# EDGAR Filing Document

**Accession Number:** 0000100122
**File Stem:** 0000100122-25-000026
**Filing Date:** 2025-11
**Character Count:** 176580
**Document Hash:** e8d8aa7a80e80a1c6ce344a1822c13dd
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0000100122-25-000026.hdr.sgml**: 20251104

**ACCESSION NUMBER**: 0000100122-25-000026

**CONFORMED SUBMISSION TYPE**: 10-Q

**PUBLIC DOCUMENT COUNT**: 69

**CONFORMED PERIOD OF REPORT**: 20250930

**FILED AS OF DATE**: 20251104

**DATE AS OF CHANGE**: 20251104

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** TUCSON ELECTRIC POWER CO
- **CENTRAL INDEX KEY:** 0000100122
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 860062700
- **STATE OF INCORPORATION:** AZ
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-Q
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-05924
- **FILM NUMBER:** 251446270

**BUSINESS ADDRESS:**
- **STREET 1:** 88 EAST BROADWAY
- **CITY:** TUCSON
- **STATE:** AZ
- **ZIP:** 85701
- **BUSINESS PHONE:** 520-651-6776

**MAIL ADDRESS:**
- **STREET 1:** 88 EAST BROADWAY BLVD
- **STREET 2:** HQE809
- **CITY:** TUCSON
- **STATE:** AZ
- **ZIP:** 85701

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** TUCSON GAS & ELECTRIC CO /AZ/
- **DATE OF NAME CHANGE:** 19790528

?xml version='1.0' encoding='ASCII'? tep-20250930

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-Q**

(Mark One)

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

**For the quarterly period ended September 30, 2025** 

**OR**

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

**For the transition period from&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; to&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; .**

**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 3, 2025.

------

**Table of Contents**

---

| | |
|:---|:---|
| <u>[Definitions](#i20523c99670a4277b7f5efd6341939f5_10)</u> | <u>[iii](#i20523c99670a4277b7f5efd6341939f5_10)</u> |
| <u>[Forward-Looking Information](#i20523c99670a4277b7f5efd6341939f5_13)</u> | <u>[iv](#i20523c99670a4277b7f5efd6341939f5_13)</u> |
| **PART I** | **PART I** |
| <u>[Item 1. Financial Statements](#i20523c99670a4277b7f5efd6341939f5_19)</u> |  |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[Condensed Consolidated Statements of Income](#i20523c99670a4277b7f5efd6341939f5_22)</u> | <u>[1](#i20523c99670a4277b7f5efd6341939f5_22)</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[Condensed Consolidated Statements of Cash Flows](#i20523c99670a4277b7f5efd6341939f5_28)</u> | <u>[2](#i20523c99670a4277b7f5efd6341939f5_28)</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[Condensed Consolidated Balance Sheets](#i20523c99670a4277b7f5efd6341939f5_31)</u> | <u>[3](#i20523c99670a4277b7f5efd6341939f5_31)</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[Condensed Consolidated Statements of Changes in Stockholder's Equity](#i20523c99670a4277b7f5efd6341939f5_34)</u> | <u>[5](#i20523c99670a4277b7f5efd6341939f5_34)</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[Notes to Condensed Consolidated Financial Statements](#i20523c99670a4277b7f5efd6341939f5_40)</u> | <u>[6](#i20523c99670a4277b7f5efd6341939f5_40)</u> |
| <u>[Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations](#i20523c99670a4277b7f5efd6341939f5_112)</u> | <u>[22](#i20523c99670a4277b7f5efd6341939f5_112)</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[Critical Accounting Estimates](#i20523c99670a4277b7f5efd6341939f5_145)</u> | <u>[37](#i20523c99670a4277b7f5efd6341939f5_145)</u> |
| &nbsp;&nbsp;&nbsp;&nbsp;<u>[New Accounting Standards Issued and Not Yet Adopted](#i20523c99670a4277b7f5efd6341939f5_148)</u> | <u>[37](#i20523c99670a4277b7f5efd6341939f5_148)</u> |
| <u>[Item 3. Quantitative and Qualitative Disclosures about Market Risk](#i20523c99670a4277b7f5efd6341939f5_151)</u> | <u>[37](#i20523c99670a4277b7f5efd6341939f5_151)</u> |
| <u>[Item 4. Controls and Procedures](#i20523c99670a4277b7f5efd6341939f5_154)</u> | <u>[37](#i20523c99670a4277b7f5efd6341939f5_154)</u> |
| **PART II** | **PART II** |
| <u>[Item 1. Legal Proceedings](#i20523c99670a4277b7f5efd6341939f5_160)</u> | <u>[38](#i20523c99670a4277b7f5efd6341939f5_160)</u> |
| <u>[Item 1A. Risk Factors](#i20523c99670a4277b7f5efd6341939f5_163)</u> | <u>[38](#i20523c99670a4277b7f5efd6341939f5_163)</u> |
| <u>[Item 6. Exhibits](#i20523c99670a4277b7f5efd6341939f5_169)</u> | <u>[39](#i20523c99670a4277b7f5efd6341939f5_169)</u> |
| <u>[Signatures](#i20523c99670a4277b7f5efd6341939f5_172)</u> | <u>[40](#i20523c99670a4277b7f5efd6341939f5_172)</u> |

---

ii

------

**DEFINITIONS**

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

**INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS**

---

| | |
|:---|:---|
| 2020 IRP | TEP's 2020 Integrated Resource Plan which outlines TEP's plan to reduce its carbon emissions by 80% (compared to 2005) by 2035 |
| 2021 Credit Agreement | The unsecured 2021 Credit Agreement, as amended in June 2023 and extended in October 2025, provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2028 |
| 2023 IRP | TEP's 2023 Integrated Resource Plan which outlines TEP's aspirational goal to reach net zero direct greenhouse gas emissions by 2050 |
| 2023 Rate Order | Order issued by the ACC resulting in a new rate structure for TEP, effective on September 1, 2023 |
| 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 |
| ADJ | SOFR Rate Spread Adjustment |
| AFUDC | Allowance for Funds Used During Construction |
| ARAM | Annual Rate Adjustment Mechanism |
| ASC | Accounting Standards Codification |
| BESS | Battery Energy Storage System |
| CCR | Coal Combustion Residuals |
| CEM | Customer Energy Management |
| 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 |
| EPA | Environmental Protection Agency |
| EPC | Engineering, Procurement, and Construction |
| FERC | Federal Energy Regulatory Commission |
| FIP | Federal Implementation Plan |
| GAAP | Generally Accepted Accounting Principles in the United States of America |
| GHG | Greenhouse Gas |
| IRA | Inflation Reduction Act of 2022, signed into law on August 16, 2022 |
| ITC | Investment Tax Credit |
| LFCR | Lost Fixed Cost Recovery |
| LIRA | Limited Income Rate Adjustment |
| LOC | Letter(s) of Credit |
| Markets+ | Southwest Power Pool Markets+ |
| OBBBA | One Big Beautiful Bill Act, signed into law on July 4, 2025 |
| PPA | Power Purchase Agreement |
| PPFAC | Purchased Power and Fuel Adjustment Clause |
| PTC | Production Tax Credit |
| RES | Renewable Energy Standard |
| Roadrunner Reserve I Accounting Order | The April 2025 accounting order issued by the ACC allowing TEP to defer for future recovery certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I |
| SIP | State Implementation Plan |
| SOFR | Secured Overnight Financing Rate |
| SRB | System Resource Benefit |
| TEAM | Tax Expense Adjustor Mechanism |

---

**ENTITIES AND GENERATING STATIONS**

---

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

---

**UNITS OF MEASURE**

---

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

---

iii

------

<u>[Table](#i20523c99670a4277b7f5efd6341939f5_7)</u><u>[of Contents](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**FORWARD-LOOKING INFORMATION**

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. TEP, or the Company, is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words or phrases that include "anticipates," "believes," "estimates," "expects," "intends," "continues," "assumes," "aspires," "may," "plans," "predicts," "projects," "would," "could," "forecast," "target," "goal," "potential," "commitment," "strategy," "will," and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany such forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as may otherwise be required by the federal securities laws.

Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed herein. We express our estimates, expectations, beliefs, aspirations, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management's estimates, expectations, beliefs, aspirations, or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part I, Item 1A. Risk Factors of our 2024 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors of this Quarterly Report on Form 10-Q; Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations of this Quarterly Report on Form 10-Q; and other parts of this report. These factors include: voter initiatives and federal, state, and local regulatory and legislative decisions and actions, including changes in tax, tariff, and energy policies, as they may be affected by the policies and priorities of governmental officials at the federal, state, and local levels; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies or the City of Tucson's study of municipalization; changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output, or accelerate generation facility retirements; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions that could affect customer growth and electricity usage; potential changes in the benefits of participation in the Western Energy Imbalance Market and Markets+; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather seasonality, extreme weather events, and their increasing frequency and severity, and wildfires, affecting electricity usage of our customers, operational performance, and operating and capital costs to ensure system reliability; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the demand plus reserve margin requirements; our ability to implement successfully our business strategies and meet the growing demand for electricity, particularly in view of potential for new large customer requirements; the cost of debt and equity capital and access to capital markets and bank markets during extended periods of volatility, which may affect our ability to raise additional capital and to use the proceeds from any capital that we do raise as originally intended; the performance of the stock market and changes in interest rates, which affect the value of our pension and other postretirement benefit plan assets and related contribution requirements and expenses; our ability to manage timelines and budgets and to access necessary materials and labor, in each case, related to capital projects, including EPC agreements to develop standalone BESS, and/or to obtain the anticipated performance or other benefits of such capital projects; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense, including increases due to inflationary 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; our ability to meet our goal related to reducing carbon emissions by 2050 due to load growth required by 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; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; the extent of the impact of a global health or other crisis on our business and operations, and any economic and/or societal disruptions resulting therefrom and from the government actions taken in response thereto; the implementation of our 2023 IRP; and our ability to obtain ACC approval of a formula rate plan with acceptable terms in response to our 2025 Rate Case.

iv

------

<u>[Table](#i20523c99670a4277b7f5efd6341939f5_7)</u><u>[of Contents](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**PART I**

**ITEM 1. FINANCIAL STATEMENTS**

**TUCSON ELECTRIC POWER COMPANY**

**CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)**

(Amounts in thousands)

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| | **2025** | **2024** | **2025** | **2024** |
| **Operating Revenues** | $**544515** | $551632 | $**1317495** | $1433934 |
| **Operating Expenses** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fuel | **103862** | 92063 | **250153** | 257165 |
| &nbsp;&nbsp;&nbsp;&nbsp;Purchased Power | **42092** | 50703 | **103904** | 104373 |
| &nbsp;&nbsp;&nbsp;&nbsp;Transmission and Other PPFAC Recoverable Costs | **19231** | 18904 | **43730** | 52371 |
| &nbsp;&nbsp;&nbsp;&nbsp;Increase (Decrease) to Reflect PPFAC Recovery Treatment | **(3257)** | 26114 | **(3837)** | 97349 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Fuel and Purchased Power** | **161928** | 187784 | **393950** | 511258 |
| &nbsp;&nbsp;&nbsp;&nbsp;Operations and Maintenance | **115526** | 105877 | **326712** | 330143 |
| &nbsp;&nbsp;&nbsp;&nbsp;Depreciation | **59183** | 56942 | **175021** | 168913 |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization | **7793** | 7346 | **23195** | 22855 |
| &nbsp;&nbsp;&nbsp;&nbsp;Taxes Other Than Income Taxes | **18414** | 17384 | **55471** | 53629 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Operating Expenses** | **362844** | 375333 | **974349** | 1086798 |
| **Operating Income** | **181671** | 176299 | **343146** | 347136 |
| **Other Income (Expense)** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest Expense | **(29652)** | (27189) | **(91013)** | (75442) |
| &nbsp;&nbsp;&nbsp;&nbsp;Allowance For Borrowed Funds | **4219** | 2221 | **13117** | 5974 |
| &nbsp;&nbsp;&nbsp;&nbsp;Allowance For Equity Funds | **9417** | 6276 | **30368** | 16935 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrealized Gains (Losses) on Investments | **1367** | 1867 | **3075** | 2857 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest Income | **1062** | 3544 | **4722** | 5615 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, Net | **(1187)** | (1425) | **(2811)** | (1780) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Other Income (Expense)** | **(14774)** | (14706) | **(42542)** | (45841) |
| **Income Before Income Tax Expense** | **166897** | 161593 | **300604** | 301295 |
| &nbsp;&nbsp;&nbsp;&nbsp;Income Tax Expense | **22510** | 21100 | **40124** | 39187 |
| **Net Income** | $**144387** | $140493 | $**260480** | $262108 |

---

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,** | **Nine Months Ended September 30,** |
| | **2025** | **2024** |
| **Cash Flows from Operating Activities** |  |  |
| Net Income | $**260480** | $262108 |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: |  |  |
| &nbsp;&nbsp;&nbsp;Depreciation Expense | **175021** | 168913 |
| &nbsp;&nbsp;&nbsp;Amortization Expense | **23195** | 22855 |
| &nbsp;&nbsp;&nbsp;Amortization of Debt Issuance Costs | **2379** | 2338 |
| &nbsp;&nbsp;&nbsp;Use of Renewable Energy Credits for Compliance | **37257** | 35976 |
| &nbsp;&nbsp;&nbsp;Deferred Income Taxes | **36300** | 28638 |
| &nbsp;&nbsp;&nbsp;Pension and Other Postretirement Benefits Expense | **13532** | 13529 |
| &nbsp;&nbsp;&nbsp;Pension and Other Postretirement Benefits Funding | **(13967)** | (17815) |
| &nbsp;&nbsp;&nbsp;Allowance for Equity Funds Used During Construction | **(30368)** | (16935) |
| &nbsp;&nbsp;&nbsp;Changes in Current Assets and Current Liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts Receivable | **(62317)** | (58522) |
| &nbsp;&nbsp;&nbsp;&nbsp;Materials, Supplies, and Fuel Inventory | **(20411)** | (22790) |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory Assets | **(14907)** | 47446 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other Current Assets | **(3473)** | (8243) |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts Payable and Accrued Charges | **40138** | 29976 |
| &nbsp;&nbsp;&nbsp;&nbsp;Income Taxes Receivable/Payable | **1128** | 1932 |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory Liabilities | **13350** | 53448 |
| &nbsp;&nbsp;&nbsp;Other, Net | **(3604)** | (12283) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Net Cash Flows—Operating Activities** | **453733** | 530571 |
| **Cash Flows from Investing Activities** |  |  |
| &nbsp;&nbsp;&nbsp;Capital Expenditures | **(691277)** | (459635) |
| &nbsp;&nbsp;&nbsp;Purchase Intangibles, Renewable Energy Credits | **(44304)** | (46291) |
| &nbsp;&nbsp;&nbsp;Contributions in Aid of Construction | **7684** | 1314 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Net Cash Flows—Investing Activities** | **(727897)** | (504612) |
| **Cash Flows from Financing Activities** |  |  |
| &nbsp;&nbsp;&nbsp;Proceeds from Borrowings, Revolving Credit Facility | **100000** | 25000 |
| &nbsp;&nbsp;&nbsp;Repayments of Borrowings, Revolving Credit Facility | **(100000)** | (25000) |
| &nbsp;&nbsp;Proceeds from Issuance, Long-Term Debt**—**Net of Discount | **299322** | 399376 |
| &nbsp;&nbsp;&nbsp;Dividend Paid to Parent | **—** | (85000) |
| &nbsp;&nbsp;&nbsp;Payment of Debt Issuance Costs | **(3641)** | (3221) |
| &nbsp;&nbsp;&nbsp;Other, Net | **(805)** | 1369 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Net Cash Flows—Financing Activities** | **294876** | 312524 |
| **Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash** | **20712** | 338483 |
| **Cash, Cash Equivalents, and Restricted Cash, Beginning of Period** | **49461** | 42595 |
| **Cash, Cash Equivalents, and Restricted Cash, End of Period** | $**70173** | $381078 |

---

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, 2025** | **December 31, 2024** |
| **ASSETS** | | |
| **Utility Plant** | | |
| &nbsp;&nbsp;&nbsp;&nbsp;Plant in Service | $**8921091** | $8349638 |
| &nbsp;&nbsp;&nbsp;&nbsp;Construction Work in Progress | **863133** | 850443 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Utility Plant** | **9784224** | 9200081 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accumulated Depreciation and Amortization | **(2804625)** | (2713492) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Utility Plant, Net** | **6979599** | 6486589 |
| **Investments and Other Property** | **72477** | 75662 |
| **Current Assets** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash and Cash Equivalents | **42925** | 14063 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts Receivable (Net of Allowance for Credit Losses of $12,884 and $12,561 as of September 30, 2025 and December 31, 2024, respectively) | **258951** | 196194 |
| &nbsp;&nbsp;&nbsp;&nbsp;Fuel Inventory | **61207** | 55267 |
| &nbsp;&nbsp;&nbsp;&nbsp;Materials and Supplies | **207801** | 196515 |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory Assets | **117908** | 97720 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative Instruments | **11928** | 9732 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **34368** | 31597 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Current Assets** | **735088** | 601088 |
| Regulatory Assets | **173349** | 177963 |
| Derivative Instruments | **27139** | 27664 |
| Other Noncurrent Assets | **155503** | 152557 |
| **Total Assets** | $**8143155** | $7521523 |

---

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, 2025** | **December 31, 2024** |
| **CAPITALIZATION AND LIABILITIES** | | |
| **Capitalization** | | |
| &nbsp;&nbsp;&nbsp;&nbsp;Common Stock Equity: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2025 and December 31, 2024) | $**1746539** | $1746539 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Capital Stock Expense | **(6357)** | (6357) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Retained Earnings | **1627393** | 1366913 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accumulated Other Comprehensive Loss | **(3854)** | (4015) |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Common Stock Equity** | **3363721** | 3103080 |
| &nbsp;&nbsp;&nbsp;&nbsp;Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2025 and December 31, 2024) | **—** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Long-Term Debt, Net | **2792097** | 2494600 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Capitalization** | **6155818** | 5597680 |
| **Current Liabilities** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Borrowings Under Credit Agreement | **70000** | 70000 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts Payable | **134614** | 151278 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued Taxes Other than Income Taxes | **84481** | 57847 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued Employee Expenses | **41776** | 37921 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued Interest | **40081** | 22260 |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulatory Liabilities | **156321** | 142844 |
| &nbsp;&nbsp;&nbsp;&nbsp;Customer Deposits | **16737** | 16255 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative Instruments | **31918** | 25710 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **32421** | 31665 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Current Liabilities** | **608349** | 555780 |
| Deferred Income Taxes, Net | **643005** | 700189 |
| Regulatory Liabilities | **432499** | 362859 |
| Pension and Other Postretirement Benefits | **64034** | 68816 |
| Derivative Instruments | **1173** | 6099 |
| Asset Retirement Obligations | **172560** | 159056 |
| Other Noncurrent Liabilities | **65717** | 71044 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Liabilities** | **1987337** | 1923843 |
| **Commitments and Contingencies** |  |  |
| **Total Capitalization and Liabilities** | $**8143155** | $7521523 |

---

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** | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** |
| | **Common Stock** | **Capital Stock Expense** | **Retained Earnings** | **Accumulated Other Comprehensive Loss** | **Total Stockholder's Equity** |
| **Balances as of June 30, 2024** | $**1696539** | $**(6357)** | $**1284536** | $**(3737)** | $**2970981** |
| &nbsp;&nbsp;&nbsp;Net Income |  |  | 140493 |  | 140493 |
| &nbsp;&nbsp;&nbsp;Other Comprehensive Income (Loss), Net of Tax |  |  |  | 99 | 99 |
| &nbsp;&nbsp;&nbsp;Dividend Declared to Parent |  |  | (85000) |  | (85000) |
| **Balances as of September 30, 2024** | $**1696539** | $**(6357)** | $**1340029** | $**(3638)** | $**3026573** |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Balances as of June 30, 2025** | $**1746539** | $**(6357)** | $**1483006** | $**(3908)** | $**3219280** |
| &nbsp;&nbsp;&nbsp;Net Income |  |  | 144387 |  | 144387 |
| &nbsp;&nbsp;&nbsp;Other Comprehensive Income (Loss), Net of Tax |  |  |  | 54 | 54 |
| **Balances as of September 30, 2025** | $**1746539** | $**(6357)** | $**1627393** | $**(3854)** | $**3363721** |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Nine Months Ended** | **Nine Months Ended** | **Nine Months Ended** | **Nine Months Ended** | **Nine Months Ended** |
| | **Common Stock** | **Capital Stock Expense** | **Retained Earnings** | **Accumulated Other Comprehensive Loss** | **Total Stockholder's Equity** |
| **Balances as of December 31, 2023** | $**1696539** | $**(6357)** | $**1162921** | $**(3829)** | $**2849274** |
| &nbsp;&nbsp;&nbsp;Net Income |  |  | 262108 |  | 262108 |
| &nbsp;&nbsp;&nbsp;Other Comprehensive Income (Loss), Net of Tax |  |  |  | 191 | 191 |
| &nbsp;&nbsp;&nbsp;Dividend Declared to Parent |  |  | (85000) |  | (85000) |
| **Balances as of September 30, 2024** | $**1696539** | $**(6357)** | $**1340029** | $**(3638)** | $**3026573** |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Balances as of December 31, 2024** | $**1746539** | $**(6357)** | $**1366913** | $**(4015)** | $**3103080** |
| &nbsp;&nbsp;&nbsp;Net Income |  |  | 260480 |  | 260480 |
| &nbsp;&nbsp;&nbsp;Other Comprehensive Income (Loss), Net of Tax |  |  |  | 161 | 161 |
| **Balances as of September 30, 2025** | $**1746539** | $**(6357)** | $**1627393** | $**(3854)** | $**3363721** |

---

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

------

<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**

**<u>NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION</u>**

TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 456,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the Western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.

**BASIS OF PRESENTATION**

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

The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2024 Annual Report on Form 10-K.

The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. TEP has reclassified Interest Income from Other, Net and Asset Retirement Obligations from Other Noncurrent Liabilities in the prior period to a separately disclosed line on the Condensed Consolidated Statements of Income and the Condensed Consolidated Balance Sheets, respectively, to conform with the current period presentation. Additionally, TEP has reclassified Change in Long-Term Regulatory Assets and Liabilities from a separately disclosed line into Other, Net on the Condensed Consolidated Statements of Cash Flows to conform with the current period presentation. The reclassifications had no impact on TEP's results of operation, financial position, or cash flows.

**Variable Interest Entities**

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

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

As of September 30, 2025, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term renewable PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.

------

<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**RESTRICTED CASH**

Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows:

---

| | | |
|:---|:---|:---|
| | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** |
| Cash and Cash Equivalents | $43 | $354 |
| Restricted Cash included in: |  |  |
| &nbsp;&nbsp;&nbsp;Investments and Other Property | 20 | 18 |
| &nbsp;&nbsp;&nbsp;Current Assets—Other | 7 | 9 |
| **Cash, Cash Equivalents, and Restricted Cash, End of Period** | $70 | $381 |

---

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

**INCOME TAXES**

**Production Tax Credits**

TEP realized PTC benefits associated with Oso Grande of $9 million and $17 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2025, respectively, and $10 million and $20 million for the three and nine months ended September 30, 2024, respectively.

**Investment Tax Credits**

TEP has elected to apply ASC 740, Income Taxes, to nonrefundable, transferable ITCs. In connection with ITCs generated by the Roadrunner Reserve I project, TEP recorded a $93 million deferred tax asset in Deferred Income Taxes, Net on the Condensed Consolidated Balance Sheets as of September 30, 2025, along with a corresponding regulatory liability in Regulatory Liabilities on the Condensed Consolidated Balance Sheets to reflect the anticipated return of benefits to customers. As of September 30, 2025, TEP recorded a $7 million valuation allowance against the deferred tax asset recognized for transferable ITCs, reflecting the expected discount in proceeds from a third-party sale.

The ACC approved TEP's request to defer recognition of ITC-related amounts that would otherwise be included in Income Tax Expense. See Note 2 for additional information regarding the ACC-issued accounting order for Roadrunner Reserve I. On the effective date of new rates, TEP expects to amortize the deferred ITC as a reduction to Income Tax Expense over five years.

**One Big Beautiful Bill Act**

In July 2025, the OBBBA was signed into law enacting extensions of the expiring provisions of the 2017 Tax Cuts and Jobs Act and additional business tax provisions. The OBBBA also accelerates phase out of, and adds various restrictions to, PTCs and ITCs applicable to certain facilities per provisions generally enacted or extended as part of the IRA. The OBBBA did not have a material impact on TEP's financial position, results of operations, or cash flows.

**NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED**

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

**Income Tax Disclosures**

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

------

<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED**

**Standards Recently Issued by the FASB**

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

<u>Targeted Improvements to the Accounting for Internal-Use Software</u>

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 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 after January 1, 2028. The guidance may be applied prospectively, retrospectively, or using a modified transition approach. Early adoption is permitted.

<u>Measurement of Credit Losses for Accounts Receivable and Contract Assets</u>

In July 2025, the FASB issued accounting guidance amending ASC 326-20 to introduce a practical expedient for estimating expected credit losses on current accounts receivable arising from revenue transactions under ASC 606. Under the amendments, entities may assume that current conditions as of the balance sheet date remain unchanged over the remaining life of the receivable. This simplifies the estimation process by removing the need to forecast future changes in conditions for short-term assets. The amendments are effective for annual and interim reporting periods beginning after January 1, 2026. The guidance must be applied on a prospective basis, with early adoption permitted.

<u>Disaggregation of Income Statement Expenses</u>

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**

The following final SEC rules regarding climate-related disclosures are pending further action by the SEC.

In March 2024, the SEC issued final rules that require disclosure of climate related risks and greenhouse gas emissions. In April 2024, the SEC issued an order staying the final rules pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit (Eighth Circuit). In March 2025, the SEC voted to end its defense of the rules and sent a letter to the Court stating that the SEC withdraws its defense. In April 2025, the Eighth Circuit ordered the litigation to be suspended and directed the SEC to indicate within 90 days whether the SEC will reconsider or review the climate disclosure rules. In July 2025, the SEC filed a response with the Eighth Circuit, indicating that the SEC does not intend to review or reconsider the climate disclosure rules at this time and requesting the court to lift the suspension on the litigation and issue a ruling. In September 2025, the Eighth Circuit paused its consideration of legal challenges against the rules, pending further action by the SEC. TEP awaits the SEC's decision whether it will defend, amend, or withdraw the rules, the timing of which TEP cannot currently predict.

**<u>NOTE 2. REGULATORY MATTERS</u>**

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.

------

<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**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.

TEP's key 2025 Rate Case proposals are described below:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a $172 million net increase in retail revenues comprised of the following components:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ a non-fuel retail revenue increase of $220 million over test year non-fuel retail revenues,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ a $26 million decrease in fuel-related retail revenues, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ elimination of certain existing adjustor mechanisms, including the DSM surcharge, and, if a new proposed ARAM is approved, the ECA, TEAM, and LFCR mechanism, that results in a $22 million reduction in revenues collected from customers;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a 7.73% return on original cost rate base of $4.3 billion, which includes a return on equity of 10.50% and an average cost of debt of 4.28%;

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a new ARAM that is a formula rate adjustor designed to update rates annually based on historical changes in TEP's revenue requirement;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ if the proposed ARAM is not approved, a new SRB mechanism, which would help recover investments in significant generation resources, and a new LIRA, which would allow TEP to recover or refund differences between actual limited income tariff costs and the costs included in base rates; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a new CEM framework, which will support initiatives to achieve energy savings and load optimization. The framework will replace the existing energy efficiency implementation and transportation electrification plans. If approved, costs would be recovered through a CEM surcharge pending inclusion in the first ARAM adjustment.

TEP requested new rates to be implemented by September 1, 2026. TEP cannot predict the timing or 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.

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| **Beginning of Period** | $(49) | $(31) | $(49) | $55 |
| &nbsp;&nbsp;Deferred Fuel and Purchased Power Costs <sup>(1)</sup> | 110 | 95 | 243 | 202 |
| &nbsp;&nbsp;&nbsp;PPFAC and Base Power Recoveries | (106) | (120) | (239) | (313) |
| **End of Period** | $(45) | $(56) | $(45) | $(56) |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>Includes costs eligible for recovery through the PPFAC and base power rates.

------

<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Transmission Cost Adjustor**

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

In May 2024, the ACC approved an extension of TEP's 2021 RES implementation 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 of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.

**Energy Efficiency Standards**

TEP is required to implement cost-effective DSM programs to comply with the ACC's 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.

<u>2020 IRP Energy Efficiency Target</u>

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

**Lost Fixed Cost Recovery Mechanism**

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues based on an estimate of lost retail kWh sales during the period. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.

------

<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**REGULATORY ASSETS AND LIABILITIES**

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

---

| | | | |
|:---|:---|:---|:---|
| ($ in millions) | **Remaining Recovery Period<br>(years)** | **September 30, 2025** | **December 31, 2024** |
| **Regulatory Assets** |  |  |  |
| &nbsp;&nbsp;Pension and Other Postretirement Benefits (Note 9) | Various | $99 | $103 |
| &nbsp;&nbsp;&nbsp;Early Generation Retirement Costs | Various | 39 | 46 |
| &nbsp;&nbsp;Property Tax Deferrals <sup>(1)</sup> | 1 | 32 | 32 |
| &nbsp;&nbsp;&nbsp;Lost Fixed Cost Recovery | 1 | 30 | 31 |
| &nbsp;&nbsp;&nbsp;Transmission Revenue Requirement Balancing Account | 1 | 27 | 11 |
| &nbsp;&nbsp;Derivatives (Note 10) | 4 | 24 | 19 |
| &nbsp;&nbsp;Roadrunner Reserve I Accounting Order <sup>(2)</sup> | Various | 8 |  |
| &nbsp;&nbsp;Final Mine Reclamation <sup>(3)</sup> | 14 | 7 | 9 |
| &nbsp;&nbsp;Income Taxes Recoverable through Future Rates <sup>(4)</sup> | Various | 4 | 5 |
| &nbsp;&nbsp;&nbsp;Other Regulatory Assets | Various | 21 | 20 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Regulatory Assets** |  | 291 | 276 |
| &nbsp;&nbsp;&nbsp;Less Current Portion | 1 | 118 | 98 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Noncurrent Regulatory Assets** |  | $173 | $178 |

---

---

| | | | |
|:---|:---|:---|:---|
| **Regulatory Liabilities** | | | |
| &nbsp;&nbsp;Income Taxes Payable through Future Rates <sup>(4)</sup> | Various | $216 | $209 |
| &nbsp;&nbsp;&nbsp;Renewable Energy Standard | Various | 99 | 88 |
| &nbsp;&nbsp;Deferred Investment Tax Credits <sup>(5)</sup> | Various | 89 | 4 |
| &nbsp;&nbsp;Net Cost of Removal <sup>(6)</sup> | Various | 83 | 110 |
| &nbsp;&nbsp;&nbsp;Over-Recovered Fuel and Purchased Energy Costs | 1 | 45 | 49 |
| &nbsp;&nbsp;Derivatives (Note 10) | 4 | 26 | 22 |
| &nbsp;&nbsp;Pension and Other Postretirement Benefits (Note 9) | Various | 18 | 19 |
| &nbsp;&nbsp;&nbsp;Demand Side Management | 1 | 11 | 5 |
| &nbsp;&nbsp;&nbsp;Other Regulatory Liabilities | Various | 1 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Regulatory Liabilities** |  | 588 | 506 |
| &nbsp;&nbsp;&nbsp;Less Current Portion | 1 | 156 | 143 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total Noncurrent Regulatory Liabilities** |  | $432 | $363 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup>Represents costs associated with TEP's jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup>Amortized over 10 years or the lives of the assets.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(5)</sup>As federal ITCs are deferred, TEP records a regulatory liability to be refunded to customers. On the effective date of new rates, TEP expects to begin amortizing the portion of the deferred ITCs related to Roadrunner Reserve I over five years.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(6)</sup>Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general plant which are not yet expended.

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

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 I**

In July 2025, Roadrunner Reserve I was placed in service. As of September 30, 2025, there was $346 million in costs related to Roadrunner Reserve I in Plant in Service on the Condensed Consolidated Balance Sheet.

**<u>NOTE 3. REPORTABLE SEGMENTS</u>**

TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP has one operating segment, its regulated utility operations. TEP's chief operating decision maker (CODM) is Susan M. Gray who holds the position of President and Chief Executive Officer of TEP and its parent company, UNS Energy. The CODM uses net income to assess performance and decide how to allocate resources for UNS Energy overall (including employees and financial or capital resources) predominantly in the annual budget and forecasting process. Net income is reported on the Condensed Consolidated Statements of Income. Operations and Maintenance expense includes expenses reimbursed by third-parties and expenses related to customer-funded RES and DSM programs. Operations and Maintenance expense excluding these reimbursable and customer funded expenses totaled $91 million, and $261 million for the three and nine months ended September 30, 2025, respectively, and $83 million and $248 million for the three and nine months ended September 30, 2024, respectively. Total assets, the measure of segment assets, is reported on the Condensed Consolidated Balance Sheets. Capital expenditures are reported on the Condensed Consolidated Statements of Cash Flows.

**<u>NOTE 4. REVENUE</u>**

**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,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| Retail | $434 | $436 | $994 | $1052 |
| Wholesale | 61 | 72 | 166 | 212 |
| Other Services | 26 | 24 | 75 | 90 |
| &nbsp;&nbsp;&nbsp;**Revenues from Contracts with Customers** | 521 | 532 | 1235 | 1354 |
| Alternative Revenues | 14 | 11 | 38 | 30 |
| Other | 10 | 9 | 44 | 50 |
| &nbsp;&nbsp;&nbsp;**Total Operating Revenues** | $545 | $552 | $1317 | $1434 |

---

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**<u>NOTE 5. ACCOUNTS RECEIVABLE</u>**

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

---

| | | |
|:---|:---|:---|
| (in millions) | **September 30, 2025** | **December 31, 2024** |
| Retail | $150 | $112 |
| Retail, Unbilled | 64 | 43 |
| Retail, Allowance for Credit Losses | (13) | (13) |
| Wholesale <sup>(1)</sup> | 33 | 24 |
| Due from Affiliates (Note 6) | 8 | 10 |
| Other | 17 | 20 |
| &nbsp;&nbsp;&nbsp;**Accounts Receivable, Net** | $259 | $196 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>Includes $13 million and $8 million as of September 30, 2025, and December 31, 2024, respectively, of receivables related to revenue from derivative instruments.

**ALLOWANCE FOR CREDIT LOSSES**

TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| **Beginning of Period** | $(11) | $(12) | $(13) | $(12) |
| &nbsp;&nbsp;&nbsp;Credit Loss Expense | (3) | (2) | (5) | (5) |
| &nbsp;&nbsp;&nbsp;Write-offs | 1 | 1 | 5 | 4 |
| **End of Period** | $(13) | $(13) | $(13) | $(13) |

---

**<u>NOTE 6. RELATED PARTY TRANSACTIONS</u>**

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, 2025** | **December 31, 2024** |
| **Receivables from Related Parties** |  |  |
| &nbsp;&nbsp;&nbsp;UNS Electric | $6 | $7 |
| &nbsp;&nbsp;&nbsp;UNS Gas | 2 | 2 |
| &nbsp;&nbsp;&nbsp;UNS Energy |  | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Due from Related Parties** | $8 | $10 |
| **Payables to Related Parties** |  |  |
| &nbsp;&nbsp;&nbsp;UNS Electric | $2 | $1 |
| &nbsp;&nbsp;&nbsp;UNS Energy | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Due to Related Parties** | $3 | $2 |

---

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| **Goods and Services Provided by TEP to Affiliates** |  |  |  |  |
| &nbsp;&nbsp;Common Costs, UNS Energy Affiliates <sup>(1)</sup> | $7 | $6 | $19 | $18 |
| &nbsp;&nbsp;Transmission Revenues, UNS Electric <sup>(2)</sup> | 2 | 2 | 6 | 6 |
| &nbsp;&nbsp;Wholesale Revenues, UNS Electric <sup>(2)</sup> | 1 | 16 | 2 | 19 |
| &nbsp;&nbsp;Control Area Services, UNS Electric <sup>(3)</sup> | 1 | 1 | 2 | 2 |
| **Goods and Services Provided by Affiliates to TEP** |  |  |  |  |
| &nbsp;&nbsp;Corporate Services, UNS Energy <sup>(4)</sup> | $1 | $2 | $7 | $7 |
| &nbsp;&nbsp;Purchased Power, UNS Electric <sup>(2)</sup> | 1 |  | 2 |  |
| &nbsp;&nbsp;Corporate Services, UNS Energy Affiliates <sup>(5)</sup> |  |  | 1 | 1 |
| &nbsp;&nbsp;Capacity Charges, UNS Gas <sup>(6)</sup> |  |  | 1 | 1 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup>TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup>Corporate Services, UNS Energy includes legal and audit, and Fortis' management fees. Costs for corporate services provided by UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 84% of UNS Energy's allocated costs. TEP's share of Fortis' management fees was $1 million and $6 million for the three and nine months ended September 30, 2025, respectively, and $2 million and $6 million for the three and nine months ended September 30, 2024, respectively.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(5)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(6)</sup>UNS Gas charges TEP for natural gas capacity used to supply Gila River Generating Station.

**<u>NOTE 7. DEBT AND CREDIT AGREEMENT</u>** 

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

**DEBT**

**Issuance**

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

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**CREDIT AGREEMENT**

**2021 Credit Agreement** 

In October 2025, the maturity date of TEP's 2021 Credit Agreement was extended one year to October 2028 as permitted by the agreement. The terms of the 2021 Credit Agreement are as follows:

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| | | **Sub-Limit Swingline** <sup>(1)</sup> | **Sub-Limit LOC** | | | **Weighted Average Interest Rate** <sup>(3)</sup> | |
| |<br>**Capacity** | **Sub-Limit Swingline** <sup>(1)</sup> | **Sub-Limit LOC** |<br>**Borrowed** <sup>(2)</sup> |<br>**Available** | **Weighted Average Interest Rate** <sup>(3)</sup> |<br>**Pricing** <sup>(4)</sup> |
| ($ in millions) | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** |
| Agreement | $250 | $15 | $50 | $91 | $159 | 5.31% | SOFR+ADJ 0.10%+1.050% or ABR+0.050% |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>ABR pricing would apply to swingline loans.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>The borrowed amount includes LOCs totaling $21 million at a rate of 1.050% per annum issued in October and November 2024 to support interconnection requests, and in May 2025 to support TEP's participation in Markets+. Upon TEP's request, LOCs totaling $6 million issued in October 2024 were cancelled in October 2025. The remaining LOCs expire at various dates between May 2026 and November 2026.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup>The weighted average interest rate is calculated on outstanding borrowings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup>TEP's pricing through October 15, 2026 may be adjusted based on performance measured using two sustainability targets: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage.

As of November 3, 2025, there was $165 million available under the 2021 Credit Agreement.

**<u>NOTE 8. COMMITMENTS AND CONTINGENCIES</u>**

**COMMITMENTS**

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

**EPC Agreement**

In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. In 2025, change orders were issued that increased costs by $34 million, bringing the total EPC cost to $302 million. TEP owns and will operate the facility, which will be located in southeast Tucson and will have a nominal capacity rating of 200 MW and energy capacity of 800 MWh. Roadrunner Reserve II is expected to be placed in service in 2026.

**CONTINGENCIES**

**Legal Matters**

TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.

**Mine Reclamation at Generation Facilities Not Operated by TEP**

TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP's PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.

TEP is liable for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP's liability balance related to its share of final mine reclamation costs at Four Corners totaled $3 million as of September 30, 2025, and December 31, 2024, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP's coal supply agreement with Four Corners expires in 2031.

TEP ceased operations at San Juan upon expiration of the coal supply agreement in 2022. TEP's remaining final mine reclamation liability at San Juan was $25 million and $31 million as of September 30, 2025, and December 31, 2024, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2040. See Note 1 for additional information on restricted cash relating to TEP's share of final mine reclamation and decommissioning costs at San Juan.

**Performance Guarantees**

TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. There is no maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of September 30, 2025, there have been no such payment defaults under either of the participation agreements.

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

**Environmental Matters**

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

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**<u>NOTE 9. EMPLOYEE BENEFIT PLANS</u>**

Net periodic benefit cost includes the following components:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Pension Benefits** | **Pension Benefits** | **Other Postretirement Benefits** | **Other Postretirement Benefits** |
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Three Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| Service Cost | $4 | $4 | $1 | $1 |
| Non-Service Cost <sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Interest Cost | 7 | 6 | 1 | 1 |
| &nbsp;&nbsp;&nbsp;Expected Return on Plan Assets | (8) | (8) | (1) | (1) |
| &nbsp;&nbsp;&nbsp;Amortization of Net Loss | 1 | 1 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;**Net Periodic Benefit Cost** | $4 | $3 | $1 | $1 |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| Service Cost | $11 | $11 | $3 | $3 |
| Non-Service Cost <sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Interest Cost | 19 | 18 | 3 | 3 |
| &nbsp;&nbsp;&nbsp;Expected Return on Plan Assets | (23) | (24) | (2) | (2) |
| &nbsp;&nbsp;&nbsp;Amortization of Net Loss | 4 | 4 | (1) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;**Net Periodic Benefit Cost** | $11 | $9 | $3 | $4 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

**<u>NOTE 10. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS</u>**

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, 2025** | **September 30, 2025** | **September 30, 2025** |
| **Assets** |  |  |  |
| &nbsp;&nbsp;Restricted Cash <sup>(1)</sup> | $27 | $— | $27 |
| &nbsp;&nbsp;Energy Derivative Contracts, Regulatory Recovery <sup>(2)</sup> |  | 35 | 35 |
| &nbsp;&nbsp;Energy Derivative Contracts, No Regulatory Recovery <sup>(2)</sup> |  | 4 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Assets** | 27 | 39 | 66 |
| **Liabilities** |  |  |  |
| &nbsp;&nbsp;Energy Derivative Contracts, Regulatory Recovery <sup>(2)</sup> |  | (33) | (33) |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Liabilities** |  | (33) | (33) |
| **Total Assets (Liabilities), Net** | $27 | $6 | $33 |

---

---

| | | | |
|:---|:---|:---|:---|
| (in millions) | **December 31, 2024** | **December 31, 2024** | **December 31, 2024** |
| **Assets** |  |  |  |
| &nbsp;&nbsp;Restricted Cash <sup>(1)</sup> | $35 | $— | $35 |
| &nbsp;&nbsp;Energy Derivative Contracts, Regulatory Recovery <sup>(2)</sup> |  | 33 | 33 |
| &nbsp;&nbsp;Energy Derivative Contracts, No Regulatory Recovery <sup>(2)</sup> |  | 4 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Assets** | 35 | 37 | 72 |
| **Liabilities** |  |  |  |
| &nbsp;&nbsp;Energy Derivative Contracts, Regulatory Recovery <sup>(2)</sup> |  | (31) | (31) |
| &nbsp;&nbsp;Energy Derivative Contracts, No Regulatory Recovery <sup>(2)</sup> |  | (1) | (1) |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Liabilities** |  | (32) | (32) |
| **Total Assets (Liabilities), Net** | $35 | $5 | $40 |

---

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>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.

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** | **Gross Amount Not Offset in the Balance Sheets** | **Net Amount** |
| | **Gross Amount Recognized in the Balance Sheets** | **Counterparty Netting of Energy Contracts** | **Cash Collateral Received/Posted** | **Net Amount** |
| (in millions) | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** | **September 30, 2025** |
| **Derivative Assets** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Energy Derivative Contracts | $39 | $20 | $— | $19 |
| **Derivative Liabilities** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Energy Derivative Contracts | (33) | (20) |  | (13) |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| (in millions) | **December 31, 2024** | **December 31, 2024** | **December 31, 2024** | **December 31, 2024** |
| **Derivative Assets** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Energy Derivative Contracts | $37 | $17 | $— | $20 |
| **Derivative Liabilities** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Energy Derivative Contracts | (32) | (17) |  | (15) |

---

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**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,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| Unrealized Net Gain (Loss) | $(21) | $8 | $(1) | $— |

---

**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,** | **Three Months Ended September 30,** | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** | **2025** | **2024** |
| Operating Revenues | $2 | $3 | $23 | $30 |

---

**Derivative Volumes**

As of September 30, 2025, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

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| | | |
|:---|:---|:---|
| | **September 30, 2025** | **December 31, 2024** |
| Power Contracts GWh | 2,755 | 1,634 |
| Gas Contracts BBtu | 78,736 | 86,070 |

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**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 $29 million as of September 30, 2025, compared with $30 million as of December 31, 2024. TEP had no cash posted as collateral to provide credit enhancement as of September 30, 2025, and December 31, 2024. TEP would have been required to post $29 million and $30 million of collateral if the credit risk contingent features had been triggered on September 30, 2025, and December 31, 2024, respectively. TEP had $18 million and $15 million in outstanding net payable balances for settled positions as of September 30, 2025, and December 31, 2024, 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.

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:

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Fair Value Hierarchy** | **Net Carrying Value** | **Net Carrying Value** | **Fair Value** | **Fair Value** |
| (in millions) | **Fair Value Hierarchy** | **September 30, 2025** | **December 31, 2024** | **September 30, 2025** | **December 31, 2024** |
| **Liabilities** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Long-Term Debt, including Current Maturities | Level 2 | $2792 | $2495 | $2529 | $2153 |

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**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)**

**<u>NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION</u>**

**CASH TRANSACTIONS**

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| | | |
|:---|:---|:---|
| | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** |
| Interest Paid, Net of Amounts Capitalized | $59 | $51 |

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**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,** | **Nine Months Ended September 30,** |
| (in millions) | **2025** | **2024** |
| Accrued Capital Expenditures <sup>(1)</sup> | $42 | $93 |
| Asset Retirement Obligations Increase (Decrease) | 5 | (2) |
| Renewable Energy Credits | 4 | 4 |
| Net Cost of Removal Increase (Decrease) <sup>(2)</sup> | (16) | (5) |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>In 2025, primarily represents accrued capital expenditures related to Roadrunner Reserve II. In 2024, primarily represents accrued capital expenditures related to Roadrunner Reserve I.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>Represents the change in accrual for future cost of retirement net of salvage values that 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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• outlook and strategies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• factors affecting results of operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• results of operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• liquidity and capital resources, including capital expenditures, income tax position, and environmental matters;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• critical accounting estimates; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• new accounting standards issued and not yet adopted.

Management's Discussion and Analysis includes financial information prepared in accordance with GAAP.

Management's Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes in Part I, Item 1 of this Quarterly Report on Form 10-Q. For information on factors that may cause our actual future results to differ from those we currently anticipate, see Forward-Looking Information at the front of this Quarterly Report on Form 10-Q and Risk Factors in Part 1, Item 1A of our 2024 Annual Report on Form 10-K, and in Part II, Item 1A of this Form Quarterly Report on 10-Q.

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

**OUTLOOK AND STRATEGIES**

Our financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws, regulations, and policies; and (iv) other regulatory and legislative actions, as well as changes to governmental policies, programs, and priorities and their impact on each of (i) - (iii) above. Our plans and strategies include:

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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 are reevaluating our interim goal which aimed to reduce carbon emissions by 80% (compared to 2005) by 2035. Our ability to achieve these goals could be impacted by various federal and state energy policies, significant load growth, and the pace of development of clean energy technologies.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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 2025 compared with the third quarter of 2024**

We reported net income of $144 million in the third quarter of 2025 compared with net income of $140 million in the third quarter of 2024. The increase of $4 million, or 3%, was primarily due to (net of tax):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $13 million in higher margin from retail revenue primarily due to an increase in the retail component of our transmission revenue requirement due to a higher rate base and higher LFCR revenues; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $5 million in higher AFUDC due to an increase in eligible construction expenditures.

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The increase was partially offset by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $6 million in higher base operations and maintenance expenses primarily due to higher employee wages and benefits expenses and an increase in outside services expenses;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in higher depreciation expense primarily due to an increase in asset base;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in lower interest income due to lower cash balances in interest-bearing bank accounts in 2025; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in higher interest expense primarily due to the issuance of debt in August 2024 and February 2025.

**Performance - The first nine months of 2025 compared with the first nine months of 2024** 

We reported net income of $260 million in the first nine months of 2025 compared with net income of $262 million in the first nine months of 2024. The decrease of $2 million, or 1%, was primarily due to (net of tax):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $13 million in higher interest expense primarily due to the issuance of debt in August 2024 and February 2025;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $11 million in higher base operations and maintenance expenses primarily due to higher employee benefits and wages expenses, higher operations and maintenance expenses at our generation facilities, and an increase in outside services expenses;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $8 million in lower margin from wholesale transactions primarily due to unfavorable market conditions resulting in a decrease in revenues from wholesale trading as defined in the PPFAC plan of administration; and

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

The decrease was partially offset by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $18 million in higher AFUDC due to an increase in eligible construction expenditures; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $18 million in higher margin from retail revenue primarily due to an increase in the retail component of our transmission revenue requirement due to a higher rate base and higher LFCR revenues.

**FACTORS AFFECTING RESULTS OF OPERATIONS**

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

**Regulatory Matters**

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

<u>2025 Rate Case</u>

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

Our key 2025 Rate Case proposals are described below:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a $172 million net increase in retail revenues comprised of the following components:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ a non-fuel retail revenue increase of $220 million over test year non-fuel retail revenues,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ a $26 million decrease in fuel-related retail revenues, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ elimination of certain existing adjustor mechanisms, including the DSM surcharge, and, if a new proposed ARAM is approved, the ECA, TEAM, and LFCR mechanism, that result in a $22 million reduction in revenues collected from customers;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a 7.73% return on original cost rate base of $4.3 billion, which includes a return on equity of 10.50% and an average cost of debt of 4.28%;

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a new ARAM that is a formula rate adjustor designed to update rates annually based on historical changes in our revenue requirement. The expected benefits of the ARAM include improved rate stability for customers, timely cost recovery, and reduced administrative burden;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ if the proposed ARAM is not approved, a new SRB mechanism, which would help recover investments in significant generation resources, and a new LIRA, which would allow us to recover or refund differences between actual limited income tariff costs and the costs included in base rates; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a new CEM framework, which will support initiatives to achieve energy savings and load optimization. The framework will replace the existing energy efficiency implementation and transportation electrification plans. If approved, costs would be recovered through a CEM surcharge pending inclusion in the first ARAM adjustment.

We requested new rates to be implemented by September 1, 2026. We cannot predict the timing or outcome of this proceeding.

<u>Roadrunner Reserve I Accounting Order</u>

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.

<u>Southwest Power Pool Markets+</u>

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

<u>Renewable Energy and Electric Energy Efficiency Standards Repeal</u>

In January 2024, the ACC opened dockets to review the RES and EE Standards. Under the current RES rules, Arizona regulated electric utilities are required to gradually increase their use of renewable energy until it comprises at least 15% of 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.

A Notice of Proposed Rulemaking (NOPR) recommending the repeal of the RES rules was published in the Arizona Administrative Register on October 3, 2025. A second NOPR, proposing the repeal of the EE Standards, was published on October 24, 2025. We are unable to predict the timing or outcome of these rulemaking proceedings.

<u>City of Tucson Energy Sourcing Study</u>

The City of Tucson engaged a consulting and engineering firm to prepare a study analyzing alternatives to our provision of service to the City of Tucson, including evaluating a municipalization option. While an initial draft of the study, published in April 2025, suggests that establishing a municipal utility that would primarily serve customers in the City of Tucson would result in potential customer savings, the study also notes that the City of Tucson would assume significant risks and incur substantial costs to pursue such an option. Such costs would include the purchase of property and plant at fair value and the costs to separate our remaining electrical grid from the City of Tucson. The City of Tucson would need to authorize the expenditure of funds for significant additional due diligence to demonstrate engineering and economic feasibility before the City of Tucson could pursue municipalization. Ultimately, establishing a municipal utility would require approval by a majority of the voters of the residents of the City of Tucson in a general or special municipal election. If such a measure were approved, the City of Tucson would need to exercise its right of eminent domain by filing an action for condemnation in Pima County Superior Court, and any determination in such condemnation proceedings would be subject to appeal. In May 2025, the Tucson City Council voted to accept the study and has not taken further action to pursue municipalization at this time.

<u>Securitization</u>

In May 2025, Arizona's governor signed House Bill 2679, which allows for securitization bond financing by public power utility companies in Arizona. Under the legislation, bonds can be issued by a special purpose entity, the costs of which are payable by the utility company's customers through an irrevocable tariff charged by the utility company upon approval of the tariff by the ACC. The proceeds of the bonds are used to finance the utility company's qualifying costs or investments including

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the remaining unrecovered book value of its assets retired or planned to be retired. This legislation allows for potentially lower overall financing costs to be recovered from customers than those charged through traditional rates. We do not currently have plans related to securitization bond financing.

<u>Wildfire Mitigation Planning</u>

In May 2025, Arizona's governor signed House Bill 2201 that requires us to submit a wildfire mitigation plan for approval by the Arizona Department of Forestry and Fire Management once every two years beginning in 2026. The plan will outline how we monitor and perform preventive actions to mitigate risk related to utility-caused wildfires. In the event of a wildfire in our service area, House Bill 2201 limits claims made against us if we are determined to be in compliance with our approved wildfire mitigation plan.

**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 identified in our 2023 IRP, we are pursuing a plan to convert Springerville Units 1 and 2 from coal-fired generation to natural gas-fired generation by 2030. This conversion allows 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 of Four Corners in 2031.

In 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards an aspirational goal of net zero direct GHG emissions by 2050. In October 2024, the ACC acknowledged our 2023 IRP and found it to be reasonable and in the public interest. Our plan to convert Springerville Units 1 and 2 from coal-fired generation is expected to result in additional natural gas-fired generation compared to our 2023 IRP. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings.

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• an EPC agreement in September 2023 to develop Roadrunner Reserve I. Roadrunner Reserve I is a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh that was placed in service in July 2025;

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

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

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

<u>Production Tax Credits</u>

PTCs are per-kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded approximately $9 million and $17 million in PTCs related to Oso Grande for the three and nine months ended September 30, 2025, respectively, and $10 million and $20 million for the three and nine months

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ended September 30, 2024, respectively. The PTC rate published by the Internal Revenue Service for electricity produced by a qualified facility using wind placed in service prior to 2022 is $0.030 for 2025 and was $0.029 for 2024.

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

<u>Pipeline Expansion Agreement</u> 

In September 2025, as part of ongoing efforts to support system reliability and to meet future load growth, we entered into a long-term gas transportation precedent agreement to secure reliable access to natural gas. The agreement supports the development of a new pipeline, expected to be in service by late 2029, which will be owned and operated by a third-party provider.

Upon successful construction and commercial operation of the pipeline, our purchase commitments under the related gas transportation services agreement are expected to begin in 2029. These commitments are estimated to total $1.5 billion over the 25-year service period.

**Sales Growth and Seasonality**

Our average retail sales growth has remained relatively flat over the past three years. Recently, we have experienced interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet above what is reflected in our 2023 IRP, as well as higher transmission and distribution infrastructure investments.

In addition to the Energy Supply Agreement (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.

<u>Energy Supply Agreement</u>

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 agreement is subject to ACC approval and other contractual contingencies. We also reached an agreement with respect to an accompanying construction project to design, engineer, procure, construct, install, and place into service transmission and switchyard facilities to provide retail electric service to the customer. The project construction agreement is subject to FERC approval. We cannot predict the timing or outcome of these requests for approval. 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 customer from our existing and planned generation resources.

<u>Weather Patterns</u>

Changing weather patterns and other factors cause seasonal fluctuations in sales of power. 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. As a result, seasonal fluctuations affect the comparability of our results of operations.

**Interest Rates**

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

**RESULTS OF OPERATIONS** 

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• **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

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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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• **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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• **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 2025 compared with the same periods in 2024 presented on a pre-tax basis.

**Operating Revenues**

The following table provides a disaggregation of Operating Revenues:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Increase (Decrease)** | &nbsp;&nbsp;&nbsp;**Nine Months Ended September 30,** | &nbsp;&nbsp;&nbsp;**Nine Months Ended September 30,** | **Increase (Decrease)** |
| (in millions) | **2025** | **2024** | **Percent** | **2025** | **2024** | **Percent** |
| **Operating Revenues** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Retail | $434 | $436 | (0.5)% | $994 | $1052 | (5.5)% |
| &nbsp;&nbsp;Wholesale, Short-Term <sup>(1)</sup> | 33 | 45 | (26.7)% | 100 | 156 | (35.9)% |
| &nbsp;&nbsp;&nbsp;Wholesale, Long-Term | 15 | 13 | 15.4% | 43 | 44 | (2.3)% |
| &nbsp;&nbsp;&nbsp;Transmission | 15 | 15 | —% | 45 | 41 | 9.8% |
| &nbsp;&nbsp;&nbsp;Springerville Units 3 and 4 Participant Billings | 23 | 21 | 9.5% | 64 | 80 | (20.0)% |
| &nbsp;&nbsp;&nbsp;Other | 25 | 22 | 13.6% | 71 | 61 | 16.4% |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Operating Revenues** | $545 | $552 | (1.3)% | $1317 | $1434 | (8.2)% |

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

We reported Operating Revenues of $545 million in the third quarter of 2025 compared with $552 million in the same period for 2024. The decrease of $7 million, or 1%, was primarily due to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $12 million in lower short-term wholesale revenue primarily due to a decrease in price and volume; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in lower retail revenue primarily due to lower PPFAC recoveries as a result of a decrease in the PPFAC rate; partially offset by an increase in the retail component of our transmission revenue requirement due to a higher rate base.

The decrease was partially offset by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $3 million in higher other revenue primarily due to higher LFCR revenues;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in higher Springerville Units 3 and 4 participant billings primarily due to higher reimbursable maintenance expenses; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in higher long-term wholesale revenue primarily due to an increase in price; partially offset by a decrease in volume as a result of less favorable market conditions.

We reported Operating Revenues of $1,317 million for the first nine months of 2025 compared with $1,434 million in the same period for 2024. The decrease of $117 million, or 8%, was primarily due to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $58 million in lower retail revenue primarily due to lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate; partially offset by an increase in the retail component of our transmission revenue requirement due to a higher rate base;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $56 million in lower short-term wholesale revenue primarily due to a decrease in volume and price, and a decrease in revenue from wholesale trading as defined in the PPFAC plan of administration due to unfavorable market conditions; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $16 million in lower Springerville Unit 4 participant billings primarily due to higher reimbursable planned outage costs in 2024.

The decrease was partially offset by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $10 million in higher other revenue primarily due to higher LFCR revenues; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $4 million in higher transmission revenue due to an increase in our transmission revenue requirement due to a higher rate base.

The following table provides key statistics impacting Operating Revenues:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Increase (Decrease)** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Nine Months Ended September 30,** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Nine Months Ended September 30,** | **Increase (Decrease)** |
| (kWh in millions) | **2025** | **2024** | **Percent** | **2025** | **2024** | **Percent** |
| **Electric Sales** (kWh) <sup>(1)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Retail Sales | 3057 | 2988 | 2.3% | 7030 | 7013 | 0.2% |
| &nbsp;&nbsp;&nbsp;Wholesale, Long-Term | 195 | 226 | (13.7)% | 642 | 740 | (13.2)% |
| &nbsp;&nbsp;&nbsp;Wholesale, Short-Term | 1126 | 1162 | (3.1)% | 2840 | 3940 | (27.9)% |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Electric Sales** | 4378 | 4376 | —% | 10512 | 11693 | (10.1)% |
| **Average Revenue** (cents per kWh) <sup>(2)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Retail | 14.20 | 14.60 | (2.7)% | 14.15 | 15.00 | (5.7)% |
| &nbsp;&nbsp;&nbsp;Wholesale, Long-Term | 7.66 | 6.08 | 26.0% | 6.71 | 6.00 | 11.8% |
| &nbsp;&nbsp;&nbsp;Wholesale, Short-Term | 3.14 | 3.87 | (18.9)% | 2.87 | 3.26 | (12.0)% |
| **Total Retail Customers** <sup>(3)</sup> |  |  |  | 456330 | 451072 | 1.2% |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>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.

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

**Operating Expenses**

<u>Fuel and Purchased Power Expense</u>

We reported Fuel and Purchased Power expense of $162 million in the third quarter of 2025 compared with $188 million in the same period for 2024. The decrease of $26 million, or 14%, was primarily due to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $29 million in lower PPFAC Recovery Treatment primarily due to a decrease in PPFAC recoveries and an increase in PPFAC eligible costs deferred as a regulatory asset for future recovery; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $9 million in lower Purchased Power expense primarily due to a decrease in price; partially offset by an increase in volume.

The decrease was partially offset by $12 million in higher Fuel expenses primarily due to an increase in gas prices; partially offset by lower realized losses on natural gas swaps.

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We reported Fuel and Purchased Power expense of $394 million for the first nine months of 2025 compared with $511 million for the same period for 2024. The decrease of $117 million, or 23%, was primarily due to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $101 million in lower PPFAC Recovery Treatment primarily due to a decrease in PPFAC recoveries and an increase in PPFAC eligible costs deferred as a regulatory asset for future recovery;

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $7 million in lower Fuel expenses primarily due to lower realized losses on natural gas swaps and a decrease in Coal-Fired and Gas-Fired Generation volumes; partially offset by an increase in gas prices.

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

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Three Months Ended September 30,** | **Three Months Ended September 30,** | **Increase (Decrease)** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Nine Months Ended September 30,** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Nine Months Ended September 30,** | **Increase (Decrease)** |
| (kWh in millions) | **2025** | **2024** | **Percent** | **2025** | **2024** | **Percent** |
| **Sources of Energy** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Coal-Fired Generation | 1011 | 933 | 8.4% | 2135 | 2512 | (15.0)% |
| &nbsp;&nbsp;&nbsp;Gas-Fired Generation | 2584 | 2696 | (4.2)% | 5794 | 6686 | (13.3)% |
| &nbsp;&nbsp;&nbsp;Utility-Owned Renewable Generation | 146 | 181 | (19.3)% | 514 | 595 | (13.6)% |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Generation** | 3741 | 3810 | (1.8)% | 8443 | 9793 | (13.8)% |
| &nbsp;&nbsp;&nbsp;Purchased Power | 815 | 749 | 8.8% | 2527 | 2323 | 8.8% |
| &nbsp;&nbsp;&nbsp;&nbsp;**Total Generation and Purchased Power** <sup>(1)</sup> | 4556 | 4559 | (0.1)% | 10970 | 12116 | (9.5)% |

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| (cents per kWh) |  |  |  |  |  |  |
| **Average Cost of Generated and Purchased Power** |  |  |  |  |  |  |
| &nbsp;&nbsp;Coal <sup>(2)</sup> | 4.32 | 4.02 | 7.5% | 4.52 | 4.42 | 2.3% |
| &nbsp;&nbsp;Natural Gas <sup>(2)(3)</sup> | 2.27 | 1.97 | 15.2% | 2.57 | 2.13 | 20.7% |
| &nbsp;&nbsp;Purchased Power <sup>(4)</sup> | 5.16 | 6.78 | (23.9)% | 4.11 | 4.49 | (8.5)% |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup>Includes realized gains and losses from hedging activity.

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

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<u>Operations and Maintenance Expense</u>

We reported Operations and Maintenance expense of $116 million in the third quarter of 2025 compared with $106 million in the same period for 2024. The increase of $10 million, or 9%, was primarily due to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $4 million increase in employee wages and benefits expenses;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in higher reimbursable maintenance expense related to Springerville Units 3 and 4; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $2 million in higher outside services expenses.

We reported Operations and Maintenance expense of $327 million for the first nine months of 2025 compared with $330 million for the same period for 2024. The decrease of $3 million, or 1%, was primarily due to $16 million in lower reimbursable maintenance expense related to Springerville Unit 4 primarily due to higher planned outage costs in 2024.

The decrease was partially offset by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $6 million increase in employee benefits and wages expenses;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $3 million in higher operations and maintenance expenses at our generation facilities; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• $3 million in higher outside services expenses.

<u>Depreciation and Amortization Expense</u>

We reported Depreciation and Amortization expense of $67 million in the third quarter of 2025 compared with $64 million in the same period for 2024. The increase of $3 million, or 5%, was primarily due to an increase in asset base.

We reported Depreciation and Amortization expense of $198 million for the first nine months of 2025 compared with $192 million for the same period for 2024. The increase of $6 million, or 3%, was primarily due to an increase in asset base.

**Other Income (Expense)**

We reported Other Expense of $15 million in each of the third quarter of 2025 and 2024. Changes in 2025 compared to 2024 were primarily due to a $3 million decrease in interest income due to lower cash balances in interest-bearing bank accounts in 2025 and $3 million in higher interest expense due to the issuance of debt in August 2024 and February 2025; offset by $6 million in higher AFUDC due to an increase in eligible construction expenditures.

We reported Other Expense of $43 million for the first nine months of 2025 compared with $46 million in the same period for 2024. The decrease of $3 million, or 7%, was primarily due to $21 million in higher AFUDC due to an increase in eligible construction expenditures. The decrease was partially offset by $16 million in higher interest expense due to the issuance of debt in August 2024 and February 2025.

**Income Tax Expense**

We reported Income Tax Expense of $23 million in the third quarter of 2025 compared with $21 million in the same period for 2024. The increase of $2 million, or 10%, was primarily due to higher tax expense due to an increase in taxable earnings.

We reported Income Tax Expense of $40 million for the first nine months of 2025 compared with $39 million for the same period for 2024. The increase of $1 million, or 3%, was primarily due to $3 million in lower tax credits related to Oso Grande PTCs; partially offset by $2 million in lower tax expense due to higher AFUDC equity due to an increase in eligible construction expenditures.

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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 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.

<u>Available Liquidity</u> 

---

| | |
|:---|:---|
| (in millions) | **September 30, 2025** |
| Cash and Cash Equivalents | $43 |
| Amount Available under Revolving Credit Agreement <sup>(1)</sup> | 159 |
| &nbsp;&nbsp;&nbsp;**Total Liquidity** | $202 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively. In October 2025, the maturity date was extended one year to October 2028. See *Access to Credit* below.

<u>Future Liquidity Requirements</u>

We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include but are not limited to: (i) dividend payments; (ii) debt maturities; (iii) employee benefit obligations; and (iv) known commitments and other contractual obligations including forecasted capital expenditures.

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

<u>Summary of Cash Flows</u>

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

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| | | | |
|:---|:---|:---|:---|
| | **Nine Months Ended September 30,** | **Nine Months Ended September 30,** | **Increase (Decrease)** |
| (in millions) | **2025** | **2024** | **Percent** |
| Operating Activities <sup>(1)</sup> | $454 | $530 | (14.3)% |
| Investing Activities <sup>(1)</sup> | (728) | (505) | 44.2% |
| Financing Activities <sup>(1)</sup> | 295 | 313 | (5.8)% |
| &nbsp;&nbsp;&nbsp;**Net Increase (Decrease)** | 21 | 338 | \* |
| **Beginning of Period** | 49 | 43 | 14.0% |
| **End of Period** | $70 | $381 | (81.6)% |

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\*Not meaningful

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>Calculated on rounded data and may not correspond exactly to amounts on the Condensed Consolidated Statements of Cash Flows.

*Operating Activities* 

Net cash flows provided by operating activities decreased by $76 million in the first nine months of 2025 compared with the same period in 2024 primarily due to lower PPFAC recoveries in 2025.

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*Investing Activities* 

Net cash flows used for investing activities increased by $223 million in the first nine months of 2025 compared with the same period in 2024 primarily due to an increase in cash paid for capital expenditures.

*Financing Activities* 

Net cash flows provided by financing activities decreased by $18 million in the first nine months of 2025 compared with the same period in 2024 primarily due to lower proceeds from debt issuance; partially offset by a decrease in dividends paid to UNS Energy.

<u>Sources of Liquidity</u> 

*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, 2025, we had no short-term investments.

*Access to Credit* 

We have access to working capital through our credit agreement with lenders. Amounts borrowed from the 2021 Credit Agreement are used for working capital and other general corporate purposes. LOCs may be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of September 30, 2025, there was $159 million available under the 2021 Credit Agreement, which reflects $70 million of outstanding borrowings and LOCs totaling $21 million issued with fees that accrue at a rate of 1.050% per annum. As of November 3, 2025, there was $165 million available under the 2021 Credit Agreement.

See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q and Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2024 Annual Report on Form 10-K for additional information regarding our 2021 Credit Agreement.

*Debt Financing*

We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings. In March 2025, we filed with the SEC an automatic shelf registration statement on Form S-3, which expires in March 2028. On October 23, 2025, the ACC issued an order granting us financing authority that will take 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.

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

*Credit Ratings*

Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2025, credit ratings from S&P Global Ratings and Moody's Investors Service for our senior unsecured debt were A- (negative) and A3 (stable), respectively.

Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold our securities. Each rating should be evaluated independently of any other ratings.

The 2021 Credit Agreement contains pricing based on our credit ratings. A change in our credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.

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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, 2025, we were in compliance with these covenants.

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

*Contributions from Parent* 

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

*Dividends Declared and Paid to Parent* 

We did not declare or pay dividends to UNS Energy in the third quarter or first nine months of 2025. We declared and paid $85 million in dividends to UNS Energy in the third quarter and first nine months of 2024.

<u>Master Trading Agreements</u>

We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of September 30, 2025, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.

**Capital Expenditures**

Our routine capital expenditures support customer growth, system reinforcement, replacements and betterments, and compliance with environmental 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 2025 were $691 million.

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

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Years Ended December 31,** | **Years Ended December 31,** | **Years Ended December 31,** | **Years Ended December 31,** | **Years Ended December 31,** |
| (in millions) | **2025** | **2026** | **2027** | **2028** | **2029** |
| Generation Facilities: |  |  |  |  |  |
| &nbsp;&nbsp;New Energy Resources <sup>(1)</sup> | $219 | $6 | $— | $— | $— |
| &nbsp;&nbsp;Other Generation Facilities <sup>(2)</sup> | 137 | 90 | 62 | 97 | 120 |
| Total Generation Facilities | 356 | 96 | 62 | 97 | 120 |
| Transmission and Distribution <sup>(3)</sup> | 371 | 447 | 358 | 322 | 716 |
| General and Other <sup>(4)</sup> | 107 | 98 | 73 | 75 | 90 |
| &nbsp;&nbsp;&nbsp;**Total Capital Expenditures** | $834 | $641 | $493 | $494 | $926 |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup>Includes investments in renewable energy, Roadrunner Reserve I and II in alignment with our long-term strategy of transitioning to a less carbon intensive energy portfolio.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup>Includes investments in existing facilities, including upgrades and ongoing maintenance to ensure reliability.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup>Investments in transmission capacity and distribution system reliability.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup>Includes costs for information technology, fleet, facilities, and communication equipment.

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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, 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. Although there has been no material effect on our operations or financial performance in 2025, future increases in tariffs or related supply chain disruptions could significantly raise costs if mitigation efforts are unsuccessful. 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.

**Income Tax Position**

<u>Tax Sharing Agreement</u>

Under the terms of the tax sharing agreement with UNS Energy, we made $3 million and $9 million in tax sharing payments for the first nine months of 2025, and 2024, respectively. Future tax sharing cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.

<u>Investment Tax Credits</u>

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. Roadrunner Reserve I has qualified for the base federal tax credit. Based on current eligibility criteria, we anticipate Roadrunner Reserve II will also qualify. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for information related to the ITCs generated by Roadrunner Reserve I. The IRA provides an election to transfer (i.e., sell) some or all of certain tax credits generated by a qualifying facility to unrelated third parties in exchange for cash. Transfer elections must be made on a facility-by-facility and year-by-year basis. Any election to transfer tax credits must be made and cash must be received on or before the due date of the tax return for the year the facility is placed in service. Roadrunner Reserve I was placed in service in July 2025, and Roadrunner Reserve II is expected to be placed in service in 2026.

<u>One Big Beautiful Bill Act</u>

In July 2025, the OBBBA was signed into law enacting extensions of the expiring provisions of the 2017 Tax Cuts and Jobs Act and additional business tax provisions. The OBBBA also accelerates phase out of, and adds various restrictions to, PTCs and ITCs applicable to certain facilities per provisions generally enacted or extended as part of the IRA. We do not expect the OBBBA to affect the federal tax credits for which Roadrunner Reserve I and Roadrunner Reserve II are eligible or our potential to transfer some or all of those credits for cash. The OBBBA did not have a material impact on TEP's financial position, results of operations, or cash flows.

**Environmental Matters** 

The EPA has the authority to regulate the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs.

<u>Regional Haze Regulations</u> 

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

In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The ADEQ began to develop a control strategy with a focus on making reasonable progress toward the national visibility goal. In July 2019, we were notified by the ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluations. We conducted the potential emissions controls evaluations, commonly referred to as the four-factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP.

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

In February 2025, TEP and SRP also concurrently filed a joint Petition for Administrative Reconsideration with the EPA. We requested the EPA reconsider the final rule and act to approve the ADEQ's Regional Haze SIP revision. In 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.

<u>Greenhouse Gas Regulation</u>

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

The final rules established:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• new source performance standards for new stationary natural gas-fired combustion turbines, which are subcategorized based on the annual capacity factor for each unit. For base load units (i.e., units with an annual capacity factor greater than 40%), the EPA established a two-phased performance standard. For phase 1, new base load units must initially meet performance standards based on the use of highly efficient combined cycle generation with the best operating and maintenance practices. For phase 2, the final rule requires that such base load units achieve emissions reductions aligned with a 90% carbon capture and sequestration (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 electric generating units do not contribute significantly to GHG air pollution. In the alternative proposal, the EPA proposed to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 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;

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

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

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

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<u>Coal Combustion Residuals Regulation</u>

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

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

We are analyzing the EPA's final rule for potential impacts to our operations. We anticipate CCRMUs will be identified at Springerville and Four Corners. The number, location, and size of these CCRMUs will be assessed in accordance with the compliance schedule outlined in the EPA's final rule; therefore, associated compliance costs cannot be accurately predicted at this time. SRP 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. We cannot predict the outcome of this matter.

<u>Good Neighbor Federal Implementation Plan</u> 

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

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

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

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

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

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

**NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED**

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

**ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

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

There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 2024 Annual Report on Form 10-K.

**ITEM 4. CONTROLS AND PROCEDURES**

TEP's Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP's evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP's periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms. These disclosure controls and procedures are also 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, 2025. There was no change in TEP's internal control over financial reporting during the quarter ended September 30, 2025, that materially affected, or is reasonably likely to materially affect, TEP's internal control over financial reporting.

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<u>[**Table of Contents**](#i20523c99670a4277b7f5efd6341939f5_7)</u>

**PART II**

**ITEM 1. LEGAL PROCEEDINGS**

For a description of certain legal proceedings affecting TEP, refer to Note 8 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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

**ITEM 1A. RISK FACTORS**

The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2024 Annual Report on Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2024 Annual Report on Form 10-K.

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**ITEM 6. EXHIBITS**

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| | |
|:---|:---|
| **EXHIBIT INDEX** | **EXHIBIT INDEX** |
| **Exhibit No.** | **Description** |
| \*<u>[31(a)](tepex31a09302025.htm)</u> | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Susan M. Gray. |
| \*<u>[31(b)](tepex31b09302025.htm)</u> | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by J. Caleb Adcock. |
| \*\*<u>[32](tepex3209302025.htm)</u> | 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, 2025, formatted in Inline XBRL and contained in Exhibit 101. |

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\* Filed herewith. <br> \*\* 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 3, 2025 | /s/ J. Caleb Adcock |
| | | J. Caleb Adcock |
| | | Chief Financial Officer and Vice President |
| | | (Principal Financial Officer and Principal Accounting Officer) |

---

## Ex-31.A

**Exhibit 31(a)**

**CERTIFICATION**

**Pursuant to Section 302 of the Sarbanes-Oxley Act**

I, Susan M. Gray, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.I have reviewed this quarterly report on Form 10-Q of Tucson Electric Power Company;

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

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

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

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

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

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

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

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

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

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

---

| | | |
|:---|:---|:---|
| Date: | November 3, 2025 | /s/ Susan M. Gray |
| | | &nbsp;&nbsp;&nbsp;&nbsp;Susan M. Gray |
| | | &nbsp;&nbsp;&nbsp;&nbsp;President, Chief Executive Officer, and Director |
| | | &nbsp;&nbsp;&nbsp;&nbsp;(Principal Executive Officer) |

---

## Ex-31.B

**Exhibit 31(b)**

**CERTIFICATION**

**Pursuant to Section 302 of the Sarbanes-Oxley Act**

I, J. Caleb Adcock, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.I have reviewed this quarterly report on Form 10-Q of Tucson Electric Power Company;

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

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

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

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

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

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

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

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

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

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

---

| | | |
|:---|:---|:---|
| Date: | November 3, 2025 | /s/ J. Caleb Adcock |
| | | &nbsp;&nbsp;&nbsp;&nbsp;J. Caleb Adcock |
| | | &nbsp;&nbsp;&nbsp;&nbsp;Chief Financial Officer and Vice President |
| | | &nbsp;&nbsp;&nbsp;&nbsp;(Principal Financial Officer) |

---

## Ex-32

**Exhibit 32**

**STATEMENTS OF CORPORATE OFFICERS**

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

In connection with the Quarterly Report of Tucson Electric Power Company (the Company) on Form 10-Q for the period ended September 30, 2025, as filed with the Securities and Exchange Commission on the date hereof (the Report), each of the undersigned, Susan M. Gray, President and Chief Executive Officer of the Company, and J. Caleb Adcock, Chief Financial Officer and Vice President of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

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| | | |
|:---|:---|:---|
| Date: | November 3, 2025 | /s/ Susan M. Gray |
|  |  | Susan M. Gray |
|  |  | President, Chief Executive Officer, and Director |
|  |  | (Principal Executive Officer) |
| Date: | November 3, 2025 | /s/ J. Caleb Adcock |
|  |  | J. Caleb Adcock |
|  |  | Chief Financial Officer and Vice President |
|  |  | (Principal Financial Officer) |

---

<br>