Depreciation Rates	3.08	%	3.13	%	2.97	%

Schedule of renewable energy credit

The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Beginning of Period	$	55		$	42
Purchased	45			45
Used for Compliance	(37		)	(32		)
End of Period	$	63		$	55

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FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

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.

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 through net income 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, 2019
Assets
Restricted Cash (1)	$	18	$	—		$	—	$	18
Energy Derivative Contracts, Regulatory Recovery (2)	—		3			—		3
Energy Derivative Contracts, No Regulatory Recovery (2)	—		3			—		3
Total Assets	18		6			—		24
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(76		)	—		(76		)
Total Liabilities	—		(76		)	—		(76		)
Total Assets (Liabilities), Net	$	18	$	(70	)	$	—	$	(52	)

(in millions)	December 31, 2018
Assets
Cash Equivalents (1)	$	55	$	—		$	—		$	55
Restricted Cash (1)	15		—			—			15
Energy Derivative Contracts, Regulatory Recovery (2)	—		10			—			10
Energy Derivative Contracts, No Regulatory Recovery (2)	—		—			2			2
Total Assets	70		10			2			82
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(35		)	(2		)	(37		)
Total Liabilities	—		(35		)	(2		)	(37		)
Total Assets (Liabilities), Net	$	70	$	(25	)	$	—		$	45

⁽¹⁾  Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit, 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 2 as of December 31, 2019 and Level 3 as of December 31, 2018) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to decreases in forward market prices of natural gas and increases in volume.

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, 2019
Derivative Assets
Energy Derivative Contracts	$	6		$	4		$	—		$	2
Derivative Liabilities
Energy Derivative Contracts	(76		)	(4		)	(2		)	(70		)

(in millions)	December 31, 2018
Derivative Assets
Energy Derivative Contracts	$	12		$	11		$	—	$	1
Derivative Liabilities
Energy Derivative Contracts	(37		)	(11		)	—		(26		)

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. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.

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 had an interest rate swap agreement that expired in January 2020. As of December 31, 2019, the total notional amount of the interest rate swap was $6 million. No notional amount remained as of February 12, 2020. The after-tax unrealized gains and losses on cash flow hedge activities were reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense on the Consolidated Statements of Income are not material to TEP's financial position or results of operations.

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 in the balance sheet:

	Years Ended December 31,
(in millions)	2019			2018			2017
Unrealized Net Loss (1)	$	(45	)	$	(9	)	$	(18	)

⁽¹⁾  In 2019, unrealized net loss on regulatory recoverable derivative contracts increased primarily due to decreases in forward market prices of natural gas and increases in volume.

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)	2019		2018		2017
Operating Revenues	$	6	$	5	$	5

Derivative Volumes

As of December 31, 2019, 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,
	2019	2018
Power Contracts GWh	4,740	1,743
Gas Contracts BBtu	122,779	146,933

Level 3 Fair Value Measurements

As of December 31, 2019, TEP does not have any Level 3 assets and liabilities balances remaining. The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:

	Valuation Approach	Fair Value of					Unobservable Inputs	Range of Unobservable Inputs
		Assets		Liabilities
(in millions)	December 31, 2018
Forward Power Contracts	Market approach	$	3	$	(2	)	Market price per MWh	$	16.80	$	47.05

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 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)	2019			2018
Beginning of Period	$	1		$	2
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	(12		)	(4		)
Operating Revenues	5			5
Settlements	1			(2		)
Transfers Out of Level 3 (1)	5			—
End of Period	$	—		$	1
Gains (Losses), Assets (Liabilities) Still Held	$	—		$	1

⁽¹⁾  Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities.

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, LOCs, 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 $100 million as of December 31, 2019, compared with $41 million as of December 31, 2018. As of December 31, 2019, TEP had $2 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets—Other on the Consolidated Balance Sheets. As of February 12, 2020, there was no collateral posted. If the credit risk contingent features were triggered on December 31, 2019, TEP would have been required to post an additional $98 million of collateral of which $19 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 net carrying value and estimated fair value of TEP's long-term debt:

		Net Carrying Value				Fair Value
	Fair Value Hierarchy	December 31,
(in millions)		2019		2018		2019		2018
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	1,602	$	1,615	$	1,755	$	1,672

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

COMMITMENTS

Unconditional Purchase Obligations

As of December 31, 2019, TEP had the following unconditional minimum purchase obligations:

(in millions)	2020		2021		2022		2023		2024		Thereafter		Total
Fuel, Including Transportation	$	94	$	61	$	40	$	33	$	33	$	194	$	455
Purchased Power	8		—		—		—		—		—		8
Transmission	21		16		14		3		3		6		63
Renewable Power Purchase Agreements	63		63		63		63		62		543		857
RES Performance-Based Incentives	8		7		7		7		7		33		69
Land Easements and Rights-of-Way (1)	1		2		1		1		3		79		87
Total Purchase Commitments	$	195	$	149	$	125	$	107	$	108	$	855	$	1,539

⁽¹⁾  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 2020 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.

TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2022 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 2020. 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, 2019.

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 2020 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 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.

Build-Transfer Agreement

In March 2019, TEP entered into a build-transfer agreement to develop a 250 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico (Oso Grande) with estimated costs of approximately $384 million. In January 2020, TEP took ownership of Oso Grande. Construction commenced in the third quarter of 2019 and is expected to be completed for operation by December 2020. TEP made payments under the build-transfer agreement of $47 million in 2019 and $226 million in January 2020.

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 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 Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to SJCC) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, 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 OSMRE so the OSMRE 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 2019. The order provides that: (i) the OSMRE’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 2019, then the approved mine plan will immediately be vacated, absent further court order. On April 30, 2019, the OSMRE issued a final Record of Decision (ROD) on the Final EIS released March 15, 2019. The Final EIS contemplates continued mining at the San Juan Mine in annual quantities similar to those currently being provided through 2033. The Assistant Secretary for Land and Minerals Management approved the mining plan outlined in the ROD in August 2019. TEP is not a party in this matter but does own 50% of Unit 1 at San Juan. San Juan is scheduled for early retirement in 2022. TEP does not anticipate any significant impact on the cost of coal at San Juan related to this matter.

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. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing 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’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP defers these expenses until recovered from rate payers 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 out.

San Juan and Four Corners

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of mine reclamation costs at both mines is $57 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $36 million and $31 million as of December 31, 2019 and 2018, respectively, was recorded in Other on the Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

Navajo

In December 2019, TEP entered into an agreement with the owner and operator of the Kayenta Mine and the third-party owners of Navajo for the settlement and release of asserted claims associated with the early retirement of Navajo. During 2019, TEP paid $17 million related to the retirement of Navajo which includes $8 million paid for final mine reclamation costs as a result of the settlement. As of December 31, 2019, TEP had no liability balance related to Navajo final mine reclamation. A liability balance related to Navajo final mine reclamation of $5 million as of December 31, 2018, was recorded in Current Liabilities—Other on the Consolidated Balance Sheets.

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, 2019, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generating station. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046.

Environmental Matters

TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.

Broadway-Pantano Site

The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop substation and a portion of a related transmission line are located on two parcel adjacent to these landfills. On November 8, 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements, however, the overall investigation and remediation plan have not been finalized.

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ACCOUNTS RECEIVABLE

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:

	December 31,
(in millions)	2019			2018
Customer (1)	$	92		$	99
Customer, Unbilled	42			45
Due from Affiliates (Note 6)	8			8
Other	19			25
Allowance for Doubtful Accounts	(6		)	(5		)
Accounts Receivable, Net	$	155		$	172

⁽¹⁾ 

Includes $5 million and $8 million as of December 31, 2019 and 2018, respectively, of receivables related to revenue from derivative instruments.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 186,515	$ 188,323	$ 176,668
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax (Expense) Benefit of $(44), $(121), and $(305)	133	364	485
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax (Expense) Benefit of $1,059, $(747), and $637	(3,190)	2,026	(2,156)
Total Other Comprehensive Income (Loss), Net of Tax	(3,057)	2,390	(1,671)
Total Comprehensive Income	$ 183,458	$ 190,713	$ 174,997

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RELATED PARTY TRANSACTIONS (Table)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Schedule of related party transactions

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)	2019		2018
Receivables from Related Parties
UNS Electric	$	6	$	7
UNS Gas	2		1
Total Due from Related Parties	$	8	$	8
Payables to Related Parties
SES	$	2	$	2
UNS Electric	1		1
UNS Gas	—		1
UNS Energy	1		1
Total Due to Related Parties	$	4	$	5

The following table presents the components of related party transactions included in the Consolidated Statements of Income:

	Years Ended December 31,
(in millions)	2019		2018		2017
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	7	$	6	$	7
Wholesale Revenues, UNS Electric (1)	1		1		—
Control Area Services, UNS Electric (2)	4		3		3
Common Costs, UNS Energy Affiliates (3)	19		18		16
Corporate Services, Fortis Affiliates (4)	—		—		2
Goods and Services Provided by Affiliates to TEP
Supplemental Workforce, SES (5)	15		15		15
Corporate Services, UNS Energy (6)	6		6		5
Corporate Services, UNS Energy Affiliates (7)	4		7		5
Capacity Charges, UNS Gas (8)	1		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 OATT.

⁽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 83% of UNS Energy's allocated costs.

Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $6 million in 2019, $5 million in 2018, and $6 million in 2017.

⁽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.

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Schedule of pension and other postretirement benefit amounts

The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet:

	Pension Benefits						Other Postretirement Benefits
	December 31,
(in millions)	2019			2018			2019			2018
Regulatory Assets	$	135		$	126		$	—		$	—
Regulatory Liabilities	—			—			(1		)	(3		)
Accrued Employee Expenses	(2		)	(1		)	(2		)	(3		)
Pension and Other Postretirement Benefits	(77		)	(63		)	(56		)	(54		)
Accumulated Other Comprehensive Loss, SERP	10			6			—			—
Net Amount Recognized	$	66		$	68		$	(59	)	$	(60	)

Schedule of changes in funded status

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)	2019			2018			2019			2018
Change in Benefit Obligation
Beginning of Period	$	440		$	475		$	74		$	82
Actuarial (Gain) Loss	76			(42		)	4			(8		)
Interest Cost	18			16			3			2
Service Cost	13			15			4			5
Benefits Paid	(23		)	(23		)	(6		)	(5		)
Plan Amendments	1			(1		)	—			(2		)
End of Period	525			440			79			74
Change in Fair Value of Plan Assets
Beginning of Period	376			403			17			17
Actual Return on Plan Assets	81			(25		)	4			(1		)
Benefits Paid	(22		)	(23		)	(6		)	(5		)
Employer Contributions (1)	11			21			6			6
End of Period	446			376			21			17
Funded Status at End of Period	$	(79	)	$	(64	)	$	(58	)	$	(57	)

⁽¹⁾ 

TEP expects to contribute $11 million to the pension plans and $1 million to the VEBA trust in 2020.

Schedule of net periodic benefit cost not yet recognized

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)	2019		2018		2019			2018
Net (Gain) Loss	$	145	$	133	$	1		$	(1	)
Prior Service Cost (Benefit)	—		—		(2		)	(2		)

Schedule of information for the pension plans with accumulated benefit obligations in excess of pension plan

The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:

	December 31,
(in millions)	2019		2018
Accumulated Benefit Obligation	$	476	$	230
Fair Value of Plan Assets	446		202

Components of net periodic benefit plan cost

Net periodic benefit plan cost includes the following components:

	Pension Benefits									Other Postretirement Benefits
	Years Ended December 31,
(in millions)	2019			2018			2017			2019			2018			2017
Service Cost	$	13		$	15		$	13		$	4		$	5		$	4
Non-Service Cost
Interest Cost	18			16			15			3			2			2
Expected Return on Plan Assets	(26		)	(28		)	(25		)	(2		)	(1		)	(1		)
Amortization of Net (Gain) Loss	8			7			8			—			—			—
Net Periodic Benefit Cost	$	13		$	10		$	11		$	5		$	6		$	5

Schedule of the changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI

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)	2019			2018			2017			2019			2018			2017		2019		2018			2017
Current Year Actuarial (Gain) Loss	$	16		$	12		$	5		$	4		$	(1	)	$	3	$	1	$	(6	)	$	(1	)
Amortization of Net Loss	(8		)	(7		)	(7		)	(1		)	—			—		—		—			—
Prior Service Credit (Cost)	—			—			—			1			(1		)	—		—		(2		)	—
Total Recognized (Gain) Loss	$	8		$	5		$	(2	)	$	4		$	(2	)	$	3	$	1	$	(8	)	$	(1	)

Schedule of weighted average assumptions used to determine benefit obligations

The following table includes the weighted average assumptions used to determine benefit obligations:

	Pension Benefits		Other Postretirement Benefits
	2019	2018	2019	2018
Discount Rate	3.6%	4.5%	3.3%	4.3%
Rate of Compensation Increase	2.8%	2.8%	N/A	N/A

Schedule of weighted average assumptions used to determine net periodic benefit costs

The following table includes the weighted average assumptions used to determine net periodic benefit costs:

	Pension Benefits			Other Postretirement Benefits
	2019	2018	2017	2019	2018	2017
Discount Rate, Service Cost	4.7%	3.8%	4.4%	4.5%	3.8%	4.3%
Discount Rate, Interest Cost	4.2%	3.4%	3.7%	4.0%	3.2%	3.3%
Rate of Compensation Increase	2.8%	2.8%	2.8%	N/A	N/A	N/A
Expected Return on Plan Assets	7.0%	7.0%	7.0%	7.0%	7.0%	7.0%

Schedule of healthcare cost trend rates

Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:

	December 31,
	2019	2018
Next Year (Pre-65)	6.3%	6.5%
Next Year (Post-65)	7.5%	7.8%
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	2037

Schedule of asset allocations, by asset category, on the measurement date

Asset allocations, by asset category, on the measurement date were as follows:

	Pension				Other Postretirement Benefits
	2019		2018		2019		2018
Asset Category
Equity Securities	46	%	45	%	65	%	60	%
Fixed Income Securities	45	%	45	%	33	%	38	%
Real Estate	8	%	8	%	—	%	—	%
Other	1	%	2	%	2	%	2	%
Total	100	%	100	%	100	%	100	%

Schedule of fair value measurements of pension plan assets by level

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, 2019
Asset Category
Cash Equivalents	$	2	$	—	$	—	$	2
Equity Securities:
United States Large Cap	—		55		—		55
United States Small Cap	—		21		—		21
Non-United States	—		80		—		80
Global	—		51		—		51
Fixed Income	—		199		—		199
Real Estate	—		10		23		33
Private Equity	—		—		5		5
Total	$	2	$	416	$	28	$	446

	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

• 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.

Schedule of reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy

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, 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
Actual Return on Plan Assets:
Assets Held at Reporting Date	1			1		2
Purchases, Sales, and Settlements	(2		)	—		(2		)
Balance as of December 31, 2019	$	5		$	23	$	28

Schedule of target allocation percentages for the major asset categories of the plan

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, 2019
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%

Schedule of expected benefit payments

TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate.

(in millions)	2020		2021		2022		2023		2024		2025-2029
Pension Benefits	$	26	$	26	$	26	$	27	$	28	$	147
Other Postretirement Benefits	5		5		5		5		5		25

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common Stock, Shares Authorized (in shares)	75,000,000	75,000,000
Common Stock, Shares Outstanding (in shares)	32,139,434	32,139,434
Preferred Stock, Shares Authorized (in shares)	1,000,000	1,000,000
Preferred Stock, Shares Outstanding (in shares)	0	0

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate

Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to pre-tax income due to the following:

	Years Ended December 31,
(in millions)	2019			2018			2017
Federal Income Tax Expense at Statutory Rate	$	46		$	49		$	97
State Income Tax Expense, Net of Federal Deduction	9			9			9
Federal/State Tax Credits	(6		)	(10		)	(9		)
Allowance for Equity Funds Used During Construction	(3		)	(1		)	(2		)
Impact of Enactment, TCJA	—			—			7
Excess Deferred Income Taxes	(9		)	(6		)	—
Impact of AMT Sequestration	(2		)	2			—
Other	(1		)	—			(1		)
Total Federal and State Income Tax Expense	$	34		$	43		$	101

Schedule of income tax reconciliation

Income Tax Expense included on the Consolidated Statements of Income consists of the following:

	Years Ended December 31,
(in millions)	2019			2018			2017
Current Income Tax Expense
Federal	$	(8	)	$	(13	)	$	—
State	—			—			—
Total Current Income Tax Expense	(8		)	(13		)	—
Deferred Income Tax Expense
Federal	41			53			98
Federal Investment Tax Credits	(4		)	(6		)	(6		)
State	5			9			9
Total Deferred Income Tax Expense	42			56			101
Total Federal and State Income Tax Expense	$	34		$	43		$	101

Schedule of components of deferred income tax assets and liabilities

The significant components of deferred income tax assets and liabilities consist of the following:

	December 31,
(in millions)	2019			2018
Gross Deferred Income Tax Assets
Finance Lease Obligations	$	21		$	48
Operating Loss Carryforwards, Net	3			23
Customer Advances and Contributions in Aid of Construction	19			16
AMT Credit	7			13
Other Postretirement Benefits	15			15
Investment Tax Credit Carryforward	34			34
Income Taxes Recoverable Through Future Rates	81			87
Other	79			60
Total Gross Deferred Income Tax Assets	259			296
Deferred Tax Assets Valuation Allowance	—			—
Gross Deferred Income Tax Liabilities
Plant, Net	(602		)	(552		)
Plant Abandonments	(17		)	(18		)
Finance Lease Assets, Net	(18		)	(44		)
Pensions	(17		)	(19		)
Income Taxes Payable Through Future Rates	(9		)	(12		)
Other	(28		)	(21		)
Total Gross Deferred Income Tax Liabilities	(691		)	(666		)
Deferred Income Taxes, Net	$	(432	)	$	(370	)

TEP had the following carryforward amounts

As of December 31, 2019, TEP had the following carryforward amounts:

(in millions)	Amount		Expiring Year
Federal Net Operating Loss	$	17	2034 - 35
State Credits	9		2022 - 29
AMT Credit	7		None
Investment Tax Credits	34		2031 - 37

Summary of reconciliation of the beginning and ending balances of unrecognized tax benefits

A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:

	December 31,
(in millions)	2019		2018
Beginning of Period	$	16	$	13
Additions Based on Tax Positions Taken in the Current Year	2		3
End of Period	$	18	$	16

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ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts	$ (6,000)	$ (5,000)
Accounts Receivable, Net	154,847	172,367
Customer
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, before Allowance for Credit Loss	92,000	99,000
Customer | Derivatives
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, before Allowance for Credit Loss	5,000	8,000
Customer | Due from Affiliates
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, before Allowance for Credit Loss	8,000	8,000
Customer | Customer, Unbilled
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, before Allowance for Credit Loss	42,000	45,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, before Allowance for Credit Loss	$ 19,000	$ 25,000

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UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 MWh	Mar. 31, 2020 MWh rice	Dec. 31, 2019 USD ($) rice	Dec. 31, 2018 USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Public utilities, plant in service			$ 4,534,896	$ 4,160,640
Plant in Service			7,118,867	$ 6,528,069
Gila River Unit 2
Public Utility, Property, Plant and Equipment [Line Items]
Term of contract	20 years
Generating capacity (MW) | MWh	550
Option to purchase unit, term	3 years
Public utilities, plant in service			$ 165,000
RICE Units
Public Utility, Property, Plant and Equipment [Line Items]
Number of units in service | rice			5
Number of units | rice			10
Plant in Service			$ 82,000
RICE Units | Forecast
Public Utility, Property, Plant and Equipment [Line Items]
Generating capacity (MW) | MWh		188
Number of units | rice		5

XML

REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 465,000	$ 400,000
Regulatory Assets	138,412	106,725
Regulatory Assets	326,860	293,078
Pension and Other Postretirement Benefits
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 135,000	126,000
Derivatives
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	10 years
Total Regulatory Assets	$ 72,000	27,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 68,000	72,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	2 years
Total Regulatory Assets	$ 46,000	35,000
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 38,000	47,000
Under Recovered Purchased Energy Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 36,000	0
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 24,000	23,000
Remaining recovery period (in years)	6 months
Final Mine Reclamation and Retiree Healthcare Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	19 years
Total Regulatory Assets	$ 19,000	29,000
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	4 years
Total Regulatory Assets	$ 9,000	11,000
Useful life (in years)	10 years
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 18,000	$ 30,000

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COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Mar. 31, 2019 USD ($) MWh
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		$ 195,000
2021		149,000
2022		125,000
2023		107,000
2024		108,000
Thereafter		855,000
Total		1,539,000
Capital expenditures		607,593	$ 392,522	$ 345,617
New Mexico
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Nominal capacity wind-powered electric generation facility | MWh					250
Contractual obligation					$ 384,000
Capital expenditures		47,000
New Mexico | Subsequent Event
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Capital expenditures	$ 226,000
Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		94,000
2021		61,000
2022		40,000
2023		33,000
2024		33,000
Thereafter		194,000
Total		455,000
Purchased Power
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		8,000
2021		0
2022		0
2023		0
2024		0
Thereafter		0
Total		8,000
Transmission
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		21,000
2021		16,000
2022		14,000
2023		3,000
2024		3,000
Thereafter		6,000
Total		63,000
Renewable Power Purchase Agreements
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		63,000
2021		63,000
2022		63,000
2023		63,000
2024		62,000
Thereafter		543,000
Total		$ 857,000
Percentage of purchase power obligations (in percentage)		100.00%
RES Performance-Based Incentives
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		$ 8,000
2021		7,000
2022		7,000
2023		7,000
2024		7,000
Thereafter		33,000
Total		69,000
Land Easements and Rights-of-Way
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2020		1,000
2021		2,000
2022		1,000
2023		1,000
2024		3,000
Thereafter		79,000
Total		$ 87,000

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EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Details)	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	3.60%	4.50%
Rate of Compensation Increase (in percentage)	2.80%	2.80%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	3.30%	4.30%

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EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Plan Assets By Level) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Level 3
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 28	$ 28	$ 27
Level 3 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	23	22	21
Level 3 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	5	6	6
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	446	376	$ 403
Pension Benefits | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	2	1
Pension Benefits | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	55	45
Pension Benefits | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	21	17
Pension Benefits | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	80	67
Pension Benefits | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	51	42
Pension Benefits | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	199	167
Pension Benefits | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	33	31
Pension Benefits | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	5	6
Pension Benefits | Level 1
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	2	1
Pension Benefits | Level 1 | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	2	1
Pension Benefits | Level 1 | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 2
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	416	347
Pension Benefits | Level 2 | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 2 | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	55	45
Pension Benefits | Level 2 | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	21	17
Pension Benefits | Level 2 | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	80	67
Pension Benefits | Level 2 | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	51	42
Pension Benefits | Level 2 | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	199	167
Pension Benefits | Level 2 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	10	9
Pension Benefits | Level 2 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	28	28
Pension Benefits | Level 3 | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	23	22
Pension Benefits | Level 3 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 5	$ 6

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EMPLOYEE BENEFIT PLANS (Pension and Other Postretirement Benefit Amounts included in Consolidated Balance Sheet ) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	$ 465	$ 400
Regulatory Liabilities	(573)	(607)
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	135	126
Regulatory Liabilities	0	0
Accrued Employee Expenses	(2)	(1)
Pension and Other Postretirement Benefits	(77)	(63)
Accumulated Other Comprehensive Loss, SERP	10	6
Net Amount Recognized	66	68
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	0	0
Regulatory Liabilities	(1)	(3)
Accrued Employee Expenses	(2)	(3)
Pension and Other Postretirement Benefits	(56)	(54)
Accumulated Other Comprehensive Loss, SERP	0	0
Net Amount Recognized	$ (59)	$ (60)