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, 2025

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 6, 2025.

Table of Contents

Definitions	iii
Forward-Looking Information	iv
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	31
Item 3. Quantitative and Qualitative Disclosures about Market Risk	31
Item 4. Controls and Procedures	31
PART II
Item 1. Legal Proceedings	33
Item 1A. Risk Factors	33
Item 6. Exhibits	34
Signatures	35

ii

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

2020 IRP	TEP's 2020 Integrated Resource Plan which outlines TEP's plan to reduce its carbon emissions by 80% (compared to 2005) by 2035
2021 Credit Agreement	The unsecured 2021 Credit Agreement, as amended in June 2023 and extended in October 2024, 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 2027
2023 IRP	TEP's 2023 Integrated Resource Plan which outlines TEP's aspirational goal to reach net zero direct greenhouse gas emissions by 2050
2023 Rate Order	Order issued by the ACC resulting in a new rate structure for TEP, effective on September 1, 2023
ACC	Arizona Corporation Commission
ADEQ	Arizona Department of Environmental Quality
AFUDC	Allowance for Funds Used During Construction
BESS	Battery Energy Storage System
CCR	Coal Combustion Residuals
DG	Distributed Generation
DSM	Demand Side Management
EPA	Environmental Protection Agency
EPC	Engineering, Procurement, and Construction
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
IRA	Inflation Reduction Act of 2022, signed into law on August 16, 2022
ITC	Investment Tax Credit
LFCR	Lost Fixed Cost Recovery
LOC	Letter(s) of Credit
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
SIP	State Implementation Plan

ENTITIES AND GENERATING STATIONS

Fortis	Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners	Four Corners Power Plant
Navajo	Navajo Generating Station
Oso Grande	A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico
Roadrunner Reserve I	A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in 2025
Roadrunner Reserve II	A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in 2026
San Juan	San Juan Generating Station
Springerville	Springerville Generating Station
SRP	Salt River Project Agricultural Improvement and Power District
Sundt	H. Wilson Sundt Generating Station
TEP	Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
UNS Electric	UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy	UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates	Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Millennium Energy Holdings, Inc.
UNS Gas	UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation

UNITS OF MEASURE

BBtu	Billion British thermal unit(s)
GWh	Gigawatt-hour(s)
kWh	Kilowatt-hour(s)
MW	Megawatt(s)
MWh	Megawatt-hour(s)

iii

Table of Contents

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. TEP, or the Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words or phrases that include "anticipates," "believes," "estimates," "expects," "intends," "continues," "assumes," "aspires," "may," "plans," "predicts," "projects," "would," "could," "forecast," "target," "goal," "potential," "commitment," "strategy," "will," 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 herein. We express our estimates, expectations, beliefs, aspirations, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, expectations, beliefs, aspirations, 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 2024 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Quarterly Report on Form 10-Q; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Quarterly Report on Form 10-Q; and other parts of this report. These factors include: voter initiatives and federal, state, and local regulatory and legislative decisions and actions, including changes in tax, tariff, and energy policies, as they may be affected by the policies and priorities of governmental officials at the federal, state, and local levels; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies or the City of Tucson's study of municipalization; 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; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; potential changes in the benefits of participation in the Western Energy Imbalance Market and Southwest Power Pool Markets+; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality, extreme weather events, and their increasing frequency and severity, and wildfires, affecting electricity usage of our customers, operational performance, and operating and capital costs to ensure system reliability; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the demand plus reserve margin requirements; our ability to implement successfully our business strategies and meet the growing demand for electricity, particularly in view of potential for new large customer requirements; the cost of debt and equity capital and access to capital markets and bank markets during extended periods of volatility, which may affect our ability to raise additional capital and to use the proceeds from any capital that we do raise as originally intended; the performance of the stock market and changes in interest rates, which affect the value of our pension and other postretirement benefit plan assets and related contribution requirements and expenses; our ability to manage timelines and budgets and to access necessary materials, in each case, related to capital projects, including EPC agreements to develop standalone BESS, and/or to obtain the anticipated performance or other benefits of such capital projects; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense, including increases due to inflationary effects, tariffs, international trade policy, heightened geopolitical instability, and/or global supply chain challenges; 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; our ability to meet our goals related to reducing carbon emissions by 2035 and 2050 due to load growth required by potential new large customers, and the potential impact on our financial condition; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other cyberspace attacks to our information security and our operations and technology infrastructure, including attacks that may arise from heightened geopolitical instability; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; the extent of the impact of a global health or other crisis on our business and operations, and any economic and/or societal disruptions resulting therefrom and from the government actions taken in response thereto; the implementation of our 2023 IRP; and our ability to obtain ACC approval of a formula rate plan with acceptable terms.

iv

Table of Contents

PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)

	Three Months Ended March 31,
	2025		2024
Operating Revenues	$	365,736	$	452,756
Operating Expenses
Fuel	76,608		101,454
Purchased Power	30,467		26,230
Transmission and Other PPFAC Recoverable Costs	8,942		18,078
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(1,242)		32,768
Total Fuel and Purchased Power	114,775		178,530
Operations and Maintenance	100,177		118,749
Depreciation	57,515		55,604
Amortization	7,781		7,736
Taxes Other Than Income Taxes	18,701		18,752
Total Operating Expenses	298,949		379,371
Operating Income	66,787		73,385
Other Income (Expense)
Interest Expense	(29,630)		(24,005)
Allowance For Borrowed Funds	4,349		1,876
Allowance For Equity Funds	9,687		5,252
Unrealized Gains (Losses) on Investments	84		862
Interest Income	1,762		1,212
Other, Net	(965)		83
Total Other Income (Expense)	(14,713)		(14,720)
Income Before Income Tax Expense	52,074		58,665
Income Tax Expense	7,643		7,484
Net Income	$	44,431	$	51,181

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,
	2025		2024
Cash Flows from Operating Activities
Net Income	$	44,431	$	51,181
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	57,515		55,604
Amortization Expense	7,781		7,736
Amortization of Debt Issuance Costs	788		763
Use of Renewable Energy Credits for Compliance	12,462		11,984
Deferred Income Taxes	7,019		5,590
Pension and Other Postretirement Benefits Expense	4,511		4,510
Pension and Other Postretirement Benefits Funding	(1,431)		(953)
Allowance for Equity Funds Used During Construction	(9,687)		(5,252)
Changes in Current Assets and Current Liabilities:
Accounts Receivable	25,280		26,817
Materials, Supplies, and Fuel Inventory	(11,031)		(3,350)
Regulatory Assets	(4,615)		48,234
Other Current Assets	2,457		(1,930)
Accounts Payable and Accrued Charges	10,680		24,007
Income Taxes Receivable/Payable	(256)		(688)
Regulatory Liabilities	(59)		(3,703)
Other, Net	(17,416)		(30,448)
Net Cash Flows—Operating Activities	128,429		190,102
Cash Flows from Investing Activities
Capital Expenditures	(172,872)		(133,283)
Purchase Intangibles, Renewable Energy Credits	(12,753)		(11,956)
Contributions in Aid of Construction	1,619		965
Net Cash Flows—Investing Activities	(184,006)		(144,274)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	30,000		15,000
Repayments of Borrowings, Revolving Credit Facility	(100,000)		(15,000)
Proceeds from Issuance, Long-Term Debt—Net of Discount	299,322		—
Payment of Debt Issuance Costs	(3,230)		—
Other, Net	652		317
Net Cash Flows—Financing Activities	226,744		317
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	171,167		46,145
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	49,461		42,595
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	220,628	$	88,740

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, 2025		December 31, 2024
ASSETS
Utility Plant
Plant in Service	$	8,414,048	$	8,349,638
Construction Work in Progress	940,382		850,443
Total Utility Plant	9,354,430		9,200,081
Accumulated Depreciation and Amortization	(2,759,020)		(2,713,492)
Total Utility Plant, Net	6,595,410		6,486,589
Investments and Other Property	71,866		75,662
Current Assets
Cash and Cash Equivalents	188,034		14,063
Accounts Receivable (Net of Allowance for Credit Losses of $11,580 and $12,561 as of March 31, 2025 and December 31, 2024, respectively)	170,797		196,194
Fuel Inventory	61,946		55,267
Materials and Supplies	199,720		196,515
Regulatory Assets	102,212		97,720
Derivative Instruments	41,088		9,732
Other	30,030		31,597
Total Current Assets	793,827		601,088
Regulatory Assets	174,213		177,963
Derivative Instruments	26,845		27,664
Other Noncurrent Assets	154,155		152,557
Total Assets	$	7,816,316	$	7,521,523

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, 2025		December 31, 2024
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2025 and December 31, 2024)	$	1,746,539	$	1,746,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	1,411,344		1,366,913
Accumulated Other Comprehensive Loss	(3,961)		(4,015)
Total Common Stock Equity	3,147,565		3,103,080
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2025 and December 31, 2024)	—		—
Long-Term Debt, Net	2,791,217		2,494,600
Total Capitalization	5,938,782		5,597,680
Current Liabilities
Borrowings Under Credit Agreement	—		70,000
Accounts Payable	139,224		151,278
Accrued Taxes Other than Income Taxes	73,869		57,847
Accrued Employee Expenses	34,920		37,921
Accrued Interest	30,843		22,260
Regulatory Liabilities	144,761		142,844
Customer Deposits	16,584		16,255
Derivative Instruments	37,185		25,710
Other	36,087		31,665
Total Current Liabilities	513,473		555,780
Deferred Income Taxes, Net	683,391		700,189
Regulatory Liabilities	371,951		362,859
Pension and Other Postretirement Benefits	70,446		68,816
Derivative Instruments	10,669		6,099
Asset Retirement Obligations	160,487		159,056
Other Noncurrent Liabilities	67,117		71,044
Total Liabilities	1,877,534		1,923,843
Commitments and Contingencies
Total Capitalization and Liabilities	$	7,816,316	$	7,521,523

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, 2023	$	1,696,539	$	(6,357)	$	1,162,921	$	(3,829)	$	2,849,274
Net Income					51,181				51,181
Other Comprehensive Income (Loss), Net of Tax							46		46
Balances as of March 31, 2024	$	1,696,539	$	(6,357)	$	1,214,102	$	(3,783)	$	2,900,501

Balances as of December 31, 2024	$	1,746,539	$	(6,357)	$	1,366,913	$	(4,015)	$	3,103,080
Net Income					44,431				44,431
Other Comprehensive Income (Loss), Net of Tax							54		54
Balances as of March 31, 2025	$	1,746,539	$	(6,357)	$	1,411,344	$	(3,961)	$	3,147,565

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 455,000 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 United States Securities and Exchange Commission's (SEC) interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems 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 2024 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. TEP has reclassified Interest Income from Other, Net and Asset Retirement Obligations from Other Noncurrent Liabilities in the prior period to a separately disclosed line on the Condensed Consolidated Statements of Income and the Condensed Consolidated Balance Sheets, respectively, to conform with the current period presentation. The reclassifications had no impact on TEP’s results of operation, financial position, or cash flows.

Variable Interest Entities

A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP regularly evaluates its primary beneficiary conclusions to determine if changes have occurred that impact its VIE assessment.

As of March 31, 2025, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term renewable PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

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 in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows:

	Three Months Ended March 31,
(in millions)	2025		2024
Cash and Cash Equivalents	$	188	$	57
Restricted Cash included in:
Investments and Other Property	24		22
Current Assets—Other	9		10
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	221	$	89

Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of final mine reclamation and decommissioning costs at San Juan.

INCOME TAXES

Production Tax Credits

TEP realized PTC benefits associated with Oso Grande of $4 million in Income Tax Expense on the Condensed Consolidated Statements of Income for each of the three months ended March 31, 2025 and 2024.

Investment Tax Credits

TEP has elected to apply Accounting Standards Codification 740, Income Taxes, to nonrefundable, transferable ITCs. Federal ITCs are deferred and amortized as a reduction to income tax expense over the life of the underlying asset. See Note 2 for additional information regarding the ACC issued accounting order for Roadrunner Reserve I.

NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED

The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) has been adopted as of January 1, 2025.

Income Tax Disclosures

In December 2023, the FASB issued accounting guidance that requires additional annual disclosure of disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. TEP does not expect the amendments to have a material impact on its annual disclosures.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

Standards Recently Issued by the FASB

The following new authoritative accounting guidance issued by the FASB has not yet been adopted and is not reflected in TEP’s financial statements. TEP is assessing the impact such guidance may have on TEP’s financial position, results of operations, cash flows, and disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued accounting guidance that requires disaggregation of income statement expenses into specified categories in the footnotes to the financial statements. In January 2025, the FASB issued accounting guidance clarifying the effective date of this standard. The amendments are effective for annual periods beginning January 1, 2027, and interim reporting periods beginning after January 1, 2028. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted.

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

SEC Climate-Related Disclosures

The following final SEC rules regarding climate-related disclosures are pending final disposition of proceedings relating to such rules.

In March 2024, the SEC issued final rules that require disclosure of climate related risks and greenhouse gas emissions. In April 2024, the SEC issued an order staying the final rules pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit. In March 2025, the SEC voted to end its defense of the rules and sent a letter to the Court stating that the SEC withdraws its defense. With the SEC’s withdrawal, TEP awaits disposition of the litigation and invalidation or rescission of the rules through the rulemaking process, the timing of which TEP cannot currently predict.

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 facilities and transmission systems, 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. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. 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 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.

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

	Three Months Ended March 31,
(in millions)	2025		2024
Beginning of Period	$	(49)	$	55
Deferred Fuel and Purchased Power Costs (1)	61		49
PPFAC and Base Power Recoveries	(60)		(97)
End of Period	$	(48)	$	7

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

Transmission Cost Adjustor

The TCA (Transmission Cost Adjustor) allows for timely recovery or refund of actual costs, net of applicable credits, required to provide transmission services to retail customers. TEP files new TCA rates with the ACC in December each year based on changes in net costs required to provide transmission services to retail customers. New TCA rates take effect in January of each year.

Renewable Energy Standard

The ACC’s RES requires Arizona regulated electric utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by the end of 2025. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. TEP recovers approved costs of carrying out this plan from retail customers through a RES tariff.

In May 2024, the ACC approved an extension of TEP's 2021 RES implementation with a budget of $66 million until further order of the ACC and an increase to the RES tariff to recover under-collected RES funds totaling $17 million. The ACC also

8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

waived for TEP the general requirement that Arizona utilities file an annual RES implementation plan. The approved amount funds: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs of implementing 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 the 2023 Rate Order, the ACC approved a 2023 energy efficiency implementation plan with a cumulative three-year budget of $72 million, which is collected through the DSM surcharge.

2020 IRP Energy Efficiency Target

In 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP periodically reports on its energy efficiency savings in filings with the ACC.

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 based on an estimate of lost retail kWh sales during the period. 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, 2025		December 31, 2024
Regulatory Assets
Pension and Other Postretirement Benefits (Note 9)	Various	$	102	$	103
Early Generation Retirement Costs	Various	44		46
Lost Fixed Cost Recovery	1	33		31
Property Tax Deferrals (1)	1	32		32
Derivatives (Note 10)	5	19		19
Transmission Revenue Requirement Balancing Account	1	14		11
Final Mine Reclamation (2)	15	8		9
Income Taxes Recoverable through Future Rates (3)	Various	5		5
Unamortized Loss on Reacquired Debt	Various	4		4
Other Regulatory Assets	Various	15		16
Total Regulatory Assets		276		276
Less Current Portion	1	102		98
Total Noncurrent Regulatory Assets		$	174	$	178

Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	212	$	209
Net Cost of Removal (4)	Various	102		110
Renewable Energy Standard	Various	90		88
Over-Recovered Fuel and Purchased Energy Costs	1	48		49
Deferred Investment Tax Credits	Various	24		4
Derivatives (Note 10)	5	18		22
Pension and Other Postretirement Benefits (Note 9)	Various	18		19
Demand Side Management	1	5		5
Total Regulatory Liabilities		517		506
Less Current Portion	1	145		143
Total Noncurrent Regulatory Liabilities		$	372	$	363

(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.

(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 2040. San Juan Unit 1 was retired in 2022.

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

(4)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 plant which are not yet expended.

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 Transmission Revenue Requirement

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

Balancing Account, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.

Roadrunner Reserve I Accounting Order

On April 28, 2025, the ACC issued an accounting order allowing TEP to defer for recovery in TEP's next rate case certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I, including depreciation and amortization, property taxes, operations and maintenance expense, interest expense, and ITC transaction costs. These costs will be partially offset by future benefits associated with ITCs.

NOTE 3. REPORTABLE SEGMENTS

TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP has one operating segment, its regulated utility operations. TEP’s chief operating decision maker (CODM) is Susan M. Gray who holds the position of President and Chief Executive Officer of TEP and its parent company, UNS Energy. The CODM uses net income to assess performance and decide how to allocate resources for UNS Energy overall (including employees and financial or capital resources) predominantly in the annual budget and forecasting process. Net income is reported on the Condensed Consolidated Statements of Income. Operations and Maintenance expense includes expenses reimbursed by third-parties and expenses related to customer-funded RES and DSM programs. Operations and Maintenance expense excluding these reimbursable and customer funded expenses totaled $82 million, and $84 million for the three months ended March 31, 2025 and 2024, respectively. Total assets, the measure of segment assets, is reported on the Condensed Consolidated Balance Sheets. Capital expenditures are reported on the Condensed Consolidated Statements of Cash Flows.

NOTE 4. REVENUE

DISAGGREGATION OF REVENUES

TEP earns most 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)	2025		2024
Retail	$	245	$	282
Wholesale	58		89
Other Services	23		39
Revenues from Contracts with Customers	326		410
Alternative Revenues	12		9
Other	28		34
Total Operating Revenues	$	366	$	453

11

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 5. ACCOUNTS RECEIVABLE

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

(in millions)	March 31, 2025		December 31, 2024
Retail	$	81	$	112
Retail, Unbilled	41		43
Retail, Allowance for Credit Losses	(12)		(13)
Wholesale (1)	26		24
Due from Affiliates (Note 6)	15		10
Other	20		20
Accounts Receivable, Net	$	171	$	196

(1)Includes $8 million as of March 31, 2025 and December 31, 2024, of receivables related to revenue from derivative instruments.

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, Net on the Condensed Consolidated Balance Sheets:

	Three Months Ended March 31,
(in millions)	2025		2024
Beginning of Period	$	(13)	$	(12)
Credit Loss Expense	(1)		(1)
Write-offs	2		2
End of Period	$	(12)	$	(11)

NOTE 6. 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, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:

(in millions)	March 31, 2025		December 31, 2024
Receivables from Related Parties
UNS Energy	$	8	$	1
UNS Electric	5		7
UNS Gas	2		2
Total Due from Related Parties	$	15	$	10
Payables to Related Parties
UNS Energy	$	7	$	1
UNS Electric	1		1
Total Due to Related Parties	$	8	$	2

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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

	Three Months Ended March 31,
(in millions)	2025		2024
Goods and Services Provided by TEP to Affiliates
Common Costs, UNS Energy Affiliates (1)	$	6	$	6
Transmission Revenues, UNS Electric (2)	2		2
Wholesale Revenues, UNS Electric (2)	1		2
Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (3)	$	3	$	3
Capacity Charges, UNS Gas (4)	1		1
Purchased Power, UNS Electric (2)	1		—

(1)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.

(2)TEP and UNS Electric sell power to each other, and TEP sells transmission services to UNS Electric. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.

(3)Corporate Services, UNS Energy includes legal and audit, and Fortis' management fees. Costs for corporate services provided by 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 84% of UNS Energy's allocated costs. TEP's share of Fortis' management fees was $3 million and $2 million for the three months ended March 31, 2025, and 2024, respectively.

(4)UNS Gas charges TEP for natural gas capacity used to supply Gila River Generating Station.

NOTE 7. DEBT AND CREDIT AGREEMENT

There have been no significant changes to TEP's debt or credit agreements since December 31, 2024, except as noted below.

DEBT

Issuance

In February 2025, TEP issued and sold $300 million aggregate principal amount of 5.90% senior unsecured notes due April 2055. TEP may redeem the notes prior to October 15, 2054, with a make-whole premium plus accrued interest. On or after October 15, 2054, TEP may redeem the notes at par plus accrued interest.

CREDIT AGREEMENT

2021 Credit Agreement

As of March 31, 2025, there was $238 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings and LOCs totaling $12 million issued with fees that accrue at a rate of 1.050% per annum.

NOTE 8. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments since December 31, 2024.

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

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 term of the respective coal supply agreement. TEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.

TEP is liable for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP’s liability balance related to its share of final mine reclamation costs at Four Corners totaled $3 million as of March 31, 2025, and December 31, 2024, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP's coal supply agreement with Four Corners expires in 2031.

TEP ceased operations at San Juan upon expiration of the coal supply agreement in 2022. TEP’s remaining final mine reclamation liability at San Juan was $29 million and $31 million as of March 31, 2025, and December 31, 2024, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities 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 2040. See Note 1 for additional information on restricted cash relating to TEP's share of final mine reclamation and decommissioning costs at San Juan.

Performance Guarantees

TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, 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. There is no maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of March 31, 2025, there have been no such payment defaults under either of the participation agreements.

The Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, the non-defaulting participants would seek financial recovery directly from the defaulting party.

Environmental Matters

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    

NOTE 9. EMPLOYEE BENEFIT PLANS

Net periodic benefit cost includes the following components:

	Pension Benefits				Other Postretirement Benefits
	Three Months Ended March 31,
(in millions)	2025		2024		2025		2024
Service Cost	$	4	$	4	$	1	$	1
Non-Service Cost (1)
Interest Cost	6		6		1		1
Expected Return on Plan Assets	(8)		(8)		(1)		(1)
Amortization of Net Loss	1		1		—		—
Net Periodic Benefit Cost	$	3	$	3	$	1	$	1

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

NOTE 10. 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.

15

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, 2025
Assets
Cash Equivalents (1)	$	85	$	—	$	85
Restricted Cash (1)	33		—		33
Energy Derivative Contracts, Regulatory Recovery (2)	—		45		45
Energy Derivative Contracts, No Regulatory Recovery (2)	—		23		23
Total Assets	118		68		186
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(47)		(47)
Energy Derivative Contracts, No Regulatory Recovery (2)	—		(1)		(1)
Total Liabilities	—		(48)		(48)
Total Assets (Liabilities), Net	$	118	$	20	$	138

(in millions)	December 31, 2024
Assets
Restricted Cash (1)	$	35	$	—	$	35
Energy Derivative Contracts, Regulatory Recovery (2)	—		33		33
Energy Derivative Contracts, No Regulatory Recovery (2)	—		4		4
Total Assets	35		37		72
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(31)		(31)
Energy Derivative Contracts, No Regulatory Recovery (2)	—		(1)		(1)
Total Liabilities	—		(32)		(32)
Total Assets (Liabilities), Net	$	35	$	5	$	40

(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.

16

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 in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:

	Gross Amount Recognized in the Balance Sheets		Gross Amount Not Offset in the Balance Sheets				Net Amount
			Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted
(in millions)	March 31, 2025
Derivative Assets
Energy Derivative Contracts	$	68	$	23	$	—	$	45
Derivative Liabilities
Energy Derivative Contracts	(48)		(23)		—		(25)

(in millions)	December 31, 2024
Derivative Assets
Energy Derivative Contracts	$	37	$	17	$	—	$	20
Derivative Liabilities
Energy Derivative Contracts	(32)		(17)		—		(15)

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 real power 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 TEP'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 evaluates the assumptions underlying its price curves monthly.

17

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

	Three Months Ended March 31,
(in millions)	2025		2024
Unrealized Net Gain (Loss)	$	(3)	$	(14)

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 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)	2025		2024
Operating Revenues	$	21	$	27

Derivative Volumes

As of March 31, 2025, 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, 2025	December 31, 2024
Power Contracts GWh	5,747	1,634
Gas Contracts BBtu	88,838	86,070

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. If such credit events were to occur, TEP, or its counterparties, could 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 individual contracts.

The fair 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 $35 million as of March 31, 2025, compared with $30 million as of December 31, 2024. TEP had no cash posted as collateral to provide credit enhancement as of March 31, 2025, and December 31, 2024. TEP would have been required to post $35 million and $30 million of collateral if the credit risk contingent features had been triggered on March 31, 2025, and December 31, 2024, respectively. TEP had $13 million and $15 million in outstanding net payable balances for settled positions as of March 31, 2025, and December 31, 2024, respectively.

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, 2025		December 31, 2024		March 31, 2025		December 31, 2024
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,791	$	2,495	$	2,479	$	2,153

NOTE 11. 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)	2025		2024
Accrued Capital Expenditures	$	50	$	47
Renewable Energy Credits	5		5
Asset Retirement Obligations Increase (Decrease)	(1)		(1)
Net Cost of Removal Increase (Decrease) (1)	(4)		4

(1)Represents an accrual for future cost of retirement net of salvage values that 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;

•factors affecting results of operations;

•results of operations;

•liquidity and capital resources, including capital expenditures, income tax position, 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 Condensed Consolidated Financial Statements and Notes in Part I, Item 1 of this Quarterly Report on 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 Quarterly Report on Form 10-Q and Risk Factors in Part 1, Item 1A of our 2024 Annual Report on Form 10-K, and in Part II, Item 1A of this Form Quarterly Report on 10-Q.

References in Management's Discussion and Analysis to "we," "our," and "us" are to TEP.

OUTLOOK AND STRATEGIES

Our 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, regulations, and policies; and (iv) other regulatory and legislative actions, as well as changes to governmental policies, programs, and priorities and their impact on each of (i) - (iii) above. Our plans and strategies include:

•Promoting economic development within our service territory to enable prosperity in the communities we serve while achieving sales growth and maintaining affordable rates for our customers. Our company is positioned to capitalize on unprecedented interest from new large customers to locate in our service territory.

•Achieving constructive outcomes in our regulatory proceedings that will provide us more timely cost recovery and an opportunity to earn an appropriate return on our rate base investments.

•Continuing our transition to a less carbon-intensive energy portfolio while complying with regulatory requirements and maintaining financial strength. We have established an aspirational goal of net zero direct GHG emissions by 2050 emphasizing our commitment to decarbonize while preserving customer reliability and affordability. To keep us on pace, we aim to reduce carbon emissions by 80% (compared to 2005) by 2035. Our ability to achieve these goals could be impacted by various federal and state energy policies and other external factors, including significant new customer growth, and an increase in demand from existing customers.

•Focusing on our core utility business through operational excellence, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.

Performance - The first three months of 2025 compared with the first three months of 2024

We reported net income of $44 million in the first three months of 2025 compared with net income of $51 million in the first three months of 2024. The decrease of $7 million, or 14%, was primarily due to (net of tax):

•$7 million in lower margin from wholesale transactions primarily due to a decrease in revenues realized from wholesale trading as defined in the PPFAC plan of administration;

•$5 million in higher interest expense primarily due to the issuance of debt in August 2024 and February 2025; and

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•$2 million in higher depreciation expense primarily due to an increase in asset base.

The decrease was partially offset by:

•$6 million in higher AFUDC due to an increase in eligible construction expenditures; and

•$2 million in lower base operations and maintenance expenses primarily due to lower operations and maintenance expenses at our generation facilities; partially offset by an increase in employee benefits expenses.

FACTORS AFFECTING RESULTS OF OPERATIONS

The most significant factors affecting our current and future results of operations are related to regulatory matters, generation resource strategy, and sales growth and seasonality.

Regulatory Matters

We are subject to comprehensive regulation. The discussion below contains material developments in regulatory matters and government actions.

2023 Rate Order

In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:

•a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;

•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% and an average cost of debt of 3.82%; and

•approval to recover costs of changes in generation resources, including the addition of Oso Grande, in rates.

Roadrunner Reserve I Accounting Order

On April 28, 2025, the ACC issued an accounting order allowing us to defer for recovery in our next rate case certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I, including depreciation and amortization, property taxes, operations and maintenance expense, interest expense, and ITC transaction costs. These costs will be partially offset by future benefits associated with ITCs.

ACC Formula Rate Plan Policy

In December 2024, the ACC adopted a formula rate policy statement that allows regulated utilities to propose a formula rate plan in future rate cases. A formula rate plan, if approved by the ACC, would adjust rates annually based on a predetermined formula. Formula rate plans are expected to improve rate stability for customers, while also reducing regulatory lag and related costs as well as the number of adjustor mechanisms and the reliance thereon. We plan to file a rate case in 2025 that includes a formula rate plan.

Southwest Power Pool Markets+

In November 2024, we, along with other Arizona utilities, announced plans to join Southwest Power Pool Markets+ (Markets+), a day-ahead and real-time energy market, and expect to participate in the market as early as 2027. The Markets+ tariff was conditionally approved by the FERC in January 2025. On April 22, 2025, the FERC accepted an agreement signed by TEP and other participating utilities to provide funding for the creation and implementation of Markets+.

City of Tucson Energy Sourcing Study

The City of Tucson engaged a consulting and engineering firm to prepare a study analyzing alternatives to our provision of service to the City of Tucson, including evaluating a municipalization option. While an initial draft of the study, published on April 22, 2025, suggests that establishing a municipal utility that would primarily serve customers in the City of Tucson would result in potential customer savings, the study also notes that the City of Tucson would assume significant risks and incur substantial costs to pursue such an option. Such costs would include the purchase of property and plant at fair value and the costs to separate our remaining electrical grid from the City of Tucson. The City of Tucson would need to authorize the expenditure of funds for significant additional due diligence to demonstrate engineering and economic feasibility before the

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City of Tucson could pursue municipalization. Ultimately, establishing a municipal utility would require approval by a majority of the voters of the residents of the City of Tucson at a general or special municipal election. If such a measure were approved, the City of Tucson would need to exercise its right of eminent domain by filing an action for condemnation in Pima County Superior Court, and any determination in such condemnation proceedings would be subject to appeal.

Generation Resource Strategy

Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while reducing reliance on coal-fired generation resources. In 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards a new aspirational goal of net zero direct GHG emissions by 2050. To keep us on pace, we aim to reduce carbon emissions by 80% (compared to 2005) by 2035. Our ability to achieve these goals could be impacted by various federal and state energy policies and other external factors, including significant new customer growth and an increase in demand from existing customers. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings. In October 2024, the ACC acknowledged our 2023 IRP and found it to be reasonable and in the public interest.

In 2022, we issued an All-Source Request for Proposal (ASRFP), which allowed for all resource types, including, among others, new wind and solar generation, battery storage, and energy efficiency resources. As a result of our 2022 ASRFP, we entered into:

•an EPC agreement in September 2023 to develop Roadrunner Reserve I. Roadrunner Reserve I will be a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh with an anticipated in-service date in 2025;

•a renewable PPA in January 2024 with Wilmot Energy Center II (Wilmot II). Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage with energy capacity of 400 MWh, with an anticipated in-service date in 2026; and

•a renewable PPA in April 2024 with Winchester Solar I, LLC (Winchester). Winchester will have 80 MW of solar capacity accompanied by 80 MW of battery storage with energy capacity of 320 MWh, with an anticipated in-service date in 2027.

In December 2023, we issued another ASRFP (2024 ASRFP) based on the resource needs outlined in our 2023 IRP targeting in-service dates of 2026 through 2027. As a result of our 2024 ASRFP, we entered into an EPC agreement in August 2024 to develop Roadrunner Reserve II. Roadrunner Reserve II will be a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh with an anticipated in-service date in 2026.

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, land lease contract extensions, environmental regulations and policies, and, for jointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we expect to exit all ownership interests in coal-fired generation facilities by the end of 2031. We will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of these actions.

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 May 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded approximately $4 million in PTCs related to Oso Grande for each of the three months ended March 31, 2025, and 2024. The PTC rate published by the Internal Revenue Service for electricity produced by a qualified facility using wind placed in service prior to 2022 was $0.029 for 2024.

Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, or if any operational constraints exist, the project's electricity generation and associated PTCs may be substantially different compared to prior periods. Oso Grande and the associated PTCs are included in rates as part of the 2023 Rate Order.

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Sales Growth and Seasonality

Our average retail sales growth has remained relatively flat over the past three years. Recently, we have experienced interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet above what is reflected in our 2023 IRP, as well as higher transmission and distribution infrastructure investments. We are analyzing the requests and cannot predict the quantity or timing of the energy demand, if any, that may result from the current interest received.

Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our retail sales are highest in the second and 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. Our operating costs are generally consistent throughout the year which produces higher operating income in the second and third quarter and lower operating income in the first and fourth quarter. As a result, seasonal fluctuations affect the comparability of our results of operations.

Interest Rates

See Part II, Item 7A in our 2024 Annual Report on Form 10-K and Part I, Item 3 of this Quarterly Report on Form 10-Q for information regarding interest rate risk and its impact on earnings.

RESULTS OF OPERATIONS

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

•Cost Recovery Mechanisms — We record operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchased power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, the RES tariff, and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on 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 mechanism.

•Springerville Units 3 and 4 — Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.

The following discussion provides the significant items that affected our results of operations for the first three months of 2025 compared with the same period in 2024 presented on a pre-tax basis.

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Operating Revenues

The following table provides a disaggregation of Operating Revenues:

	Three Months Ended March 31,				Increase (Decrease)
(in millions)	2025		2024		Percent
Operating Revenues
Retail	$	245	$	282	(13.1)	%
Wholesale, Short-Term (1)	47		84		(44.0)	%
Wholesale, Long-Term	17		19		(10.5)	%
Transmission	14		14		—	%
Springerville Units 3 and 4 Participant Billings	20		36		(44.4)	%
Other	23		18		27.8	%
Total Operating Revenues	$	366	$	453	(19.2)	%

(1)Includes revenue realized from wholesale trading as defined in the PPFAC plan of administration. We share 10% of any realized gains on trading transactions with retail customers through the PPFAC mechanism.

We reported Operating Revenues of $366 million for the first three months of 2025 compared with $453 million in the same period for 2024. The decrease of $87 million, or 19%, was primarily due to:

•$37 million in lower short-term wholesale revenues primarily due to a decrease in price and volume and a decrease in revenues realized from wholesale trading as defined in the PPFAC plan of administration;

•$37 million in lower retail revenue primarily due to lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate; and

•$16 million in lower Springerville Units 3 and 4 participant billings primarily due to higher reimbursable planned outage costs in 2024.

The following table provides key statistics impacting Operating Revenues:

	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2025	2024	Percent
Electric Sales (kWh) (1)
Retail Sales	1,759	1,795	(2.0)	%
Wholesale, Long-Term	292	317	(7.9)	%
Wholesale, Short-Term	890	1,533	(41.9)	%
Total Electric Sales	2,941	3,645	(19.3)	%
Average Revenue (cents per kWh) (2)
Retail	13.93	15.71	(11.3)	%
Wholesale, Long-Term	5.96	5.85	1.9	%
Wholesale, Short-Term	2.96	3.73	(20.6)	%
Total Retail Customers (3)	455,052	449,619	1.2	%

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

(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, 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 and 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.

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Operating Expenses

Fuel and Purchased Power Expense

We reported Fuel and Purchased Power expense of $115 million for the first three months of 2025 compared with $179 million for the same period for 2024. The decrease of $64 million, or 36%, was primarily due to:

•$34 million in lower PPFAC Recovery Treatment primarily due to a decrease in PPFAC cost recoveries and an increase in PPFAC eligible costs deferred as a regulatory asset for future recovery;

•$25 million in lower Fuel expenses primarily due to a decrease in Coal-Fired and Gas-Fired Generation volumes, and lower realized losses on natural gas swaps; partially offset by an increase in gas prices; and

•$9 million in lower Transmission and Other PPFAC Recoverable Costs primarily due to a decrease in transmission service expenses.

The decrease was partially offset by $4 million in higher Purchased Power expenses primarily due to an increase in volume.

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

	Three Months Ended March 31,		Increase (Decrease)
(kWh in millions)	2025	2024	Percent
Sources of Energy
Coal-Fired Generation	538	936	(42.5)	%
Gas-Fired Generation	1,541	1,892	(18.6)	%
Utility-Owned Renewable Generation	168	198	(15.2)	%
Total Generation	2,247	3,026	(25.7)	%
Purchased Power	800	721	11.0	%
Total Generation and Purchased Power (1)	3,047	3,747	(18.7)	%

(cents per kWh)
Average Cost of Generated and Purchased Power
Coal (2)	5.01	5.43	(7.7)	%
Natural Gas (2)(3)	3.13	2.62	19.5	%
Purchased Power (4)	3.81	3.73	2.1	%

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

(2)These metrics represent the fuel cost as cents per kWh for coal and natural gas generated power. These numbers are calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses these metrics to monitor rates and pricing as well as analyze the performance of generation facilities.

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

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

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Operations and Maintenance Expense

We reported Operations and Maintenance expense of $100 million for the first three months of 2025 compared with $119 million for the same period for 2024. The decrease of $19 million, or 16%, was primarily due to:

•$16 million in lower reimbursable maintenance expense related to Springerville Units 3 and 4 primarily due to higher planned outage costs in 2024; and

•$3 million in lower operations and maintenance expenses at our generation facilities.

The decrease was partially offset by a $1 million increase in employee benefits expenses.

Depreciation and Amortization Expense

We reported Depreciation and Amortization expense of $65 million for the first three months of 2025 compared with $63 million for the same period for 2024. The increase of $2 million, or 3%, was primarily due to an increase in asset base.

Other Income (Expense)

We reported Other Expense of $15 million for the first three months of 2025 and 2024. Changes in 2025 compared to 2024 were primarily due to $7 million in higher AFUDC due to an increase in eligible construction expenditures; partially offset by $6 million in higher interest expense due to the issuance of debt in August 2024 and February 2025.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Any extended period of economic disruption could affect our business, financial condition, and access to sources of liquidity. Cash flows 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 our summer peaking load. We face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. 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, 2025
Cash and Cash Equivalents	$	188
Amount Available under Revolving Credit Agreement (1)	238
Total Liquidity	$	426

(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 2027. See Access to Credit below.

Future Liquidity Requirements

We expect to meet all of our short-term 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 contractual obligations including forecasted capital expenditures.

See Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk of this Quarterly Report on Form 10-Q for additional information regarding our market risks. See Note 1, Note 8, and Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2024 Annual Report on Form 10-K for additional information regarding our leases, financing arrangements, and purchase commitments, respectively.

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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)	2025		2024		Percent
Operating Activities (1)	$	129	$	190	(32.1)	%
Investing Activities (1)	(184)		(144)		27.8	%
Financing Activities (1)	227		—		*
Net Increase (Decrease)	172		46		*
Beginning of Period	49		43		14.0	%
End of Period	$	221	$	89	148.3	%

* Not meaningful

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

Operating Activities

Net cash flows provided by operating activities decreased by $61 million in the first three months of 2025 compared with the same period in 2024 primarily due to higher PPFAC recoveries in 2024.

Investing Activities

Net cash flows used for investing activities increased by $40 million in the first three months of 2025 compared with the same period in 2024 primarily due to an increase in cash paid for capital expenditures.

Financing Activities

Net cash flows provided by financing activities increased by $227 million in the first three months of 2025 compared with the same period in 2024 primarily due to higher proceeds from debt issuance; partially offset by higher repayments of credit facility borrowings.

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, 2025, our short-term investments were deposited in insured cash sweep, interest-bearing checking, and money market accounts.

Access to Credit

We have access to working capital through our credit agreement with lenders. Amounts borrowed from the 2021 Credit Agreement are used for working capital and other general corporate purposes. LOCs may be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of March 31, 2025, there was $238 million available under the 2021 Credit Agreement, which reflects no outstanding borrowings and LOCs totaling $12 million issued with fees that accrue at a rate of 1.050% per annum.

See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q and Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2024 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 March 2025, we filed a financing application with the ACC. The application requests extending and expanding the existing financing authority by: (i) extending authority from December 2025 to December 2030; (ii) increasing the outstanding long-term debt limitation from $2.9 billion to $4.5 billion; and (iii) allowing parent equity contributions of up to $1.7 billion. In March 2025, we filed with the SEC an automatic shelf registration statement on Form S-3, which expires in March 2028.

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We have, from time to time, refinanced or repurchased portions of our outstanding debt before scheduled maturity. Depending on market conditions, we may refinance or repurchase additional outstanding debt before its scheduled maturity.

In February 2025, we issued and sold $300 million aggregate principal amount of 5.90% senior unsecured notes due April 2055. We used a portion of the net proceeds to repay debt and plan to use the remaining net proceeds for general corporate purposes.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of March 31, 2025, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- (negative) and A3 (stable), 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 our 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 our 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 we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of March 31, 2025, we were in compliance with these covenants.

We do not have any provisions in any of our debt 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

We received no equity contributions from UNS Energy in the first three months of 2025 or 2024.

Dividends Declared and Paid to Parent

We did not declare or pay dividends to UNS Energy in the first three months of 2025 or 2024.

Master Trading Agreements

We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of March 31, 2025, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.

Capital Expenditures

Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. In the first three months of 2025, there were no material changes to our forecasted capital expenditures as reported in our 2024 Annual Report on Form 10-K. We are continuing to monitor government policy on foreign trade, including new or increased tariffs, and the potential impacts it may have on our capital projects. While there has been no material impact to date in 2025 on our operations or financial performance as a result of changes in government policy, new or increased tariffs and corresponding disruptions in the supply chain could significantly increase costs in future periods if we are unable to mitigate the impacts of such tariffs.

Income Tax Position

Tax Sharing Agreement

Under the terms of the tax sharing agreement with UNS Energy, we made $1 million and $3 million in tax sharing payments for the first three months of 2025, and 2024, respectively. Future tax sharing cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.

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Investment Tax Credits

Standalone battery storage systems that began construction before January 29, 2023 may qualify for a base federal tax credit equal to 30% of the eligible costs of the facility. We expect both Roadrunner Reserve I and II to qualify for the base federal tax credit and an additional 10% energy community bonus credit. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for additional information regarding the ACC issued accounting order for Roadrunner Reserve I. The IRA provides an election to transfer (i.e., sell) some or all of certain tax credits generated by a qualifying facility to unrelated third parties in exchange for cash. Transfer elections must be made on a facility-by-facility and year-by-year basis. Any election to transfer tax credits must be made and cash must be received on or before the due date of the tax return for the year the facility is placed in service. Roadrunner Reserve I is expected to be placed in service in 2025, and Roadrunner Reserve II is expected to be placed in service in 2026.

Environmental Matters

The EPA has the authority to regulate 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.

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 (Regional Haze). 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 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, we were notified by the ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluations. We conducted the potential emissions controls evaluations, commonly referred to as the four-factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP.

In December 2024, the EPA published a final rule partially approving and partially disapproving the ADEQ’s Regional Haze SIP revision. The EPA disapproved the ADEQ’s control strategy in the revised SIP, which relies, in part, on the compliance measures for Sundt Unit 3 and Springerville Units 1 and 2. The EPA also disapproved the ADEQ's selection of sources for potential emissions controls evaluations and requested further evaluation of Sundt Unit 4. The disapproval established a two-year deadline for the EPA to promulgate a FIP that contains EPA-required compliance measures for Springerville and Sundt, unless the EPA approves a subsequent SIP submission by the ADEQ curing the SIP deficiencies within that timeframe.

In February 2025, in response to the EPA’s December 2024 final rule, TEP and SRP filed a joint Petition for Administrative Reconsideration with the EPA. We requested the EPA reconsider the final rule and act to approve the ADEQ's Regional Haze SIP revision. In February 2025, TEP and SRP also filed a joint Petition for Review with the U.S. Court of Appeals for the 9th Circuit. In March 2025, the Court entered an order staying the briefing until June 23, 2025. We cannot predict the outcome of this matter.

Greenhouse Gas Regulation

In May 2024, the EPA published final rules to regulate GHG emissions from two categories of fossil-based electric generating units (EGUs): (i) existing steam units (including coal- and natural gas-fired); and (ii) new natural gas-fired turbines.

The final rules established:

•emission guidelines for existing coal-fired steam EGUs, which are subcategorized based on federally enforceable retirement dates. These emission guidelines affect Springerville Units 1 and 2, as well as Four Corners Units 4 and 5;

•emission guidelines for existing natural gas- and oil-fired steam EGUs aligned with routine methods of operation and maintenance, which are subcategorized based on the annual capacity factor of each unit beginning January 1, 2030. These emission guidelines affect Sundt Units 3 and 4;

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•a requirement for states to establish standards of performance that align with the emission guidelines in the form of emission limits. States must submit these standards of performance to the EPA for approval in the form of a state plan, which is due to the EPA in May 2026; and

•new source performance standards for new stationary natural gas-fired combustion turbines, which are subcategorized based on the annual capacity factor for each unit. For base load units (i.e., units with an annual capacity factor greater than 40%), the EPA established a two-phased performance standard. For phase 1, new base load units must initially meet performance standards based on the use of highly efficient combined cycle generation with the best operating and maintenance practices. For phase 2, the final rule requires that such base load units achieve emissions reductions aligned with a 90% carbon capture and sequestration rate beginning on January 1, 2032.

We are analyzing the EPA's final rules. Various legal challenges to the final rules are pending before the U.S. Court of Appeals for the District of Columbia Circuit. On April 25, 2025, the Court granted the EPA's unopposed motion to hold the case in abeyance indefinitely (following a previous sixty-day stay), while the EPA conducts a rulemaking to reassess the rules. We cannot predict the outcome of this matter.

The EPA did not take final action on existing natural gas-fired combustion turbines but has indicated that it plans to issue a supplemental proposal to address these units.

Coal Combustion Residuals Regulation

The EPA published final rules effective October 2015 (2015 CCR Rule) that established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The 2015 CCR Rule provides for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at Springerville. Arizona Public Service Company, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility. SRP, the operator of Navajo, is completing closure activities at the facility's CCR landfill. No corrective actions to comply with the 2015 CCR Rule have been identified at Springerville or Navajo. With regards to future corrective actions at Four Corners to comply with the 2015 CCR Rule, our share of costs to complete any corrective actions and to gather and perform remedial evaluations on groundwater at Units 4 and 5 is not expected to have a significant impact on our financial position, results of operations, or cash flows.

In May 2024, the EPA published the final Legacy CCR Surface Impoundments Rule that expands the scope of the 2015 CCR Rule to address the impacts from historical CCR management and placement activities that would have ceased prior to 2015. The EPA rule establishes two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCR Management Units (CCRMUs) which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. A CCRMU includes not only historically closed landfills and surface impoundments, but also prior applications of CCR on land, such as for structural fill. The final rule also establishes assessment, groundwater monitoring, closure, and post-closure requirements for legacy CCR impoundments and CCRMUs.

We are analyzing the EPA's final rule for potential impacts to our operations. We anticipate CCRMUs will be identified at Springerville and Four Corners. The number, location, and size of these CCRMUs will be assessed in accordance with the compliance schedule outlined in the EPA's final rule; therefore, associated compliance costs cannot be accurately predicted at this time. SRP identified CCRMUs at Navajo. Our estimated cost to comply with the EPA's final rule at Navajo is not expected to have a significant impact on our financial position, results of operations, or cash flows. Legal challenges to the final rule are pending before the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this matter.

Good Neighbor Federal Implementation Plan

In September 2018, the ADEQ submitted to the EPA the Arizona SIP Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone National Ambient Air Quality Standard (NAAQS). In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.

In March 2023, the EPA released its final FIP to address the interstate transport of ozone (Good Neighbor FIP) with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be

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significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.

In February 2024, the EPA published a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona’s inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOx emission reduction requirements. The EPA must take final action on Arizona’s Ozone Transport SIP Revision by February 26, 2026, per consent decree entered in the U.S. District Court for the Northern District of California.

In June 2024, the U.S. Supreme Court granted a stay of the Good Neighbor FIP pending the disposition of the petitions for review of the Good Neighbor FIP currently pending in the U.S. Court of Appeals for the District of Columbia Circuit. In October 2024, the EPA issued an interim final rule administratively staying the effectiveness of the Good Neighbor FIP for all emissions sources subject to the plan as promulgated.

In September 2024, the U.S Court of Appeals for the District of Columbia Circuit Court granted the EPA's request to remand the Good Neighbor FIP rulemaking record and further respond to comments related to the issues addressed in the U.S. Supreme Court's stay. The EPA published its updated response to comments for the Good Neighbor FIP in December 2024.

On March 10, 2025, the EPA filed a motion in the U.S. Court of Appeals for the District of Columbia Circuit indicating it plans to reconsider the Good Neighbor Rule. We cannot predict the outcome of this matter.

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 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, 2025, to the items that we disclosed as our critical accounting estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. TEP 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 2024 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 SEC’s rules and forms. These disclosure controls and procedures are also

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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, 2025. There was no change in TEP’s internal control over financial reporting during the quarter ended March 31, 2025, 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 8 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Pursuant to Item 103 of Regulation S-K under the Exchange Act, TEP is required to disclose certain information about environmental proceedings to which a governmental authority is a party if TEP reasonably believes such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. TEP has elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.

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 2024 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 2024 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 21, 2025, establishing the terms of the 5.90% Senior Notes due 2055 (Form 8-K dated February 21, 2025, 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 J. Caleb Adcock.
**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 TEP's Quarterly Report on Form 10-Q for the quarter ended March 31, 2025, formatted in Inline XBRL and contained in Exhibit 101.

*	Filed herewith.
**	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 6, 2025	/s/ J. Caleb Adcock
		J. Caleb Adcock
		Chief Financial Officer and Vice President
		(Principal Financial Officer and Principal Accounting Officer)

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