tep-20260930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2026

☐ 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 November 2, 2026.

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			21
Critical Accounting Estimates			38
New Accounting Standards Issued and Not Yet Adopted			38
Item 3. Quantitative and Qualitative Disclosures about Market Risk			38
Item 4. Controls and Procedures			38

PART II

Item 1. Legal Proceedings			39
Item 1A. Risk Factors			39

Item 6. Exhibits			40
Signatures			41

DEFINITIONS

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

INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS



2021 Credit Agreement						The unsecured 2021 Credit Agreement, as amended in June 2023 and extended in October 2025, provided for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and was amended and restated by the 2026 Credit Agreement on October 15, 2026
2026 Credit Agreement						The unsecured 2026 Credit Agreement provides for $350 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2031

2023 IRP						TEP's 2023 Integrated Resource Plan which outlines TEP's aspirational goal to reach net zero direct greenhouse gas emissions by 2050
2026 IRP						TEP's 2026 Integrated Resource Plan which outlines TEP's long-term plan for meeting customers' energy needs while maintaining reliable and affordable electric service
2023 Rate Order						Order issued by the ACC resulting in a new rate structure for TEP, effective on September 1, 2023
2025 Rate Case						TEP's June 2025 general rate case filed with the ACC based on a test year ended December 31, 2024

ACC						Arizona Corporation Commission
ADEQ						Arizona Department of Environmental Quality

AFUDC						Allowance for Funds Used During Construction
AI						Artificial Intelligence

ALJ						Administrative Law Judge
ARAM						Annual Rate Adjustment Mechanism


ASRFP						All-Source Request for Proposal
BESS						Battery Energy Storage System
CAMT						Corporate Alternative Minimum Tax
CCR						Coal Combustion Residuals
CCRMU						CCR Management Units
CCS						Carbon Capture and Sequestration


CO2						Carbon Dioxide
CODM						Chief Operating Decision Maker

Customer 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
DG						Distributed Generation

DSM						Demand Side Management
ECA						Environmental Compliance Adjustor
EE Standards						Energy Efficiency Standards
EGUs						Electric Generating Units


EPA						Environmental Protection Agency


ESA						Energy Supply Agreement
FASB						Financial Accounting Standards Board
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
IRS						Internal Revenue Service
ITC						Investment Tax Credit
LFCR						Lost Fixed Cost Recovery

LOC						Letter(s) of Credit
Markets+						Southwest Power Pool Markets+
NAAQS						National Ambient Air Quality Standard

NOx						Nitrogen Oxide




PPA						Power Purchase Agreement
PPFAC						Purchased Power and Fuel Adjustment Clause

PTC						Production Tax Credit


RES						Renewable Energy Standard
ROO						Recommended Opinion and Order
RUCO						Residential Utility Consumer Office
SEC						United States Securities and Exchange Commission
SIP						State Implementation Plan
SO2						Sulfur Dioxide


TCA						Transmission Cost Adjustor
TEAM						Tax Expense Adjustor Mechanism


VIE						Variable Interest Entity

ENTITIES AND GENERATING STATIONS


APS						Arizona Public Service Company
Babacomari North						Babacomari Solar North, LLC
Fortis						Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
FortisUS						Fortis intermediate holding company
Four Corners						Four Corners Power Plant
Gila River						Gila River Generating Station
Luna						Luna Generating Station
Navajo						Navajo Generating Station
Oso Grande						A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico

Roadrunner Reserve I						A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh, located in southeast Tucson
Roadrunner Reserve II						A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh, located in southeast Tucson

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
Wilmot II						Wilmot Energy Center II

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

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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 2025 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 (including, among other things, data center energy use, efficiency standards, and sources of power), as they may be affected by the policies and priorities of governmental officials at the federal, state, and local levels; the outcome of the November 2026 general election vote on our new franchise agreement with the City of Tucson; any change in our expected benefit of or obligations relating to ITCs, including from the result of the transfer of ITCs; 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 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, including any impediments to implementing such strategies arising from state or local opposition, and meet the growing demand for electricity, particularly in view of existing and potential new large customer requirements; the ability and willingness of our large customer counterparties, including counterparties to data center ESAs, to satisfy their financial and performance commitments; 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 and labor, in each case, related to capital projects 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 pressures, 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 and the potential repeal of such mandates; our ability to meet our aspirational goal related to reducing carbon emissions by 2050 due to load growth required by existing and potential new large customers, and the potential impact on our financial condition; our ability to exit all ownership interests in coal-fired generation by 2032; 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 or due to the evolution of AI or otherwise, as well as additional

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exposure to data breaches, algorithmic bias and legal liability resulting from the implementation of AI into our business operations; 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 2026 IRP; uncertainty surrounding the RES repeal; and our ability to obtain ACC approval of a formula rate plan with acceptable terms in response to our 2025 Rate Case.

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PART I

ITEM 1. FINANCIAL STATEMENTS

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in thousands)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Operating Revenues	$	565,841	$	544,515	$	1,337,227	$	1,317,495

Operating Expenses
Fuel and Purchased Power	177,050		161,928		391,722		393,950
Operations and Maintenance	112,641		115,526		354,191		326,712
Depreciation	67,313		59,183		189,726		175,021
Amortization	9,221		7,793		26,808		23,195
Taxes Other Than Income Taxes	18,479		18,414		56,178		55,471
Total Operating Expenses	384,704		362,844		1,018,625		974,349

Operating Income	181,137		181,671		318,602		343,146

Other Income (Expense)
Interest Expense	(29,326)		(29,652)		(88,450)		(91,013)
Allowance For Borrowed Funds	3,120		4,219		12,333		13,117
Allowance For Equity Funds	7,112		9,417		27,205		30,368
Unrealized Gains (Losses) on Investments	(804)		1,367		888		3,075
Interest Income	3,418		1,062		7,834		4,722
Other, Net	(1,346)		(1,187)		676		(2,811)
Total Other Income (Expense)	(17,826)		(14,774)		(39,514)		(42,542)

Income Before Income Tax Expense	163,311		166,897		279,088		300,604
Income Tax Expense	13,696		22,510		24,521		40,124
Net Income	$	149,615	$	144,387	$	254,567	$	260,480

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in thousands)


	Nine Months Ended September 30,
	2026		2025
Cash Flows from Operating Activities
Net Income	$	254,567	$	260,480
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	189,726		175,021
Amortization Expense	26,808		23,195

Amortization of Debt Issuance Costs	2,367		2,379
Use of Renewable Energy Credits for Compliance	37,497		37,257
Deferred Income Taxes	22,998		36,300

Pension and Other Postretirement Benefits Expense	8,864		13,532
Pension and Other Postretirement Benefits Funding	(15,306)		(13,967)

Allowance for Equity Funds Used During Construction	(27,205)		(30,368)




Sales of Investment Tax Credits	91,830		—
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(70,212)		(62,317)
Materials, Supplies, and Fuel Inventory	(9,462)		(20,411)
Regulatory Assets	2,813		(14,907)

Other Current Assets	(5,089)		(3,473)
Accounts Payable and Accrued Charges	61,683		40,138


Regulatory Liabilities	21,769		13,350
Other, Net	(47,193)		(2,476)
Net Cash Flows—Operating Activities	546,455		453,733
Cash Flows from Investing Activities
Capital Expenditures	(453,084)		(691,277)



Purchase Intangibles, Renewable Energy Credits	(43,921)		(44,304)


Contributions in Aid of Construction	41,340		7,684

Other	11,700		—
Net Cash Flows—Investing Activities	(443,965)		(727,897)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	215,000		100,000
Repayments of Borrowings, Revolving Credit Facility	(215,000)		(100,000)


Proceeds from Issuance, Long-Term Debt—Net of Discount	—		299,322

Dividends Paid to Parent	(150,000)		—

Payment of Debt Issuance Costs	(14)		(3,641)

Contributions from Parent	95,000		—
Other, Net	1,076		(805)
Net Cash Flows—Financing Activities	(53,938)		294,876
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	48,552		20,712
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	56,392		49,461
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	104,944	$	70,173

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

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	September 30, 2026		December 31, 2025
ASSETS
Utility Plant
Plant in Service	$	9,580,229	$	9,000,669

Construction Work in Progress	672,215		890,095
Total Utility Plant	10,252,444		9,890,764
Accumulated Depreciation and Amortization	(2,980,003)		(2,837,619)

Total Utility Plant, Net	7,272,441		7,053,145

Investments and Other Property	70,392		75,717

Current Assets
Cash and Cash Equivalents	81,326		26,192
Accounts Receivable (Net of Allowance for Credit Losses of $11,788 and $13,827 as of September 30, 2026 and December 31, 2025, respectively)	266,818		195,923
Fuel Inventory	54,785		59,281
Materials and Supplies	225,130		211,555
Regulatory Assets	115,223		126,836
Derivative Instruments	15,441		9,187

Other	37,376		31,864
Total Current Assets	796,099		660,838

Regulatory Assets	189,805		167,108
Derivative Instruments	16,391		21,123
Other Noncurrent Assets	191,554		161,339

Total Assets	$	8,536,682	$	8,139,270

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

(Continued)

TUCSON ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in thousands, except share data)


	September 30, 2026		December 31, 2025
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2026 and December 31, 2025)	$	1,906,539	$	1,811,539
Capital Stock Expense	(6,357)		(6,357)
Retained Earnings	1,754,862		1,650,295
Accumulated Other Comprehensive Loss	(6,597)		(6,930)
Total Common Stock Equity	3,648,447		3,448,547
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2026 and December 31, 2025)	—		—

Long-Term Debt, Net	2,794,278		2,792,642
Total Capitalization	6,442,725		6,241,189
Current Liabilities



Accounts Payable	163,708		128,540
Accrued Taxes Other than Income Taxes	85,324		58,410
Accrued Employee Expenses	44,264		42,383
Accrued Interest	37,144		23,627
Regulatory Liabilities	166,638		143,851
Customer Deposits	18,903		17,508
Derivative Instruments	18,414		31,143
Other	29,335		29,743
Total Current Liabilities	563,730		475,205

Deferred Income Taxes, Net	721,084		704,199
Regulatory Liabilities	486,892		419,132
Pension and Other Postretirement Benefits	53,706		54,158
Derivative Instruments	4,018		1,750
Asset Retirement Obligations	194,253		175,128
Other Noncurrent Liabilities	70,274		68,509
Total Liabilities	2,093,957		1,898,081

Commitments and Contingencies

Total Capitalization and Liabilities	$	8,536,682	$	8,139,270

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

(Concluded)

TUCSON ELECTRIC POWER COMPANY

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

(Amounts in thousands)


	Three Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of June 30, 2025	$	1,746,539	$	(6,357)	$	1,483,006	$	(3,908)	$	3,219,280
Net Income					144,387				144,387
Other Comprehensive Income (Loss), Net of Tax							54		54


Balances as of September 30, 2025	$	1,746,539	$	(6,357)	$	1,627,393	$	(3,854)	$	3,363,721


Balances as of June 30, 2026	$	1,906,539	$	(6,357)	$	1,605,247	$	(6,708)	$	3,498,721
Net Income					149,615				149,615
Other Comprehensive Income (Loss), Net of Tax							111		111



Balances as of September 30, 2026	$	1,906,539	$	(6,357)	$	1,754,862	$	(6,597)	$	3,648,447


	Nine Months Ended
	Common Stock		Capital Stock Expense		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholder's Equity
Balances as of December 31, 2024	$	1,746,539	$	(6,357)	$	1,366,913	$	(4,015)	$	3,103,080
Net Income					260,480				260,480
Other Comprehensive Income (Loss), Net of Tax							161		161



Balances as of September 30, 2025	$	1,746,539	$	(6,357)	$	1,627,393	$	(3,854)	$	3,363,721


Balances as of December 31, 2025	$	1,811,539	$	(6,357)	$	1,650,295	$	(6,930)	$	3,448,547
Net Income					254,567				254,567
Other Comprehensive Income (Loss), Net of Tax							333		333
Dividends Declared to Parent					(150,000)				(150,000)
Contributions from Parent	95,000								95,000

Balances as of September 30, 2026	$	1,906,539	$	(6,357)	$	1,754,862	$	(6,597)	$	3,648,447

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

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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 459,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the Western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

BASIS OF PRESENTATION

TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC's interim reporting requirements.

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and 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 on 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 2025 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. To conform with the current period presentation, TEP combined four prior period Operating Expense line items: (i) Fuel; (ii) Purchased Power; (iii) Transmission and Other PPFAC Recoverable Costs; and (iv) Increase (Decrease) to Reflect PPFAC Recovery Treatment, into a single line item titled Fuel and Purchased Power on the Condensed Consolidated Statements of Income. Additionally, TEP has reclassified Income Taxes Receivable/Payable in the prior period from a separately disclosed line into Other, Net on the Condensed Consolidated Statements of Cash Flows to conform with the current period presentation. Both the change in presentation and reclassification had no impact on TEP’s results of operation, financial position, or cash flows.

Variable Interest Entities

A 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 September 30, 2026, 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.

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 CODM is Susan M. Gray who holds the position of 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 $87 million and $275 million for the three and nine months ended September 30, 2026, respectively, and $91 million and $261 million for three and nine months ended September 30, 2025, 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.

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:


	Nine Months Ended September 30,
(in millions)	2026		2025
Cash and Cash Equivalents	$	81	$	43
Restricted Cash included in:
Investments and Other Property	16		20
Current Assets—Other	8		7
Cash, Cash Equivalents, and Restricted Cash, End of Period	$	105	$	70

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

TEP's effective tax rate for the three and nine months ended September 30, 2026, differed from the federal statutory tax rate primarily due to ITC amortization, including the incremental benefit associated with the Roadrunner Reserve II energy community bonus credit, and PTCs. The ITC benefit associated with Roadrunner Reserve II is being recognized in 2026, while recognition of the Roadrunner Reserve I ITC benefit is substantially deferred until the effective date of new rates as established in the 2025 Rate Case.

Investment Tax Credits

Roadrunner Reserve II was placed in service in June 2026 and has generated approximately $130 million of ITCs, which includes a 10% energy community bonus credit. The amount of ITCs generated is subject to adjustments to qualifying project costs. TEP recorded a deferred tax asset with a corresponding regulatory liability to reflect the anticipated return of benefits to customers. TEP also recorded a valuation allowance against the deferred tax asset reflecting the discount in proceeds from a planned sale of ITCs to a third-party.

In March 2026, TEP entered into an agreement to transfer ITCs related to Roadrunner Reserve II in the second half of 2026. In connection with the transfer of ITCs from Roadrunner Reserve II, TEP has agreed to provide customary indemnifications to the buyer for certain tax-related risks, including potential disallowance or recapture of credits. See Note 7 for additional information regarding tax credit transfer indemnifications. In July 2026, TEP transferred $50 million of the ITCs and received $46 million in cash proceeds. As of September 30, 2026, TEP had a $67 million deferred tax asset, net of the remaining $2 million valuation allowance, in Deferred Income Taxes, Net on the Condensed Consolidated Balance Sheets. On October 1, 2026, TEP transferred an additional $40 million of ITCs related to Roadrunner Reserve II and received $37 million in cash proceeds.

Roadrunner Reserve I was placed in service in July 2025 and generated $98 million of ITCs. TEP transferred $49 million of ITCs related to Roadrunner Reserve I in December 2025 and an additional $49 million of such ITCs in April 2026, receiving cash proceeds of $46 million for each transaction.

Production Tax Credits

TEP realized PTC benefits associated with Oso Grande of $11 million and $18 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2026, respectively, and $9 million and $17 million for the three and nine months ended September 30, 2025, respectively.

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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 reflected in TEP’s financial statements. Unless otherwise indicated, TEP is assessing the impact such guidance may have on TEP’s financial position, results of operations, cash flows, and disclosures.

Environmental Credits

In May 2026, the FASB issued accounting guidance that establishes accounting requirements for environmental credits and related obligations. The update introduces recognition, measurement, presentation, and disclosure requirements, including: (i) classification of credits based on intended use (compliance versus noncompliance); (ii) initial measurement at cost with subsequent measurement models varying based on classification; and (iii) recognition and measurement of environmental credit obligations based on a “linked” approach, which reflects the cost of credits on hand, contractual arrangements, or current market prices. The guidance also requires expanded disclosures, including the intended use of credits, changes in the intended use of credits, and the nature and measurement of related obligations. The update is effective for public business entities beginning with annual and interim reporting periods that start on or after January 1, 2028. Entities are required to apply the guidance on a retrospective basis, with a cumulative-effect adjustment recorded to the opening retained earnings. Early adoption is permitted.

Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, the FASB issued accounting guidance that updates the recognition criteria for internal-use software. The update removes references to software development project stages and requires capitalization of software costs once: (i) management has authorized and committed to funding the project; and (ii) it is probable that the project will be completed and the software will perform its intended function. Evaluating the probability that the project will be completed includes an assessment of whether significant development uncertainty exists. The amendment requires entities to apply the disclosure requirements applicable to property, plant, and equipment to all capitalized internal-use software costs, irrespective of financial statement presentation. The amendments are effective for annual and interim reporting periods beginning January 1, 2028. The guidance may be applied prospectively, retrospectively, or using a modified transition approach. Early adoption is permitted. TEP does not expect the amendments to have a material impact on its financial position, results of operations, cash flows or 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.

SEC Climate-Related Disclosures

In March 2024, the SEC issued final rules requiring disclosure of climate‑related risks and GHG emissions, which were subsequently stayed pending judicial review. In September 2025, the Court of Appeals for the Eighth Circuit paused its consideration of legal challenges to the rules, pending further action by the SEC. In May 2026, the SEC proposed rescinding the March 2024 climate-related disclosure rules in their entirety. The proposal was published in the Federal Register in June 2026, and the public comment period with respect to such proposed rescission ended in August 2026. No final action has been taken, and the rules remain stayed and are not currently effective. TEP does not expect the proposed rule to have a significant impact on TEP's financial position, results of operations, cash flows and disclosures.

NOTE 2. REGULATORY MATTERS

The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation 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.

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RATE CASE MATTERS

2025 Rate Case

In June 2025, TEP filed a general rate case with the ACC based on a test year ended December 31, 2024.

On October 20, 2026, an ACC ALJ issued a ROO in TEP's 2025 Rate Case. Key recommendations of the ROO include:

•a $114 million net increase in retail revenues comprised of the following components:

◦a non-fuel retail revenue increase of $160 million over test year non-fuel retail revenues;

◦a $26 million decrease in fuel-related retail revenues;

◦an $18 million decrease in retail revenues collected from the discontinuation or modification of certain existing adjustor mechanisms; and

◦a $2 million decrease in retail revenues due to a reduction in service fees;

•a 7.25% return on original cost rate base of $4.3 billion, which includes a return on equity of 9.65% and an average cost of debt of 4.28%;

•a capital structure for ratemaking purposes of approximately 55% common equity and 45% long-term debt;

•a new ARAM that is a formula rate adjustor designed to update rates annually based on historical changes in TEP's revenue requirement. The proposed ARAM includes:

◦an earnings test with a deadband of plus or minus 50 basis points around the allowed return;

◦the inclusion of six months of post-test year plant in the calculation; and

◦annual updates to the cost of debt and capital structure, while maintaining a fixed return on equity;

•an increase to the proportion of realized gains on trading transactions shared with retail customers through the PPFAC mechanism from 10% to 50%; and

•an accounting order to defer for future recovery certain incurred costs associated with owning, operating and maintaining Roadrunner Reserve II, offset by future benefits associated with ITCs.

The ROO also discontinues the TEAM and ECA mechanisms, continues the LFCR mechanism until all lost fixed costs incurred prior to the effective date of the new rates are fully recovered, and continues the DSM surcharge and RES tariff to recover remaining costs associated with the programs. The PPFAC and TCA mechanisms are largely unaffected by the ROO.

The ALJ issued an extension of the time allowed for the ACC to issue a final decision in the rate case, moving the deadline to November 17, 2026, and the ROO proposes new rates to be implemented by December 1, 2026. TEP cannot predict the outcome of this proceeding.

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 Customer Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Beginning of Period	$	(25)	$	(49)	$	(32)	$	(49)
Deferred Fuel and Purchased Power Costs (1)	99		110		235		243
PPFAC and Base Power Recoveries	(105)		(106)		(234)		(239)
End of Period	$	(31)	$	(45)	$	(31)	$	(45)

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

Transmission Cost Adjustor

The TCA 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 required Arizona regulated electric utilities to increase their use of renewable energy each year until it represented at least 15% of their total annual retail energy sales by the end of 2025. Consistent with prior years, TEP met these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. TEP recovers approved costs of meeting the requirements from retail customers through a RES tariff.

In May 2024, the ACC approved an extension of TEP's 2021 RES implementation plan 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 waived for TEP the general requirement that Arizona utilities file an annual RES implementation plan. The approved amount funds: (i) above market cost for renewable power purchases under agreements that were operational when the implementation plans were filed; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

In March 2026, the ACC issued an order repealing the RES. The order was submitted to the Arizona Attorney General for review, and in May 2026, the Arizona Attorney General provided notice of disapproval of the RES repeal. On October 7, 2026, an ACC ALJ issued a recommended order that would modify the March 2026 order and state that the Arizona Attorney General's approval is not required for the repeal. If approved, the ACC could submit the order repealing the RES directly to the Secretary of State of Arizona. TEP cannot predict the timing or outcome of this proceeding and is continuing to evaluate the potential impacts on its regulatory obligations and financial position. Until otherwise ordered, TEP will continue to operate under its existing RES implementation plan.

Energy Efficiency Standards

TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs 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.

In July 2026, the ACC issued an order repealing the EE Standards which becomes effective on November 23, 2026. In September 2026, the Arizona Attorney General filed a legal challenge, now pending in the Superior Court of Maricopa County, contesting the order. Until otherwise ordered, TEP will continue to operate under its existing energy efficiency implementation plan. The DSM surcharge will remain in effect until further order of the ACC. TEP does not expect the order to have a significant impact on its financial position, results of operations, or cash flows.

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

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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.

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)	September 30, 2026		December 31, 2025
Regulatory Assets
Pension and Other Postretirement Benefits (Note 8)	Various	$	88	$	91
Roadrunner Reserve I Accounting Order (1)	Various	44		16
Lost Fixed Cost Recovery	1	41		33
Early Generation Retirement Costs	Various	35		36
Property Tax Deferrals (2)	1	33		32
Transmission Revenue Requirement Balancing Account	2	20		32
Derivatives (Note 9)	3	15		23
Transportation Electrification and Electric Vehicle Infrastructure	Various	10		8
Self-Insured Medical & Short-Term Disability	1	7		7
Income Taxes Recoverable through Future Rates (3)	Various	4		4


Other Regulatory Assets	Various	8		12
Total Regulatory Assets		305		294
Less Current Portion	1	115		127
Total Noncurrent Regulatory Assets		$	190	$	167


Regulatory Liabilities
Income Taxes Payable through Future Rates (3)	Various	$	197	$	199
Deferred Investment Tax Credits (4)	Various	193		94
Renewable Energy Standard	Various	115		102
Net Cost of Removal (5)	Various	53		75
Pension and Other Postretirement Benefits (Note 8)	Various	31		32
Over-Recovered Fuel and Purchased Energy Costs	1	31		32
Demand Side Management	1	19		9
Derivatives (Note 9)	3	14		20
Other Regulatory Liabilities	Various	1		—
Total Regulatory Liabilities		654		563
Less Current Portion	1	167		144
Total Noncurrent Regulatory Liabilities		$	487	$	419

(1)In April 2025, the ACC issued an accounting order allowing TEP to defer for future recovery in the 2025 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 benefits associated with ITCs.

(2)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes.

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

(4)As federal ITCs are deferred, TEP records a regulatory liability to be refunded to customers. The ITCs associated with Roadrunner Reserve I were deferred pursuant to a deferral order and are expected to be amortized beginning on the effective date of new rates established in the 2025 Rate Case. Roadrunner Reserve II was not subject to a deferral order; therefore, amortization of the ITCs

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related to it began upon commercial operation. The ITCs associated with both facilities are amortized over five years and recorded as a reduction of income tax expense.

(5)Represents an estimate of the future cost of retirement, net of salvage value. The reserve is funded through ACC‑approved depreciation rates for transmission, distribution, generation, and general plant assets. These amounts are billed to customers but will not be spent until the assets are retired.

Regulatory assets are either being collected or are expected to be collected through Customer Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Transmission Revenue Requirement 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 II

In June 2026, Roadrunner Reserve II was placed in service. As of September 30, 2026, there were $360 million in costs related to Roadrunner Reserve II in Plant in Service on the Condensed Consolidated Balance Sheet. See 2025 Rate Case above for additional details related to TEP's request to defer certain incurred costs associated with Roadrunner Reserve II for future recovery. TEP intends to request recovery of Roadrunner Reserve II costs in its next ARAM filing, subject to approval of the ARAM in the 2025 Rate Case.

NOTE 3. 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 September 30,				Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Retail	$	433	$	434	$	1,006	$	994
Wholesale	75		61		165		166
Other Services	30		26		92		75
Revenues from Contracts with Customers	538		521		1,263		1,235
Alternative Revenues	1		14		18		38
Other	27		10		56		44
Total Operating Revenues	$	566	$	545	$	1,337	$	1,317

NOTE 4. ACCOUNTS RECEIVABLE

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


(in millions)	September 30, 2026		December 31, 2025
Retail	$	157	$	107
Retail, Unbilled	60		47
Retail, Allowance for Credit Losses	(12)		(14)
Wholesale (1)	31		33
Due from Affiliates (Note 5)	12		9
Other	19		14
Accounts Receivable, Net	$	267	$	196

(1)Includes $10 million as of September 30, 2026 and December 31, 2025, of receivables related to revenue from derivative instruments.

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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 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 September 30,				Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Beginning of Period	$	(11)	$	(11)	$	(14)	$	(13)
Credit Loss Expense	(2)		(3)		(4)		(5)
Write-offs	1		1		6		5

End of Period	$	(12)	$	(13)	$	(12)	$	(13)

NOTE 5. RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services.

The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:


(in millions)	September 30, 2026		December 31, 2025
Receivables from Related Parties
UNS Electric	$	8	$	7
UNS Gas	2		2
UNS Energy	2		—








Total Due from Related Parties	$	12	$	9

Payables to Related Parties
UNS Electric	$	2	$	1
UNS Energy	1		4





Total Due to Related Parties	$	3	$	5

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Goods and Services Provided by TEP to Affiliates
Common Costs, UNS Energy Affiliates (1)	$	7	$	7	$	21	$	19
Transmission Revenues, UNS Electric (2)	2		2		6		6
Control Area Services, UNS Electric (3)	1		1		2		2
Wholesale Revenues, UNS Electric (2)	1		1		2		2


Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (4)	$	2	$	1	$	8	$	7
Purchased Power, UNS Electric (2)	1		1		2		2
Corporate Services, UNS Energy Affiliates (5)	1		—		2		1
Capacity Charges, UNS Gas (6)	—		—		1		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.

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

(4)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 were $2 million and $7 million for the three and nine months ended September 30, 2026, respectively, and $1 million and $6 million for the three and nine months ended September 30, 2025, respectively.

(5)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

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

NOTE 6. DEBT AND CREDIT AGREEMENT

There have been no significant changes to TEP's debt or credit agreements since December 31, 2025, except as noted below.

CREDIT AGREEMENTS

2021 Credit Agreement

In September 2026, TEP amended and reduced a $5 million LOC with fees accruing at a rate of 1.025% per annum to less than $1 million. As of September 30, 2026, TEP had $241 million available under the 2021 Credit Agreement, which reflected no outstanding revolver borrowings and $9 million of LOCs, with fees that accrued at a rate of 1.025% per annum. On October 15, 2026, the 2021 Credit Agreement revolving credit and LOC facility was amended and restated by the 2026 Credit Agreement as described below.

2026 Credit Agreement

On October 15, 2026, the 2021 Credit Agreement was amended and restated. The 2026 Credit Agreement is an unsecured credit agreement with a maturity date of October 2031 that provides for revolving credit and LOC facilities and allows for two one-year extensions if certain conditions are satisfied. Terms of the 2026 Credit Agreement include a: (i) $350 million revolving credit facility, with a $15 million swingline sublimit; and (ii) $50 million LOC sublimit. Interest rates and fees are based on a pricing grid tied to TEP's credit ratings. Amounts borrowed under the 2026 Credit Agreement will be 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. On October 22, 2026, TEP amended and reduced a $1 million LOC with fees accruing at a rate of 1.000% per annum to less than $1 million. As of November 2, 2026, there was $342 million available under the 2026 Credit Agreement, which reflects no outstanding revolver borrowings and $8 million of LOCs, with fees accruing at a rate of 1.000% per annum.

NOTE 7. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

There have been no significant changes to TEP's long-term commitments since December 31, 2025, except as noted below.

Purchase Commitments

Renewable Power Purchase Agreements

In March 2026, a renewable PPA facility with 160 MW of solar capacity was placed in service. In April 2026, an additional facility with 100 MW of solar capacity and 100 MW of battery storage (400 MWh of energy capacity) was placed in service.

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CONTINGENCIES

Legal Matters

TEP is involved in various legal proceedings that arise in the ordinary course of business. These matters include, from time to time, claims for punitive or exemplary damages. Based on currently available information, TEP does not believe that the outcome of these proceedings will have a material adverse effect on TEP's financial position, results of operations, or cash flows.

Mine Reclamation at Generation Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs for coal mines that supply generation facilities where TEP holds an ownership interest but is not the operator. The estimated liability for final mine reclamation depends on assumptions, such as projected costs, timing, and inflation. When these assumptions change, TEP adjusts future expense recognition over the remaining term of the applicable coal supply agreement. TEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as part of fuel costs. Therefore, TEP defers these expenses by recording a regulatory asset and a reclamation liability over the remaining life of the respective coal supply agreement. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, any changes in the estimated liability are recorded to both the regulatory asset and reclamation liability.

TEP is responsible for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP’s liability related to Four Corners totaled $2 million and $3 million as of September 30, 2026, and December 31, 2025, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP's Four Corners coal supply agreement expires in 2031.

TEP ceased operations at San Juan in 2022 following expiration of its coal supply agreement. TEP’s remaining final mine reclamation liability at San Juan was $17 million and $23 million as of September 30, 2026, and December 31, 2025, 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 that will remain in effect until reclamation activities are completed, which are currently projected to be completed in 2040. See Note 1 for additional information on restricted cash related to reclamation and decommissioning costs at San Juan.

Tax Credit Transfer Indemnification

In connection with the transfer of federal ITCs, TEP provided indemnities to the purchaser for certain losses arising from the disallowance, reduction, or recapture of the transferred ITCs. TEP’s maximum exposure under these indemnities is limited to 125% of the transferred ITCs. The indemnities remain in effect through the applicable tax statute of limitations period, plus 90 days. As of September 30, 2026, no claims had been asserted, and no liability had been recorded.

FERC Market-Based Rate Authority

On October 30, 2026, FERC issued an order revoking TEP’s market-based rate authority for wholesale power sales within the TEP balancing authority area. As a result, such sales are required to be made at FERC-approved cost-based rates. The order establishes a refund date of January 29, 2026, and requires refunds to any applicable wholesale power purchasers of amounts collected above the applicable cost-based rate.

TEP is evaluating the affected transactions and the applicable cost-based rates in response to the FERC order to determine the amount of any refunds that may be required. Any such refunds are expected to be eligible for recovery through the PPFAC. TEP is also considering whether to propose tailored mitigation that, if approved by the FERC, would apply prospectively as an alternative to cost-based rates. TEP does not expect the FERC order and related refunds to have a material impact on its financial position, results of operations, cash flows and disclosures.

Performance Guarantees

TEP participates in joint generation agreements at Four Corners and Luna, which expire in 2041 and 2046, respectively. Under these agreements, all participants, including TEP, guarantee certain performance obligations. If a participant defaults on payment, the non-defaulting participants must cover a proportionate share of expenses otherwise payable by the defaulting participant. In return, the non-defaulting participants are entitled to receive a proportionate share of the defaulting participant's generation capacity. For Luna, there is no maximum potential payment under this guarantee. For Four Corners, the maximum potential payment for non-defaulting participants is $250 million. As of September 30, 2026, no payment defaults have occurred under either agreement.

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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 on these continuing obligations, the non-defaulting participants are entitled to seek financial recovery directly from the defaulting party.

Environmental Matters

TEP operates under federal, state, and local environmental laws and regulations covering air and water quality, renewable portfolio standards, emissions performance, 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. These requirements are subject to interpretation and may be clarified by court decisions. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations or consolidated financial results. TEP expects to recover environmental compliance costs through customer rates. TEP believes it is in material compliance with applicable environmental laws and regulations.

NOTE 8. EMPLOYEE BENEFITS PLANS

Net periodic benefit cost includes the following components:


	Pension Benefits				Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2026		2025		2026		2025
Service Cost	$	4	$	4	$	—	$	1
Non-Service Cost (1)
Interest Cost	6		7		1		1
Expected Return on Plan Assets	(9)		(8)		(1)		(1)
Amortization of Net Loss	1		1		—		—
Net Periodic Benefit Cost	$	2	$	4	$	—	$	1



	Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Service Cost	$	12	$	11	$	2	$	3
Non-Service Cost (1)
Interest Cost	19		19		2		3
Expected Return on Plan Assets	(26)		(23)		(2)		(2)
Amortization of Net Loss	3		4		(1)		(1)
Net Periodic Benefit Cost	$	8	$	11	$	1	$	3

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

NOTE 9. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS

TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS

The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:


	Level 1		Level 2		Total
(in millions)	September 30, 2026
Assets
Cash Equivalents (1)	$	60	$	—	$	60
Restricted Cash (1)	24		—		24
Energy Derivative Contracts, Regulatory Recovery (2)	—		20		20
Energy Derivative Contracts, No Regulatory Recovery (2)	—		12		12
Total Assets	84		32		116
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(22)		(22)

Total Liabilities	—		(22)		(22)
Total Assets (Liabilities), Net	$	84	$	10	$	94


(in millions)	December 31, 2025
Assets

Restricted Cash (1)	$	30	$	—	$	30
Energy Derivative Contracts, Regulatory Recovery (2)	—		28		28
Energy Derivative Contracts, No Regulatory Recovery (2)	—		2		2
Total Assets	30		30		60
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)	—		(33)		(33)


Total Liabilities	—		(33)		(33)
Total Assets (Liabilities), Net	$	30	$	(3)	$	27

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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis 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)	September 30, 2026
Derivative Assets
Energy Derivative Contracts	$	32	$	11	$	—	$	21
Derivative Liabilities
Energy Derivative Contracts	(22)		(11)		—		(11)


(in millions)	December 31, 2025
Derivative Assets
Energy Derivative Contracts	$	30	$	17	$	—	$	13
Derivative Liabilities
Energy Derivative Contracts	(33)		(17)		—		(16)

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.

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 September 30,				Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Unrealized Net Gain (Loss)	$	4	$	(21)	$	3	$	(1)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 September 30,				Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Operating Revenues	$	6	$	2	$	21	$	23

Derivative Volumes

As of September 30, 2026, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:


	September 30, 2026	December 31, 2025
Power Contracts GWh	5,283	1,430
Gas Contracts BBtu	63,845	72,959

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 $24 million as of September 30, 2026, compared with $31 million as of December 31, 2025. TEP had no cash posted as collateral to provide credit enhancement as of September 30, 2026, and December 31, 2025. TEP would have been required to post $24 million and $31 million of collateral if the credit risk contingent features had been triggered on September 30, 2026, and December 31, 2025, respectively. TEP had $15 million and $16 million in outstanding net payable balances for settled positions as of September 30, 2026, and December 31, 2025, respectively.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

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


	Fair Value Hierarchy	Net Carrying Value				Fair Value
(in millions)		September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025
Liabilities
Long-Term Debt, including Current Maturities	Level 2	$	2,794	$	2,793	$	2,317	$	2,532

NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION

CASH TRANSACTIONS


	Nine Months Ended September 30,
(in millions)	2026		2025
Interest Paid, Net of Amounts Capitalized	$	67	$	59
Income Taxes Paid (Net of Refunds) (1)(2)	(89)		3

(1)Reflects payments to UNS Energy under a tax sharing agreement.

(2)In April 2026, TEP sold ITCs related to Roadrunner Reserve I and received $46 million in cash proceeds. In July 2026, TEP sold ITCs related to Roadrunner Reserve II and received $46 million in cash proceeds. On October 1, 2026, TEP sold additional ITCs related to Roadrunner Reserve II and received $37 million in cash proceeds, which are not reflected in the amount presented in the table above. See Note 1 for additional information regarding ITCs.

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:


	Nine Months Ended September 30,
(in millions)	2026		2025
Accrued Capital Expenditures	$	59	$	42
Asset Retirement Obligations Increase (Decrease)	10		5
Renewable Energy Credits	3		4



Operating Leases	2		—

Net Cost of Removal Increase (Decrease) (1)	(10)		(16)

(1)Represents the change in accrual for future retirement costs, net of salvage values. This change does not impact earnings.

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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 I, Item 1A of our 2025 Annual Report on Form 10-K, and in Part II, Item 1A of this Quarterly Report on Form 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, and changes in governmental policies, programs, and priorities, such as energy policy, as well as their impact on the factors listed above. Our plans and strategies include:

•Maintaining affordable rates and reliable service for our customers while promoting economic development within our service territory to enable prosperity in the communities we serve.

•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. While we still intend to exit all ownership interests in coal-fired generation by 2032, we will no longer meet our interim goal of reducing carbon emissions by 80% from 2005 levels by 2035 due to changing market conditions. Our ability to achieve net zero direct GHG emissions by 2050 could be impacted by various federal and state energy policies, significant load growth, and the pace of clean-energy technology development.

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

Performance - The third quarter of 2026 compared with the third quarter of 2025

We reported net income of $150 million in the third quarter of 2026 compared with net income of $144 million in the third quarter of 2025. The increase of $6 million, or 4%, was primarily due to (net of tax):

•$9 million in lower income tax expense due to higher amortization of ITCs;

•$4 million in higher margin from other revenue primarily due to the net impact of consenting to the use of certain transmission corridor rights, with the favorable impact expected to be substantially offset by related lower revenues through year-end;

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•$3 million in lower base operations and maintenance expenses primarily due to lower employee benefits expenses driven in part by timing;

•$2 million in higher interest income associated with customer prepayments; and

•$2 million in higher margin from transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base.

The increase was partially offset by:

•$9 million in higher depreciation expense primarily due to an increase in asset base;

•$3 million in lower AFUDC due to a decrease in eligible construction expenditures;

•$2 million decrease due to unfavorable market conditions that decreased the value of investments used to support certain post-employment benefits; and

•$1 million in lower margin from retail revenue primarily due to milder weather; partially offset by an increase in industrial sales and customer growth.

Performance - The first nine months of 2026 compared with the first nine months of 2025

We reported net income of $255 million in the first nine months of 2026 compared with net income of $260 million in the first nine months of 2025. The decrease of $5 million, or 2%, was primarily due to (net of tax):

•$17 million in higher depreciation expense primarily due to an increase in asset base;

•$13 million in higher base operations and maintenance expenses primarily due to higher operation and maintenance expenses at our generation facilities, higher outside services expenses, and higher employee wages expenses net of a decrease in employee benefits expense;

•$8 million in lower margin from wholesale transactions primarily due to decreased long-term wholesale sales volumes due to unfavorable market conditions; and

•$4 million in lower AFUDC due to a decrease in eligible construction expenditures.

The decrease was partially offset by:

•$14 million in lower income tax expense due to higher amortization of ITCs;

•$7 million in higher margin from retail revenue primarily due to an increase in industrial sales and customer growth; partially offset by milder weather;

•$6 million in higher margin from other revenue primarily due to the net impact of consenting to the use of certain transmission corridor rights, with the favorable impact expected to be substantially offset by related lower revenues through year-end;

•$4 million in lower non-service components of net periodic benefit cost primarily due to a decrease in interest cost and an increase in expected return on plan assets;

•$3 million in higher margin from transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base; and

•$3 million in higher interest income associated with customer prepayments.

FACTORS AFFECTING RESULTS OF OPERATIONS

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

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Regulatory Matters

We are subject to comprehensive regulation. The following discussion describes material regulatory developments, market participation initiatives, and government actions that affect our business.

2025 Rate Case

In June 2025, we filed a general rate case with the ACC based on a test year ended December 31, 2024.

On October 20, 2026, an ACC ALJ issued a ROO in our 2025 Rate Case. Key recommendations of the ROO include:

•a $114 million net increase in retail revenues comprised of the following components:

◦a non-fuel retail revenue increase of $160 million over test year non-fuel retail revenues,

◦a $26 million decrease in fuel-related retail revenues;

◦an $18 million decrease in retail revenues collected from the discontinuation or modification of certain existing adjustor mechanisms; and

◦a $2 million decrease in retail revenues due to a reduction in service fees;

•a 7.25% return on original cost rate base of $4.3 billion, which includes a return on equity of 9.65% and an average cost of debt of 4.28%;

•a capital structure for ratemaking purposes of approximately 55% common equity and 45% long-term debt;

•a new ARAM that is a formula rate adjustor designed to update rates annually based on historical changes in our revenue requirement. The proposed ARAM includes:

◦an earnings test with a deadband of plus or minus 50 basis points around the allowed return;

◦the inclusion of six months of post-test year plant in the calculation; and

◦annual updates to the cost of debt and capital structure, while maintaining a fixed return on equity;

•an increase to the proportion of realized gains on trading transactions shared with retail customers through the PPFAC mechanism from 10% to 50%; and

•an accounting order to defer for future recovery certain incurred costs associated with owning, operating and maintaining Roadrunner Reserve II, offset by future benefits associated with ITCs.

Roadrunner Reserve I Accounting Order

In April 2025, the ACC issued an accounting order allowing us to defer for future recovery in the 2025 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 benefits associated with ITCs. As of September 30, 2026, we have deferred $44 million of eligible costs, net of benefits under this accounting order.

ACC Formula Rate Plan Policy

In December 2024, the ACC adopted a formula rate policy statement that provides a framework for 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

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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 reducing the reliance on and number of adjustor mechanisms.

In February 2026, the ACC approved the implementation of an ARAM as part of UNS Gas’s rate case, representing the first approval of a formula rate mechanism under the policy. In May 2026, RUCO appealed the ACC’s rate case decision, seeking to overturn the approval of UNS Gas's ARAM. The appeal is currently pending before the Arizona Court of Appeals.

Separately, RUCO has challenged the ACC's authority to implement the formula rate framework through a policy statement, and in November 2025, the Arizona Court of Appeals ruled that RUCO may proceed with its challenge. In September 2026, the Superior Court of Maricopa County stayed the proceeding pending resolution of the UNS Gas rate case appeal, and RUCO petitioned the Arizona Supreme Court to block implementation of the formula rate policy. We are unable to predict the timing or outcome of these regulatory and legal processes. The ACC has previously approved adjustor mechanisms, including formula-based mechanisms, in rate cases.

Southwest Power Pool Markets+

In November 2024, we and other Arizona utilities announced plans to join Southwest Power Pool Markets+, a day-ahead and real-time wholesale energy market, with anticipated participation as early as 2027. The FERC conditionally approved the Markets+ tariff in January 2025. In April 2025, the FERC accepted the funding agreement signed by us and other participating utilities to support the market's development and implementation. Our participation in Markets+ is expected to: (i) reduce our cost to serve customers; (ii) increase access to clean energy resources; and (iii) enhance system reliability.

Renewable Energy and Electric Energy Efficiency Standards Repeal

In January 2024, the ACC opened dockets to review the RES and EE Standards. The ACC's RES required Arizona regulated electric utilities to increase their use of renewable energy each year until it represented at least 15% of their total annual retail energy sales by the end of 2025, with a portion sourced from customer-sited DG. Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption.

In March 2026, the ACC issued an order repealing the RES. The order was submitted to the Arizona Attorney General for review, and in May 2026, the Arizona Attorney General provided notice of disapproval of the RES repeal. On October 7, 2026, an ACC ALJ issued a recommended order that would modify the March 2026 order and state that the Arizona Attorney General's approval is not required for the repeal. If approved, the ACC could submit the order repealing the RES directly to the Secretary of State of Arizona. We cannot predict the timing or outcome of this proceeding and are continuing to evaluate the potential impacts on our regulatory obligations and financial position. Until otherwise ordered, we will continue to operate under our existing RES implementation plan.

In July 2026, the ACC issued an order repealing the EE Standards which becomes effective on November 23, 2026. In September 2026, the Arizona Attorney General filed a legal challenge, now pending in the Superior Court of Maricopa County, contesting the order. Until otherwise ordered, we will continue to operate under our existing energy efficiency implementation plan. The DSM surcharge will remain in effect until further order of the ACC. We do not expect the order to have a significant impact on our financial position, results of operations, or cash flows.

City of Tucson Energy Sourcing Study

The City of Tucson engaged a consulting and engineering firm to analyze alternatives to our provision of electric service, including a study of a potential municipal electric utility. An initial draft of the study, published in April 2025, suggested that a city-owned utility serving primarily Tucson customers could offer potential customer savings, but also noted that the City of Tucson would assume significant risks and incur substantial costs if it pursued municipalization. These costs would include purchasing property and plant at fair value and separating our remaining electrical grid from the City of Tucson.

In February 2026, The Brattle Group released an analysis commissioned by us concluding that the establishment of a municipal electric utility would be expected to result in higher energy costs for city residents and businesses.

In March 2026, the Tucson Mayor and City Council rejected a proposal that would have directed city staff to pursue the creation of a municipal electric utility. Instead, the Mayor and Council voted to direct the City's Commission on Climate, Energy, and Sustainability to engage with stakeholders and evaluate that potential option, along with other public power alternatives, to inform future policy considerations.

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Energy Collaboration Agreement

In April 2026, the City of Tucson approved an energy collaboration agreement with us that establishes a framework for collaboration on energy reliability, affordability, clean energy, and community resilience. The agreement is contingent upon voter approval of a new franchise agreement at the November 3, 2026 general election. Both the energy collaboration agreement and franchise agreement have 25‑year terms. Under the energy collaboration agreement, our annual contributions will begin at $2 million and increase by 2% every year to support agreed‑upon initiatives, with payments excluded from recovery through customer rates.

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 planning to exit ownership interests in coal-fired generation by 2032. Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply, and land lease contract extensions. Given these uncertainties and the need to economically replace such generation to support anticipated load, we plan to convert Springerville Units 1 and 2 from coal-fired generation to natural gas-fired generation by 2030. This conversion will allow us to leverage existing infrastructure with the development of replacement energy sources while also furthering our goals of ending our use of coal-fired generation and supporting both customer affordability and reliability. We will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of the conversion of Springerville Units 1 and 2 and our planned exit from Four Corners in 2031. In March 2026, the ACC approved an amendment to the facility’s Certificate of Environmental Compatibility to permit the conversion of Springerville Units 1 and 2 from coal‑fired to natural gas‑fired generation. This regulatory approval advances our plans to extend the operational life of the units and support long‑term system reliability.

On October 30, 2026, we filed with the ACC our 2026 IRP, which outlines our plan to meet customers' projected energy needs over the next fifteen years while maintaining reliability, supporting affordability, and continuing progress toward our aspirational goal of achieving net zero direct GHG emissions by 2050, as established in our 2023 IRP.

In March 2026, we issued an ASRFP to solicit capacity and energy resources for the purpose of supporting growth opportunities. We are in the process of evaluating the proposals.

Babacomari North was placed in service in March 2026 with 160 MW of solar capacity, and Wilmot II was placed in service in April 2026 with 100 MW of solar capacity and 100 MW of battery storage (400 MWh of energy capacity), both under existing power purchase agreements. Roadrunner Reserve II, a standalone BESS facility with a nominal capacity of 200 MW and energy capacity of 800 MWh, was placed in service in June 2026.

Nuclear Generation

In collaboration with other Arizona electric utilities, we are assessing the potential role of nuclear generation as a long-term carbon-free energy resource to support Arizona's growth in electricity demand. In April 2026, the utilities entered into a memorandum of understanding that establishes a framework for site evaluation and preliminary permitting activities. A siting study is currently underway and is expected to be complete by the end of the year. In May 2026, the utilities were notified that their previously filed application for a U.S. Department of Energy grant, intended to help support the multi-year site selection process and potential permitting preparation, was not selected. Once the current siting study concludes, we will evaluate technical, financial, and other factors before determining whether to develop and submit an Early Site Permit application to the U.S. Nuclear Regulatory Commission for approval. These efforts are in the early exploratory stage, are subject to regulatory approvals and funding availability, and may not result in the development of a nuclear facility.

Production Tax Credits

PTCs are federal tax credits earned per-kWh of electricity generated using qualified energy resources for a 10-year period after a qualifying facility is placed in service. In 2021, Oso Grande, a qualifying 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 $11 million and $18 million in PTCs related to Oso Grande for the three and nine months ended September 30, 2026, respectively, and $9 million and $17 million for the three and nine months ended September 30, 2025, respectively. The PTC rate published by the IRS for wind facilities placed in service prior to 2022 is $0.031 for 2026 and was $0.030 for 2025.

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Electricity generated from Oso Grande depends heavily on wind conditions. If actual conditions differ from our estimates, or if operational constraints arise, including insufficient transmission capacity to deliver the electricity, then the project's generation and associated PTCs may vary significantly from prior periods.

Pipeline Expansion Agreements

In April 2026, to support system reliability, facilitate the conversion of Springerville Units 1 and 2 to natural gas-fired generation, and meet future load growth, we entered into a 20-year gas transportation precedent agreement and amended an existing 25-year agreement to secure reliable access to natural gas. The agreements support the development of new third-party pipelines. Subject to the receipt of required regulatory approvals and other conditions, the pipelines are expected to be in service by late 2029.

Once the pipelines enter commercial operation, we will enter into related gas transportation service agreements with estimated purchase commitments of approximately $2.6 billion over 25 years and $1.0 billion over 20 years.

Sales Growth and Seasonality

Our average retail sales have 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 and higher transmission and distribution infrastructure investments beyond those reflected in the base assumption of our 2026 IRP. Our 2026 IRP includes a high load factor customer scenario to evaluate the potential resource needs associated with significant load growth.

In addition to the ESA described below, we are analyzing additional requests from existing and potential new large retail customers and cannot predict the quantity or timing of the energy demand, if any, that may result.

Energy Supply Agreement

In 2025, we reached an agreement to serve a data center campus expected to be located in our service territory, requiring potential power demand of approximately 300 MW. The ACC approved the ESA in December 2025. The ESA provides additional consumer protections such as establishing minimum monthly payment obligations that apply irrespective of customer energy use, authorizing termination fees supported by financial assurance mechanisms, and imposing credit standards designed to mitigate the risk of default. In April 2026, the parties satisfied or waived all remaining contingencies and conditions precedent under the ESA. Under the terms of the ESA, a $40 million termination payment is required if the ESA is terminated by the customer prior to the commencement of electric service, which is secured by a $40 million LOC that we received in April 2026.

In February 2026, the Arizona Attorney General and the City of Tucson filed legal challenges, now pending in the Superior Court of Maricopa County, contesting the ACC’s approval of the ESA. In June 2026, the ACC filed a motion to dismiss these proceedings, and in July 2026, we filed our own motion to dismiss. In September 2026, oral arguments were held, and on October 1, 2026, the Superior Court denied the motions to dismiss and ordered further briefing on the merits of the case. We cannot predict the timing or outcome of these proceedings.

Separately, we entered into a project construction agreement to develop transmission and switchyard facilities to provide retail electric service to the customer. The FERC accepted the original project construction agreement in September 2025. In April 2026, we executed an amended and restated project construction agreement to reflect the change of location of the switchyard. The amended and restated project construction agreement requires the customer to pre-fund all project costs. In June 2026, the FERC accepted the amended and restated project construction agreement, triggering a $20 million advance payment from the customer thereunder. The payment reduced construction work in progress by $17 million and resulted in the recognition of $3 million in interest income. In September 2026, we received an additional $24 million advance payment from the customer. The payment reduced construction work in progress by $21 million and resulted in the recognition of $3 million in interest income.

In August 2026, we executed a second amended and restated project construction agreement to reflect a revised scope of work and to include additional indemnity and insurance provisions. On October 26, 2026, the FERC accepted the second amended and restated project construction agreement.

The data center campus is projected to be operational as early as 2027, with a ramp schedule through 2029. We currently expect to serve this retail customer from our existing and planned generation resources.

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Weather Patterns

Changing weather patterns and other factors cause seasonal fluctuations in power sales. Our retail sales are highest in the second and third quarters 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 quarters and lower operating income in the first and fourth quarters.

Interest Rates

See Part II, Item 7A in our 2025 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 in the third quarter and first nine months of 2026 compared with the same periods in 2025 presented on a pre-tax basis.

Operating Revenues

The following table provides a disaggregation of Operating Revenues:


	Three Months Ended September 30,				Increase (Decrease)		Nine Months Ended September 30,				Increase (Decrease)
(in millions)	2026		2025		Percent		2026		2025		Percent
Operating Revenues
Retail	$	433	$	434	(0.2)	%	$	1,006	$	994	1.2	%
Wholesale, Long-Term	8		15		(46.7)	%	27		43		(37.2)	%
Wholesale, Short-Term (1)	57		33		72.7	%	112		100		12.0	%
Transmission	17		15		13.3	%	47		45		4.4	%
Springerville Units 3 and 4 Participant Billings	26		23		13.0	%	82		64		28.1	%
Other	25		25		—	%	63		71		(11.3)	%
Total Operating Revenues	$	566	$	545	3.9	%	$	1,337	$	1,317	1.5	%

(1)Includes revenue realized from wholesale trading as defined in the PPFAC plan of administration of $6 million and $21 million for the three and nine months ended September 30, 2026, respectively, and $2 million and $23 million for the three and nine months ended September 30, 2025, respectively. We share 10% of any realized gains on trading transactions with retail customers through the PPFAC mechanism. The 2025 Rate Case includes a proposed increase in the proportion of realized wholesale trading gains shared with retail customers through the PPFAC mechanism from 10% to 50%, which would reduce the amount of such gains retained by TEP in 2027 and future periods. In addition, 2026 wholesale trading revenues were higher than historical levels due to market conditions that may not continue. As trading revenues are influenced by market factors outside our control, including price volatility and regional supply and demand, 2026 results may not be indicative of future periods.

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We reported Operating Revenues of $566 million in the third quarter of 2026 compared with $545 million in the same period for 2025. The increase of $21 million, or 4%, was primarily due to:

•$24 million in higher short-term wholesale revenue primarily due to an increase in price, an increase in volume due to an increase in generation capacity available under PPAs and battery resources, and an increase in revenues from wholesale trading, as defined in the PPFAC plan of administration;

•$3 million in higher Springerville Unit 4 participant billings primarily due to higher reimbursable repair and maintenance costs; and

•$2 million in higher transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base.

The increase was partially offset by:

•$7 million in lower long-term wholesale revenue primarily due to a decrease in volume due to unfavorable market conditions resulting in lower demand from certain customers and a decrease in price; and

•$1 million in lower retail revenue primarily due to milder weather; partially offset by an increase in industrial sales and customer growth.

We reported Operating Revenues of $1,337 million for the first nine months of 2026 compared with $1,317 million in the same period for 2025. The increase of $20 million, or 2%, was primarily due to:

•$18 million in higher Springerville Unit 3 and Unit 4 participant billings primarily due to higher reimbursable repair and maintenance costs primarily for a Unit 3 planned outage;

•$12 million in higher retail revenue primarily due to an increase in industrial sales and customer growth; partially offset by milder weather, lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate, and a decrease in RES tariff and DSM surcharge revenues due to lower program expenses;

•$12 million in higher short-term wholesale revenue primarily due to higher volumes as a result of an increase in generation capacity available under PPAs and battery resources; and

•$2 million in higher transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base.

The increase was partially offset by:

•$16 million in lower long-term wholesale revenue primarily due to a decrease in volume due to unfavorable market conditions resulting in lower demand from certain customers; and

•$8 million in lower other revenue primarily due to lower TCA revenue.

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The following table provides key statistics impacting Operating Revenues:


	Three Months Ended September 30,		Increase (Decrease)		Nine Months Ended September 30,		Increase (Decrease)
(kWh in millions)	2026	2025	Percent		2026	2025	Percent
Electric Sales (kWh) (1)
Retail Sales	3,037	3,057	(0.7)	%	7,149	7,030	1.7	%
Wholesale, Long-Term	126	195	(35.4)	%	370	642	(42.4)	%
Wholesale, Short-Term	1,311	1,126	16.4	%	3,323	2,840	17.0	%
Total Electric Sales	4,474	4,378	2.2	%	10,842	10,512	3.1	%

Average Revenue (cents per kWh) (2)
Retail	14.27	14.20	0.5	%	14.07	14.15	(0.6)	%
Wholesale, Long-Term	6.05	7.66	(21.0)	%	7.24	6.71	7.9	%
Wholesale, Short-Term	3.88	3.14	23.6	%	2.74	2.87	(4.5)	%

Total Retail Customers (3)					459,247	456,330	0.6	%

(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 average number of active service agreements during each period. Management uses this count to monitor the growth of retail customers.

Operating Expenses

Fuel and Purchased Power Expense

We reported Fuel and Purchased Power expense of $177 million in the third quarter of 2026 compared with $162 million in the same period for 2025. The increase of $15 million, or 9%, was primarily due to:

•$8 million in higher PPFAC recovery treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; and

•$7 million in higher transmission and other PPFAC recoverable costs primarily due to an increase in energy storage expense and an increase in transmission service expense.

The increase was partially offset by $3 million in lower purchased power expense primarily due to a decrease in short-term volumes; partially offset by an increase in renewable PPA purchases.

We reported Fuel and Purchased Power expense of $392 million for the first nine months of 2026 compared with $394 million for the same period for 2025. The decrease of $2 million, or 1%, was primarily due to $29 million in lower fuel expenses primarily due to a decrease in gas prices and a decrease in Gas-Fired Generation volumes; partially offset by higher realized losses on natural gas swaps and an increase in Coal-Fired Generation volumes.

The decrease was partially offset by:

•$20 million in higher transmission and other PPFAC recoverable costs primarily due to an increase in transmission service expenses related to a FERC rate case credit that was received in January 2025 and an increase in energy storage expense;

•$3 million in higher PPFAC recovery treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery, partially offset by a decrease in PPFAC recoveries; and

•$3 million in higher purchased power expense primarily due to an increase in renewable PPA purchases; partially offset by a decrease in short-term volumes.

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


	Three Months Ended September 30,		Increase (Decrease)		Nine Months Ended September 30,		Increase (Decrease)
(kWh in millions)	2026	2025	Percent		2026	2025	Percent
Sources of Energy
Coal-Fired Generation	1,063	1,011	5.1	%	2,379	2,135	11.4	%
Gas-Fired Generation	2,577	2,584	(0.3)	%	5,553	5,794	(4.2)	%
Utility-Owned Renewable Generation	156	146	6.8	%	540	514	5.1	%
Total Generation	3,796	3,741	1.5	%	8,472	8,443	0.3	%


Purchased Power	904	815	10.9	%	2,901	2,527	14.8	%
Total Generation and Purchased Power (1)	4,700	4,556	3.2	%	11,373	10,970	3.7	%


(cents per kWh)
Average Cost of Generated and Purchased Power
Coal (2)	4.42	4.32	2.3	%	4.50	4.52	(0.4)	%
Natural Gas (2)(3)	2.20	2.27	(3.1)	%	1.98	2.57	(23.0)	%
Purchased Power (4)	4.34	5.16	(15.9)	%	3.68	4.11	(10.5)	%

(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.

Operations and Maintenance Expense

We reported Operations and Maintenance expense of $113 million in the third quarter of 2026 compared with $116 million in the same period for 2025. The decrease of $3 million, or 3%, was primarily due to:

•$5 million in lower employee benefits expenses driven in part by timing; and

•$3 million in lower RES tariff and DSM expenses primarily due to lower program expenses.

The decrease was partially offset by $3 million in higher reimbursable materials and maintenance expenses related to Springerville Unit 4.

We reported Operations and Maintenance expense of $354 million for the first nine months of 2026 compared with $327 million for the same period for 2025. The increase of $27 million, or 8%, was primarily due to:

•$17 million in higher reimbursable materials and maintenance expenses related to Springerville Units 3 and 4;

•$8 million in higher operations and maintenance expenses at our generation facilities;

•$4 million in higher outside services expenses; and

•$3 million in higher employee wages expense net of a decrease in employee benefits expense.

The increase was partially offset by $4 million in lower RES tariff and DSM expenses primarily due to lower program expenses.

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Depreciation and Amortization Expense

We reported Depreciation and Amortization expense of $77 million in the third quarter of 2026 compared with $67 million in the same period for 2025. The increase of $10 million, or 15%, was primarily due to an increase in asset base.

We reported Depreciation and Amortization expense of $217 million for the first nine months of 2026 compared with $198 million for the same period for 2025. The increase of $19 million, or 10%, was primarily due to an increase in asset base.

Other Income (Expense)

We reported Other Expense of $18 million in the third quarter of 2026 compared with $15 million in the same period for 2025. The increase of $3 million, or 20%, was primarily due to:

•$3 million in lower AFUDC due to a decrease in eligible construction expenditures; and

•$2 million increase due to unfavorable market conditions that decreased the value of investments used to support certain post-employment benefits.

The increase was partially offset by:

•$2 million in higher interest income associated with customer prepayments; and

•$2 million in lower non-service components of net periodic benefit cost primarily due to a decrease in interest cost and an increase in expected return on plan assets.

We reported Other Expense of $40 million for the first nine months of 2026 compared with $43 million in the same period for 2025. The decrease of $3 million, or 7%, was primarily due to:

•$5 million in lower non-service components of net periodic benefit cost primarily due to a decrease in interest cost and an increase in expected return on plan assets;

•$3 million in higher interest income associated with customer prepayments; and

•$3 million in lower interest expense primarily due to the deferral of interest expense associated with Roadrunner Reserve I.

The decrease was partially offset by:

•$4 million in lower AFUDC due to a decrease in eligible construction expenditures; and

•$2 million increase due to unfavorable market conditions that decreased the value of investments used to support certain post-employment benefits.

Income Tax Expense

We reported Income Tax Expense of $14 million in the third quarter of 2026 compared with $23 million in the same period for 2025. The decrease of $9 million, or 39%, was primarily due to higher amortization of ITCs.

We reported Income Tax Expense of $25 million for the first nine months of 2026 compared with $40 million for the same period for 2025. The decrease of $15 million, or 38%, was primarily due to higher amortization of ITCs.

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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 2026 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)	September 30, 2026
Cash and Cash Equivalents	$	81
Amount Available under Revolving Credit Agreement (1)	241
Total Liquidity	$	322

(1)The 2021 Credit Agreement provided for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and was amended and restated on October 15, 2026 by the 2026 Credit Agreement. The 2026 Credit Agreement provides for $350 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and expires in October 2031. 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 7, and Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2025 Annual Report on Form 10-K for additional information regarding our leases, financing arrangements, and purchase commitments, respectively.

Summary of Cash Flows

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


	Nine Months Ended September 30,				Increase (Decrease)
(in millions)	2026		2025		Percent
Operating Activities (1)	$	547	$	454	20.5	%
Investing Activities (1)	(444)		(728)		(39.0)	%
Financing Activities (1)	(54)		295		(118.3)	%
Net Increase (Decrease)	49		21		*
Beginning of Period	56		49		14.3	%
End of Period	$	105	$	70	50.0	%

*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 increased by $93 million in the first nine months of 2026 compared with the same period in 2025 primarily due to the receipt of proceeds from the sale of ITCs.

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Investing Activities

Net cash flows used for investing activities decreased by $284 million in the first nine months of 2026 compared with the same period in 2025 primarily due to a decrease in cash paid for capital expenditures.

Financing Activities

Net cash flows used for financing activities was $54 million in the first nine months of 2026, compared with net cash flows provided by financing activities of $295 million in the same period for 2025. The $349 million change was primarily due to lower proceeds from debt issuance and an increase in dividends paid to UNS Energy; partially offset by an increase in equity contributions from UNS Energy.

Sources of Liquidity

Short-Term Investments

Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of September 30, 2026, our short-term investments were deposited in money market accounts.

Access to Credit

We have access to working capital through our credit agreement with lenders. LOCs may be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of September 30, 2026, there was $241 million available under the 2021 Credit Agreement, which reflected no outstanding revolver borrowings and LOCs totaling $9 million issued with fees that accrued at a rate of 1.025% per annum.

On October 15, 2026, the 2021 Credit Agreement was amended and restated by the 2026 Credit Agreement. On October 22, 2026, TEP amended and reduced a $1 million LOC with fees accruing at a rate of 1.000% per annum to less than $1 million. As of November 2, 2026, there was $342 million available under the 2026 Credit Agreement, which reflects no outstanding revolver borrowings and $8 million of LOCs, with fees accruing at a rate of 1.000% per annum. Amounts borrowed from the 2026 Credit Agreement are used for working capital and other general corporate purposes.

See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding our 2026 Credit Agreement. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2025 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 with the SEC an automatic shelf registration statement on Form S-3 which expires in March 2028. In October 2025, the ACC issued an order granting us financing authority which took effect on January 1, 2026. The order provides authority through December 2030 for: (i) a maximum amount of outstanding long-term debt not to exceed $4.5 billion; (ii) parent equity contributions of up to $1.7 billion, provided that no such equity infusion results in an increase to the equity portion of our capital structure of more than 50 basis points above the level approved in our rate order in effect at the time of the contribution; and (iii) credit facilities not to exceed $350 million in the aggregate.

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.

Credit Ratings

Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2026, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- (stable) 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 2026 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.

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Debt Covenants

Under certain agreements, should we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2026, 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 third quarter of 2026 and received equity contributions of $95 million in the first nine months of 2026. We received no equity contributions from UNS Energy in the third quarter or first nine months of 2025.

Dividends Declared and Paid to Parent

We did not declare or pay dividends to UNS Energy in the third quarter of 2026. We declared and paid $150 million in dividends to UNS Energy in the first nine months of 2026. We did not declare or pay dividends to UNS Energy in the third quarter or first nine months of 2025.

Master Trading Agreements

We conduct our wholesale marketing and risk management activities under certain master trading agreements. These agreements may require us to post credit enhancements in the form of cash or LOCs if our exposures exceed 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 September 30, 2026, 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 support customer growth, system reinforcement, replacements and betterments, and compliance with environmental rules and regulations. We prioritize capital projects that mitigate supply chain risks, particularly in light of ongoing geopolitical instability and global supply chain challenges. Capital expenditures for the first nine months of 2026 were $453 million.

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


	Years Ended December 31,
(in millions)	2026		2027		2028		2029		2030


Generation Facilities (1)	$	131	$	86	$	138	$	213	$	187

Transmission and Distribution (2)	461		424		390		703		439
General and Other (3)	93		86		78		95		75
Total Capital Expenditures	$	685	$	596	$	606	$	1,011	$	701

(1)Includes investments in existing facilities, including upgrades and ongoing maintenance to ensure reliability.

(2)Investments in transmission capacity and distribution system reliability.

(3)Includes costs for information technology, fleet, facilities, and communication equipment.

These estimates are subject to continuing review and adjustment. Actual capital expenditures may vary due to fluctuations in business and market conditions, including inflationary pressures, tariffs, construction schedules, supply chain constraints, labor shortages and/or labor strikes, potential early plant closures, shifts in generation resources, any changes to governmental programs, such as loans, grants, guarantees, and other subsidies, evolving environmental requirements, local, state or federal regulations and policies, and other factors. We continue to monitor government trade policies, particularly those related to tariffs, and assess their potential impact on our capital projects. We expect to fund forecasted capital expenditures through a combination of internally generated cash and external financing, which may include long-term debt issuances, other borrowings, or equity contributions.

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Income Tax Position

Tax Sharing Agreement

Under the terms of the tax sharing agreement with UNS Energy, we made $3 million in net tax sharing payments for the first nine months of 2026 and 2025. Future cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.

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. In addition, projects located in qualifying energy communities may be eligible for an additional 10% bonus credit. Roadrunner Reserve I and II qualify for federal ITCs; Roadrunner Reserve II also qualifies for the energy community bonus credit, increasing its total federal investment tax credit to 40% of eligible project costs. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the ITCs generated by Roadrunner Reserve I and II. 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.

In April 2026, we received the final $46 million of cash proceeds from the sale of ITCs related to Roadrunner Reserve I.

Roadrunner Reserve II was placed in service in June 2026. In March 2026, we entered into an agreement to transfer ITCs related to Roadrunner Reserve II in the second half of 2026. In July 2026, we transferred $50 million of ITCs and received $46 million in cash proceeds from the sale of ITCs related to Roadrunner Reserve II. On October 1, 2026, we transferred $40 million of additional ITCs related to Roadrunner Reserve II and received $37 million in cash proceeds.

Environmental Matters

The EPA has the authority to regulate emissions of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced from 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 certain industrial facilities to reduce emissions that impair visibility in national parks and wilderness areas. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a 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, moved the next deadline for Regional Haze SIP revisions from 2018 to 2021. Following this change, the ADEQ began developing a control strategy to make reasonable progress toward the national visibility goal. In July 2019, the ADEQ notified us 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 Review with the U.S. Court of Appeals for the Ninth Circuit. In September 2025, the Court granted a motion filed by the Coalition to Protect America’s National Parks, the National Parks Conservation Association, and Sierra Club to intervene in the case, which had the effect of taking the case out of abeyance and reinstating a briefing schedule. The petitioners (TEP, SRP, ASARCO, and

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Phoenix Cement) and respondents (the EPA) jointly filed a motion with the Court asking for the case to be held in abeyance, which the Court granted in December 2025.

In February 2025, TEP and SRP also concurrently filed a joint Petition for Administrative Reconsideration with the EPA. We requested that the EPA reconsider the final rule and act to approve the ADEQ's Regional Haze SIP revision. In July 2025, TEP and SRP filed a supplement to the Petition for Administrative Reconsideration, providing further justification for the EPA to reconsider the final rule, and the EPA granted the request for reconsideration. In October 2025, we filed a modification to the original and supplemental Petition for Administrative Reconsideration providing justification for the EPA’s reconsideration with respect to Sundt Unit 3 and Springerville Units 1 and 2.

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 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;

•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 was 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% CCS rate beginning on January 1, 2032.

Various legal challenges to the final rules are pending before the U.S. Court of Appeals for the District of Columbia Circuit. In April 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. In June 2025, the EPA published a proposed rule containing two co-proposals to address the 2024 final rules. In the primary proposal, the EPA proposed to repeal the 2024 final rules in their entirety based on a determination that fossil-based EGUs do not contribute significantly to GHG air pollution. In the alternative proposal, the EPA proposed to:

•repeal the Best System of Emission Reductions determinations, presumptive standards of performance, and all related requirements in the emission guidelines for existing long-term and medium-term coal-fired steam EGUs;

•repeal the requirements for existing natural gas- and oil-fired steam EGUs; and

•repeal the phase 2 CCS-based requirements for new base load combustion turbine EGUs.

In September 2026, the EPA published a final rule adopting the alternative proposal and also issued a supplemental proposal seeking additional comment on the primary proposal. On the same day, legal challenges to the final rule were filed in the U.S. Court of Appeals for the District of Columbia Circuit.

We cannot predict the outcome of the rulemaking or the legal challenges at this time.

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.

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APS, 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 2024 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) 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 anticipate CCRMUs will be identified at Springerville and Four Corners; however, our assessment is ongoing and therefore associated compliance costs cannot be accurately predicted at this time. SRP tentatively 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.

In April 2026, the EPA published a proposed rule that reconsiders many requirements that were established by the Legacy CCR Surface Impoundments Rule and the 2015 CCR Rule. The proposed rule includes multiple proposals including potential removal of all requirements associated with CCRMUs or up to seven alternative amendments to the CCRMU requirements. The proposed rule also includes incorporating site-specific risk provisions into the 2015 CCR Rule requirements for CCR units. Public comment on the proposed rule closed in June 2026. We are analyzing the EPA's proposed rule.

In May 2026, the EPA announced the reopening of the public comment period for the proposed federal CCR permitting program that was originally published in February 2020. Public comment on the proposed rule closed in July 2026. TEP does not anticipate a material impact on operations or financial results from the proposed rule.

We cannot predict the outcome of the proposed rulemakings or any of the legal challenges at this time.

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 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 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 December 15, 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.

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In March 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. In January 2026, the EPA published the first proposal of a two-phase plan to revise the interstate transport regulations for the 2015 ozone NAAQS. The EPA proposed to approve SIPs from eight states (including Arizona) based on a determination that emissions from these states do not significantly contribute to nonattainment or interfere with maintenance of the 2015 ozone NAAQS in downwind states. 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 nine months ended September 30, 2026, 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 2025 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 may enter into 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 2025 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 designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures were effective as of September 30, 2026. There was no change in TEP’s internal control over financial reporting during the quarter ended September 30, 2026, that materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

For a description of certain legal proceedings affecting TEP, refer to Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this 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 2025 Annual Report on Form 10-K should be carefully considered, together with the following update to the risk factor titled "Changes in tax regulation may negatively affect the results of operations, net income, and cash flows of TEP" in our 2025 Annual Report on Form 10-K.

Changes in tax regulation, including those relating to ITCs that TEP has generated and sold, may negatively affect the results of operations, net income, and cash flows of TEP.

The Company is subject to taxation by the various taxing authorities at the federal, state, and local levels where it does business. Legislation or regulation could be enacted, modified, or terminated by any of these governmental authorities, which could affect the Company’s tax positions, results of operations, net income, and cash flows.

TEP may become subject to indemnification obligations and other contractual liabilities when it sells ITCs. As part of its sale of ITCs related to Roadrunner Reserve I and II, TEP has agreed to indemnify the purchasers for certain tax-related risks. If any such indemnification obligations or other contractual liabilities arise in connection with the sale of these ITCs, TEP's results of operations, net income, and cash flows could be negatively affected.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.

Description

*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 September 30, 2026, 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.

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:	November 2, 2026	/s/ J. Caleb Adcock
		J. Caleb Adcock
		Chief Financial Officer, Sr. Vice President, and Director
		(Principal Financial Officer and Principal Accounting Officer)