tep-20200930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2020

☐ 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

Former name, former address and former fiscal year, if changed since last report: N/A

Securities registered pursuant to Section 12(b) of the Act: None

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 ☒ No ☐

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 ☒ No ☐

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 ☐ Accelerated Filer ☐ 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. ☐

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

All shares of outstanding common stock of Tucson Electric Power Company are held by its parent company, UNS Energy Corporation, which is an indirect, wholly-owned subsidiary of Fortis Inc. There were 32,139,434 shares of common stock, no par value, outstanding as of October 29, 2020.

Table of Contents


Definitions			iii
Forward-Looking Information			v
PART I

Item 1. Financial Statements
Condensed Consolidated Statements of Income			1
Condensed Consolidated Statements of Comprehensive Income			2
Condensed Consolidated Statements of Cash Flows			3
Condensed Consolidated Balance Sheets			4
Condensed Consolidated Statements of Changes in Stockholder's Equity			6
Notes to Condensed Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Critical Accounting Policies and Estimates			37
New Accounting Standards Issued and Not Yet Adopted			37
Item 3. Quantitative and Qualitative Disclosures about Market Risk			37
Item 4. Controls and Procedures			37

PART II

Item 1. Legal Proceedings			38
Item 1A. Risk Factors			38

Item 6. Exhibits			39
Signatures			40

DEFINITIONS

The abbreviations and acronyms used in this Form 10-Q are defined below:

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS



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 October 2022
2019 Credit Agreement						The 2019 Credit Agreement provided for $225 million in term loans. In April 2020, the term loans were repaid and the agreement terminated
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
2019 FERC Rate Case						In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings
2020 IRP						TEP's 2020 Integrated Resource Plan filed with the ACC in June 2020, which outlines TEP's energy portfolio over the next 15 years
ABR						Alternate Base Rate
ACC						Arizona Corporation Commission
ACC Refund Order						An order issued in 2018 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 customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018
ADEQ						Arizona Department of Environmental Quality
AFUDC						Allowance for Funds Used During Construction
ALJ						Administrative Law Judge
AMT						Alternative Minimum Tax

COVID-19						Coronavirus Disease 2019
DG						Distributed Generation
DSM						Demand Side Management
EDIT						Excess Deferred Income Taxes


FASB						Financial Accounting Standards Board
FERC						Federal Energy Regulatory Commission
GAAP						Generally Accepted Accounting Principles in the United States of America

LFCR						Lost Fixed Cost Recovery
LIBOR						London Interbank Offered Rate
LOC						Letter(s) of Credit
OATT						Open Access Transmission Tariff
PPA						Power Purchase Agreement
PPFAC						Purchased Power and Fuel Adjustment Clause
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

Summer Moratorium						Emergency rules first enacted by the ACC in 2019 that suspend service disconnections and late fees for electric residential customers who otherwise would be eligible for service disconnection during the period from June 1 through October 15
TCA						Transmission Cost Adjustor
TCJA						Tax Cuts and Jobs Act
TEAM						Tax Expense Adjustor Mechanism

iii

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
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
San Juan						San Juan Generating Station
SES						Southwest Energy Solutions, Inc.

Springerville						Springerville Generating Station
SRP						Salt River Project Agricultural Improvement and Power District
Sundt						H. Wilson Sundt Generating Station
TEP						Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation

UNS Electric						UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy						UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates						Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas						UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation

UNITS OF MEASURE


BBtu						Billion British thermal unit(s), a measure of the quantity of heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit at the temperature at which water has its greatest density, in billions
GWh						Gigawatt-hour(s), a measure of electricity that represents one billion watts of power expended over one hour
kWh						Kilowatt-hour(s), a measure of electricity that represents one thousand watts of power expended over one hour
MW						Megawatt(s), a measure of electricity that represents one million watts of power

Table of Contents

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q. 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 of our 2019 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors; Part I, Item 2. 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 final outcome of the FERC order effective August 2019, subject to refund, approving 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, including renewable generation resources; the development of our wind-powered electric generation facility in southeastern New Mexico; participation in the Energy Imbalance Market; the extent of the impact of the COVID-19 pandemic on our business and operations, and the economic and societal disruptions resulting from the COVID-19 pandemic; the impact of the TCJA on our financial condition and results of operations, including the assumptions we make relating thereto; and the implementation of our 2020 IRP.

Table of Contents

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating Revenues	$	471,672	$	441,171	$	1,089,933	$	1,100,265

Operating Expenses
Fuel	90,900		112,961		216,896		277,820
Purchased Power	71,562		37,049		118,713		97,244
Transmission and Other PPFAC Recoverable Costs	16,966		14,976		39,566		38,995
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(83)		(15,532)		5,113		(20,244)
Total Fuel and Purchased Power	179,345		149,454		380,288		393,815
Operations and Maintenance	88,504		94,154		259,991		272,787
Depreciation	47,462		42,187		141,084		124,931
Amortization	7,330		7,039		21,328		22,053
Taxes Other Than Income Taxes	14,571		14,054		44,123		42,375
Total Operating Expenses	337,212		306,888		846,814		855,961

Operating Income	134,460		134,283		243,119		244,304

Other Income (Expense)
Interest Expense	(23,159)		(22,132)		(66,212)		(66,407)
Allowance For Borrowed Funds	2,246		1,521		7,141		4,098
Allowance For Equity Funds	5,823		4,034		16,046		10,755
Unrealized Gains (Losses) on Investments	842		456		(2,309)		4,470
Other, Net	1,278		(551)		3,470		(434)
Total Other Income (Expense)	(12,970)		(16,672)		(41,864)		(47,518)

Income Before Income Tax Expense	121,490		117,611		201,255		196,786
Income Tax Expense	21,029		19,441		35,386		30,358
Net Income	$	100,461	$	98,170	$	165,869	$	166,428

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in thousands)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Comprehensive Income
Net Income	$	100,461	$	98,170	$	165,869	$	166,428
Other Comprehensive Income
Net Changes in Fair Value of Cash Flow Hedges:
Net of Income Tax Expense of $0 and $13	—		40
Net of Income Tax Expense of $0 and $30					—		92
Supplemental Executive Retirement Plan Adjustments:
Net of Income Tax Expense of $45 and $22	135		66
Net of Income Tax Expense of $134 and $66					405		198
Total Other Comprehensive Income, Net of Tax	135		106		405		290
Total Comprehensive Income	$	100,596	$	98,276	$	166,274	$	166,718

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)


	Nine Months Ended September 30,
	2020		2019
Cash Flows from Operating Activities
Net Income	$	165,869	$	166,428
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	141,084		124,931
Amortization Expense	21,328		22,053

Amortization of Debt Issuance Costs	2,010		1,735
Use of Renewable Energy Credits for Compliance	32,672		28,083
Deferred Income Taxes	38,809		37,168

Pension and Other Postretirement Benefits Expense	11,162		13,321
Pension and Other Postretirement Benefits Funding	(14,503)		(15,038)

Allowance for Equity Funds Used During Construction	(16,046)		(10,755)
Regulatory Deferral, ACC Refund Order	16,364		5,946



Changes in Current Assets and Current Liabilities:
Accounts Receivable	(57,208)		(28,547)
Materials, Supplies, and Fuel Inventory	(8,392)		(6,724)
Regulatory Assets	4,948		4,426

Other Current Assets	(5,100)		(961)
Accounts Payable and Accrued Charges	(939)		(13,832)

Income Taxes Receivable, Net	6,865		(6,987)
Regulatory Liabilities	8,944		(5,335)
Other, Net	7,260		715
Net Cash Flows—Operating Activities	355,127		316,627
Cash Flows from Investing Activities
Capital Expenditures	(597,375)		(322,142)



Purchase Intangibles, Renewable Energy Credits	(41,117)		(39,419)

Purchase, Other Investments	(8,500)		—
Contributions in Aid of Construction	2,816		4,520
Note Receivable	—		(1,000)
Net Cash Flows—Investing Activities	(644,176)		(358,041)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	105,000		—
Repayments of Borrowings, Revolving Credit Facility	(105,000)		—
Proceeds from Borrowings, Term Loan	60,000		—
Repayments of Borrowings, Term Loan	(225,000)		—
Proceeds from Issuance, Long-Term Debt—Net of Discount	645,768		—
Repayments of Long-Term Debt	(180,410)		—

Dividend Paid to Parent	(37,500)		(37,500)
Payments of Finance Lease Obligations	(17,086)		(10,889)

Contribution from Parent	200,000		—
Other, Net	(4,731)		67
Net Cash Flows—Financing Activities	441,041		(48,322)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	151,992		(89,736)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	28,472		152,747
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	180,464	$	63,011

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	September 30, 2020		December 31, 2019
ASSETS
Utility Plant
Plant in Service	$	6,944,251	$	6,663,912
Utility Plant Under Finance Leases	151,467		151,467
Construction Work in Progress	546,497		303,488
Total Utility Plant	7,642,215		7,118,867
Accumulated Depreciation and Amortization	(2,592,399)		(2,506,686)
Accumulated Amortization of Finance Lease Assets	(84,675)		(77,285)
Total Utility Plant, Net	4,965,141		4,534,896

Investments and Other Property	67,769		62,136

Current Assets
Cash and Cash Equivalents	163,009		9,762
Accounts Receivable (Net of Allowance for Credit Losses of $9,572 and $5,716)	211,488		154,847
Fuel Inventory	31,163		23,731
Materials and Supplies	122,502		121,542
Regulatory Assets	118,734		138,412
Derivative Instruments	13,763		3,596

Other	20,564		21,416
Total Current Assets	681,223		473,306
Regulatory and Other Assets
Regulatory Assets	308,973		326,860
Derivative Instruments	2,567		2,763
Other	92,046		89,196
Total Regulatory and Other Assets	403,586		418,819
Total Assets	$	6,117,719	$	5,489,157

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	September 30, 2020		December 31, 2019
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 September 30, 2020 and December 31, 2019)	$	1,596,539	$	1,396,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	724,161		595,792
Accumulated Other Comprehensive Loss	(7,366)		(7,771)
Total Common Stock Equity	2,306,977		1,978,203
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2020 and December 31, 2019)	—		—
Finance Lease Obligations	—		67,316
Long-Term Debt, Net	2,063,352		1,522,087
Total Capitalization	4,370,329		3,567,606
Current Liabilities
Current Maturities of Long-Term Debt, Net	—		80,330
Borrowings Under Credit Agreements, Net	—		165,000
Finance Lease Obligations	67,316		17,086
Accounts Payable	115,633		136,465
Accrued Taxes Other than Income Taxes	68,170		42,741
Accrued Employee Expenses	29,717		32,567
Accrued Interest	17,503		16,700
Regulatory Liabilities	107,458		96,017
Customer Deposits	18,303		24,568
Derivative Instruments	18,379		27,615
Other	19,287		23,678
Total Current Liabilities	461,766		662,767
Regulatory and Other Liabilities
Deferred Income Taxes, Net	489,409		432,484
Regulatory Liabilities	453,393		477,495
Pension and Other Postretirement Benefits	124,333		133,452
Derivative Instruments	39,589		48,697
Other	178,900		166,656
Total Regulatory and Other Liabilities	1,285,624		1,258,784

Commitments and Contingencies

Total Capitalization and Other Liabilities	$	6,117,719	$	5,489,157

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

(Concluded)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited)

(Amounts in thousands)


	Three Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of June 30, 2019	$	1,346,539	$	(6,357)	$	552,535	$	(4,530)	$	1,888,187
Net Income					98,170				98,170
Other Comprehensive Income, Net of Tax							106		106
Dividend Declared to Parent					(37,500)				(37,500)


Balances as of September 30, 2019	$	1,346,539	$	(6,357)	$	613,205	$	(4,424)	$	1,948,963


Balances as of June 30, 2020	$	1,596,539	$	(6,357)	$	661,200	$	(7,501)	$	2,243,881
Net Income					100,461				100,461
Other Comprehensive Income, Net of Tax							135		135
Dividend Declared to Parent					(37,500)				(37,500)


Balances as of September 30, 2020	$	1,596,539	$	(6,357)	$	724,161	$	(7,366)	$	2,306,977


	Nine Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2018	$	1,346,539	$	(6,357)	$	484,277	$	(4,714)	$	1,819,745
Net Income					166,428				166,428
Other Comprehensive Income, Net of Tax							290		290
Dividend Declared to Parent					(37,500)				(37,500)


Balances as of September 30, 2019	$	1,346,539	$	(6,357)	$	613,205	$	(4,424)	$	1,948,963


Balances as of December 31, 2019	$	1,396,539	$	(6,357)	$	595,792	$	(7,771)	$	1,978,203
Net Income					165,869				165,869
Other Comprehensive Income, Net of Tax							405		405
Dividend Declared to Parent					(37,500)				(37,500)
Contribution from Parent	200,000								200,000

Balances as of September 30, 2020	$	1,596,539	$	(6,357)	$	724,161	$	(7,366)	$	2,306,977

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

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 433,000 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 Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2019 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results.

Certain amounts from prior periods have been reclassified to conform to the current period presentation. Most notably, TEP bifurcated Other, Net on the Condensed Consolidated Statements of Income as follows:


	As Filed		Amount Reclassified		As Reclassified		As Filed		Amount Reclassified		As Reclassified
(in thousands)	Three Months Ended September 30, 2019						Nine Months Ended September 30, 2019
Other Income (Expense)
Other, Net	$	(95)	$	(456)	$	(551)	$	4,036	$	(4,470)	$	(434)
Unrealized Gains (Losses) on Investments	—		456		456		—		4,470		4,470

Variable Interest Entities

TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if 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 September 30, 2020, the carrying amounts of assets and liabilities on 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 TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 on the balance sheet and reconciles their sum to the cash flow statement:


	September 30,
(in millions)	2020		2019
Cash and Cash Equivalents	$	163	$	49
Restricted Cash included in:
Investments and Other Property	15		13
Current Assets—Other	2		1
Total Cash, Cash Equivalents, and Restricted Cash	$	180	$	63

Restricted cash included in Investments and Other Property on the Condensed 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.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2020. 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.

Credit Losses

TEP adopted accounting guidance that requires entities to incorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. See Note 4 for additional disclosure about TEP's allowance for credit losses.

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.

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 TEP'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%;

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•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 the Sundt RICE Units;

•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 concluded in June 2020. Parties to the rate case filed post-hearing briefs in July and August 2020. As a result of work schedule disruptions arising from the COVID-19 pandemic, the timing of when new rates will go into effect remains uncertain.

TEP cannot predict the 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 and further proceedings.

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 a more timely recovery of transmission related costs. As part of the order, the FERC established hearing and settlement procedures. All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. TEP had reserved $11 million as of September 30, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP cannot predict the outcome of the proceeding.

FEDERAL TAX LEGISLATION

Arizona Corporation Commission

In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved 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 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Beginning of Period	$	1	$	1	$	—	$	4
ACC Refund (Reduction in Operating Revenues)	(15)		(11)		(31)		(27)

Amount Returned to Customers through Bill Credits	6		7		14		17
Regulatory Deferral	7		3		16		6
End of Period	$	(1)	$	—	$	(1)	$	—

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 rate case. A regulatory liability balance related to the deferred TCJA customer refunds of $24 million as of September 30, 2020, and $8 million as of December 31, 2019, was recorded in Regulatory and Other Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. On October 1, 2020, TEP filed an informational filing with the ACC to establish a 2021 customer refund of $38 million.

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 typically adjusted annually on 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:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Beginning of Period	$	28	$	(9)	$	36	$	(17)
Deferred Fuel and Purchased Power Costs (1)	109		104		224		232
PPFAC and Base Power Recoveries (2)	(110)		(91)		(233)		(211)
End of Period	$	27	$	4	$	27	$	4

(1)Includes costs eligible for recovery through the PPFAC and base power rates.

(2)In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request, which went into effect on April 1, 2019. In March 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2020.

Renewable Energy Standard

The ACC’s RES requires Arizona-regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2020 is 10% of retail electric sales, which will increase annually until renewable retail sales represent at least 15% by 2025. DG will account 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 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million. The recovery funds: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards (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 both 2020 and 2019 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.

In 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, and approved a waiver of the 2018 EE Standard. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans. In June 2020, TEP filed its 2021 energy efficiency implementation plan with a budget of approximately $23 million. TEP cannot predict the outcome of the proceeding.

TEP filed a request with the ACC in April 2020 to refund to customers approximately $8 million of over-collected DSM funds as a result of the COVID-19 pandemic. In May 2020, the ACC approved the request and TEP returned the funds in the form of customer bill credits over the June 2020 billing cycle.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 amounts are verifiable regardless of when the lost retail kWh sales occurred. 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 Condensed Consolidated Statements of Income:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
LFCR Revenues	$	12	$	9	$	34	$	25

REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below:


($ in millions)	Remaining Recovery Period (years)	September 30, 2020		December 31, 2019
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	129	$	135
Early Generation Retirement Costs	Various	63		68
Lost Fixed Cost Recovery	2	57		46
Derivatives (Note 9)	9	48		72
Income Taxes Recoverable through Future Rates (1)	Various	28		38
Under Recovered Purchased Energy Costs	1	27		36
Property Tax Deferrals (2)	1	26		24
Final Mine Reclamation and Retiree Healthcare Costs (3)	8	23		19
Springerville Unit 1 Leasehold Improvements (4)	3	7		9
Other Regulatory Assets	Various	20		18
Total Regulatory Assets		428		465
Less Current Portion	1	119		138
Total Non-Current Regulatory Assets		$	309	$	327


Regulatory Liabilities
Income Taxes Payable through Future Rates (1)	Various	$	300	$	327
Net Cost of Removal (5)	Various	151		164
Renewable Energy Standard	Various	63		59
Deferred Investment Tax Credits (6)	Various	2		3

Other Regulatory Liabilities	Various	44		20
Total Regulatory Liabilities		560		573
Less Current Portion	1	107		96
Total Non-Current Regulatory Liabilities		$	453	$	477

(1)Amortized over the lives of the assets.

(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.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(3)Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. 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 be funded by TEP through 2028.

(4)Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe and 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.

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, 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.

PLANT IN SERVICE

Under an air permit approved by the Pima County Department of Environmental Quality, TEP placed in service five natural gas RICE units at Sundt in December 2019 and an additional five units in March 2020. There was $186 million as of September 30, 2020, and $82 million as of December 31, 2019, related to the Sundt RICE Units recorded in Plant in Service on the Condensed Consolidated Balance Sheets. The 10 units have a total nominal generation capacity of 188 MW.

NOTE 3. REVENUE

DISAGGREGATION OF REVENUES

TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Retail	$	361	$	333	$	818	$	771
Wholesale (1)	61		60		127		187
Other Services	24		30		71		84
Revenues from Contracts with Customers	446		423		1,016		1,042
Alternative Revenues	12		9		36		27
Other	14		9		38		31
Total Operating Revenues	$	472	$	441	$	1,090	$	1,100

(1)In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. 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 2019 FERC Rate Case.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 4. ACCOUNTS RECEIVABLE

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


(in millions)	September 30, 2020		December 31, 2019
Retail	$	114	$	61
Retail, Unbilled	57		42
Retail, Allowance for Credit Losses	(10)		(6)
Wholesale (1)	30		31
Due from Affiliates (Note 5)	7		8
Other	13		19
Accounts Receivable	$	211	$	155

(1)Includes $7 million as of September 30, 2020, and $5 million as of December 31, 2019, of receivables related to revenue from derivative instruments.

ALLOWANCE FOR CREDIT LOSSES

TEP records an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. Based on these factors, TEP has not recorded an allowance for credit losses on non-retail trade receivables as of September 30, 2020 and December 31, 2019.

The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets:


	Three Months Ended		Nine Months Ended
(in millions)	September 30, 2020
Beginning of Period	$	(7)	$	(6)
Credit Loss Expense	(3)		(5)
Write-offs	—		1

End of Period	$	(10)	$	(10)

Service Disconnection Moratoriums

In 2019, the ACC enacted emergency rules that suspended service disconnections and late fees for electric residential customers who would have otherwise been eligible for service disconnection during the period from June 1 through October 15 (Summer Moratorium). The Summer Moratorium remained in effect for 2020 and will remain in effect until the ACC permanently adopts new rules regarding electric service disconnections. In addition, TEP voluntarily suspended service disconnections and late fees for all customers who would have otherwise been eligible for service disconnection to help customers affected by the COVID-19 pandemic beginning March 2020 through December 31, 2020.

As a result of the moratoriums, TEP has increased its bad debt reserve by $3 million as of September 30, 2020, compared to December 31, 2019. TEP will continue to monitor collection activity and adjust the bad debt reserve as needed.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and 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 and Accounts Payable on the Condensed Consolidated Balance Sheets:


(in millions)	September 30, 2020		December 31, 2019
Receivables from Related Parties
UNS Electric	$	5	$	6

UNS Gas	2		2








Total Due from Related Parties	$	7	$	8

Payables to Related Parties
SES	$	3	$	2
UNS Energy	2		1
UNS Electric	—		1




Total Due to Related Parties	$	5	$	4

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)	$	3	$	2	$	7	$	5
Wholesale Revenues, UNS Electric (1)	1		—		1		—
Control Area Services, UNS Electric (2)	1		1		3		3
Common Costs, UNS Energy Affiliates (3)	5		4		14		14


Goods and Services Provided by Affiliates to TEP

Supplemental Workforce, SES (4)	3		4		10		11
Corporate Services, UNS Energy (5)	1		1		4		4
Corporate Services, UNS Energy Affiliates (6)	1		1		3		3

(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)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.

(5)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 $1 million and $4 million for the three and nine months ended September 30, 2020 and 2019, respectively.

(6)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.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 6. DEBT AND CREDIT AGREEMENTS

There have been no significant changes to TEP's debt or credit agreements from those reported in its 2019 Annual Report on Form 10-K, except as noted below.

DEBT

Issuances and Redemptions

In April 2020, TEP issued and sold $350 million aggregate principal amount of 4.00% senior unsecured notes due June 2050. TEP may call the debt prior to December 15, 2049, with a make-whole premium plus accrued interest. After December 15, 2049, TEP may call the debt at par plus accrued interest. TEP used the net proceeds from the sale to repay amounts outstanding under its credit agreements and for general corporate purposes.

In August 2020, TEP issued and sold $300 million aggregate principal amount of 1.50% senior unsecured notes due August 2030. TEP may call the debt prior to May 1, 2030, with a make-whole premium plus accrued interest. After May 1, 2030, TEP may call the debt at par plus accrued interest. An amount equal to the net proceeds was allocated to the total costs of Oso Grande.

In September 2020, TEP deposited with the trustee money sufficient to pay the interest and principal due on: (i) $80 million of fixed rate tax-exempt bonds prior to the maturity date on October 1, 2020; and (ii) $100 million of fixed rate tax-exempt bonds that were callable for redemption at par on or after October 1, 2020. As of September 30, 2020, TEP's obligations with respect to both series of bonds were extinguished.

CREDIT AGREEMENTS

2019 Credit Agreement

The following table presents components of TEP's unsecured 2019 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:


	Capacity		Borrowed		Available		Weighted Average Interest Rate		Pricing
(in millions)	September 30, 2020
Term Loan	$	225	$	225	$	—	—	%	LIBOR + 0.550%	or ABR + 0.00%

In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the outstanding term loans and terminate such agreement.

2015 Credit Agreement

The following table presents components of TEP's unsecured 2015 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:


	Capacity		Sub-Limit LOC		Borrowed (1)		Available		Weighted Average Interest Rate		Pricing (2)
(in millions)	September 30, 2020
Revolver and LOC	$	250	$	50	$	12	$	238	—	%	LIBOR + 1.000%	or ABR + 0.00%

(1)Includes $12 million in LOCs issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement.

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

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments from those reported in its 2019 Annual Report on Form 10-K.

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.

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 of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts 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 customers 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.

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 final mine reclamation costs at both mines is $55 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 $39 million as of September 30, 2020, and $36 million as of December 31, 2019, was recorded in Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.

Performance Guarantees

TEP has joint participation agreements with participants at 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 September 30, 2020, there have been no such payment defaults under any of the participation agreements. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046.

The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generating station. Relative to the Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party.

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 customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 parcels adjacent to these landfills. In November 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 8. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2020		2019		2020		2019
Service Cost	$	4	$	3	$	1	$	1
Non-Service Cost (1)
Interest Cost	4		5		—		1
Expected Return on Plan Assets	(7)		(6)		—		(1)
Amortization of Net Loss	2		2		—		—
Net Periodic Benefit Cost	$	3	$	4	$	1	$	1


	Pension Benefits				Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Service Cost	$	12	$	9	$	3	$	3
Non-Service Cost (1)
Interest Cost	12		14		1		2
Expected Return on Plan Assets	(22)		(19)		(1)		(1)
Amortization of Net Loss	6		6		—		—
Net Periodic Benefit Cost	$	8	$	10	$	3	$	4

(1)The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

NOTE 9. 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. TEP has no financial instruments categorized as Level 3.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value 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		Total
(in millions)	September 30, 2020
Assets

Restricted Cash (1)	$	17	$	—	$	17
Energy Derivative Contracts, Regulatory Recovery (2)	—		12		12
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	17		16		33
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(57)		(57)
Energy Derivative Contracts, No Regulatory Recovery (2)	—		(1)		(1)
Total Liabilities	—		(58)		(58)
Total Assets (Liabilities), Net	$	17	$	(42)	$	(25)


(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)

(1)Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.

(2)Energy Derivative Contracts include gas swap agreements and forward purchased power and sales contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis on 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)	September 30, 2020
Derivative Assets
Energy Derivative Contracts	$	16	$	12	$	—	$	4
Derivative Liabilities
Energy Derivative Contracts	(58)		(12)		(3)		(43)

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)


(in millions)	December 31, 2019
Derivative Assets
Energy Derivative Contracts	$	6	$	4	$	—	$	2
Derivative Liabilities
Energy Derivative Contracts	(76)		(4)		(2)		(70)

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.

TEP 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. TEP 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.

Energy Derivative Contracts, Regulatory Recovery

TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Unrealized Net Gain (Loss)	$	13	$	1	$	28	$	(19)

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 Condensed Consolidated Statements of Income:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Operating Revenues	$	—	$	—	$	5	$	5

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivative Volumes

As of September 30, 2020, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:


	September 30, 2020	December 31, 2019
Power Contracts GWh	5,119	4,740
Gas Contracts BBtu	104,030	122,779

Level 3 Fair Value Measurements

As of September 30, 2020, TEP did not have any Level 3 asset or liability balances. 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:


	Three Months Ended		Nine Months Ended
(in millions)	September 30, 2019
Beginning of Period	$	(4)	$	1
Gains (Losses) Recorded
Regulatory Assets or Liabilities, Derivative Instruments	6		(4)
Operating Revenues	—		5
Settlements	2		2
End of Period	$	4	$	4

Gains (Losses), Assets (Liabilities) Still Held	$	7	$	4

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 due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in counterparties' assessment of TEP's credit strength. In the event that such credit events were to occur, TEP, 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 $56 million as of September 30, 2020, compared with $100 million as of December 31, 2019. As of September 30, 2020, TEP had $3 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets—Other on the Condensed Consolidated Balance Sheets. As of October 29, 2020, there was $7 million of cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on September 30, 2020, TEP would have been required to post an additional $54 million of collateral of which $15 million relates to outstanding net payable balances for settled positions.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

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. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they 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:


	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		September 30, 2020		December 31, 2019		September 30, 2020		December 31, 2019
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,063	$	1,602	$	2,366	$	1,755

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

•outlook and strategies;

•factors affecting 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.

Management’s Discussion and Analysis should be read in conjunction with the financial statements and accompanying notes that appear in Part I, Item 1 of this Form 10-Q. 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 Risk Factors in Part 1, Item 1A of our 2019 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.

References in this discussion and analysis to "we" and "our" are to TEP.

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 our transition 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. In June 2020, we filed our 2020 IRP with the ACC. The 2020 IRP provides details on our long-term proposed strategy to eliminate the use of coal-fired generation over the next 12 years as part of our goal to reduce carbon emissions 80% compared to levels in 2005 by 2035. This resource strategy may be impacted by various federal and state energy policies, including policies currently under consideration.

•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.

CURRENT ECONOMIC CONDITIONS—COVID-19

In March 2020, the World Health Organization declared COVID-19 a pandemic. As a result, Arizona's governor and many local governments have issued various requirements and recommendations in response to the COVID-19 pandemic, and further actions may continue to be taken. This pandemic has caused changes in consumer and business behavior and disrupted economic activity in TEP’s service territory. These disruptions could continue for a prolonged period of time or become more severe. We activated our business continuity plans and continue to reevaluate and reassess protocols and plans as the pandemic conditions evolve. These actions are intended to aid in the prevention of the spread of COVID-19 among our employees and customers, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Actions we have taken include: (i) implemented work from home practices for a portion of our workforce; (ii) increased precautions with regard to employee and facility hygiene for field crews and others who must continue working on premises, including elimination of in-person meetings and separation of field crews; (iii) imposed travel limitations on employees; (iv) implemented screening procedures conducted prior to entering our facilities; (v) distributed face masks to our workforce; and

Table of Contents

(vi) restricted access to critical facilities. Additional safety protocols have been implemented for work required within customers' premises that are intended to aid in the protection of our employees, our customers, and the community.

Recognizing the potential effect that the COVID-19 pandemic could have on many customers’ ability to pay their bills and the need for continued utility service, we voluntarily suspended service disconnections and late fees for non-payment of bills until December 31, 2020. In addition, the ACC approved our request to refund customers approximately $8 million of over-collected DSM funds in excess of program expenditures. Funds were returned to customers in the form of bill credits over the June 2020 billing cycle. We are also working with our suppliers, vendors, and contractors to assess and mitigate potential impacts to the procurement of goods and services.

The COVID-19 pandemic is a continuously evolving situation. We cannot predict the duration of the pandemic or the ultimate effects of it on the global, national, or local economy. We will continue to monitor developments affecting our workforce, customers, suppliers, and operations and take additional measures as we believe are warranted. Through the first nine months of 2020, we have not experienced a material impact to our results of operations as a result of the COVID-19 pandemic.

Performance - The third quarter of 2020 compared with the third quarter of 2019

TEP reported net income of $100 million in the third quarter of 2020 compared with net income of $98 million in the third quarter of 2019. The increase of $2 million, or 2%, was primarily due to:

•$6 million in higher retail revenue primarily due to an increase in usage related to favorable weather;

•$2 million in higher LFCR revenues; and

•$2 million in higher AFUDC due to an increase in construction projects.

The increase was partially offset by:

•$5 million in higher depreciation and amortization expense due to an increase in asset base;

•$3 million in higher interest expense primarily related to long-term debt issuances in 2020; and

•$1 million in higher income tax expense primarily due to AMT credits recognized in 2019 not recurring in 2020.

Performance - The first nine months of 2020 compared with the first nine months of 2019

TEP reported net income of $166 million in the first nine months of 2020 compared with net income of $166 million in the first nine months of 2019. The net change included a slight decrease in net income primarily due to:

•$13 million in higher depreciation and amortization expense due to an increase in asset base;

•$7 million in higher interest expense primarily related to long-term debt issuances in 2020;

•$7 million decrease in value of investments used to support certain post-employment benefits as a result of unfavorable market conditions; and

•$3 million in higher income tax expense primarily due to AMT credits recognized in 2019 not recurring in 2020.

The decrease was partially offset by:

•$16 million in higher retail revenue primarily due to an increase in usage related to favorable weather;

•$7 million in higher LFCR revenues; and

•$7 million in higher AFUDC due to FERC Order to adjust the AFUDC calculation and an increase in construction projects.

Table of Contents

FACTORS AFFECTING RESULTS OF OPERATIONS

Several factors affect our current and future results of operations. The most significant factors are related to the potential economic impacts of the COVID-19 pandemic, regulatory matters, generation resource shift, and weather patterns.

COVID-19 Pandemic Impacts

The extent of the impact of the COVID-19 pandemic on our operational and financial performance depends on certain developments, including: (i) the duration of the declared health emergencies; (ii) actions being taken by governmental authorities and regulators; (iii) the impact on our customers, employees, and vendors; and (iv) actions being taken by us to assist our customers through this crisis. These developments are continuously evolving and are challenging to predict. Areas that we currently anticipate as likely to be materially impacted and that may have an effect on our results of operations, cash flows, and earnings are noted below.

Retail Sales

As a result of various Executive Orders issued in 2020 by Arizona's governor and changes in consumer and business behavior in response to the COVID-19 pandemic, energy usage by our commercial and industrial customers has decreased below average levels experienced in prior periods. This decrease is expected to last for the duration of the pandemic response and may continue beyond as a result of sustained economic impacts in our service territory. However, energy usage by our residential customers has increased due to stay at home orders and widespread adoption of work from home practices. We expect the increase to last for the duration of the pandemic response and possibly beyond as companies rethink their work from home practices. In the first nine months of 2020, we have not experienced a significant impact to total retail sales as a result of the COVID-19 pandemic.

Electricity sold to retail customers by class of customer in the first nine months of the last three years were as follows:


	Nine Months Ended September 30,
(sales in GWh)	2020			2019			2018
Electric Sales
Residential	3,356	47	%	2,986	43	%	3,074	44	%
Commercial	1,556	22	%	1,620	24	%	1,683	24	%
Industrial, non-Mining	1,409	20	%	1,456	21	%	1,500	21	%
Industrial, Mining	829	11	%	807	12	%	762	11	%
Other	12	—	%	12	—	%	12	—	%
Total Retail Sales by Customer Class	7,162	100	%	6,881	100	%	7,031	100	%

Timing of Regulatory Decisions

Proceedings for our pending ACC rate case have been delayed as regulators and stakeholders experience work schedule disruptions related to the COVID-19 pandemic. Further rate case delays may occur due to continued work schedule disruptions.

Return on Investments

We experienced a decrease in the value of investments used to support certain post-employment benefits during the first nine months of 2020 as a result of unfavorable market conditions arising from the COVID-19 pandemic. The value of investments used to support certain post-employment benefits may continue to fluctuate due to volatility in equity and fixed-income markets.

Retail Customer Assistance

We voluntarily suspended service disconnections and late fees for all customers who would have otherwise been eligible for service disconnection to help customers affected by the COVID-19 pandemic beginning March 2020 through December 31, 2020. During the third quarter of 2020, we experienced an increase in accounts receivable balances greater than 90 days as a result of COVID-19-related suspension of service disconnections and the Summer Moratorium. As a result of the moratoriums, we increased our bad debt reserve by $3 million as of September 30, 2020 compared to December 31, 2019. We are continuing to monitor collection activity and will adjust our bad debt reserve as needed.

Table of Contents

Reduction to DSM Surcharge

In April 2020, we filed a request with the ACC to refund to customers approximately $8 million of over-collected DSM funds. In May 2020, the ACC approved the request and we returned the funds in the form of customer bill credits over the June 2020 billing cycle.

Regulatory Matters

TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2019 Annual Report on Form 10-K and new regulatory matters occurring in 2020.

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 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 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.

We cannot predict the 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 and further proceedings.

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 a more timely recovery of transmission-related costs. If this request is approved, transmission revenues would increase by approximately $7 million annually. As part of the order, the FERC established hearing and settlement procedures. All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. We had reserved $11 million as of September 30, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. We cannot predict the outcome of the proceeding.

Table of Contents

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 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. In October 2019, TEP filed an informational filing with the ACC to establish a 2020 customer refund of $35 million. The refund is being 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. On October 1, 2020, TEP filed an informational filing with the ACC to establish a 2021 customer refund of $38 million.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 and Liquidity and Capital Resources, Income Tax Position of this Form 10-Q for additional information regarding the ACC Refund Order and the TCJA.

Arizona Energy Policy

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy and energy efficiency goals, integrated resource planning, and retail competition for generation services. In 2019 and 2020, ACC staff and two commissioners prepared different drafts of retail electric competition rules. The ACC discussed those draft rules during workshops, but such rules have not been officially proposed and no changes have been made.

In July 2020, ACC staff issued a proposed order that would adopt new energy rules. The new rules, if adopted, would require affected utilities to, among other things, implement plans designed to supply: (i) 50% of their retail electric sales with renewable energy by 2035; and (ii) 100% of their retail electric sales with clean energy by 2050. The proposed rules would also allow utilities to request cost recovery of compliance in rate proceedings. During various meetings in 2020, the ACC discussed the rules proposed by ACC staff as well as various amendments to those rules filed by commissioners. 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 their impact on the Company's financial position or results of operations.

Generation Resource Shift

Our long-term strategy is to continue our shift from carbon-intensive sources to a more sustainable energy portfolio including expanding renewable energy resources while reducing reliance on coal-fired generation resources. In June 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.

2020 IRP

Our 2020 IRP proposal includes a goal of reducing our carbon dioxide emissions 80% compared to levels in 2005 by 2035. To achieve this goal, we will continue the retirement of older fossil-fuel resources and replace these assets with a combination of renewable resources, energy storage, and energy efficiency programs. The 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, we are considering options that include the exit of all ownership interests in coal plants over the next 12 years. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions. The execution of our IRP proposal is dependent on obtaining regulatory recovery approval.

As of September 30, 2020, approximately 37% of our generation capacity was from coal-fired generation.

See Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding generation facility operations.

Table of Contents

Navajo Generating Station

TEP and the co-owners of Navajo retired the generation station in November 2019 and began decommissioning activities. We expect 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, we requested recovery of final retirement costs over a 10-year period in the 2019 ACC Rate Case. As of September 30, 2020, the net book value of Navajo was $39 million, with estimated other related costs of $4 million.

Sundt Generating Station

In 2018, the Pima County Department of Environmental Quality approved TEP's air permit, which allowed the Company to place in service 10 natural gas RICE units at Sundt and required the retirement of Sundt Units 1 and 2 in November 2019. We are 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, we requested recovery of final retirement costs over a 10-year period in the 2019 ACC Rate Case. As of September 30, 2020, the net book value of Sundt Units 1 and 2 was $23 million, with estimated other related costs of $1 million.

The Company placed in service five of the RICE units in December 2019, and the remaining five were placed in service in March 2020. The Sundt RICE Units balance the variability of intermittent renewable energy resources. The units replaced 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 Sundt RICE Units. We requested recovery of the 10 Sundt RICE Units over the useful lives of the assets in the 2019 ACC Rate Case. The total cost of the Sundt RICE Units project was $186 million.

Gila River Generating Station

In 2017, we entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three-year option to purchase the unit. The Company completed the purchase of Gila River Unit 2 in December 2019 for $165 million. The 550 MW of capacity, power, and ancillary services replaced coal-fired generation lost due to early retirements. We requested recovery of the Gila River Unit 2 purchase over the remaining useful life of the asset in the 2019 ACC Rate Case.

Executive Order

On May 1, 2020, the President of the United States of America signed an Executive Order, Securing the United States Bulk-Power System. We are currently evaluating the potential impacts of this Executive Order. The Department of Energy issued a request for information seeking to understand current industry practices surrounding supply chain components of the bulk-power system. In August 2020, we participated in industry comments facilitated by the Edison Electric Institute.

On September 17, 2020, the FERC issued a Notice of Inquiry (NOI) requesting comments on the potential risks to the bulk-power system posed by equipment and services provided by certain entities. We are currently evaluating the potential impacts of this NOI.

Production Tax Credits

Federal renewable electricity Production Tax Credits (PTC) are earned as energy from qualifying wind-powered facilities is generated based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law. Qualifying generating facilities are eligible for the credit for 10 years from the date the facilities are placed in service. The PTC rate is published annually by the IRS and was $0.025 per kWh generated for 2020. The Company will begin earning PTCs once Oso Grande begins generating power to serve our customers. In 2021, Oso Grande is expected to generate approximately $25 million in PTCs, which are anticipated to offset the operating and interest expenses of Oso Grande.

Electricity generated from Oso Grande depends heavily on weather conditions. If such conditions are unfavorable or below our estimates, the project’s electricity generation and associated PTCs may be substantially different than forecasted.

Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. The Company'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.

Table of Contents

Interest Rates

See Part II, Item 7A in our 2019 Annual Report on Form 10-K and Part I, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.

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, Renewable Energy Standard Tariff, and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q 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 Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.

The following discussion provides the significant items that affected TEP's results of operations in the third quarter and first nine months of 2020 compared with the same periods in 2019 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:


	Three Months Ended September 30,				Increase (Decrease)		Nine Months Ended September 30,				Increase (Decrease)
(in millions)	2020		2019		Percent		2020		2019		Percent
Operating Revenues
Retail	$	361	$	333	8.4	%	$	818	$	771	6.1	%
Wholesale, Long-Term	12		11		9.1	%	26		27		(3.7)	%
Wholesale, Short-Term (1)	44		46		(4.3)	%	98		153		(35.9)	%
Transmission	8		7		14.3	%	21		23		(8.7)	%
Springerville Units 3 and 4 Participant Billings	20		26		(23.1)	%	58		72		(19.4)	%
Other	27		18		50.0	%	69		54		27.8	%
Total Operating Revenues	$	472	$	441	7.0	%	$	1,090	$	1,100	(0.9)	%

(1)Revenues associated with derivatives are primarily returned to retail customers by offsetting the fuel and purchase power costs eligible for recovery through the PPFAC mechanism similar to short-term wholesale sales. As a result, revenues associated with derivatives are included in Wholesale, Short-Term in the table above.

TEP reported Operating Revenues of $472 million in the third quarter of 2020 compared with $441 million in the same period for 2019. The increase of $31 million, or 7%, was primarily due to:

•$19 million in higher retail revenue primarily due to higher fuel and purchase power recoveries due to changes in the PPFAC rate;

•$7 million in higher retail revenue primarily due to favorable weather;

•$5 million in higher other revenue due to a new contract entered into in 2020 which sells excess natural gas pipeline capacity back to the market; and

•$3 million in higher other revenue due to an increase in LFCR revenue.

The increase was partially offset by $7 million in lower participant billings related to Springerville Units 3 and 4.

Table of Contents

TEP reported Operating Revenues of $1,090 million in the first nine months of 2020 compared with $1,100 million in the same period for 2019. The decrease of $10 million, or 1%, was primarily due to:

•$54 million in lower wholesale short-term sales primarily due to a decrease in volumes driven by the expiration of a capacity sale contract in December 2019; and

•$14 million in lower participant billings related to Springerville Units 3 and 4.

The decrease was partially offset by:

•$22 million in higher retail revenue primarily due to higher fuel and purchase power recoveries due to increased volumes;

•$18 million in higher retail revenue primarily due to favorable weather;

•$9 million in higher other revenue due to an increase in LFCR revenue; and

•$7 million in higher retail revenue due to higher RES and DSM cost recoveries as a result of higher program expenses.

The following table provides key statistics impacting Operating Revenues:


	Three Months Ended September 30,		Increase (Decrease)		Nine Months Ended September 30,		Increase (Decrease)
(kWh in millions)	2020	2019	Percent		2020	2019	Percent
Electric Sales (kWh) (1)
Retail Sales	3,064	2,940	4.2	%	7,162	6,881	4.1	%
Wholesale, Long-Term	225	173	30.1	%	373	382	(2.4)	%
Wholesale, Short-Term	1,199	1,915	(37.4)	%	3,547	5,568	(36.3)	%
Total Electric Sales	4,488	5,028	(10.7)	%	11,082	12,831	(13.6)	%

Average Revenue Per kWh (2)
Retail	11.78	11.31	4.2	%	11.42	11.20	2.0	%
Wholesale, Long-Term	5.65	6.11	(7.5)	%	7.08	6.90	2.6	%
Wholesale, Short-Term	4.01	2.77	44.8	%	2.75	2.86	(3.8)	%

Total Retail Customers (3)					432,727	427,888	1.1	%

(1)These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.

(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.

(3)This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining), industrial (non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.

Table of Contents

Operating Expenses

Fuel and Purchased Power Expense

TEP reported Fuel and Purchased Power expense of $179 million in the third quarter of 2020 compared with $149 million in the same period for 2019. The increase of $30 million, or 20%, was primarily due to:

•$35 million in higher purchased power primarily due to an increase in price and volume; and

•$15 million in higher PPFAC recoveries primarily due to changes in the PPFAC rate.

The increase was partially offset by $21 million in lower fuel costs primarily due to a decrease in Coal and Gas-Fired Generation volumes and a decrease in realized losses on gas swaps.

TEP reported Fuel and Purchased Power expense of $380 million in the first nine months of 2020 compared with $394 million in the same period for 2019. The decrease of $14 million, or 4%, was primarily due to $61 million in lower fuel costs primarily due to decreases in: (i) Coal and Gas-Fired Generation volumes; (ii) realized losses on natural gas swaps; and (iii) natural gas prices.

The decrease was partially offset by:

•$25 million in higher PPFAC recoveries due to: (i) an increase in the PPFAC rate; and (ii) a decrease in PPFAC eligible costs; and

•$22 million in higher purchased power primarily due to an increase in price; offset by the purchase of Gila River Unit 2.

The following provides key statistics impacting Fuel and Purchased Power:


	Three Months Ended September 30,		Increase (Decrease)		Nine Months Ended September 30,		Increase (Decrease)
(kWh in millions)	2020	2019	Percent		2020	2019	Percent
Sources of Energy
Coal-Fired Generation	1,646	1,956	(15.8)	%	4,181	5,328	(21.5)	%
Gas-Fired Generation	2,366	2,698	(12.3)	%	5,685	6,379	(10.9)	%
Utility-Owned Renewable Generation	21	19	10.5	%	66	58	13.8	%
Total Generation	4,033	4,673	(13.7)	%	9,932	11,765	(15.6)	%
Purchased Power, Non-Renewable	557	450	23.8	%	1,136	1,124	1.1	%
Purchased Power, Renewable	165	152	8.6	%	533	502	6.2	%
Total Generation and Purchased Power (1)	4,755	5,275	(9.9)	%	11,601	13,391	(13.4)	%


(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal	2.43	2.63	(7.6)	%	2.49	2.41	3.3	%
Natural Gas (3)	2.10	2.25	(6.7)	%	1.93	2.29	(15.7)	%
Average Cost of Purchased Power (4)
Purchased Power, Non-Renewable	9.99	5.16	93.6	%	6.41	4.24	51.2	%
Purchased Power, Renewable	9.55	9.68	(1.3)	%	9.46	9.48	(0.2)	%

(1)This number represents the kWh generated from TEP's generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.

(2)This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation stations.

Table of Contents

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

(4)This metric represents the fuel cost as cents per kWh for renewable and non-renewable purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh) for each respective form of purchased power. Management uses this metric to compare and monitor the costs of renewable and non-renewable purchased power.

Operations and Maintenance Expense

Operations and Maintenance Expense decreased by $6 million, or 6%, and $13 million, or 5%, in the third quarter and first nine months of 2020, respectively, when compared with the same periods in 2019. The decreases were primarily due to lower reimbursable maintenance expense related to Springerville Unit 3 planned outages in 2019 not recurring in 2020.

Depreciation and Amortization Expense

Depreciation and Amortization expense increased by $6 million, or 11%, and $15 million, or 10%, in the third quarter and first nine months of 2020, respectively, when compared with the same periods in 2019 primarily due to an increase in asset base.

Other Income (Expense)

TEP reported other expense of $13 million in the third quarter of 2020 compared with $17 million in the same period for 2019. The decrease of $4 million, or 24%, was primarily due to:

•$3 million in lower finance lease interest expense related to PPFAC recoverable demand charges due to the purchase of Gila River Unit 2 in December 2019;

•$3 million in higher AFUDC due to an increase in construction projects; and

•$1 million increase in other income due to an increase in expected return on pension plan assets.

The decrease was partially offset by $4 million in higher interest expense primarily related to long-term debt issuances in 2020.

TEP reported other expense of $42 million in the first nine months of 2020 compared with $48 million in the same period for 2019. The decrease of $6 million, or 13%, was primarily due to:

•$9 million in lower finance lease interest expense related to PPFAC recoverable demand charges due to the purchase of Gila River Unit 2 in December 2019;

•$8 million in higher AFUDC due to an increase in construction projects and a FERC Order to adjust the AFUDC calculation; and

•$4 million increase in other income due to an increase in expected return on pension plan assets.

The decrease was partially offset by:

•$9 million in higher interest expense primarily related to long-term debt issuances in 2020; and

•$7 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions.

Income Tax Expense

TEP reported Income Tax Expense of $21 million in the third quarter of 2020 compared with $19 million in the same period for 2019. The increase of $2 million, or 11%, was primarily due to lower investment tax credit amortization recognized in 2020.

TEP reported Income Tax Expense of $35 million in the first nine months of 2020 compared with $30 million in the same period for 2019. The increase of $5 million, or 17%, was primarily due to lower tax credits related to investment tax credit amortization and AMT credits recognized in 2019 not recurring in 2020.

Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

The COVID-19 pandemic has negatively impacted the global economy and created significant volatility and disruption of financial markets. An extended period of economic disruption could negatively affect our business and financial condition, and access to sources of liquidity. In addition, cash flows may vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to TEP's summer peaking load. We use our revolving credit facility as needed to fund our business activities. We believe that we have sufficient liquidity under our revolving credit facility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depends on a variety of factors, including our credit ratings and conditions in the bank and capital markets.

Available Liquidity


(in millions)	September 30, 2020
Cash and Cash Equivalents	$	163
Amount Available under Revolving Credit Agreement (1)	238
Total Liquidity	$	401

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

Future Liquidity Requirements

We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to: (i) dividend payments; (ii) debt maturities; and (iii) obligations included in the Contractual Obligations and forecasted Capital Expenditures tables reported in our 2019 Annual Report on Form 10-K and the material changes summarized below in the respective sections.

Summary of Cash Flows

The table below presents net cash provided by (used for) operating, investing and financing activities:


	Nine Months Ended September 30,				Increase (Decrease)
(in millions)	2020		2019		Percent
Operating Activities	$	355	$	317	12.0	%
Investing Activities	(644)		(358)		79.9	%
Financing Activities	441		(48)		*
Net Increase (Decrease)	152		(89)		270.8	%
Beginning of Period	28		153		(81.7)	%
End of Period (1)	$	180	$	64	181.3	%

* Not meaningful

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

Operating Activities

In the first nine months of 2020, net cash flows from operating activities increased by $38 million compared with the same period in 2019. The increase was primarily due to: (i) higher customer usage related to favorable weather; (ii) fuel and purchase power recoveries as a result of changes in the PPFAC rate; and (iii) AMT credit refunds received. The increase was partially offset by: (i) higher interest paid as a result of 2020 debt issuances; and (ii) changes in working capital related to higher sales and the timing of billing collections.

Investing Activities

In the first nine months of 2020, net cash flows used for investing activities increased by $286 million compared with the same period in 2019 primarily due to: (i) higher capital expenditures primarily due to $258 million in payments for the Oso Grande project under the Build-Transfer Agreement (BTA); and (ii) an $8 million payment for other investments.

Table of Contents

Financing Activities

In the first nine months of 2020, net cash flows from financing activities increased by $489 million compared with the same period in 2019 primarily due to: (i) higher proceeds related to the issuance of senior unsecured notes in April 2020 and August 2020, net of debt repayments; and (ii) an increase in equity contributions from UNS Energy.

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 September 30, 2020, 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. In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the 2019 Credit Agreement's outstanding term loan and terminate such agreement.

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 September 30, 2020, there was $238 million available under the 2015 Credit Agreement.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2019 Annual Report on Form 10-K for additional information regarding TEP's 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 February 2020, TEP filed a financing application with the ACC. The application requests extending and expanding the existing financing authority by: (i) extending authority from December 2020 to December 2025; (ii) increasing the outstanding long-term debt limitation from $2.2 billion to $2.9 billion; (iii) allowing parent equity contributions of up to $700 million; and (iv) continuing the interest rate hedging authority.

In April 2020, we issued and sold $350 million aggregate principal amount of senior unsecured notes to repay: (i) $225 million of outstanding borrowings under our 2019 Credit Agreement, which we terminated; and (ii) outstanding borrowings under our 2015 Credit Agreement and for general corporate purposes.

TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, we may refinance other debt issuances or make additional debt repurchases in the future.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2020, 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 depend 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.

Table of Contents

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 September 30, 2020, TEP was in compliance with these covenants.

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

Contribution from Parent

TEP received no equity contributions from UNS Energy in the third quarter of 2020 and received equity contributions of $200 million in the first nine months of 2020. TEP received no equity contributions in the third quarter or first nine months of 2019.

Dividends Paid to Parent

TEP declared and paid a $38 million dividend to UNS Energy in the third quarter and first nine months of 2020 and 2019.

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 based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of September 30, 2020, TEP had $3 million of cash posted as collateral to provide credit enhancement with its counterparties related to our wholesale marketing or risk management activities. As of October 29, 2020, there was $7 million of cash posted as collateral to provide credit enhancement.

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. TEP is prioritizing capital projects to mitigate supply chain risk and other potential impacts of the COVID-19 pandemic and ensure we continue providing safe and reliable service while supporting public health. As a result, we have reduced forecasted capital expenditures for 2020 due to prioritizing certain projects and postponing others. Capital expenditures for the first nine months of 2020 were $597 million.

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


	Years Ended December 31,
(in millions)	2020		2021		2022		2023		2024
Generation Facilities:
Renewable Energy (1)	$	366	$	30	$	4	$	97	$	226
Other Generation Facilities (2)	185		57		49		51		37
Total Generation Facilities	551		87		53		148		263
Transmission and Distribution (3)	218		301		371		353		268
General and Other (4)	115		118		57		55		49
Total Capital Expenditures	$	884	$	506	$	481	$	556	$	580

(1)Includes investment 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 the first nine months of 2020, TEP made total payments of $258 million for Oso Grande under the Build-Transfer Agreement.

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

(3)Increases due to investments in transmission capacity and system reinforcements.

(4)Includes cost for information technology, fleet, facilities, and communication equipment.

Table of Contents

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, 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.

Oso Grande Wind Project

In 2019, we entered into a BTA to develop Oso Grande by December 2020. The Oso Grande project will add approximately 250 MW of wind-powered electric generation, increasing our total renewable nominal generation capacity to over 500 MW, which includes PPAs and owned utility-scale generation. The project is estimated to cost $430 million, which includes, among other costs, $22 million for AFUDC and $397 million related to the BTA. As of September 30, 2020, total costs of construction incurred from inception was $331 million, which includes, among other costs, $16 million for AFUDC and $304 million related to the BTA. The project costs are currently included in Construction Work in Progress on the Condensed Consolidated Balance Sheets.

Contractual Obligations

In the first nine months of 2020, there were no material changes outside the ordinary course of business to contractual obligations as reported in our 2019 Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2019 Annual Report on Form 10-K, 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 in the first nine months of 2020 due to existing net operating loss and tax credit carryforwards in those jurisdictions. Based on our remaining carryforward balances and limitations on their use in individual years, we expect to resume making U.S. federal and state income tax payments in 2021. The payments are not expected to have a significant impact on our operating cash flows.

Under the TCJA, existing AMT credit carryforwards could be refunded or used to offset U.S. federal income tax liabilities through our 2021 tax year. In response to the COVID-19 pandemic, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was signed into law March 27, 2020. Along with other significant provisions, the CARES Act further accelerated the recovery of AMT credits by allowing corporations to immediately claim refunds of all unused carryforward balances. For the first nine months of 2020 TEP received AMT credit refunds of $14 million recorded to Current Assets—Other on the Condensed Consolidated Balance Sheets.

See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the TCJA.

Payroll Tax

The CARES Act also allows employers to defer the deposit and payment of the employer's share of social security taxes. TEP is deferring the deposit of the employer's portion of social security tax through the end of 2020. We recorded deferred deposits of $5 million as of September 30, 2020, in Accrued Taxes Other than Income Taxes on the Condensed Consolidated Balance Sheets. We expect the total deferred deposits to be approximately $7 million, and be paid to the IRS in equal payments in 2021 and 2022.

Environmental Matters

The Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (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. TEP will request recovery from its customers of the costs of environmental compliance

Table of Contents

through cost recovery mechanisms and Retail Rates. See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the Broadway-Pantano site.

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 toward the national visibility goal. In July 2019, the ADEQ notified TEP that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluation.

TEP conducted the potential emissions controls evaluation, commonly referred to as the four factor analysis, for both facilities. These evaluations were submitted to the ADEQ in March 2020 for the agency's use in developing the revised SIP. TEP will continue to work with the agency to determine compliance strategies as needed, however, TEP cannot predict the outcome of these matters at this time.

The ADEQ must submit the revised SIP to the EPA for approval by July 2021. Based on current Regional Haze requirement time-frames, TEP anticipates that compliance strategies, if any, will likely be required to be implemented three to five years after the 2021 SIP submittal date.

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 established state-level CO2 emission rates and mass-based goals that applied to fossil fuel-based generation. The plan targeted CO2 emissions reductions for existing facilities by 2030 and established interim goals that begin in 2022.

In June 2019, the EPA issued the Affordable Clean Energy (ACE) rule, establishing new emission guidelines for existing coal-fired generation facilities based on the Best System of Emission Reduction (BSER) for Greenhouse Gas (GHG) emissions. The BSER for GHG emissions from existing coal-fired generation facilities is defined as Heat-Rate Improvements (HRI) 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.

The ADEQ began the stakeholder process in November 2019 and notified subject facilities that HRI analysis would be due to the agency by December 2020. We are in the process of conducting the HRI analysis for Springerville Units 1 and 2, and therefore cannot predict the outcome of these matters at this time.

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. TEP will continue to work with other Arizona utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed.

Legal challenges to the rule are expected to delay the effectiveness and implementation of the new rule. Oral arguments in consolidated litigation over the ACE rule were held on October 8, 2020. A final decision from the U.S. Court of Appeals for the D.C. Circuit is not expected before the first quarter of 2021.

Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring disposal of coal ash and other Coal Combustion Residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) for disposal in landfills and/or surface impoundments. Our share of costs to comply with the CCR rule at Four Corners is estimated to be $3 million. This includes estimated costs for corrective action for two CCR units at the facility, which will be incurred over 30 years. Arizona Public Service began an assessment of corrective measures in 2019, and expects the assessment to continue through late 2020.

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

Table of Contents

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. On February 20, 2020, the EPA proposed a federal CCR permitting program. The comment period for this rulemaking closed on July 20, 2020. TEP does not anticipate a material impact on operations or financial results from the proposed rule revisions.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to apply accounting policies and make estimates, judgments, 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 there have been no significant changes during the nine months ended September 30, 2020, to the items that we disclosed as our critical accounting policies and estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We can enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.

The COVID-19 pandemic has had a negative impact on the global economy and financial markets. There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2019 Annual Report on Form 10-K, other than as described below.

Credit Risk

In response to the COVID-19 pandemic, we have increased our monitoring of the effects of the economic slowdown on counterparties’ abilities to perform under their contractual obligations.

ITEM 4. 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 September 30, 2020. There was no change in TEP’s internal control over financial reporting during the quarter ended September 30, 2020, that materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

Table of Contents

PART II

ITEM 1. LEGAL PROCEEDINGS

For a description of certain legal proceedings affecting TEP, refer to Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2019 Annual Report on Form 10-K, except the additional risk factor noted below, which is an update to the risk factor included in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020:

The widespread outbreak of an illness or any other communicable disease, or any other public health crisis, including the COVID-19 pandemic, could adversely affect our business, results of operations and financial condition.

TEP could be negatively impacted by the widespread outbreak of an illness or any other communicable disease, or any other public health crisis that results in economic and trade disruptions, including the disruption of global supply chains. The COVID-19 pandemic has negatively impacted the economy on a global, national, and local level, disrupted global supply chains, and created significant volatility and disruption of financial markets. Responses from governmental authorities and companies to reduce the spread of the COVID-19 pandemic have significantly reduced economic activity through various containment measures including, among others, business closures, work stoppages or work-from-home orders, shuttering of public spaces and events, and/or severe restrictions of global and regional travel.

The extent of the impact of the COVID-19 pandemic on TEP’s operational and financial performance, including the ability to execute business strategies and initiatives in the expected time frame, the ability to obtain external financing, and the timing of regulatory actions, will depend on factors beyond our control, including the duration, spread, and severity of the pandemic, and how quickly and to what extent normal economic and operating conditions resume, all of which are uncertain and cannot be predicted at this time. An extended period of global supply chain and economic disruption could materially affect TEP’s business, results of operations, access to sources of liquidity, and financial condition.

Table of Contents

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.

Description

31(a)

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by David G. Hutchens

31(b)

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, 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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in Inline XBRL and contained in Exhibit 101


*			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.

SIGNATURES

Pursuant to the requirements 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:	October 29, 2020	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President and Chief Financial Officer
		(Principal Financial Officer)