Tucson Electric Power 10-Q 2022 Q1 Quarterly report

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 March 31, 2022

OR

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

For the transition period from                     to                     .

Commission File Number 1-5924

TUCSON ELECTRIC POWER COMPANY

(Exact name of registrant as specified in its charter)

Arizona	86-0062700
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

88 East Broadway Boulevard, Tucson, AZ 85701

(Address of principal executive offices)(Zip Code)

Registrant's telephone number, including area code: (520) 571-4000

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 May 3, 2022.

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 Cash Flows	2
Condensed Consolidated Balance Sheets	3
Condensed Consolidated Statements of Changes in Stockholder's Equity	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Critical Accounting Estimates	31
New Accounting Standards Issued and Not Yet Adopted	32
Item 3. Quantitative and Qualitative Disclosures about Market Risk	33
Item 4. Controls and Procedures	33
PART II
Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 6. Exhibits	35
Signatures	36

ii

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

2019 FERC Rate Order	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 which calls for TEP to reduce its carbon emissions by 80% and to supply more than 70% of its energy to retail customers from renewable resources by 2035
2020 Rate Order	A rate order issued by the ACC resulting in a new rate structure for TEP, effective on January 1, 2021
2021 Credit Agreement	The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026
ACC	Arizona Corporation Commission
ADEQ	Arizona Department of Environmental Quality
AFUDC	Allowance for Funds Used During Construction
COVID-19	Coronavirus Disease 2019
DG	Distributed Generation
DSM	Demand Side Management
EDIT	Excess Deferred Income Taxes
EE Standards	Energy Efficiency Standards
EIM	Energy Imbalance Market
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles in the United States of America
IRS	Internal Revenue Service
LFCR	Lost Fixed Cost Recovery
LOC	Letter(s) of Credit
OATT	Open Access Transmission Tariff
Phase 2	The 2020 Rate Order established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities
PPA	Power Purchase Agreement
PPFAC	Purchased Power and Fuel Adjustment Clause
PTC	Production Tax Credit
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
TCA	Transmission Cost Adjustor
TEAM	Tax Expense Adjustor Mechanism

ENTITIES AND GENERATING STATIONS

APS	Arizona Public Service Company
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
Navajo	Navajo Generating Station
Oso Grande	A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico

iii

San Juan	San Juan Generating Station
Springerville	Springerville Generating Station
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	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

iv

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 such 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 2021 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Form 10-Q; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q; 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 the adoption of new regulations regarding electric service disconnections; any change in the structure of utility service in Arizona resulting from: (i) the ACC or state legislature's examination of the state's energy policies; and (ii) applications by other companies to the ACC requesting a certificate of public convenience and necessity to provide competitive electric generation service to customers in our service territory; 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 Phase 2 of the 2020 Rate Order; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality and extreme weather events affecting electricity usage of our customers and the performance of our operations; 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 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, including inflationary effects; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting estimates; the ongoing impact of mandated energy efficiency and DG initiatives; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal from our suppliers; cyber-attacks, data breaches, or other cyberspace attacks to our information security and our operations and technology infrastructure, including attacks that may rise from heightened geopolitical instability; the performance of generation facilities, including renewable generation resources; participation in the EIM; 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 and government actions taken in response thereto; and the implementation of our 2020 IRP.

v

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
		2022		2021
Operating Revenues		$	336,726	$	335,543
Operating Expenses
Fuel		82,964		91,158
Purchased Power		30,544		31,377
Transmission and Other PPFAC Recoverable Costs		16,835		13,901
Decrease to Reflect PPFAC Recovery Treatment		(11,881)		(16,992)
Total Fuel and Purchased Power		118,462		119,444
Operations and Maintenance		97,233		111,188
Depreciation		53,598		47,758
Amortization		9,918		10,631
Taxes Other Than Income Taxes		16,699		15,557
Total Operating Expenses		295,910		304,578
Operating Income		40,816		30,965
Other Income (Expense)
Interest Expense		(21,490)		(21,062)
Allowance For Borrowed Funds		610		2,702
Allowance For Equity Funds		1,671		7,094
Unrealized Gains (Losses) on Investments		(2,784)		1,864
Other, Net		2,986		2,808
Total Other Income (Expense)		(19,007)		(6,594)
Income Before Income Tax Expense		21,809		24,371
Income Tax Expense		2,389		1,827
Net Income		$	19,420	$	22,544

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

1

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
	2022		2021
Cash Flows from Operating Activities
Net Income	$	19,420	$	22,544
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	53,598		47,758
Amortization Expense	9,918		10,631
Amortization of Debt Issuance Costs	722		686
Use of Renewable Energy Credits for Compliance	11,908		12,217
Deferred Income Taxes	1,988		6,793
Pension and Other Postretirement Benefits Expense	2,912		3,835
Pension and Other Postretirement Benefits Funding	(1,924)		(1,324)
Allowance for Equity Funds Used During Construction	(1,671)		(7,094)
Changes in Current Assets and Current Liabilities:
Accounts Receivable	25,842		15,155
Materials, Supplies, and Fuel Inventory	1,305		(17,185)
Regulatory Assets	(10,252)		(21,034)
Other Current Assets	743		(5,812)
Accounts Payable and Accrued Charges	6,734		19,372
Income Taxes Receivable	(282)		(4,147)
Regulatory Liabilities	593		(7,588)
Other, Net	(1,918)		3,208
Net Cash Flows—Operating Activities	119,636		78,015
Cash Flows from Investing Activities
Capital Expenditures	(107,734)		(104,381)
Purchase Intangibles, Renewable Energy Credits	(12,702)		(11,408)
Contributions in Aid of Construction	3,857		1,449
Net Cash Flows—Investing Activities	(116,579)		(114,340)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	5,000		20,000
Repayments of Borrowings, Revolving Credit Facility	(20,000)		(20,000)
Proceeds from Issuance, Long-Term Debt—Net of Discount	323,804		—
Repayments of Long-Term Debt	(177,000)		—
Payment of Debt Issuance Costs	(2,419)		—
Other	3,415		374
Net Cash Flows—Financing Activities	132,800		374
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	135,857		(35,951)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	33,489		82,003
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	169,346	$	46,052

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

2

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	March 31, 2022		December 31, 2021
ASSETS
Utility Plant
Plant in Service	$	7,872,796	$	7,797,935
Construction Work in Progress	271,141		320,931
Total Utility Plant	8,143,937		8,118,866
Accumulated Depreciation and Amortization	(2,791,123)		(2,786,839)
Total Utility Plant, Net	5,352,814		5,332,027
Investments and Other Property	77,790		81,958
Current Assets
Cash and Cash Equivalents	146,464		9,970
Accounts Receivable (Net of Allowance for Credit Losses of $9,433 and $10,044)	166,653		192,579
Fuel Inventory	28,313		26,971
Materials and Supplies	141,601		141,677
Regulatory Assets	125,935		116,442
Derivative Instruments	58,198		19,406
Other	20,914		24,229
Total Current Assets	688,078		531,274
Regulatory and Other Assets
Regulatory Assets	266,955		267,669
Derivative Instruments	61,794		14,392
Other	100,514		94,420
Total Regulatory and Other Assets	429,263		376,481
Total Assets	$	6,547,945	$	6,321,740

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

(Continued)

3

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)

	March 31, 2022		December 31, 2021
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 March 31, 2022 and December 31, 2021)	$	1,696,539	$	1,696,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	870,362		850,942
Accumulated Other Comprehensive Loss	(9,718)		(9,915)
Total Common Stock Equity	2,550,826		2,531,209
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2022 and December 31, 2021)	—		—
Long-Term Debt, Net	2,280,056		2,134,534
Total Capitalization	4,830,882		4,665,743
Current Liabilities
Borrowings Under Credit Agreement	—		15,000
Accounts Payable	125,937		139,329
Accrued Taxes Other than Income Taxes	69,547		53,534
Accrued Employee Expenses	26,341		36,217
Accrued Interest	17,148		16,265
Regulatory Liabilities	151,709		111,356
Customer Deposits	13,648		12,791
Derivative Instruments	10,373		15,854
Other	32,576		25,358
Total Current Liabilities	447,279		425,704
Regulatory and Other Liabilities
Deferred Income Taxes, Net	551,311		548,750
Regulatory Liabilities	383,527		352,226
Pension and Other Postretirement Benefits	119,415		120,020
Derivative Instruments	1,052		3,848
Other	214,479		205,449
Total Regulatory and Other Liabilities	1,269,784		1,230,293
Commitments and Contingencies	0		0
Total Capitalization and Other Liabilities	$	6,547,945	$	6,321,740

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

(Concluded)

4

TUCSON ELECTRIC POWER COMPANY

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

(Amounts in thousands)

	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2020	$	1,646,539	$	(6,357)	$	712,197	$	(10,942)	$	2,341,437
Net Income					22,544				22,544
Other Comprehensive Income, Net of Tax							219		219
Balances as of March 31, 2021	$	1,646,539	$	(6,357)	$	734,741	$	(10,723)	$	2,364,200

Balances as of December 31, 2021	$	1,696,539	$	(6,357)	$	850,942	$	(9,915)	$	2,531,209
Net Income					19,420				19,420
Other Comprehensive Income, Net of Tax							197		197
Balances as of March 31, 2022	$	1,696,539	$	(6,357)	$	870,362	$	(9,718)	$	2,550,826

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

5

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 441,000 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 SEC's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP 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 2021 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.

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 March 31, 2022, 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.

6

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:

	March 31,
(in millions)	2022		2021
Cash and Cash Equivalents	$	146	$	26
Restricted Cash included in:
Investments and Other Property	19		18
Current Assets—Other	4		2
Total Cash, Cash Equivalents, and Restricted Cash	$	169	$	46

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.

Income Tax Expense

TEP realized PTC benefits of $2 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three months ended March 31, 2022, as a result of Oso Grande being placed in service in May 2021.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

New authoritative accounting guidance issued by the Financial Accounting Standards Board 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 the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

RATE CASE MATTERS

2020 Rate Order

In 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.

Provisions of the 2020 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $58 million over test year retail revenues;

•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%; and

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

In addition, the 2020 Rate Order established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. On January 19, 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. TEP cannot predict the timing or outcome of these proceedings.

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

2019 FERC Rate Order

In 2019, TEP filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more timely recovery of transmission-related costs. The FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.

Provisions of the settlement agreement include, but are not limited to:

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

•a 9.79% 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.

Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. Amounts deferred as a regulatory liability in excess of the rates approved in the settlement agreement will be returned to customers. TEP had $17 million as of March 31, 2022, and $15 million as of December 31, 2021, of wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets.

OTHER FERC MATTERS

In January 2021, the FERC notified TEP that it was commencing an audit that intends to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covers the period of January 1, 2018 to the present. The audit is ongoing and TEP cannot predict the outcome or findings, if any, of the FERC audit at this time.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are 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 allows for reconciliation of differences between actual costs and those recovered in the preceding period. On April 13, 2022, the ACC approved a rate adjustment for the PPFAC, which became effective on April 29, 2022. The rate adjustment sets the true-up component of the PPFAC rate to recover the existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which may result in future under-collection of PPFAC costs.

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

	Three Months Ended March 31,
(in millions)		2022		2021
Beginning of Period		$	91	$	23
Deferred Fuel and Purchased Power Costs (1)		65		67
PPFAC and Base Power Recoveries (2)		(54)		(50)
End of Period		$	102	$	40

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

(2)In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021.

Tax Expense Adjustor Mechanism

The TEAM allows for the timely recovery of future significant income tax changes and provides the Company the ability to pass through as a kWh surcharge: (i) the change in EDIT compared to the test year; and (ii) the income tax effects of tax

8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

legislation that materially impacts TEP's 2018 test year revenue requirements. The TEAM went into effect January 1, 2021, as approved in the 2020 Rate Order.

Transmission Cost Adjustor

The TCA went into effect January 1, 2021, as approved in the 2020 Rate Order. The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January of each year.

In February 2022, the ACC approved TEP's motion to modify the TCA plan of administration to reflect the terms of the 2019 FERC Rate Order settlement agreement.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2022 is 12% of retail electric sales. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES surcharge.

In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal by July 1, 2022, to phase out the RES tariff. TEP expects to file a general rate application with the ACC in June 2022, which will include a proposal to transition away from the current RES and DSM surcharges and to recover those costs in a different manner.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year.

In 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of $23 million, which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standards. 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 2021, TEP filed its 2022 energy efficiency implementation plan with a budget of $23 million. In March 2022, TEP filed an application with the ACC requesting the 2022 energy efficiency implementation plan be considered as its 2023 energy efficiency implementation plan. TEP cannot predict the outcome of the proceeding.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. 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.

9

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below:

($ in millions)	Remaining Recovery Period (years)	March 31, 2022		December 31, 2021
Regulatory Assets
Pension and Other Postretirement Benefits	Various	$	127	$	128
Under Recovered Purchased Energy Costs	2	102		91
Early Generation Retirement Costs	Various	38		38
Lost Fixed Cost Recovery	1	35		37
Property Tax Deferrals (1)	1	28		27
Final Mine Reclamation and Retiree Healthcare Costs (2)	7	17		17
Income Taxes Recoverable through Future Rates (3)	Various	16		17
Derivatives (Note 9)	8	8		8
Unamortized Loss on Reacquired Debt	Various	6		5
Springerville Unit 1 Leasehold Improvements (4)	2	4		4
Other Regulatory Assets	Various	12		12
Total Regulatory Assets		393		384
Less Current Portion	1	126		116
Total Non-Current Regulatory Assets		$	267	$	268

Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	265	$	268
Derivatives (Note 9)	8	108		19
Renewable Energy Standard	Various	66		66
Net Cost of Removal (5)	Various	58		73
Transmission Revenue Subject to Refund—FERC	1	17		15
Demand Side Management	1	13		12
Transmission Cost Adjustor	1	7		9
Other Regulatory Liabilities	Various	2		1
Total Regulatory Liabilities		536		463
Less Current Portion	1	152		111
Total Non-Current Regulatory Liabilities		$	384	$	352

(1)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.

(2)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. Final mine reclamation costs are expected to be funded by TEP through 2028.

(3)Amortized over five years, 10 years, or the lives of the assets.

(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, 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, and general and intangible plant which are not yet expended. As a result of the 2020 Rate Order, TEP transferred costs from Net Cost of Removal to Accumulated Depreciation and Amortization.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, 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. TEP pays a return on the majority of its regulatory liability balances.

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 March 31,
(in millions)		2022		2021
Retail		$	218	$	215
Wholesale (1)		56		56
Other Services		24		36
Revenues from Contracts with Customers		298		307
Alternative Revenues		11		8
Other		28		21
Total Operating Revenues		$	337	$	336

(1)Pursuant to a FERC order, all rates charged under TEP's revised OATT were subject to refund until the 2019 FERC Rate Order proceedings concluded. Wholesale Revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Order.

NOTE 4. ACCOUNTS RECEIVABLE

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

(in millions)	March 31, 2022		December 31, 2021
Retail	$	67	$	78
Retail, Unbilled	34		44
Retail, Allowance for Credit Losses	(9)		(10)
Wholesale (1)	33		47
Due from Affiliates (Note 5)	24		17
Other	18		17
Accounts Receivable	$	167	$	193

(1)Includes $13 million as of March 31, 2022, and $16 million as of December 31, 2021, of receivables related to revenue from derivative instruments.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

ALLOWANCE FOR CREDIT LOSSES

TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. 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 March 31,
(in millions)	2022		2021
Beginning of Period	$	(10)	$	(13)
Credit Loss Expense	—		(1)
Write-offs	1		1
End of Period (1)	$	(9)	$	(13)

(1)In 2021, the ACC adopted rules that suspended service disconnections and late fees for electric residential customers who otherwise are eligible for service disconnection during the period from June 1 through October 15.

TEP continuously monitors collection activity and adjusts its allowance for credit losses as needed.

Customer Payment Assistance

In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $7 million in DES payment assistance funds in the first three months of 2022.

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)	March 31, 2022		December 31, 2021
Receivables from Related Parties
UNS Energy	$	14	$	7
UNS Electric	8		8
UNS Gas	2		2
Total Due from Related Parties	$	24	$	17
Payables to Related Parties
UNS Energy	$	3	$	1
UNS Electric	1		—
UNS Gas	—		1
Total Due to Related Parties	$	4	$	2

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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

	Three Months Ended March 31,
(in millions)		2022		2021
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric (1)		$	2	$	3
Wholesale Revenues, UNS Electric (1)		1		1
Control Area Services, UNS Electric (2)		1		2
Common Costs, UNS Energy Affiliates (3)		5		5
Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (4)		3		2
Corporate Services, UNS Energy Affiliates (5)		—		1

(1)TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable OATT.

(2)TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement.

(3)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.

(4)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 85% of UNS Energy's allocated costs. The Corporate Services, UNS Energy line includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million for the three months ended March 31, 2022 and 2021.

(5)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.

NOTE 6. DEBT AND CREDIT AGREEMENTS

There have been no significant changes to TEP's debt or credit agreements from those reported in its 2021 Annual Report on Form 10-K, except as noted below.

DEBT

Issuance and Redemption

In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt and for general corporate purposes.

In March 2022, TEP redeemed at par $177 million aggregate principal amount of 4.50% tax-exempt bonds, prior to maturity.

CREDIT AGREEMENT

2021 Credit Agreement

As of March 31, 2022, there was $240 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings and a $10 million LOC issued with fees accruing at a rate of 1.00% per annum.

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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 2021 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 to retail customers final mine reclamation costs, as a component of fuel costs. 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 funded.

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 $44 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 $40 million as of March 31, 2022 and December 31, 2021, was recorded in Other on the Condensed Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. See Note 1 and Note 2 for additional information related to final mine reclamation costs.

Performance Guarantees

TEP has joint generation participation agreements with participants at San Juan, Four Corners, and Luna Generating Station, which expire in 2022, 2041, and 2046, respectively. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generation facility. 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. Relative to Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party. 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 by the non-defaulting parties is $250 million at Four Corners. As of March 31, 2022, there have been no such payment defaults under any of the participation agreements.

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.

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

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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 March 31,
(in millions)	2022		2021		2022		2021
Service Cost	$	5	$	5	$	1	$	2
Non-Service Cost (1)
Interest Cost	4		3		—		—
Expected Return on Plan Assets	(9)		(8)		—		—
Amortization of Net Loss	2		2		—		—
Net Periodic Benefit Cost	$	2	$	2	$	1	$	2

(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.

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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)	March 31, 2022
Assets
Cash Equivalents (1)	$	50	$	—	$	50
Restricted Cash (1)	23		—		23
Energy Derivative Contracts, Regulatory Recovery (2)	—		110		110
Energy Derivative Contracts, No Regulatory Recovery (2)	—		10		10
Total Assets	73		120		193
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(11)		(11)
Total Liabilities	—		(11)		(11)
Total Assets (Liabilities), Net	$	73	$	109	$	182

(in millions)	December 31, 2021
Assets
Restricted Cash (1)	$	23	$	—	$	23
Energy Derivative Contracts, Regulatory Recovery (2)	—		30		30
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	23		34		57
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(20)		(20)
Total Liabilities	—		(20)		(20)
Total Assets (Liabilities), Net	$	23	$	14	$	37

(1)Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. 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 power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis 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)	March 31, 2022
Derivative Assets
Energy Derivative Contracts	$	120	$	9	$	—	$	111
Derivative Liabilities
Energy Derivative Contracts	(11)		(9)		—		(2)

(in millions)	December 31, 2021
Derivative Assets
Energy Derivative Contracts	$	34	$	14	$	—	$	20
Derivative Liabilities
Energy Derivative Contracts	(20)		(14)		—		(6)

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 TEP'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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Energy Derivative Contracts, Regulatory Recovery

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

	Three Months Ended March 31,
(in millions)		2022		2021
Unrealized Net Gain (Loss) (1)		$	89	$	(4)

(1)Increase in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas.

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 March 31,
(in millions)		2022		2021
Operating Revenues		$	8	$	1

Derivative Volumes

As of March 31, 2022, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

	March 31, 2022	December 31, 2021
Power Contracts GWh	5,358	2,617
Gas Contracts BBtu	111,261	112,316

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 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 parties' assessments of each other'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 $15 million as of March 31, 2022, compared with $26 million as of December 31, 2021. As of March 31, 2022, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on March 31, 2022, TEP would have been required to post $15 million of collateral. As of March 31, 2022, TEP had $20 million in outstanding net payable balances for settled positions.

18

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)		March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,280	$	2,135	$	2,283	$	2,357

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

NON-CASH TRANSACTIONS

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

	Three Months Ended March 31,
(in millions)	2022		2021
Accrued Capital Expenditures	$	29	$	40
Renewable Energy Credits	6		5
Net Cost of Removal Decrease (1)	(1)		(34)
Asset Retirement Cost Decrease (2)	(14)		—

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

(2)Primarily represents a reduction in the net value of asset retirement cost of San Juan for deferred depreciation, which does not impact earnings.

19

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;

•current economic conditions;

•factors affecting results of operations;

•results of operations;

•liquidity and capital resources, including capital expenditures and environmental matters;

•critical accounting 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 2021 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; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers.

•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. Our goal is to reduce carbon emissions by 80% and to supply more than 70% of our energy to retail customers from renewable resources by 2035. In May 2022, Fortis set a goal to achieve net-zero direct carbon emissions by 2050. The establishment of this additional target reinforces Fortis' commitment, along with that of its subsidiaries, to decarbonize over the long-term, while preserving customer reliability and affordability. These goals 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

The COVID-19 pandemic caused changes in consumer and business behavior and disrupted economic activity in TEP’s service territory. Our business continuity plans and protocols are intended to support the continued delivery of safe and reliable service to our customers and the communities we serve. As the pandemic abates and conditions evolve, we continue to evaluate and assess protocols and plans and monitor our workforce, customers, suppliers, and operations. We have not experienced a material impact to our results of operations as a result of the COVID-19 pandemic.

TEP faces market risks associated with fluctuations in electricity, natural gas, and coal prices, and these commodity price fluctuations can temporarily affect the Company’s cash flows prior to recovery through regulatory mechanisms. Particularly in view of heightened geopolitical instability, we cannot project the future level of commodity prices or their volatility.

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Performance - The first three months of 2022 compared with the first three months of 2021

TEP reported net income of $19 million in the first three months of 2022 compared with net income of $23 million in the first three months of 2021. The decrease of $4 million, or 17%, was primarily due to:

•$7 million in lower AFUDC primarily due to a decrease in eligible construction expenditures as a result of Oso Grande being placed in service in May 2021;

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

•$5 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions.

The decrease was partially offset by:

•$9 million in higher margin from wholesale transactions primarily due to an increase in sales volume;

•$2 million in higher transmission revenue due to the 2019 FERC Rate Order settlement agreement; and

•$2 million in lower operations and maintenance expenses primarily due to a decrease in planned generation outages in 2022.

FACTORS AFFECTING RESULTS OF OPERATIONS

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

Regulatory Matters

We are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2021 Annual Report on Form 10-K and new regulatory matters occurring in 2022.

2020 Rate Order

In 2020, the ACC issued a rate order for new rates that took effect January 1, 2021.

Provisions of the 2020 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $58 million over test year retail revenues;

•a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%; and

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

In addition, the 2020 Rate Order established a second phase of our rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. On January 19, 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. We cannot predict the timing or outcome of these proceedings.

2022 Rate Case

On May 2, 2022, we submitted a notice of intent with the ACC to file a general rate application in June 2022. TEP will request that new rates become effective in the second half of 2023. Our proposed rates will be based on a test year ending December 31, 2021, and will include: (i) infrastructure investments made since the last rate case; (ii) changes in fuel and non-fuel operating expenses; and (iii) proposals to eliminate certain adjustor mechanisms, as well as to modify an existing adjustor to provide more timely recovery of clean energy investments.

Energy Imbalance Market

In 2019, TEP signed an agreement with the California Independent System Operator indicating its intent to begin participating in the EIM by spring of 2022. The EIM is a real-time energy market intended to find automatically low-cost energy to serve

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real-time consumer demand across a wide geographic area. Participation in the EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the EIM, TEP must demonstrate resource adequacy through a combination of owned or contracted resources. Our participation in the EIM is expected to: (i) reduce the costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance reliability through improved system utilization and responsiveness. Our entry into the EIM is scheduled for May 2022.

2019 FERC Rate Order

In 2019, we filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more timely recovery of transmission-related costs. The FERC issued an order approving our proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement.

Provisions of the settlement agreement include, but are not limited to:

•replacing our stated transmission rates with a single forward-looking formula rate;

•a 9.79% 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.

Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. Amounts deferred to the regulatory liability in excess of the rates approved in the settlement agreement will be returned to customers. We had $17 million as of March 31, 2022, and $15 million as of December 31, 2021, of wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets.

Other FERC Matters

In January 2021, the FERC notified us that it was commencing an audit that intends to evaluate our compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covers the period of January 1, 2018 to the present. The audit is ongoing and we cannot predict the outcome or findings, if any, of the FERC audit at this time.

Generation Resource Strategy

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 2020, we filed our 2020 IRP with the ACC, which provides details on our long-term strategy.

In February 2022, the ACC acknowledged our 2020 IRP, and found it to be reasonable and in the public interest. Our 2020 IRP calls for TEP to reduce its carbon emissions by 80% and to supply more than 70% of its energy to retail customers from renewable resources by 2035. In April 2022, we issued an All-Source Request for Proposals (ASRFP), which requests new wind and solar generation, energy storage systems and other resources such as energy efficiency resources. As part of the ASRFP, we are seeking bids for all resource types, including:

•up to 250 MW of renewable and energy efficiency resources, including new wind and solar generation systems and new energy efficiency initiatives, including demand response programs that reduce usage during periods of high energy demand; and

•up to 300 MW of “firm capacity” resources that can be called on at any time, including energy storage systems designed to provide at least four hours of continuous energy every day during the summer for TEP to dispatch as needed.

Our existing coal-fired generation fleet faces a number of uncertainties affecting 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 plan to exit all ownership interests in coal-fired generation facilities over the next decade. We will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.

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The execution of our 2020 IRP is dependent on obtaining regulatory recovery in future rate proceedings. We expect to file a general rate application with the ACC in June 2022.

Renewable Energy Projects

In 2021, three renewable energy projects were added to our resource portfolio increasing our total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 700 MW.

We are planning to provide more than 70% of our power from renewable resources by 2035 as part of our transition to a cleaner energy portfolio. The strategy provides a shift towards renewable generation and further decreases our dependency on coal-fired generation.

Oso Grande

Production Tax Credits

PTCs are per-kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In 2021, the PTC rate for electricity from wind was $0.025 per kWh generated. In May 2021, Oso Grande, a qualified energy resource, was placed in service. Oso Grande recorded approximately $2 million in PTCs in the three months ended March 31, 2022.

Contractual Provisions

If actual availability of the Oso Grande wind turbines is below a contractually established availability factor, we are entitled to liquidated damages to partially offset the cost of operation and maintenance costs incurred. We recorded a reduction in Operations and Maintenance on the Condensed Consolidated Statements of Income of $1 million in the three months ended March 31, 2022, related to Oso Grande liquidated damages. Any liquidated damages in excess of operating expenses will reduce Utility Plant—Plant in Service on the Condensed Consolidated Balance Sheets. The PTCs and liquidated damages will mostly offset the operating expenses of Oso Grande, which is not currently in base rates.

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

Arizona Energy Policy

In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various clean energy policies including existing renewable energy and energy efficiency goals, integrated resource planning, and retail competition for generation services.

In 2019 and 2020, the ACC discussed draft rules related to retail electric competition, but such rules have not been officially proposed. In 2021, a company filed an application with the ACC requesting a certificate of public convenience and necessity that would grant it the authority to provide competitive electric generation service to customers in our service territory. The ACC has not considered this application. On April 26, 2022, the Governor of Arizona signed legislation that repealed statutes supporting statewide implementation of retail electric competition.

In January 2022, the ACC voted to open a new rule-making docket on integrated resource planning. We cannot predict the timing or outcome of this proceeding.

Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year, due to mild winter weather in our retail service territory. Seasonal fluctuations affect the comparability of our results of operations.

Interest Rates

See Part II, Item 7A in our 2021 Annual Report on Form 10-K and Part I, Item 3 of this Form 10-Q for information regarding interest rate risk and its impact on earnings.

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RESULTS OF OPERATIONS

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

•Cost Recovery Mechanisms — TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, Renewable Energy Standard Tariff, DSM, and TEAM 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 Salt River Project Agricultural Improvement and Power District, 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 first three months of 2022 compared with the same period in 2021 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:

	Three Months Ended March 31,				Increase (Decrease)
(in millions)	2022		2021		Percent
Operating Revenues
Retail	$	218	$	215	1.4	%
Wholesale, Long-Term	18		10		80.0	%
Wholesale, Short-Term (1)	46		50		(8.0)	%
Transmission	13		11		18.2	%
Springerville Units 3 and 4 Participant Billings	20		31		(35.5)	%
Other	22		19		15.8	%
Total Operating Revenues	$	337	$	336	0.3	%

(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 $337 million in the first three months of 2022 compared with $336 million in the same period for 2021. The increase of $1 million, or less than 1%, was primarily due to:

•$8 million in higher long-term wholesale sales primarily due to an increase in volume;

•$7 million in higher margin from wholesale transactions;

•$4 million in higher retail revenue primarily due to higher PPFAC cost recoveries as a result of a higher PPFAC rate;

•$3 million in higher retail margin primarily due to: (i) industrial re-openings from COVID-19 closures; (ii) an increase in customers; and (iii) favorable weather; and

•$2 million in higher transmission revenue due to the 2019 FERC Rate Order settlement agreement.

The increase was partially offset by:

•$11 million in lower participant billings related to Springerville Units 3 and 4; and

•$11 million in lower wholesale short-term sales primarily due to a decrease in volumes; partially offset by an increase in price.

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The following table provides key statistics impacting Operating Revenues:

	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2022	2021	Percent
Electric Sales (kWh) (1)
Retail Sales	1,789	1,768	1.2	%
Wholesale, Long-Term	309	137	125.5	%
Wholesale, Short-Term	1,103	1,596	(30.9)	%
Total Electric Sales	3,201	3,501	(8.6)	%
Average Revenue per kWh (2)
Retail	12.18	12.16	0.2	%
Wholesale, Long-Term	5.74	6.97	(17.6)	%
Wholesale, Short-Term	3.44	3.11	10.6	%
Total Retail Customers (3)	441,207	436,454	*

*Not meaningful

(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 amount 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.

Operating Expenses

Fuel and Purchased Power Expense

TEP reported Fuel and Purchased Power expense of $118 million in the first three months of 2022 compared with $119 million in the same period for 2021. The decrease of $1 million, or 1%, was primarily due to $8 million in lower fuel costs due to Utility-Owned Renewable Generation and Purchased Power, Renewables volumes that replaced Coal and Gas-Fired Generation output; partially offset by: (i) a decrease in realized gains on natural gas swaps due to a spike in natural gas prices in February 2021 as a result of a severe winter storm in the southwestern United States; and (ii) an increase in the Average Fuel Cost of Coal.

The decrease was partially offset by a $5 million decrease to PPFAC eligible costs deferred as a regulatory asset for future recovery.

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The following table provides key statistics impacting Fuel and Purchased Power:

	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2022	2021	Percent
Sources of Energy
Coal-Fired Generation	1,301	1,484	(12.3)	%
Gas-Fired Generation	1,322	1,608	(17.8)	%
Utility-Owned Renewable Generation (1)	209	19	*
Total Generation	2,832	3,111	(9.0)	%
Purchased Power, Non-Renewable	198	212	(6.6)	%
Purchased Power, Renewable (2)	313	186	68.3	%
Total Generation and Purchased Power (3)	3,343	3,509	(4.7)	%

(cents per kWh)
Average Fuel Cost of Generated Power (4)
Coal	2.54	2.21	14.9	%
Natural Gas (5) (6)	3.69	3.56	3.7	%
Average Cost of Purchased Power (7)
Purchased Power, Non-Renewable (6)	5.82	6.77	(14.0)	%
Purchased Power, Renewable	6.71	8.70	(22.9)	%

*Not meaningful

(1)In May 2021, Oso Grande was placed in service, adding 250 MW of wind-powered electric generation, increasing TEP's total utility-owned renewable generation.

(2)In April 2021, a solar facility achieved commercial operation, adding 100 MW of renewable purchased power capacity for TEP under the related PPA.

(3)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.

(4)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.

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

(6)In February 2021, a severe winter storm in the southwestern United States drove increased energy demand, limited the availability of natural gas to fuel generation stations, and increased the cost of natural gas and purchased power.

(7)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

TEP reported Operations and Maintenance expense of $97 million in the first three months of 2022 compared with $111 million in the same period for 2021. The decrease of $14 million, or 13%, was primarily due to:

•$9 million in lower reimbursable maintenance expense related to Springerville Unit 4 planned generation outages in 2021, not recurring in 2022; and

•$2 million in lower maintenance expense primarily related to a decrease in planned generation outages in 2022.

Depreciation and Amortization Expense

TEP reported Depreciation and Amortization expense of $64 million in the first three months of 2022 compared with $58 million in the same period for 2021. The increase of $6 million, or 10%, was primarily due to an increase in asset base.

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Other Income (Expense)

TEP reported other expense of $19 million in the first three months of 2022 compared with $7 million in the same period for 2021. The increase of $12 million, or 171%, was primarily due to:

•$5 million in lower AFUDC equity primarily due to a decrease in the construction work in progress balance as a result of Oso Grande being placed in service in May 2021; and

•$5 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Any extended period of economic disruption could affect our business and financial conditions, and access to sources of liquidity. 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 as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 Credit Agreement 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 depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.

Available Liquidity

(in millions)	March 31, 2022
Cash and Cash Equivalents	$	146
Amount Available under Revolving Credit Agreement (1)	240
Total Liquidity	$	386

(1)The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026. See Access to Credit Agreement below.

Future Liquidity Requirements

We expect to meet all of our short and long-term 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; (iii) employee benefit obligations; and (iv) known commitments and other obligations including forecasted capital expenditures.

See Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk of this Form 10-Q for additional information regarding TEP's market risks and Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item I of this Form 10-Q for additional information regarding TEP's financing arrangements.

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Summary of Cash Flows

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

	Three Months Ended March 31,				Increase (Decrease)
(in millions)	2022		2021		Percent
Operating Activities	$	120	$	78	53.8	%
Investing Activities	(117)		(114)		2.6	%
Financing Activities	133		—		*
Net Increase (Decrease)	136		(36)		*
Beginning of Period	33		82		(59.8)	%
End of Period	$	169	$	46	267.4	%

*Not meaningful

Operating Activities

In the first three months of 2022, net cash flows from operating activities increased by $42 million compared with the same period in 2021. The increase was primarily due to: (i) higher gains from wholesale transactions; (ii) changes in working capital related to the timing of billing collections; and (iii) lower operations and maintenance expenses due to planned generation outages in 2021, not recurring in 2022.

Investing Activities

In the first three months of 2022, net cash flows used for investing activities increased by $3 million compared with the same period in 2021 primarily due to an increase in cash paid for capital expenditures in 2022.

Financing Activities

In the first three months of 2022, net cash flows from financing activities increased by $133 million compared with the same period in 2021 primarily due to higher proceeds from issuance of senior unsecured notes in February 2022, net of the repayment of tax-exempt bonds in March 2022, prior to their maturity.

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 March 31, 2022, TEP's short-term investments included highly-rated and liquid money market funds.

Access to Credit Agreement

We have access to working capital through our credit agreement with lenders.

As of March 31, 2022, there was $240 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings and a $10 million LOC issued with fees accruing at a rate of 1.00% per annum. As of May 3, 2022, there was $240 million available under the 2021 Credit Agreement.

See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2021 Annual Report on Form 10-K for additional information regarding our 2021 Credit Agreement.

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 December 2020, the ACC issued an order granting TEP financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate.

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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 repurchase debt.

•In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032 with proceeds used to redeem debt and for general corporate purposes.

•In March 2022, TEP redeemed at par $177 million aggregate principal amount of 4.50% tax-exempt bonds prior to the maturity of the bonds.

We anticipate redeeming additional long-term debt in the second quarter of 2022.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of March 31, 2022, 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.

The 2021 Credit Agreement contains 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 March 31, 2022, TEP was in compliance with these covenants.

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

Contributions from Parent

TEP received no equity contributions from UNS Energy in the first three months of 2022 or 2021.

Dividends Declared and Paid to Parent

TEP did not declare or pay dividends to UNS Energy in the first three months of 2022 or 2021.

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 established for TEP based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of March 31, 2022, TEP had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.

Capital Expenditures

TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In the first three months of 2022, there were no material changes to capital expenditures as reported in our 2021 Annual Report on Form 10-K.

Income Tax Position

Under the terms of the tax sharing agreement with UNS Energy, TEP made $1 million in tax sharing payments in the first three months of 2022 and 2021. Based on our remaining tax credit carryforward balances and limitations on their use in individual years, we expect to make additional tax sharing payments in 2022. Future payment obligations are subject to change and are not expected to have a significant impact on our operating cash flows.

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Payroll Tax

In response to the COVID-19 pandemic, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was signed into law on March 27, 2020. As permitted by the CARES Act, TEP deferred payment of the employer's portion of social security taxes. In 2020, TEP recorded total deferred deposits of $7 million in Accrued Taxes Other than Income Taxes and Regulatory and Other Liabilities—Other on the Condensed Consolidated Balance Sheets. TEP paid $3 million in 2021 and expects to pay the remaining deferred deposits to the IRS by the end of 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 of the costs of environmental compliance 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. The regulatory deadline for ADEQ to submit the revised SIP to the EPA for approval was July 31, 2021, however, ADEQ was not able to meet this deadline, and is continuing to develop the SIP for submittal. Based on current Regional Haze requirement time-frames, TEP anticipates that compliance strategies, if any, will likely be required to be implemented three years after the ADEQ submits the revised SIP to the EPA. TEP cannot predict the outcome of these matters at this time, but will continue to work with the agency to determine compliance strategies as needed.

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 repealed the CPP and 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 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.

On March 5, 2021, the U.S. Court of Appeals for the D.C. Circuit issued a mandate vacating and remanding the ACE rule to the EPA. The mandate also vacated amendments that extended the timeline under which companies had to come into compliance with the rule.

TEP cannot predict the outcome of these matters at this time, but will continue to monitor legal challenges, legislative efforts, and administrative rulemakings.

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Coal Combustion Residuals Regulation

In April 2015, the EPA issued a final rule requiring the 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. APS, the operating agent of Four Corners, began an assessment of corrective measures in 2019, and expects the assessment to continue through 2022.

Since these regulations were finalized, the EPA has taken steps to further modify the rule. The following are pending rulemakings:

•In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act, which gave the EPA authority to either authorize states to establish their own permit program under RCRA for implementing regulation of CCR or issue federal permits in states without a program and on tribal lands. In accordance with the WIIN Act, the EPA proposed to establish a federal CCR permit program on February 20, 2020. Public comment on the EPA's proposal closed in August 2020.

•On March 15, 2018, the EPA proposed to add boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. In a separate proposal dated August 14, 2019, the EPA acknowledged that if it finalizes the addition of boron it will need to establish an alternative risk-based groundwater protection standard for boron, as boron does not have a Maximum Contaminant Level. TEP cannot predict the outcome or timing on when the EPA will take final action on this matter.

As of March 31, 2022, the EPA has not taken final action on these proposals. As a result, TEP cannot predict the impact of the proposed rulemakings.

Effluent Limitation Guidelines

In 2015, as part of the Clean Water Act, the EPA published the final Steam Electric Power Generating category Effluent Limitation Guidelines and Standard rule, revising standards and limitations for coal-fired generation wastewater discharges. The rule established new or additional Effluent Limitations Guidelines (ELG) for wastewater discharges associated with fly ash, bottom ash, flue gas desulfurization, flue gas mercury control, and gasification of fuels such as coal and petroleum coke. With the exception of Four Corners, none of TEP's coal-fired generation facilities are subject to the rule.

In response to legal challenges, the EPA revised the ELGs and issued a final rule on August 31, 2020, which became effective December 14, 2020. The final rule revised requirements for flue gas desulfurization wastewater and bottom ash transport water and warrants a modification of Four Corners' National Pollution Discharge Elimination System permit. APS, the operator of Four Corners, filed a permit modification request on January 11, 2021, which is still pending EPA final action. TEP cannot predict the timing or final outcome of these matters at this time.

National Pollution Discharge Elimination System Permit

Several environmental non-governmental organizations (Petitioners) sought review of EPA’s September 2019 issuance of Four Corners’ current National Pollution Discharge Elimination System permit from the EPA Environmental Appeals Board (EAB) in November 2019. The EPA EAB denied the petition in September 2020 and the Petitioners pursued review of the EAB decision from the U.S. Court of Appeals for the Ninth Circuit in January 2021. In November 2021, a tentative settlement agreement was reached by all parties to the Ninth Circuit Court case. The terms of the settlement agreement are currently under review by the EPA.

TEP cannot predict the timing or final outcome of this matter at this time.

CRITICAL ACCOUNTING 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 three months ended March 31, 2022, 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 2021 Annual Report on Form 10-K.

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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.

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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.

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2021 Annual Report on Form 10-K.

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 March 31, 2022. There was no change in TEP’s internal control over financial reporting during the quarter ended March 31, 2022, that materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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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 2021 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 2021 Annual Report on Form 10-K.

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ITEM 6. EXHIBITS

EXHIBIT INDEX
Exhibit No.	Description
4(1)	Officer’s Certificate, dated February 17, 2022, authorizing 3.25% Senior Notes due 2032 (Form 8-K dated February 17, 2022, File No. 1-05924 – Exhibit 4.1)
31(a)	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Susan M. Gray
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 March 31, 2022, 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.

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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:	May 3, 2022	/s/ Frank P. Marino
		Frank P. Marino
		Sr. Vice President, Chief Financial Officer, and Director
		(Principal Financial Officer)

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