UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 (Mark One)
 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2024
 OR
 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from to.
 Commission File Number 1-5924
 TUCSON ELECTRIC POWER CO MPANY
 (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

 Securities registered pursuant to Section 12(b) of the Exchange Act: None
 Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, No Par Value (Title of Class)
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
 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 x No o
 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 x No o
 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 x

 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. o

 Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. o
 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). o
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No x
 State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter: None
 As of February 13, 2025, Tucson Electric Power Company had 32,139,434 shares of common stock, no par value, outstanding, all of which were held by UNS Energy Corporation, an indirect wholly-owned subsidiary of Fortis Inc.
 Documents incorporated by reference: None
 Tucson Electric Power Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is, therefore, filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

 ii

 Definitions

 v

 Forward-Looking Information

 viii

 Item 1. Business

 Overview of Business

 Environmental Matters

 Human Capital

 Information about our Executive Officers

 SEC Reports Available

 Item 1A. Risk Factors

 Item 1B. Unresolved Staff Comments

 Item 1C. Cybersecurity

 Item 2. Properties

 Item 3. Legal Proceedings

 Item 4. Mine Safety Disclosures

 Item 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

 Item 6. [Reserved]

 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

 Critical Accounting Estimates

 New Accounting Standards Issued and Adopted or Not Yet Adopted

 Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 Item 8. Consolidated Financial Statements and Supplementary Data

 Report of Independent Registered Public Accounting Firm

 Consolidated Statements of Income

 Consolidated Statements of Cash Flows

 Consolidated Balance Sheets

 Consolidated Statements of Changes in Stockholder's Equity

 Notes to Consolidated Financial Statements

 Note 1. Nature of Operations and Summary of Significant Accounting Policies

 Note 2. Regulatory Matters

 Note 3. Reportable Segments

 Note 4. Utility Plant and Jointly-Owned Facilities

 Note 5. Revenue

 Note 6. Accounts Receivable

 Note 7. Related Party Transactions

 Note 8. Debt and Credit Agreement

 Note 9. Commitments and Contingencies

 Note 10. Employee Benefits Plans

 Note 11. Share-Based Compensation

 Note 12. Supplemental Cash Flow Information

 Note 13. Fair Value Measurements and Derivative Instruments

 Note 14. Income Taxes

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 iii

 Item 9A. Controls and Procedures

 Item 9B. Other Information

 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Item 10. Directors, Executive Officers, and Corporate Governance

 Item 11. Executive Compensation

 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 Item 13. Certain Relationships and Related Transactions and Director Independence

 Item 14. Principal Accountant Fees and Services

 Item 15. Exhibits and Financial Statement Schedules

 Item 16. Form 10-K Summary

 Exhibits

 Signatures

 iv

 DEFINITIONS
 The abbreviations and acronyms used in the 2024 Form 10-K are defined below:
 INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS

 2020 IRP
 TEP's 2020 Integrated Resource Plan which outlines TEP's plan to reduce its carbon emissions by 80% compared to 2005 by 2035

 2021 Credit Agreement
 The unsecured 2021 Credit Agreement, as amended in June 2023 and extended in October 2024, provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2027

 2022 Final FERC Rate Order
 Order issued by the FERC in 2022 approving the settlement agreement filed in conjunction with TEP's 2019 transmission rate case

 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

 ABR
 Alternate Base Rate

 ACC
 Arizona Corporation Commission

 ADEQ
 Arizona Department of Environmental Quality

 ADJ
 SOFR Rate Spread Adjustment

 AFUDC
 Allowance for Funds Used During Construction

 AOCI
 Accumulated Other Comprehensive Income

 AOCL
 Accumulated Other Comprehensive Loss

 ARO
 Asset Retirement Obligation

 BESS
 Battery Energy Storage System

 CCR
 Coal Combustion Residuals

 COVID-19
 Coronavirus Disease 2019

 DG
 Distributed Generation

 DSM
 Demand Side Management

 ECA
 Environmental Compliance Adjustor

 EDIT
 Excess Deferred Income Taxes

 EE Standards
 Energy Efficiency Standards

 EIM
 Energy Imbalance Market

 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

 IRS
 Internal Revenue Service

 ITC
 Investment Tax Credit

 LFCR
 Lost Fixed Cost Recovery

 LOC
 Letter(s) of Credit

 NERC
 North American Electric Reliability Corporation

 OATT
 Open Access Transmission Tariff

 PBI
 Performance Based Incentives

 PPA
 Power Purchase Agreement

 PPFAC
 Purchased Power and Fuel Adjustment Clause

 PSU
 Performance-Based Share Units

 v

 PTC
 Production Tax Credit

 PV
 Photovoltaic

 REC
 Renewable Energy Credit

 RES
 Renewable Energy Standard

 Retail Rates
 Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment.

 RSU
 Restricted Share Units

 SERP
 Supplemental Executive Retirement Plan

 SIP
 State Implementation Plan

 SOFR
 Secured Overnight Financing Rate

 TCA
 Transmission Cost Adjustor

 TEAM
 Tax Expense Adjustor Mechanism

 VEBA
 Voluntary Employee Beneficiary Association

 ENTITIES AND GENERATING STATIONS
 APS
 Arizona Public Service Company

 Fortis
 Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4

 FortisUS
 Fortis intermediate holding company

 Four Corners
 Four Corners Power Plant

 Gila River
 Gila River Generating Station

 Luna
 Luna Generating Station

 Navajo
 Navajo Generating Station

 Oso Grande
 A 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico

 PNM
 Public Service Company of New Mexico

 Roadrunner Reserve I
 A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in 2025

 Roadrunner Reserve II
 A standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in 2026

 San Juan
 San Juan Generating Station

 Springerville
 Springerville Generating Station

 Springerville Common Facilities
 Portion of the facilities at Springerville used in common with Springerville Units 1-4.

 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

 Tri-State
 Tri-State Generation and Transmission Association, Inc.

 UASTP
 University of Arizona Science and Technology Park

 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
 AC
 Alternating Current

 vi

 BBtu
 Billion British thermal unit(s)

 GWh
 Gigawatt-hour(s)

 kWh
 Kilowatt-hour(s)

 kV
 Kilovolt

 MMBtu
 Million Metric British thermal units

 MW
 Megawatt(s)

 MWh
 Megawatt-hour(s)

 vii

 FORWARD-LOOKING INFORMATION
 This Annual Report on Form 10-K 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 Annual Report on Form 10-K. 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 therein. 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; Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations; 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 EIM; 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, 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 related to capital projects, including EPC agreements to develop standalone BESS, and/or to obtain the anticipated performance or other benefits of such capital projects; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense, including increases due to inflationary effects, heightened geopolitical instability, and/or global supply chain challenges; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting estimates; the ongoing impact of mandated energy efficiency and DG initiatives; our ability to meet our goals related to reducing carbon emissions by 2035 and 2050 due to load growth required by potential large new customers, and the potential impact on our financial condition; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other cyberspace attacks to our information security and our operations and technology infrastructure, including attacks that may arise from heightened geopolitical instability; physical attacks to our electric generation, transmission, and distribution assets; the performance of generation facilities, including renewable generation resources; the extent of the impact of a global health or other crisis on our business and operations, and any economic and/or societal disruptions resulting therefrom and from the government actions taken in response thereto; the implementation of our 2023 IRP; and our ability to obtain ACC approval of a formula rate plan with acceptable terms.
 viii

 ITEM 1. BUSINESS

 OVERVIEW OF BUSINESS
 General
 TEP and its predecessor companies have served the greater Tucson metropolitan area for 132 years. TEP was incorporated in the State of Arizona in 1963. TEP is a regulated electric utility company serving approximately 452,000 retail customers. TEP's service territory covers 1,155 square miles and includes a population of over one million people in Pima County, as well as parts of Cochise County. 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 is subject to comprehensive state and federal regulation. The regulated electric utility operation is TEP's only segment.
 TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis, whose principal executive offices are located in St. John's, Newfoundland and Labrador, Canada.
 Regulated Utility Operations
 TEP delivers electricity to retail customers in southern Arizona. TEP owns or has contracts for natural gas, coal-fired, and renewable generation resources, as well as battery storage to provide electricity. This electricity, together with electricity purchased in the wholesale market, is delivered over transmission lines which are part of the Western Interconnection, a regional grid in the United States. The electricity is then transformed to lower voltages and delivered to customers through TEP's distribution system.
 FERC Regulation and Rates
 The FERC regulates portions of TEP's utility accounting practices and rates, including rates and services for electric transmission and wholesale power sales in interstate commerce. The FERC establishes rates that allow a utility to recover transmission related costs.
 FERC Rates
 TEP has a forward-looking OATT formula rate, which updates annually and allows for timely recovery of transmission-related costs and an opportunity to earn a reasonable return on its investment.
 ACC Regulation and Rates
 TEP operates under a certificate of public convenience and necessity as regulated by the ACC, under which TEP is obligated to provide electric service to customers within its service territory. The ACC establishes rates that are designed to allow a regulated utility recovery of its cost of providing services and an opportunity to earn a reasonable return on its investment.
 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 TEP's business decisions and accounting practices.
 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 2025. In 2024, the percentage of TEP's retail kWh sales attributable to the RES was approximately 23%, exceeding the 2024 RES requirement of 14%. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG.
 Energy Efficiency Standard
 Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. TEP has continued to achieve or exceed the ACC's cumulative annual targeted retail kWh savings each year since the 2020 compliance date. As of December 31, 2024, TEP's cumulative annual energy savings was approximately 29%.

 See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding RES and EE Standards.
 ACC Rates
 Retail Rates are generally established in rate case proceedings. TEP's last rate case proceeding was finalized in 2023. As a result of past regulatory decisions, TEP has cost recovery mechanisms that allow for more timely recovery of certain costs between rate case proceedings. These mechanisms are generally reset annually through separate filings with the ACC. TEP's usage-based cost recovery mechanisms include:
 • PPFAC — a charge or credit that reflects changes in energy costs that are under- or over-recovered through base rates established in a rate case.
 • RES tariff — a charge that recovers the cost of complying with the RES.
 • DSM — a charge that recovers the cost of complying with the EE Standards.
 • LFCR — a charge that partially offsets the revenue TEP loses when customers reduce their bills as a result of energy efficiency programs and DG system installations.
 • ECA — a charge that recovers certain costs incurred at TEP's generation facilities to comply with environmental regulations.
 • TEAM — a charge or credit used to pass through certain income tax effects to retail customers, which may include impacts of post-test year tax law changes.
 • TCA — a charge or credit that allows TEP to reflect changes in costs related to investments and expenses included in TEP's FERC OATT formula rate.
 See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations and Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on TEP's 2023 Rate Order and cost recovery mechanisms.

 Customers
 Electricity sold to retail and wholesale customers by class of customer and the average number of retail customers over the last five years were as follows:
 (sales in GWh)
 2024
 2023
 2022
 2021
 2020

 Electric Sales

 Residential
 3,964
 %
 3,967
 %
 3,879
 %
 3,820
 %
 4,170
 %

 Commercial
 1,956
 %
 1,948
 %
 1,917
 %
 1,939
 %
 2,005
 %

 Industrial, non-Mining
 1,952
 %
 1,944
 %
 1,946
 %
 1,893
 %
 1,834
 %

 Industrial, Mining
 1,078
 %
 1,080
 %
 1,053
 %
 1,050
 %
 1,086
 %

 Other
 —
 %
 —
 %
 —
 %
 —
 %
 —
 %

 Total Retail Sales
 8,964
 %
 8,954
 %
 8,810
 %
 8,718
 %
 9,111
 %

 Wholesale, Long-Term (1)

 %
 1,314
 %
 1,659
 %
 %
 %

 Wholesale, Short-Term
 5,061
 %
 4,486
 %
 4,203
 %
 5,643
 %
 5,279
 %

 Total Electric Sales
 14,965
 %
 14,754
 %
 14,672
 %
 15,198
 %
 14,898
 %

 Average Number of Retail Customers

 Residential
 409,548
 %
 404,616
 %
 400,751
 %
 396,562
 %
 391,953
 %

 Commercial
 39,958
 %
 39,702
 %
 39,547
 %
 39,395
 %
 39,096
 %

 Industrial, non-Mining
 —
 %
 —
 %
 —
 %
 —
 %
 —
 %

 Industrial, Mining
 —
 %
 —
 %
 —
 %
 —
 %
 —
 %

 Other
 1,862
 —
 %
 1,870
 —
 %
 1,875
 —
 %
 1,873
 %
 1,877
 %

 Total Retail Customers
 451,936
 %
 446,762
 %
 442,751
 %
 438,357
 %
 433,421
 %

 (1)Decreases in 2024 and 2023 due to reductions in sales to certain long-term wholesale customers. Increases prior to 2023 primarily due to favorable market conditions.
 Retail Customers
 TEP provides electric utility service to a diverse group of residential, commercial, industrial, and public sector customers. Major industries served include copper mining, cement manufacturing, defense, healthcare, education, military bases, and governmental entities. TEP's retail sales are influenced by several factors including economic conditions, seasonal weather patterns, DSM initiatives and the increasing use of energy-efficient products, and customer-sited DG.
 Local, regional, and national economic factors impact the growth in the number of customers in TEP's service territory. In each of the past five years, TEP's average number of retail customers increased by approximately 1%. TEP expects the number of retail customers to increase at a rate of approximately 1% in 2025 based on the estimated population growth in its service territory.
 TEP's retail sales volume in 2024 was 8,964 GWh, which is a decrease of 2% from 2020 levels. During the past five years, decreased sales volumes due to variations in weather and state requirements to promote energy efficiency and DG have been tempered by customer growth.
 Wholesale Customers
 TEP's utility operations include the wholesale marketing of electricity to other utilities and power marketers. Wholesale sales transactions are made on both a firm and interruptible basis. A firm contract requires TEP to supply power on demand (except under limited emergency circumstances), while an interruptible contract allows TEP to stop supplying power under defined conditions.
 Generally, TEP commits to future sales based on expected generation capability, forward prices, and generation costs using a diversified portfolio approach to provide a balance between long-term, mid-term, and spot power sales.
 Long-Term Wholesale Sales
 Contracts for long-term wholesale sales cover periods of one year or greater. TEP typically uses its own generation to serve the requirements of its long-term wholesale customers.

 TEP's primary long-term wholesale sale contracts are presented in the table below:
 Counterparty
 Contracts Expire December 31,

 Navajo Tribal Utility Authority
 2025

 TRICO Electric Cooperative
 2025

 Central Arizona Water Conservation District
 2025

 Navopache Electric Cooperative
 2041

 Short-Term Wholesale Sales
 Certain contracts for short-term wholesale sales cover periods of less than one year and obligate TEP to sell capacity or power at a fixed price. TEP also engages in short-term wholesale sales by selling power in the daily or hourly markets at fluctuating spot market prices and making other non-firm power sales. The majority of TEP's revenues from short-term wholesale sales are passed through to TEP's retail customers offsetting fuel and purchased power costs. TEP uses short-term wholesale sales as part of its hedging strategy to reduce customer exposure to fluctuating power prices.
 In 2022, TEP began to participate in the EIM, a voluntary, real-time energy market operated by the California Independent System Operator. TEP expects that its participation in the EIM will continue to: (i) reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources; (ii) allow for more effective integration of renewables; and (iii) enhance reliability through improved system utilization and responsiveness.
 In November 2024, TEP, along with other Arizona utilities, announced plans to join Southwest Power Pool (SPP) Markets+, a day-ahead and real-time energy market, when it launches in 2027. TEP's participation in Markets+ is expected to (i) reduce our cost to serve customers; (ii) provide additional access to clean energy resources; and (iii) enhance reliability.
 Competition
 Retail Customers
 TEP is the primary electric service provider to retail customers within its service territory and operates under a certificate of public convenience and necessity as regulated by the ACC.
 The Tucson City Council engaged a consulting and engineering firm to analyze alternatives to TEP's provision of service to the City of Tucson, including a study evaluating a municipalization option. The study process is ongoing, and the contract schedule provides for delivery of its results in 2025.
 Wholesale Customers
 TEP engages in long-term wholesale sales to optimize its generation resources. As a result of its wholesale power activity, TEP competes with other utilities, power marketers, and independent power producers in wholesale markets.

 Generation Facilities
 As of December 31, 2024, TEP had 3,126 MW of nominal generation capacity, as presented in the table below. Nominal rating is based on current unit design basis net output, measured in AC:
 Unit
 Date
 Capacity
 Operating
 TEP's Share

 Generation Source
 No.
 Location
 In Service
 (MW)
 Agent
 %
 (MW)

 Natural Gas

 Gila River
 Gila Bend, AZ
 2003
 SRP

 Gila River (1)

 Gila Bend, AZ
 2003
 SRP
 75.0

 Luna
 Deming, NM
 2006
 PNM
 33.3

 Sundt
 1962
 TEP

 Sundt
 1967
 TEP

 Sundt Reciprocating Internal Combustion Engine
 1-10
 2019-2020
 TEP

 Sundt Internal Combustion Turbines
 1972-1973
 TEP

 DeMoss Petrie
 2001
 TEP

 North Loop
 2001
 TEP

 Coal

 Springerville
 Springerville, AZ
 1985
 TEP

 Springerville (2)

 Springerville, AZ
 1990
 TEP

 Four Corners
 Farmington, NM
 1969
 APS
 7.0

 Four Corners
 Farmington, NM
 1970
 APS
 7.0

 Renewables

 Utility-Owned Renewables
 2002-2023
 TEP

 Total Capacity
 3,126

 (1)In January 2024, Gila River Unit 3 turbine upgrades increased capacity by 34 MW, for a total nominal capacity of 607 MW.
 (2)Springerville Unit 2 is owned by San Carlos Resources, Inc., a wholly-owned subsidiary of TEP.
 Springerville Units 3 and 4 are each approximately 400 MW coal-fired generation facilities that are operated, but not owned, by TEP. These facilities are located at the same site as Springerville Units 1 and 2. Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, compensate TEP for operating the facilities, including performance incentives depending on unit availability. Tri-State pays an allocated portion of the fixed costs related to the Springerville Common Facilities and Springerville Coal Handling Facilities. SRP owns 17.05% of the Springerville Coal Handling Facilities and 14% of the Springerville Common Facilities.

 Utility-Owned Renewables
 As of December 31, 2024, TEP owned 57 MW of PV solar generation capacity and 250 MW of wind generation capacity, measured in AC. The following table presents TEP's owned renewable generation resources:
 Generation Source
 Location
 Date in Service
 In Service

 Solar

 Fort Huachuca Phase I & II (1)

 Sierra Vista, AZ
 2014-2017

 Raptor Ridge
 2022

 Springerville Solar
 Springerville, AZ
 2002-2014

 UASTP Phase I & II (2)

 2010-2011

 Solon Prairie Fire (2)

 2012

 Small Solar Generation (<5MW)
 2012-2023

 Wind

 Oso Grande (3)

 Chaves County, NM
 2021

 Total Capacity

 (1)TEP has a 30-year easement agreement to facilitate operations on behalf of the Department of the Army.
 (2)UASTP Phase I & II and Solon Prairie Fire are located on properties held under land easements and leases.
 (3)Oso Grande is located on properties held under leases.
 Renewable Power Purchase Agreements
 As of December 31, 2024, TEP had renewable PPAs for 256 MW from solar resources and 179 MW from wind resources as presented in the table below. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date. The following table's capacity is measured in AC:
 Generation Source
 Location
 Date/Projected Date
in Service
 In Service
 Under Development

 Solar

 Wilmot I
 2021

 Red Horse
 Willcox, AZ
 2015

 Avalon I
 Sahuarita, AZ
 2014

 Avra Valley
 Marana, AZ
 2012

 Picture Rocks
 Marana, AZ
 2012

 Avalon II
 Sahuarita, AZ
 2016

 Valencia
 2013

 Gato Montes
 2012

 E.On Tech Park
 2012

 Small PPAs (<5MW)

 Babacomari North
 Cochise County, AZ
 2026

 Wilmot II
 2026

 Winchester
 Cochise County, AZ
 2027

 Wind

 Borderlands Wind

 Catron County, NM
 2021

 Macho Springs
 Deming, NM
 2011

 Red Horse Wind
 Willcox, AZ
 2015

 Total Capacity

 Non-Renewable Purchased Power
 TEP purchases power from other utilities and power marketers. TEP may enter into contracts to purchase: (i) power under long-term contracts to serve retail load and long-term wholesale contracts; (ii) capacity or power during periods of planned outages or for peak summer load conditions; and (iii) power for resale to certain wholesale customers under load and resource management agreements. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to purchased power commitments.
 TEP typically uses its generation, supplemented by purchased power, to meet the summer peak demands of its retail customers. TEP hedges a portion of its total energy price exposure with forward priced contracts. TEP also purchases power in the daily and hourly markets: (i) to meet higher than anticipated demands; (ii) during periods of generation outages; or (iii) when doing so is more economical than TEP generating its own power.
 TEP is a member of a regional reserve-sharing organization and has reliability and power-sharing relationships with other utilities. These relationships allow TEP to call upon other utilities during emergencies, such as generation facility outages and system disturbances, which reduces the number of reserves TEP is required to carry as a participant in the regional reserve-sharing organization.
 Battery Storage
 TEP's battery storage capacity (measured in AC) as of December 31, 2024, is presented in the table below:
 Battery Storage
 Location
 Date/Projected Date
in Service
 In Service
 Under Development

 Utility-Owned Battery Storage

 Roadrunner Reserve I
 2025

 Roadrunner Reserve II
 2026

 PPA Battery Storage (1)

 Wilmot I
 2021

 Iron Horse
 2017

 Pima Energy Storage (2)

 2017

 Wilmot II
 2026

 Winchester
 Cochise County, AZ
 2027

 Total Capacity

 (1)Payments for battery storage are accounted for as variable lease costs.
 (2)Battery storage is attached to DeMoss Petrie substation.
 Peak Demand and Future Resources
 Peak Demand
 (in MW)
 2024
 2023
 2022
 2021
 2020

 Retail Customers
 2,357
 2,393
 2,273
 2,427
 2,467

 In 2024, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale peak demand, while maintaining a reserve margin in compliance with reliability criteria set forth by the Western Electricity Coordinating Council, a regional entity with delegated authority from NERC.
 Peak demand occurs during the summer months due to the cooling requirements of retail customers in TEP's service territory. Retail peak demand varies from year-to-year due to weather, energy conservation, DG, economic conditions, and other factors. The impacts of remote work as a result of COVID-19 increased peak demand for residential customers in 2020 and 2021. The decrease in retail peak demand in 2022 was primarily due to less extreme heat during peak load.
 Forecasted retail peak demand for 2025 is 2,434 MW compared with actual peak demand of 2,357 MW in 2024. TEP's 2025 estimated retail peak demand is based on weather patterns observed over a 10-year period and other factors, including estimates of customer usage. TEP believes that existing generation capacity and PPAs are sufficient to meet the expected demand and reserve margin requirements in 2025.

 Future Resources
 TEP's strategy on future resources is to continue its transition to a less carbon-intensive energy portfolio, while preserving customer reliability and affordability.
 In November 2023, TEP filed with the ACC its 2023 IRP, which outlined its plan to accelerate its clean energy expansion to support the anticipated growth at that time and to maintain affordable, reliable service as the Company works towards an aspirational goal of net zero direct GHG emissions by 2050. To keep TEP on pace, the Company aims to reduce carbon emissions by 80% (compared to 2005) by 2035. TEP's ability to achieve these goals could be impacted by various federal and state energy policies and other external factors, including significant new customer growth and an increase in demand from existing customers. TEP's clean energy transition plan includes reducing the Company's dependency on coal-fired generation, while developing new renewable energy projects and energy storage projects, to meet electric demand. Investments in new natural gas-fired capacity will support the integration of these new renewable energy projects while maintaining system reliability and meeting future load growth.
 See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Factors Affecting Results of Operations of this Form 10-K for additional information regarding TEP's 2023 IRP.
 Fuel, Purchased Power, and Other Resources
 A summary of fuel, purchased power, and other resource information is provided below:
 Average Cost (cents per kWh)
 Percentage of Total kWh Resources

 2024
 2023
 2022
 2024
 2023
 2022

 Coal (1)

 4.51
 3.17
 2.83
 %
 %
 %

 Natural Gas
 2.20
 3.27
 5.36
 %
 %
 %

 Purchased Power, Non-Renewable (2)

 2.75
 6.70
 7.31
 %
 %
 %

 Total Non-Renewable
 %
 %
 %

 Purchased Power, Renewable
 6.86
 6.74
 6.76
 %
 %
 %

 Utility-Owned, Renewable
 N/A
 N/A
 N/A
 %
 %
 %

 Total Renewable
 %
 %
 %

 Total Fuel, Purchased Power and Other Resources
 %
 %
 %

 (1)In 2024, coal prices increased due to the execution of a coal supply agreement for Springerville Units 1 and 2 through 2031, which includes price adjustment components that will affect future costs.
 (2)The decrease in the average cost of non-renewable purchased power is due to the expiration of a tolling agreement in October 2023.
 Coal Supply
 The coal used for generation is low-sulfur, bituminous or sub-bituminous coal sourced from mines in New Mexico. The table below provides information on TEP's coal supply contracts. The average cost of coal per MMBtu, including transportation, was $3.77 in 2024, $2.92 in 2023, and $2.65 in 2022.
 Station
 Coal Supplier
 2024 Coal Consumption (tons in 000s)
 Contract Expiration Date
 Average Sulfur Content
 Coal Obtained From

 Springerville
 Peabody CoalSales
 1,382
 2031
 0.8%
 Lee Ranch Mine/El Segundo Mine

 Four Corners
 NTEC
 2031
 0.8%
 Navajo Mine

 The coal supplies for Springerville Units 1 and 2 are transported approximately 200 miles by railroad from northwestern New Mexico. TEP expects to have access to coal supplies to fulfill the estimated requirements for each of the Springerville units over its respective remaining life.

 Coal-Fired Generation Facilities Operated by Others
 TEP also participates in a jointly-owned coal-fired generation facility at Four Corners. Four Corners, which is operated by APS, is a mine-mouth generation facility located adjacent to the coal reserves. TEP expects coal reserves available to this jointly-owned generation facility to be sufficient for the remaining life of the station.
 Natural Gas Supply
 The table below provides information on the natural gas transportation agreements that deliver natural gas to TEP's generation facilities. The average cost of natural gas per MMBtu, including transportation, was $1.53 in 2024, $3.72 in 2023, and $8.35 in 2022. The decrease in cost in 2024 compared to 2023 and 2022 was primarily due to a decrease in natural gas prices resulting from an increase in natural gas production.
 Station
 Natural Gas Transportation Counterparty
 Contract Expiration Date(s)

 Gila
 Transwestern Pipeline Co./El Paso Natural Gas Company, LLC
 2025-2040

 Luna
 El Paso Natural Gas Company, LLC
 2032

 Sundt
 El Paso Natural Gas Company, LLC
 2039-2048

 DeMoss Petrie
 Southwest Gas Corporation
 Retail Tariff

 North Loop
 Southwest Gas Corporation
 Retail Tariff

 Transmission and Distribution
 TEP's distribution and transmission facilities are located in Arizona and New Mexico. These facilities are located on property owned by: (i) TEP; (ii) public entities; (iii) private entities; and (iv) Tribal Nations. TEP's transmission and distribution systems include approximately 2,231 miles of transmission lines and 8,050 miles of distribution lines as of December 31, 2024.
 TEP's transmission facilities transmit the output from TEP's electric generation facilities to the Tucson area and power markets. The transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces, and parts of Mexico. TEP's transmission system, together with contractual rights on other systems, enables TEP to integrate and access generation resources to meet its energy load requirements.

 ENVIRONMENTAL MATTERS
 The EPA regulates, or has the authority to regulate, the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), carbon dioxide (CO2), particulate matter, mercury, and other by-products produced by generation facilities. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its 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, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects recovery of the cost of environmental compliance through Retail Rates and cost recovery mechanisms.
 Refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources of this Form 10-K for additional information related to environmental laws and regulations as well as environmental compliance capital expenditures.

 HUMAN CAPITAL
 As of December 31, 2024, TEP had 1,761 employees, of which approximately 751 were represented by the International Brotherhood of Electrical Workers Local No. 1116 (IBEW). The current collective bargaining agreement between the IBEW and TEP was ratified in June 2023 and expires on June 30, 2028. TEP also engages with independent contractors in the ordinary course of its business, as necessary.
 TEP strives to create a positive environment for its employees through various initiatives consistent with its values. A strong culture allows TEP to attract and retain a talented workforce while preserving institutional knowledge and mentorship opportunities. The Company believes that the foundation for an engaged and inclusive work environment starts with the Executive Officers' and Board of Directors' active involvement in the Company's strategies for employee success. TEP's business strategy includes a commitment to help employees thrive by adapting to change, investing in continuous learning, and promoting collaboration, inclusion, and engagement, while deepening the Company's safety culture.
 TEP's compliance team and Board of Directors review the Company's Code of Ethics and Business Conduct (Code) annually and make updates based on direct feedback from employees. The Code serves as TEP's ethical compass and expressly states

 that the Company will not tolerate certain behaviors including: (i) retaliation; (ii) discrimination; (iii) harassment; or (iv) abuse of positions of trust. The Code is intended to help TEP create a safe and respectful workplace where employees feel valued and secure.
 Engagement and inclusion are an integral part of TEP's vision and values. TEP values an inclusive culture and the unique contributions, perspectives, and experiences of its employees. TEP continues to identify and focus on building capabilities that empower and inspire employees to achieve excellence together.
 The Company supports employee participation in Business Resource Groups (BRG), which are voluntary, employee-led groups that have established missions, goals, and practices that support career development and employee engagement and align with TEP's business priorities. Participants share ideas and issues to help promote an inclusive and respectful workplace. Examples of BRGs that provide professional networking opportunities at TEP include:
 • Veterans in Energy — dedicated to: (i) building relationships between its members; (ii) providing support and mentorship for military veterans and families; and (iii) promoting engagement and retention of military veteran employees.
 • Women in Energy — dedicated to: (i) inspiring women in their professional growth; (ii) developing leadership qualities in women; and (iii) promoting engagement of women and diverse representation and thought.
 • Native American, Tribal, and Indigenous Voices in Energy — dedicated to: (i) being a resource to Native Americans and creating a space of comfort and acceptance in the workplace; (ii) increasing visibility and representation of Native, Tribal, and Indigenous people in the energy field; and (iii) supporting and encouraging Native American employees in their professional growth.
 TEP's workforce pipeline initiatives center on attracting, engaging, and developing a workforce with a range of backgrounds and experiences.
 TEP is a Troops to Energy Jobs employer that works with the Center for Energy Workforce Development to match military skills with open positions in a variety of fields within the Company. TEP has sponsored numerous military internships for separating or retiring service members in partnership with Davis-Monthan Air Force Base, among other military bases. As of December 31, 2024, 10% of TEP's employees were military veterans.

 INFORMATION ABOUT OUR EXECUTIVE OFFICERS
 Executive Officers, who are elected annually by TEP's Board of Directors, acting at the direction of the Board of Directors of UNS Energy, as of January 1, 2025, are as follows:
 Name
 Age
 Position(s) Held
 Executive Officer Since

 Susan M. Gray (1)

 President and Chief Executive Officer
 2015

 J. Caleb Adcock
 Chief Financial Officer and Vice President
 2023

 Erik B. Bakken
 Chief Administrative Officer and Senior Vice President
 2018

 Cynthia A. Garcia
 Chief Operating Officer and Senior Vice President
 2020

 Todd C. Hixon (1)

 Senior Vice President, Chief Legal Officer and Corporate Secretary
 2011

 Frank P. Marino (1)

 Senior Vice President, Finance
 2013

 Ana M. Bustamante
 Vice President, Energy Delivery
 2025

 Dallas J. Dukes
 Vice President, Customer Experience, Programs and Pricing
 2019

 Orrin T. Nay
 Vice President of Energy Resources
 2022

 Christopher W. Norman
 Vice President, Public Policy
 2022

 Michael E. Sheehan
 Vice President, Fuels and Resource Planning
 2020

 Amy J. Welander
 Vice President, General Counsel and Assistant Corporate Secretary
 2023

 Gail M. Zody-Serbia
 Vice President of Human Resources
 2022

 Martha B. Pritz
 Treasurer
 2017

 (1)Member of TEP's Board of Directors. The directors of TEP are elected annually by TEP's sole shareholder, UNS Energy, acting at the direction of the board of directors of UNS Energy.

 SEC REPORTS AVAILABLE
 TEP makes available its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practical after it electronically files or furnishes them to the SEC. The SEC maintains a website at  that contains reports, proxy and information statements, and other information regarding issuers that file electronically. TEP's reports are also available free of charge through TEP's website at
 TEP is providing the address of its website solely for the information of investors and does not intend for the address to be an active link. The information contained on TEP's website is not a part of, or incorporated by reference into, any report or other filing by TEP filed with the SEC.

 ITEM 1A. RISK FACTORS
 TEP's business and financial results are subject to a number of risks and uncertainties, including those set forth below. These risks and uncertainties fall primarily into five major categories: operational, regulatory, revenues, environmental, and financial. Additional risks and uncertainties that are not currently known to TEP or that are not currently believed by TEP to be material may also negatively impact TEP's business and financial results.
 OPERATIONAL
 TEP is subject to cyber-attacks which could have a negative impact on the Company's business and results of operations.
 Cybercrime, which includes the use of malware, ransomware attacks, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years due to heightened geopolitical instability, an increase in remote work, the increased use of smartphones, tablets, and other wireless devices, and the continued monetization of cybercrime. The Company is subject to inherent technological risk from hacking, software viruses, and other types of data security breaches, as well as to third-party cybersecurity risk. Furthermore, the nature and sophistication of cyber-attacks continues to evolve as cyber-attackers use Artificial Intelligence to develop malicious code and sophisticated phishing attempts and other attacks on operational control systems and data. The Company's utility business requires access to and retention of sensitive customer data, including personal and credit information, in the ordinary course of business. The Company relies on the continued operation of sophisticated digital information technology systems and network infrastructure to operate the utility as part of an interconnected regional electrical grid. TEP's operations technology systems face a heightened risk of cyber-attack due to the critical nature of such infrastructure.
 TEP's information technology systems and network infrastructure have been subject to, and will likely continue to be subject to, cyber-attacks from foreign or domestic sources attempting to gain unauthorized access to information and/or information systems through computer viruses and phishing attempts either directly or indirectly through its vendors or related third parties. Such attempts could be motivated by a desire to disrupt utility operations or seek financial gain.
 If, despite TEP's security measures, a significant cybersecurity event or data breach occurred, the Company could: (i) have operations disrupted, have customer information stolen, and experience general business system and process interruption or compromise, including that which could prevent TEP from servicing customers, collecting revenues or recording, processing and/or reporting financial information correctly; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, including class action litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations. See Part I, Item 1C Cybersecurity of this Form 10-K for a discussion of cybersecurity risk management, strategy, and governance, which should be read in conjunction with this Item 1A.
 TEP is subject to capacity shortfalls which could result in an inability for the Company to reliably serve load requirements and could negatively affect TEP's results of operations, net income, and cash flows.
 Increased capacity scarcity in the Western United States may result in TEP's inability to meet customer demand. Conditions that could cause a capacity shortfall include but are not limited to: water scarcity, fuel supply shortages related to constrained natural gas pipelines or coal delivery interruptions, increased customer demand, including as a result of potential new large customers such as data centers, coal mine or natural gas well field outages, an extreme weather event, a wildfire, changes in regulatory policy, unplanned outages, including extensions of planned outages due to equipment failures or other complications, in-service delays of new generation and transmission resources, and/or retirement of generation resources. These conditions have and may continue to require collaboration with other regional energy providers to investigate additional resources and

 technologies, including nuclear and natural gas-fired generation and increased gas pipeline capacity, necessary to meet the future needs of customers. Additionally, these conditions may contribute to market price volatility and increased difficulty in procuring market energy. An inability to serve load requirements could negatively affect TEP's results of operations, net income, and cash flows.
 The operation of generation facilities, battery energy storage systems, and transmission and distribution systems and the construction of capital projects involves risks and uncertainties that could negatively affect TEP's results of operations, net income, and cash flows.
 The operation of generation facilities, battery energy storage systems, and transmission and distribution systems involves certain risks and uncertainties that could result in reduced generation capability or unplanned outages, including equipment breakdown or failures, fires and other hazards, lower than expected levels of efficiency or operational performance, and/or disruptions in operations due to union strikes or a labor shortage. Governmental actions and market trends that cause continued global supply chain challenges, including new or increased tariffs, lead time impacts, and price volatility, have and could continue to increase the risk that TEP's operations could be negatively impacted and/or TEP's capital investing could increase. If TEP's generation facilities or transmission and distribution systems operate below expectations, TEP's operating results could be negatively affected and/or TEP's capital expenditures could increase.
 In addition, as coal-fired generation facilities are closed, the economic viability of coal mines and coal suppliers may be jeopardized. To date, several coal suppliers have declared bankruptcy and coal mines have been closed. As additional coal-fired generation facilities are closed, the availability of sufficient coal supplies could decrease and prices may increase, which could, in turn, negatively affect the viability of our remaining coal-fired generation facilities.
 Also, a significant portion of TEP's capital plan includes the construction of capital projects to serve the growing demand for electricity which may result from the introduction of new large customers. These projects and plans are subject to risks and uncertainties including, among others, changes in legislation or regulation, such as environmental compliance requirements, direct and indirect trade and tariff impacts, supply chain disruptions, and other events beyond TEP's control, any of which could materially affect the schedule, cost, and performance of these projects. A failure to execute these projects successfully, and on a timely basis, could negatively affect TEP's financial condition or results of operations.
 The effects of climate change may create operational and financial risks for TEP that, if realized, could negatively affect TEP's results of operations, net income, and cash flows.
 Climate change impacts regional and global weather conditions and results in extreme weather events, including high temperatures, severe thunderstorms, and drought. Changes in weather conditions and extreme weather have and could continue to occur in the Western United States and have and could continue to affect TEP's transmission and distribution systems. In addition, extreme weather could increase the potential likelihood of wildfires. Both extreme weather events and wildfires could lead to service outages and business interruptions, either of which would increase capital expenditures and operating expenses. There can be no assurance that physical utility assets will successfully withstand severe weather conditions or wildfires. Additionally, a fire caused by our equipment could result in litigation where plaintiffs may assert claims alleging TEP is liable for resulting damages.
 Drought conditions in the Western United States have and may continue to lead to a regional decrease in surface water and groundwater accessibility. Drought conditions may result in: (i) additional regulation, impacting TEP's water use for generation; and (ii) regional power constraints, impacting power market prices. Regional water scarcity may also impact existing customers' operations and future economic development, affecting retail sales volumes and related revenue, as well as the region's ability to contain and mitigate risk from wildfires.
 Other potential risks associated with changes in weather conditions, extreme weather events, and wildfires, including wildfires outside of TEP's service territory, include the inability to secure sufficient insurance coverage, increased insurance costs, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. Any damage caused to our assets or disruption of service to our customers could lead to a negative impact on TEP's results of operations, net income, and cash flows.
 The operation of generation facilities and transmission systems on tribal lands may create operational and financial risks for TEP that, if realized, could negatively affect TEP's results of operations, net income, and cash flows.
 Certain jointly-owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements, or other rights-of-way that are effective for specified periods. TEP is unable to predict the final outcomes of pending and future approvals by the applicable sovereign governing bodies with respect to the cost of renewals and continued access to

 these leases, land easements, and rights-of-way. If pending and future approvals are not obtained and if continued access to the facilities is not granted, it could negatively affect TEP's results of operations, net income, and cash flows.
 TEP receives power from certain generation facilities that are jointly-owned with, or operated by, third parties. Therefore, TEP may not have the ability to affect the management or operations at such facilities which could negatively affect TEP's results of operations, net income, and cash flows.
 Certain generation facilities from which TEP receives power are jointly-owned with, or operated by, third parties. TEP does not have the sole discretion to affect the management or operations at such facilities. As a result of this reliance on other operators, TEP may not be able to ensure the proper management of the operations and maintenance of such generation facilities. Further, TEP may have limited ability to determine how best to manage the changing economic conditions, more restrictive trade policies, higher tariffs, or environmental requirements that may affect such facilities. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such facilities could negatively impact TEP's business and operations.
 TEP is subject to physical attacks which could have a negative impact on the Company's business and results of operations.
 TEP's generation, transmission, and distribution assets are critical to the provision of electric service to our customers and stability of the bulk electric system. These assets also provide the framework for our service infrastructure. TEP is facing a heightened risk of physical attacks on the Company's electric assets. The Company's electric generation, transmission, and distribution assets are geographically dispersed and are often in rural or unpopulated areas which makes it especially difficult to adequately detect, defend from, and respond to such attacks. The Company relies on the continued operation of these assets, which are part of an interconnected regional electrical grid. Any significant interruption in the availability or operation of these assets could prevent the Company from fulfilling its critical business functions, including delivering energy to customers. Security threats continue to evolve and adapt. Such attempts could be motivated by a desire to disrupt utility operations or seek financial gain. TEP, the energy industry, and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to disrupt operations through physical security attacks and breaches. Such events or the threat of such events may increase costs associated with heightened security requirements. Despite implementation of security measures, there can be no assurance that the Company will be able to prevent such disruptions.
 If, despite TEP's security measures, a significant physical attack occurred, the Company could: (i) have operations disrupted, including a disruption to the stability of the bulk electric system, and/or property damaged; (ii) experience loss of revenues, response costs, and other financial loss; and (iii) be subject to increased regulation, litigation, and damage to the Company's reputation. Any of these outcomes could have a negative impact on TEP's business and results of operations.
 REGULATORY
 Government action or changes in legislation, regulation, or regulatory structure could negatively affect TEP's results of operations, net income, and cash flows.
 TEP incurs costs to comply with legislative and regulatory requirements and initiatives, including those relating to clean energy requirements, the deployment of distributed energy resources, and implementation of programs for demand response, customer energy efficiency, and electric vehicles. Additionally, the City of Tucson is studying the feasibility of municipalization. TEP could be adversely affected if we are subject to municipalization or other related government action. Initiatives or changes to existing requirements have occurred and could arise again in the future through legislative, regulatory, or other measures (including ballot initiatives) on a federal, state, or local level.
 TEP's ability to recover its investments and costs associated with legislative and regulatory initiatives will, in large part, depend on the final form of legislative, regulatory, or government actions. Further increases to rates could negatively affect the affordability of rates charged to customers, which may negatively affect TEP's results of operations, net income, and cash flows.
 TEP's business is significantly impacted by government legislation, regulation and oversight. TEP's inability to recover its costs, earn a reasonable return on its investments, or comply with current regulations would negatively affect its results of operations, net income, and cash flows.
 TEP's financial condition is influenced by how regulatory authorities, including the ACC and the FERC, establish the rates TEP can charge customers and authorize rates of return, common equity levels, and the amount of costs that may be recovered from TEP's customers. The Company's ability to timely obtain rate adjustments that provide TEP with the opportunity to earn

 authorized rates of return depends upon timely regulatory action under applicable statutes and regulations and cannot be guaranteed.
 • ACC—The ACC is a constitutionally created body composed of five elected commissioners and has jurisdiction over rates for retail customers. Commissioners are elected state-wide for staggered four-year terms and are limited to serving two consecutive terms. As a result, the composition of the ACC, and therefore its policies, are subject to change every two years.
 • FERC—The FERC has jurisdiction over rates for electric transmission in interstate commerce and rates for wholesale sales of electric power, including terms and prices of transmission services and sales of electricity at wholesale. Commissioners are appointed by the President of the United States, with advice and consent of the Senate, for staggered five-year terms.
 Owners and operators of bulk power systems, including TEP, are subject to mandatory reliability standards developed and enforced by NERC and subject to the oversight of the FERC. Compliance with modified or new reliability standards may subject TEP to higher operating costs and increased capital costs. Failure to comply with the mandatory reliability standards could subject TEP to sanctions, including substantial monetary penalties.
 REVENUES
 TEP's results of operations, net income, and cash flows could be negatively affected by various factors impacting demand for electricity.
 Weather Conditions and Customer Usage Patterns
 TEP's revenues, results of operations, and cash flows are seasonal and are subject to weather conditions and customer usage patterns, which are beyond the Company's control.
 Retail Sales
 TEP earns the majority of its operating revenue and net income in the third quarter because retail customers increase their air conditioning usage during the summer. Conversely, first quarter net income is limited by relatively mild winter weather in TEP's retail service territory. Unseasonably cool summers or warm winters may reduce customer usage, negatively affecting results of operations, net income, and cash flows by reducing sales.
 Production Tax Credits
 Electricity generated from TEP's wind-powered facility depends heavily on wind conditions, turbine availability, and transmission capacity. If such conditions are unfavorable, or if any other operational constraints exist, the facility's electricity generation and associated PTCs may be reduced, negatively affecting tax payments and net income.
 Economic Conditions and Energy Conservation Measures
 A significant decrease in the demand for electricity in TEP's service area would negatively impact retail sales and adversely affect results of operations, net income, and cash flows. National and local economic conditions have a significant impact on customer growth and overall retail sales in TEP's service area. TEP anticipates an annual customer growth rate of 1% for the next five years.
 Research and development activities are ongoing for new technologies that produce power and/or reduce power consumption, such as renewable energy resources, including energy storage and customer-sited DG, energy-efficient products, and control systems. Continued development and use of these technologies and compliance with the ACC's EE Standards and RES continue to have a negative impact on TEP's use per customer and overall retail sales. TEP's use per customer declined by an average of 1% per year from 2020 through 2024.
 Significant Customers
 Existing Large Customers
 TEP is dependent on a small number of customers for a significant portion of future revenues. A reduction in the electricity sales to these customers would negatively affect results of operations, net income, and cash flows.
 TEP's ten largest customers represented 11% of total revenues in 2024. TEP sells electricity to mines, military installations, and other large commercial and industrial customers. Retail sales volumes and revenues from these customers could decline as a

 result of, among other things: global, national, and local economic conditions; curtailments of customers' operations due to unfavorable market conditions; military base reorganization or closure decisions by the federal government; the effects of energy efficiency; or the decision by customers to self-generate all or a portion of their energy needs. A reduction in retail kWh sales to any one of TEP's ten largest customers would negatively affect the Company's results of operations, net income, and cash flows.
 Future Large Customers
 TEP's revenue growth projections and resource plans are based on assumed additions of a small number of customers with large load requirements. TEP could need to make significant infrastructure investments and commitments to service the associated demand growth. Meeting such demand growth may create challenges to TEP's ability to achieve its goals related to reducing carbon emissions by 2035 and 2050. If these prospective customers do not ultimately locate in our service territory, or if the potential customers reduce their load projections for which TEP planned after significant investments are made, it could materially impact our financial condition. Additionally, if TEP is unable to serve these prospective customers, the Company may not be able to fully recover its infrastructure investments and could lose future growth opportunities resulting in reputational harm, including with regulators. A concentration of sales to a small number of such customers, and the scale of investment required to support those customers, intensifies this risk and the potential for a negative impact on TEP's results of operations, net income, and cash flows, as well as on its ability to achieve its carbon emission reduction goals.
 ENVIRONMENTAL
 TEP is subject to numerous environmental laws and regulations that may increase its cost of operations or expose it to environmental litigation and liabilities.
 Numerous federal, state, and local environmental laws and regulations affect present and future operations. Those laws and regulations include rules regarding air emissions of conventional pollutants and GHGs, water quality and water use, wastewater discharges, solid waste, hazardous waste, and management of CCR. Policy initiatives, such as environmental justice that considers disproportionately adverse environmental impacts on vulnerable communities, may also impact operations.
 We have incurred costs in connection with environmental compliance, and we anticipate that we will continue to do so in the future. These laws and regulations can contribute to higher capital expenditures and operating expenses, particularly resulting from enforcement efforts focused on existing generation facilities and compliance standards related to new and existing generation facilities. These laws and regulations generally require TEP to obtain and comply with a wide variety of environmental licenses, permits, authorizations, and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations and policies. Failure to comply with applicable laws and regulations, or address certain policies, or the release of hazardous or toxic substances into the air, water, or soil, including, for example, leaking or spilled insulating fluid from electrical equipment and release of contaminants caused by the failure of battery energy storage systems may result in litigation, as well as the imposition of fines and penalties.
 Existing environmental laws and regulations may be revised, and new environmental laws and regulations may be adopted or become applicable to the Company's facilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a negative effect on TEP's results of operations, particularly if those costs are not timely and fully recoverable from TEP customers. TEP's obligation to comply with these laws and regulations as an owner or participant in regulated facilities like Springerville and Four Corners, coupled with the financial impact of future climate change legislation, other environmental regulations and policies, and other business considerations, could jeopardize the economic viability of these generation facilities. Additionally, these regulations may jeopardize continued generation facility operations or the ability of individual participants to meet their obligations and willingness to continue their participation in these facilities, potentially resulting in increased operational costs for the remaining participants.
 TEP also is contractually obligated to pay a portion of the environmental reclamation costs incurred at generation facilities in which it has a minority interest and is obligated to pay similar costs at the mines that supply these generation facilities. While TEP has recorded the portion of its costs that can be determined at this time, the total costs for final reclamation at these sites are unknown and could be substantial.

 FINANCIAL
 Early closures of coal-fired generation facilities could result in TEP recognizing regulatory impairments or increased costs of operations if recovery of TEP's remaining investments in such facilities and the costs associated with early closures are not permitted through rates charged to customers.
 TEP's remaining coal-fired generation facilities may close before the end of their useful lives in response to our transition to a less carbon-intensive energy portfolio, economic conditions and/or changes in regulation. TEP has previously closed coal-fired generation facilities. If any additional coal-fired generation facilities from which TEP obtains power are closed prior to the end of their useful lives, TEP may need to seek regulatory recovery of the remaining net book value and could incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation, and cancellation of long-term coal contracts of such generation facilities. As of December 31, 2024, the net book value of TEP's in-service coal-fired generation facilities was $1.0 billion.
 Volatility, disruptions, or unfavorable changes in the financial markets, changes in interest rates, or unanticipated financing needs, could increase TEP's financing costs, limit access to the credit or bank markets, affect the Company's ability to comply with financial covenants in debt agreements, and increase TEP's pension funding obligations. Such outcomes may negatively affect liquidity and TEP's ability to fund the Company's operations and carry out the Company's financial strategy.
 We rely on access to bank and capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flows from TEP's operations. Market disruptions such as those experienced in the financial crises of 2008, 2009, and 2020 in the United States and abroad may increase the Company's cost of borrowing or negatively affect TEP's ability to access sources of liquidity needed to finance the Company's operations and satisfy its obligations as they become due. These disruptions may include turmoil in the financial services industry, including substantial uncertainty surrounding particular lending institutions with which we do business, increases in interest rates, significant volatility in the bank and capital markets, and general economic downturns in TEP's utility service territory or in the broader economy. If TEP is unable to access credit at reasonable rates, or if the Company's borrowing costs dramatically increase, TEP's ability to finance its operations, meet debt obligations, and execute its financial strategy could be negatively affected. Increases in short-term interest rates would increase the cost of borrowings under TEP's credit facility.
 In addition, unfavorable market conditions have and could again negatively affect the market value of assets held in its pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required future funding contributions.
 GENERAL RISK FACTORS
 Events beyond our control, such as public health crises, geopolitical tensions, natural disasters, or other catastrophic events, could adversely affect our business, results of operations and financial condition.
 TEP could be negatively impacted by various events beyond our control, including, without limitation, public health crises, geopolitical tensions and other political instability, terrorist attacks, natural disasters, or other catastrophic events, whether occurring locally, nationally, or globally. Any of the forgoing events and any resulting impact, such as economic and/or trade disruptions, including the disruption of global supply chains and volatility and disruption of financial markets, labor shortages, or government-mandated actions in response to any such event could materially affect TEP's business, results of operations, access to sources of liquidity, and financial condition, either directly or through the impact on third parties upon whom we rely.
 Changes in tax regulation may negatively affect the results of operations, net income, and cash flows of TEP.
 The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. Legislation or regulation could be enacted, modified, or terminated by any of these governmental authorities, which could affect the Company's tax positions, results of operations, net income, and cash flows.
 The failure to attract, retain, and manage an appropriately qualified workforce could negatively impact TEP's business and results of operations.
 TEP's business is dependent on its ability to attract, retain, and manage qualified personnel, including key executive officers and skilled professional and technical employees and contractors. Certain events and conditions, such as an aging workforce without available replacements, a shift in employee expectations with respect to compensation and flexible work arrangements, the unavailability of contract resources, and the ongoing need to negotiate collective bargaining agreements with union employees, may lead to significant operating challenges, including lack of resources, loss of knowledge base, time required for

 skill development, and labor disruptions. If TEP is unable to successfully attract, retain, and manage an appropriately qualified workforce, its business and results of operations could be negatively affected.

 ITEM 1B. UNRESOLVED STAFF COMMENTS
 None.

 ITEM 1C. CYBERSECURITY
 In response to ever-changing cybersecurity threats, TEP maintains a comprehensive cybersecurity risk management program for its operations, information systems, data, and critical infrastructure. Risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected TEP, including its business strategy, results of operations, or financial condition. See Part I, Item 1A Risk Factors of this Form 10-K for a discussion of cybersecurity threats that could have a material impact on TEP, which should be read in conjunction with this Item 1C for a detailed description of the risks related to cybersecurity.
 Risk Management and Strategy
 TEP's cybersecurity risk management program is informed by the National Institute of Standards and Technology Cybersecurity Framework. This program includes dedicated investments in people, processes, and technology to manage and reduce cybersecurity risk, including third-party threats. Multiple layers of security controls are deployed across asset and technology classes with a special emphasis on the reliable and safe operation of TEP's utility systems. Cybersecurity controls employed include firewalls, access management, multi-factor authentication, backups, endpoint protection, threat intelligence, and security monitoring. TEP continues to adjust and refine this program in response to the shifting threat landscape, third-party assessments, and industry best practices.
 Cybersecurity risk is tactically and strategically managed by TEP's Enterprise Cybersecurity team comprised of experienced professionals with various cybersecurity certifications, including Certified Information Systems Security Professional (CISSP) and Global Industrial Cyber Security Professional (GICSP). This team uses governmental and industry threat intelligence, such as the Electricity Information Sharing and Analysis Center, Cybersecurity and Infrastructure Security Agency, and internal cybersecurity tools to proactively identify, assess, manage, and respond to risk, including network monitoring and vulnerability scanning.
 TEP regularly conducts internal evaluations and testing of its design and operational effectiveness of security controls and is subject to external independent cybersecurity audits including those associated with the NERC Critical Infrastructure Protection standards. TEP engages third-party services to provide consulting on best practices to address new challenges. TEP participates in regular cybersecurity roundtable discussions with peer cybersecurity professionals to review current threats and opportunities, lessons learned, and best practices. TEP's Compliance Program Management Office provides additional ongoing internal oversight of response to cybersecurity regulation. Third-party cybersecurity risk is addressed through vendor risk management processes and includes technology reviews and contractual specifications. Third-party risk management is designed to reduce risk associated with the use of third-party providers.
 Cybersecurity training is conducted on a regular basis and includes awareness campaigns, in-person training, and simulations. Users of TEP's information systems are required to comply with a comprehensive internal acceptable use policy.
 TEP employs and regularly exercises UNS Energy's Cybersecurity Incident Response and Reporting Plan. This plan identifies key roles and responsibilities applicable during a cybersecurity incident and classifies incidents according to qualitative and quantitative factors that are continuously reviewed as information evolves over the course of an incident. The plan also identifies certain reporting obligations and may trigger additional response processes such as activation of UNS Energy's Data Breach Response Plan.
 Governance
 Cybersecurity risk is identified and tracked through TEP's Enterprise Risk Management (ERM) program that consists of formal vetting and quarterly reporting to the UNS Energy Audit and Risk Committee and the UNS Energy Board. The UNS Energy Board Environmental, Safety, and Security Committee oversees cybersecurity strategy, performance, and risk, and timely reviews cybersecurity events, depending on severity, even if not material to TEP. The UNS Energy Board is notified of significant cybersecurity events as outlined in UNS Energy's Cybersecurity Incident Response and Reporting Plan.

 TEP's Security Steering Committee provides management oversight to its cybersecurity strategy, performance, and risk assessment and management. This committee also reviews significant cybersecurity events, including the scope of the incident and the associated prevention, detection, mitigation, and remediation efforts. This committee includes the Chief Operating Officer, Chief Legal Officer, Senior Vice President of Finance, Senior Director of IT Operations and Enterprise Security, and others with the requisite cybersecurity experience, training, and skills who oversee TEP's ERM program. The Senior Director of IT Operations and Enterprise Security has 16 years of experience in managing technology and risks and advising on cybersecurity issues and holds CISSP and GICSP certifications.

 ITEM 2. PROPERTIES
 TEP's corporate headquarters and operational support facilities for Tucson operations are owned by TEP and located in Tucson, Arizona.
 TEP has land easements for transmission facilities related to San Juan, Four Corners, and Navajo located on tribal lands of the Zuni, Navajo, and Tohono O'odham Nations. Four Corners and Navajo are located on properties held under land easements from the United States and under leases from the Navajo Nation. TEP, in conjunction with PNM and Samchully Power & Utilities 1 LLC, holds an undivided ownership interest in the property on which Luna is located.
 TEP's rights under various land easements and leases may be subject to defects such as:
 • possible conflicting grants or encumbrances due to the absence of, or inadequacies in, the recording laws or record systems of the Bureau of Indian Affairs and the Tribal Nations;
 • possible inability of TEP to legally enforce its rights against adverse claims and the Tribal Nations without Congressional consent; or
 • failure or inability of the Tribal Nations to protect TEP's interests in the land easements and leases from disruption by the U.S. Congress, Secretary of the Interior, or other adverse claims.
 These possible defects have not interfered, and are not expected to materially interfere, with TEP's interest in and operation of its facilities.
 TEP's rights under land easements expire at various times, and renewal action by the applicable tribal or federal agencies is required. The ultimate cost of renewal for certain of the rights-of-way for the Company's transmission lines is uncertain. The principal owned generation, distribution, and transmission facilities of TEP are described in Part I, Item 1. Business, Overview of Business, and such descriptions are incorporated herein by reference.

 ITEM 3. LEGAL PROCEEDINGS
 TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company believes such normal and routine litigation will not have a material impact on its operations or financial results.
 See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
 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 4. MINE SAFETY DISCLOSURES
 Not applicable.

 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
 Market Information
 TEP's common stock is wholly-owned by UNS Energy and is not listed for trading on any stock exchange.

 ITEM 6. [Reserved]

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 Management's Discussion and Analysis explains the results of operations, the financial condition, and the outlook for TEP. It includes the following:
 • outlook and strategies;
 • factors affecting results of operations;
 • results of operations;
 • liquidity and capital resources, including capital expenditures, income tax position, and environmental matters;
 • critical accounting estimates; and
 • new accounting standards issued and adopted or not yet adopted.
 Management's Discussion and Analysis includes financial information prepared in accordance with GAAP.
 This section of this Form 10-K primarily discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 activity and year-to-year comparisons between 2023 and 2022 that are not included in this Form 10-K can be found in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for our fiscal year ended December 31, 2023.
 Management's Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes in Part II, Item 8 of this Form 10-K. For information on factors that may cause our actual future results to differ from those we currently anticipate, see Forward-Looking Information and Part I, Item 1A. Risk Factors of this Form 10-K.
 References in this 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. Our plans and strategies include:
 • Promoting economic development within our service territory to enable prosperity in the communities we serve while achieving sales growth and maintaining affordable rates for our customers. Our company is positioned to capitalize on unprecedented interest from new large customers to locate in our service territory.
 • Achieving constructive outcomes in our regulatory proceedings that will provide us more timely cost recovery and an opportunity to earn an appropriate return on our rate base investments.
 • Continuing our transition to a less carbon-intensive energy portfolio while complying with regulatory requirements and maintaining financial strength. We have established an aspirational goal of net zero direct GHG emissions by 2050 emphasizing our commitment to decarbonize while preserving customer reliability and affordability. To keep us on pace, we aim to reduce carbon emissions by 80% (compared to 2005) by 2035. Our ability to achieve these goals could be impacted by various federal and state energy policies and other external factors, including significant new customer growth, and an increase in demand from existing customers.
 • Focusing on our core utility business through operational excellence, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
 Performance - 2024 Compared with 2023
 We reported net income of $289 million in 2024 compared with $259 million in 2023. The increase of $30 million, or 12%, was primarily due to:
 •$60 million in higher margin from retail revenue primarily due to an increase in rates as approved in the 2023 Rate Order; partially offset by lower LFCR revenues;

 •$13 million in higher AFUDC due to an increase in eligible construction expenditures;
 •$8 million in lower income tax expense primarily due to an increase in tax credits primarily related to Oso Grande PTCs; and
 •$6 million in higher margin from wholesale transactions primarily due to an increase in revenues realized from wholesale trading as defined in the PPFAC plan of administration; partially offset by a decrease in long-term wholesale volumes due to less favorable market conditions and the expiration of certain contracts.
 The increase was partially offset by:
 •$22 million in higher base operations and maintenance expenses primarily due to an increase in outside services expenses, an increase in employee wages and benefits expenses, and higher operations and maintenance expenses at our generation facilities;
 •$18 million in higher depreciation expense primarily due to an increase in depreciation rates as approved in the 2023 Rate Order;
 •$9 million in higher interest expense primarily due to the issuance of debt in August 2024; and
 •$7 million in lower margin from transmission revenue primarily due to a regulatory decision approving a credit to retail customers for certain transmission revenue beginning in December 2023; partially offset by an increase in TEP's transmission formula rate revenue requirement.

 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 those matters.
 2023 Rate Order
 In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:
 • a non-fuel retail revenue increase of $100 million over test year non-fuel retail revenues;
 • a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% and an average cost of debt of 3.82%; and
 • approval to recover costs of changes in generation resources, including the addition of Oso Grande, in rates.
 Roadrunner Reserve I Application for Accounting Order
 In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I with an anticipated in-service date in 2025. In October 2024, we filed an application with the ACC for an accounting order requesting authorization to defer for future recovery certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I, offset by future benefits associated with investment tax credits. We cannot predict the timing or outcome of this application.
 ACC Formula Rate Plan Policy
 In December 2024, the ACC adopted a formula rate policy statement that allows regulated utilities to propose a formula rate plan in future rate cases. A formula rate plan, if approved by the ACC, would adjust rates annually based on a predetermined

 formula. Formula rate plans are expected to improve rate stability for customers, while also reducing regulatory lag and related costs, as well as reducing the number of adjustor mechanisms and the reliance thereon.
 Generation Resource Strategy
 Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while reducing reliance on coal-fired generation resources. In 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards an aspirational goal of net zero direct GHG emissions by 2050. To keep us on pace, we aim to reduce carbon emissions by 80% (compared to 2005) by 2035. Our ability to achieve these goals could be impacted by various federal and state energy policies and other external factors, including significant new customer growth and an increase in demand from existing customers. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings. In October 2024, the ACC acknowledged our 2023 IRP and found it to be reasonable and in the public interest.
 In 2022, we issued an All-Source Request for Proposal (ASRFP), which allowed for all resource types, including, among others, new wind and solar generation, battery storage, and energy efficiency resources. As a result of our 2022 ASRFP, we entered into:
 • an EPC agreement in September 2023 to develop Roadrunner Reserve I. Roadrunner Reserve I will be a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh with an anticipated in-service date in 2025;
 • a renewable PPA in January 2024 with Wilmot Energy Center II (Wilmot II). Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage with energy capacity of 400 MWh with an anticipated in-service date in 2026; and
 • a renewable PPA in April 2024 with Winchester Solar I, LLC (Winchester). Winchester will have 80 MW of solar capacity accompanied by 80 MW of battery storage with energy capacity of 320 MWh with an anticipated in-service date in 2027.
 In December 2023, we issued another ASRFP (2024 ASRFP) based on the resource needs outlined in our 2023 IRP targeting in-service dates of 2026 through 2027. As a result of our 2024 ASRFP, we entered into an EPC agreement in August 2024 to develop Roadrunner Reserve II. Roadrunner Reserve II will be a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh with an anticipated in-service date in 2026. See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the EPC agreement.
 Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply, land lease contract extensions, environmental regulations and policies, and, for jointly-owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, we expect to exit all ownership interests in coal-fired generation facilities by the end of 2031. We will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of these actions.
 Federal Tax Credits
 Production Tax Credits
 PTCs are per-kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In May 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded approximately $21 million and $15 million in PTCs related to Oso

 Grande in 2024 and 2023, respectively. The PTC rate published by the IRS for electricity produced by a qualified facility using wind placed in service prior to 2022 was $0.029 for 2024 and $0.028 for 2023.
 Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, or if any operational constraints exist, the project's electricity generation and associated PTCs may be substantially different compared to prior periods. Oso Grande and the associated PTCs are included in rates as part of the 2023 Rate Order.
 Investment Tax Credits
 ITCs are federal tax credits based on the initial investment in clean energy generation including qualifying solar and wind. Beginning in 2023, standalone BESS also qualify for the credit. The base credit rate is 30% of the qualifying costs for projects that began construction before January 29, 2023. TEP began construction prior to this date for Roadrunner I and II, which are expected to be placed in service in 2025 and 2026, respectively.
 Sales Growth and Seasonality
 Our average retail sales growth has remained relatively flat over the past three years. Recently, we have experienced interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet above what is reflected in our 2023 IRP, as well as higher transmission and distribution infrastructure investments. We are analyzing the requests and cannot predict the quantity or timing of the energy demand that may result from the current interest received.
 Weather Patterns
 Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our retail sales are highest in the second and third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year, due to mild winter weather in our retail service territory. Our operating costs are generally consistent throughout the year which produces higher operating income in the second and third quarter and lower operating income in the first and fourth quarter. As a result, seasonal fluctuations affect the comparability of our quarterly results of operations.
 Interest Rates
 See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this Form 10-K for information regarding interest rate risk and its impact on earnings.

 RESULTS OF OPERATIONS
 Significant drivers of our results of operations that do not have a significant impact on net income include:
 • Cost Recovery Mechanisms — We record operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchased power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, the RES tariff, DSM, and TEAM are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information on cost recovery mechanisms.
 • Short-Term Wholesale Sales — Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC mechanism.
 • Springerville Units 3 and 4 — Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Consolidated Statements of Income.
 The following discussion provides the significant items that affected our results of operations for the year ended 2024 compared to 2023 presented on a pre-tax basis.

 Operating Revenues
 The following table provides a disaggregation of Operating Revenues:
 Year Ended

 2024
 2023
 2022

 Operating Revenues

 Retail
 $
 1,321
 $
 1,283
 3.0
 %
 $
 1,140
 12.5
 %

 Wholesale, Long-Term
 (25.0)
 %
 (23.2)
 %

 Wholesale, Short-Term (1)

 (26.5)
 %
 (23.3)
 %

 Transmission
 (1.8)
 %
 (9.7)
 %

 Springerville Units 3 and 4 Participant Billings
 (4.5)
 %
 23.3
 %

 Other
 (16.7)
 %
 10.3
 %

 Total Operating Revenues
 $
 1,805
 $
 1,875
 (3.7)
 %
 $
 1,808
 3.7
 %

 (1)Includes revenue realized from wholesale trading as defined in the PPFAC plan of administration. We share 10% of any realized gains on trading transactions with retail customers through the PPFAC mechanism.
 We reported Operating Revenues of $1,805 million in 2024 compared with $1,875 million in 2023. The decrease of $70 million, or 4%, was primarily due to:
 •$67 million in lower short-term wholesale revenues primarily due to a decrease in price; partially offset by an increase in revenue realized from wholesale trading as defined in the PPFAC plan of administration;
 •$19 million in lower long-term wholesale revenues primarily due to a decrease in volume as a result of less favorable market conditions and the expiration of certain contracts;
 •$16 million in lower other revenue primarily due to the expiration of an asset management agreement related to natural gas pipeline capacity; and
 •$5 million in lower Springerville Units 3 and 4 participant billings primarily due to higher reimbursable planned outage costs in 2023.
 The decrease was partially offset by $38 million in higher retail revenues primarily due to an increase in rates as approved in the 2023 Rate Order; partially offset by lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate.
 The following table provides key statistics impacting Operating Revenues:
 Year Ended

 (kWh in millions)
 2024
 2023
 2022

 Electric Sales (kWh) (1)

 Retail Sales

 8,964
 8,954
 0.1
 %
 8,810
 1.6
 %

 Wholesale, Long-Term
 1,314
 (28.5)
 %
 1,659
 (20.8)
 %

 Wholesale, Short-Term
 5,061
 4,486
 12.8
 %
 4,203
 6.7
 %

 Total Electric Sales
 14,965
 14,754
 1.4
 %
 14,672
 0.6
 %

 Average Revenue cents per kWh (2)

 Retail
 14.74
 14.33
 2.9
 %
 12.94
 10.7
 %

 Wholesale, Long Term
 6.09
 5.79
 5.2
 %
 5.99
 (3.3)
 %

 Wholesale, Short-Term
 3.12
 5.23
 (40.3)
 %
 7.62
 (31.4)
 %

 Total Retail Customers (3)

 451,937
 446,762
 1.2
 %
 442,751
 0.9
 %

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

 (2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
 (3)This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining and non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.
 Operating Expenses
 Fuel and Purchased Power Expense
 We reported Fuel and Purchased Power expense of $633 million in 2024 compared with $756 million in 2023. The decrease of $123 million, or 16%, was primarily due to:
 •$92 million in lower Purchased Power expenses primarily due to a decrease in price and volume;
 •$38 million in lower Fuel expenses primarily due to a decrease in natural gas prices; partially offset by: (i) higher realized losses on natural gas swaps; (ii) an increase in coal prices; and (iii) an increase in Gas-Fired Generation volumes; and
 •$14 million in lower Transmission and Other PPFAC Recoverable Costs primarily due to a decrease in transmission service expenses.
 The decrease was partially offset by a $21 million increase in PPFAC Recovery Treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; partially offset by a decrease in PPFAC cost recoveries.
 The following table provides key statistics impacting Fuel and Purchased Power:
 Year Ended December 31,

 (kWh in millions)
 2024
 2023
 2022

 Sources of Energy

 Coal-Fired Generation
 3,054
 3,688
 (17.2)
 %
 4,626
 (20.3)
 %

 Gas-Fired Generation
 8,679
 7,336
 18.3
 %
 6,459
 13.6
 %

 Utility-Owned Renewable Generation
 25.5
 %
 (19.9)
 %

 Total Generation
 12,554
 11,678
 7.5
 %
 11,901
 (1.9)
 %

 Purchased Power, Non-Renewable
 1,596
 2,267
 (29.6)
 %
 2,152
 5.3
 %

 Purchased Power, Renewable
 1,342
 1,363
 (1.5)
 %
 1,299
 4.9
 %

 Total Generation and Purchased Power (1)

 15,492
 15,308
 1.2
 %
 15,352
 (0.3)
 %

 (cents per kWh)

 Average Fuel Cost of Generated Power (2)

 Coal (3)

 4.51
 3.17
 42.3
 %
 2.83
 12.0
 %

 Natural Gas (4)

 2.20
 3.27
 (32.7)
 %
 5.36
 (39.0)
 %

 Average Cost of Purchased Power (5)

 Purchased Power, Non-Renewable (6)

 2.75
 6.70
 (59.0)
 %
 7.31
 (8.3)
 %

 Purchased Power, Renewable
 6.86
 6.74
 1.8
 %
 6.76
 (0.3)
 %

 (1)This number represents the kWh generated from our generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.
 (2)This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation facilities.
 (3)In 2024, coal prices increased due to the execution of a coal supply agreement for Springerville Units 1 and 2 through 2031, which includes price adjustment components that will affect future costs.

 (4)Includes realized gains and losses from hedging activity.
 (5)This metric represents cost as cents per kWh for renewable and non-renewable purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh) for each respective form of purchased power. Management uses this metric to compare and monitor the costs of renewable and non-renewable purchased power.
 (6)The decrease in the average cost of non-renewable purchased power is due to the expiration of a tolling agreement in October 2023.
 Operations and Maintenance Expense
 We reported Operations and Maintenance expense of $447 million in 2024 compared with $445 million in 2023. The increase of $2 million, or less than 1%, was primarily due to:
 •$10 million in higher outside services expenses;
 •$8 million in higher employee wages and benefits expenses; and
 •$7 million in higher operations and maintenance expenses at our generation facilities.
 The increase was partially offset by:
 •$12 million in lower RES and DSM expenses; and
 •$11 million in lower reimbursable maintenance expense related to Springerville Units 3 and 4 primarily due to higher planned outage costs in 2023.
 Depreciation and Amortization Expense
 We reported Depreciation and Amortization expense of $257 million in 2024 compared with $236 million in 2023. The increase of $21 million, or 9%, was primarily due to an increase in depreciation rates as approved in the 2023 Rate Order.
 Other Income (Expense)
 We reported Other Expense of $63 million in 2024 and 2023. Changes in 2024 compared to 2023 were primarily due to:
 • $15 million in higher AFUDC due to an increase in eligible construction expenditures.
 Offset by:
 •$10 million in higher interest expense due to the issuance of debt in August 2024; and
 •$3 million in lower interest income on under-recovered PPFAC balances.
 Income Tax Expense
 We reported Income Tax Expense of $44 million in 2024 compared with $49 million in 2023. The decrease of $5 million, or 10%, was primarily due to higher tax credits related to Oso Grande PTCs.

 LIQUIDITY AND CAPITAL RESOURCES
 Liquidity
 Any extended period of economic disruption could affect our business, financial condition, and access to sources of liquidity. Cash flows vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to our summer peaking load. We face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. We use our revolving credit as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.

 Available Liquidity

 Cash and Cash Equivalents
 $

 Amount Available under Revolving Credit Agreement (1)

 Total Liquidity
 $

 (1)The 2021 Credit Agreement provides for revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and had an original maturity date of October 2026. In October 2024, the maturity date was extended one year to October 2027. See Access to Credit below.
 Future Liquidity Requirements
 We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include but are not limited to: (i) dividend payments; (ii) debt maturities; (iii) employee benefit obligations; and (iv) known commitments and other contractual obligations including forecasted capital expenditures.
 See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk 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 of this Form 10-K for additional information regarding our leases, financing arrangements, and purchase commitments, respectively.
 Summary of Cash Flows
 The table below presents net cash provided by (used for) operating, investing, and financing activities:
 Years Ended
 Increase
(Decrease)
 Year Ended
 Increase
(Decrease)

 2024
 2023
 2022

 Operating Activities
 $
 $
 18.4
 %
 $
 10.0
 %

 Investing Activities
 (788)
 (633)
 24.5
 %
 (510)
 24.1
 %

 Financing Activities
 101.5
 %
 242.1
 %

 Net Increase (Decrease) (1)

 (8)
 *
 *

 (15.7)
 %
 54.5
 %

 $
 $
 14.0
 %
 $
 (15.7)
 %

 * Not meaningful
 (1)Calculated on rounded data and may not correspond exactly to amounts on the Consolidated Statements of Cash Flows.
 Operating Activities
 Net cash flows provided by operating activities increased by $103 million in 2024 compared with 2023 primarily due to: (i) lower PPFAC recoverable costs driven by lower purchased power and fuel costs; (ii) higher retail revenues due to an increase in rates approved in the 2023 Rate Order; and (iii) changes in working capital associated with wholesale sales.
 Investing Activities
 Net cash flows used for investing activities increased by $155 million in 2024 compared with 2023 primarily due to an increase in cash paid for capital expenditures.
 Financing Activities
 Net cash flows provided by financing activities increased by $66 million in 2024 compared with 2023 primarily due to: (i) higher proceeds from credit facility borrowings, net of repayments; (ii) an increase in equity contributions from UNS Energy; and (iii) higher proceeds from debt issuance; partially offset by: (i) higher redemptions of long-term debt in 2024; and (ii) an increase in dividends declared and paid to UNS Energy.

 Sources of Liquidity
 Short-Term Investments
 Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of December 31, 2024, 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 will be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of December 31, 2024, there was $168 million available under the 2021 Credit Agreement, which reflects $70 million of outstanding borrowings and $12 million in LOCs issued with fees that accrue at a rate of 1.050% per annum. As of February 13, 2025, there was $138 million available under the 2021 Credit Agreement.
 See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding our 2021 Credit Agreement.
 Debt Financing
 We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings. In December 2020, the ACC issued an order granting our financing authority that took effect January 1, 2021. The order provides authority through December 2025 for: (i) a maximum amount of long-term debt outstanding not to exceed $2.9 billion; (ii) parent equity contributions up to $700 million; and (iii) credit facilities not to exceed $300 million in the aggregate. In May 2022, we filed with the SEC an automatic shelf registration statement on Form S-3 which expires in May 2025.
 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 August 2024, we issued and sold $400 million aggregate principal amount of 5.20% senior unsecured notes due September 2034. We used the net proceeds to repay debt and for general corporate purposes.
 • In December 2024, we redeemed at par prior to maturity $300 million aggregate principal amount of 3.05% senior unsecured notes.
 We anticipate issuing long-term debt in 2025.
 Credit Ratings
 Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2024, credit ratings from S&P Global Ratings and Moody's Investors Service for our senior unsecured debt were A- (negative) and A3 (stable), respectively.
 Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold our securities. Each rating should be evaluated independently of any other ratings.
 The 2021 Credit Agreement contains pricing based on our credit ratings. A change in our credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.
 Debt Covenants
 Under certain agreements, should we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of December 31, 2024, 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 an equity contribution of $50 million from UNS Energy in 2024 and no equity contributions in 2023.

 Dividends Declared and Paid to Parent
 We declared and paid $85 million in dividends to UNS Energy in 2024 and $64 million in 2023.
 Master Trading Agreements
 We conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, we may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of December 31, 2024, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.
 Capital Expenditures
 Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. We prioritize capital projects to mitigate supply chain risk, particularly in view of heightened geopolitical instability and global supply chain challenges. In 2024, total capital expenditures of $733 million included: (i) investments in distribution and transmission assets, including payments for the construction of the Vail to Tortolita 230kV transmission line; and (ii) investments in Roadrunner Reserve I and II. In 2023, total capital expenditures of $578 million included: (i) investments in distribution and transmission assets, including initial payments for the construction of the Vail to Tortolita 230kV transmission line; and (ii) investments in Roadrunner Reserve I.
 Our forecasted capital expenditures presented below exclude amounts for AFUDC equity and other non-cash items:

 2025
 2026
 2027
 2028
 2029

 Generation Facilities:

 New Energy Resources (1)

 $
 $
 $
 $
 $

 Other Generation Facilities (2)

 Total Generation Facilities

 Transmission and Distribution (3)

 General and Other (4)

 Total Capital Expenditures
 $
 $
 $
 $
 $

 (1)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. In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. See Note 9 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-K for additional information regarding the EPC agreement.
 (2)Includes investments in existing facilities, including upgrades and ongoing maintenance to ensure reliability.
 (3)Investments in transmission capacity and distribution system reliability.
 (4)Includes costs for information technology, fleet, facilities, and communication equipment.
 These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, including inflationary pressures, tariffs, construction schedules, supply chain constraints, labor shortages and/or labor strikes, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, new or changing commitments, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt, other borrowings, or equity contributions.
 Roadrunner Reserve I
 In 2023, we entered into an EPC agreement to develop Roadrunner Reserve I at a cost of $294 million. The facility is expected to be placed in service in 2025. As of December 31, 2024, total cost of construction incurred from inception was $269 million. The project costs incurred are currently included in Construction Work in Progress on the Consolidated Balance Sheets. In January 2025, TEP paid $19 million in connection with the construction and development of Roadrunner Reserve I.

 Roadrunner Reserve II
 In 2024, we entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. The facility is expected to be placed in service in 2026. As of December 31, 2024, total cost of construction incurred from inception was $76 million. The project costs incurred are currently included in Construction Work in Progress on the Consolidated Balance Sheets. In January 2025, TEP paid $5 million in connection with the construction and development of Roadrunner Reserve II.
 See Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the EPC agreements.
 Income Tax Position
 Under the terms of the tax sharing agreement with UNS Energy, we made $13 million in net tax sharing payments in 2024 and $6 million in 2023. Future cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.

 Environmental Matters
 The EPA has the authority to regulate the amount of SO2, NOx, 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.
 We capitalized $3 million in 2024 and $5 million in 2023 to comply with environmental rules and regulations. In addition, we recorded operations and maintenance expenses related to environmental compliance of $6 million in each of 2024 and 2023. We expect environmental compliance related capital expenditures of $1 million in 2025 and less than $1 million in each year from 2026 through 2029. We will request and expect recovery of the costs of environmental compliance through Retail Rates and cost recovery mechanisms.
 Regional Haze Regulations
 The EPA's Regional Haze rule requires emission reductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas (Regional Haze). The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a SIP and must review and submit revisions to the SIP on a periodic basis.
 In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The ADEQ began to develop a control strategy with a focus on making reasonable progress toward the national visibility goal. In July 2019, we were notified by the ADEQ that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluations. We conducted the potential emissions controls evaluations, commonly referred to as the four-factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP.
 In December 2024, the EPA published a final rule partially approving and partially disapproving the ADEQ's Regional Haze SIP revision. The EPA disapproved the ADEQ's control strategy in the revised SIP, which relies, in part, on the compliance measures for Sundt Unit 3 and Springerville Units 1 and 2. The EPA also disapproved the ADEQ's selection of sources for potential emissions controls evaluations and requested further evaluation of Sundt Unit 4. The disapproval establishes 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. We cannot predict the outcome of this matter.
 Greenhouse Gas Regulation
 On May 9, 2024, the EPA published final rules to regulate GHG emissions from two categories of fossil-based electric generating units (EGUs): (i) existing steam units (including coal- and natural gas-fired); and (ii) new natural gas-fired turbines. The final rules established:
 • emission guidelines for existing coal-fired steam EGUs, which are subcategorized based on federally enforceable retirement dates. These emission guidelines affect Springerville Units 1 and 2, as well as Four Corners Units 4 and 5;

 • emission guidelines for existing natural gas- and oil-fired steam EGUs aligned with routine methods of operation and maintenance, which are subcategorized based on the annual capacity factor of each unit beginning January 1, 2030. These emission guidelines affect Sundt Units 3 and 4;
 • a requirement for states to establish standards of performance that align with the emission guidelines, in the form of emission limits. States must submit these standards of performance to the EPA for approval in the form of a state plan, which is due to the EPA in May 2026; and
 • new source performance standards for new stationary natural gas-fired combustion turbines, which are subcategorized based on the annual capacity factor for each unit. For base load units (i.e., units with an annual capacity factor greater than 40%), the EPA established a two-phased performance standard. For phase 1, new base load units must initially meet performance standards based on the use of highly efficient combined cycle generation with the best operating and maintenance practices. For phase 2, the final rule requires that such base load units achieve emissions reductions aligned with a 90% carbon capture and sequestration rate beginning on January 1, 2032.
 We are analyzing the EPA's final rule. Various 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.
 The EPA did not take final action on existing natural gas-fired combustion turbines but has indicated that it plans to issue a supplemental proposal to address these units.
 Coal Combustion Residuals Regulation
 The EPA published final rules effective October 2015 (2015 CCR Rule) that established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The 2015 CCR Rule provides for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at Springerville. APS, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility. SRP, the former operator of Navajo, is completing closure activities at the facility's CCR landfill. No corrective actions to comply with the 2015 CCR Rule have been identified at Springerville or Navajo. With regards to future corrective actions at Four Corners to comply with the 2015 CCR Rule, our share of costs to complete any corrective actions and to gather and perform remedial evaluations on groundwater at Units 4 and 5, is not expected to have a significant impact on our financial position, results of operations, or cash flows.
 In May 2024, the EPA published the final Legacy CCR Surface Impoundments Rule that expands the scope of the 2015 CCR Rule to address the impacts from historical CCR management and placement activities that would have ceased prior to 2015. The EPA rule establishes two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCR Management Units (CCRMUs) which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. A CCRMU includes not only historically closed landfills and surface impoundments, but also prior applications of CCR on land such as for structural fill. The final rule also establishes assessment, groundwater monitoring, closure, and post-closure requirements for legacy CCR impoundments and CCRMUs.
 We are analyzing the EPA's final rule for potential impacts to our operations. We anticipate CCRMUs will be identified at Springerville and Four Corners. The number, location, and size of these CCRMUs will be assessed in accordance with the compliance schedule outlined in the EPA's final rule; therefore, associated compliance costs cannot be accurately predicted at this time. SRP identified CCRMUs at Navajo. Our estimated cost to comply with the EPA's final rule at Navajo is not expected to have a significant impact on our financial position, results of operations or cash flows.
 Good Neighbor Federal Implementation Plan
 In September 2018, the ADEQ submitted to the EPA the Arizona SIP Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone National Ambient Air Quality Standard (NAAQS). In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.
 In March 2023, the EPA released its final FIP to address the interstate transport of ozone (Good Neighbor FIP) with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be

 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. On October 29, 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.
 On September 12, 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 on December 10, 2024. We cannot predict the outcome of this matter.

 CRITICAL ACCOUNTING ESTIMATES
 The preparation of financial statements in accordance with GAAP requires management to apply accounting policies and to make estimates 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 the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on TEP's other significant accounting policies can be found in Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
 Accounting for Regulated Operations
 We account for our regulated electric operations in accordance with accounting standards that allow the actions of our regulators, the ACC and the FERC, to be reflected in our financial statements. Regulator actions may cause us to capitalize certain costs that would be recorded as an expense, or in AOCI, in the current period by unregulated companies. We evaluate regulatory assets and liabilities each period and believe future recovery or settlement is probable. Our assessment includes consideration of recent rate orders, historical regulatory treatment of similar costs, and changes in the regulatory and political environment. If management's assessment is ultimately different than actual regulatory outcomes, the impact on our results of operations, financial position, and future cash flows could be material.
 As of December 31, 2024, regulatory liabilities net of regulatory assets in the balance sheet totaled $230 million. There are no current or expected changes in the regulatory environment that impact our ability to apply accounting guidance for regulated operations. If we conclude in a future period that our operations no longer meet the criteria in this guidance, we will record our pension and other postretirement benefit plan regulatory assets or liabilities in AOCL and recognize other regulatory assets and liabilities in the income statement. The impact of this change would be material to our financial statements. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding regulatory matters.
 Plant Asset Depreciable Lives
 We have significant investments in electric generation, transmission, and distribution assets. We calculate depreciation expense based on our estimate of the useful lives of our plant assets and estimated net removal costs. The ACC approves depreciation rates for all generation, distribution, and general plant assets. Depreciation rates for these assets cannot be changed without the ACC's approval. Our transmission assets are subject to the jurisdiction of the FERC. The useful lives of plant assets are further detailed in Note 4 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K. Changes to depreciation estimates resulting from a change of estimated service life or removal costs could have a significant impact on the amount of depreciation expense recorded in the income statement. See Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding depreciation rates.

 Accounting for Asset Retirement Obligations
 GAAP requires us to record the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. This includes obligations resulting from conditional future events. We incur legal obligations as a result of environmental regulations imposed by state and federal regulators, contractual agreements, and other factors. To estimate the liability, management must use judgment and assumptions in determining or estimating: (i) whether a legal obligation exists to remove assets; (ii) the probability of a future event for a conditional obligation; (iii) the fair value of the cost of removal; (iv) when final removal will occur; and (v) the credit-adjusted risk-free interest rates to be used to discount the future liabilities. Changes that may arise over time with regard to our judgment and assumptions will change amounts recorded in the future as expense for AROs. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and amortized over the useful life of the related asset. Accretion of the liability and amortization of the asset are recorded as a regulated asset to be recovered through depreciation rates.
 We identified legal obligations to retire generation facilities specified in land leases for our jointly-owned Four Corners, Navajo and San Juan facilities. Four Corners and Navajo reside on land leased from the Navajo Nation. The provisions of the Four Corners' lease require the lessees to remove the facilities at Four Corners upon request of the Navajo Nation at expiration of the lease. We are currently incurring costs to remove facilities at Navajo at the request of the Navajo Nation. We also have certain environmental obligations at Gila River, Luna, Sundt, and Springerville. We estimate that our share of the AROs to remove the Navajo and Four Corners facilities and settle the Luna, San Juan, Sundt, Gila River, and Springerville environmental and contractual obligations will be approximately $363 million at the retirement dates. Additionally, we entered into land lease agreements or land easement agreements with certain landowners for the installation of PV and wind assets. The provisions of the PV and wind land leases or land easements require us to remove the PV or wind facilities upon expiration of the agreements. In addition, we are required to properly dispose of or recycle certain PV assets under the Resource Conservation and Recovery Act. We estimate our ARO related to the PV and wind assets to be approximately $37 million at the retirement dates. We have identified no other legal obligations to retire generation assets.
 We have various transmission and distribution lines that operate under land easements and rights-of-way that contain end dates and may contain site restoration clauses. We operate transmission and distribution lines as if they will be operated in perpetuity and will continue to be used or sold without land remediation. As such, there are no AROs for these assets.
 The total net present value of our ARO liability recorded in Current Liabilities—Other and Other Noncurrent Liabilities was $168 million as of December 31, 2024. See Note 4 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding AROs.
 Additionally, ACC approved depreciation rates include a component designed to accrue the future costs of retiring assets for which no legal obligations exist. The accumulated balances are recorded as a regulatory liability and represent non-legal estimated cost of removal accruals, net of actual removal costs incurred and salvage proceeds realized. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding future net cost of removal.
 Pension and Other Postretirement Benefit Assumptions
 We record the underfunded amount for our pension and other postretirement benefit obligations as a current liability, noncurrent liability, or combination of both, and record the overfunded amount as a noncurrent asset. For plans other than the SERP, amounts not yet recognized in the income statement are recorded as a regulatory asset or liability to reflect expected recovery or refund of pension and other postretirement benefits obligations or benefits through rates charged to retail customers. As the funded status, discount rates, and actuarial facts change, the liability and asset balances may vary significantly in future years. Key assumptions used include:
 • discount rates used to determine obligations;
 • expected returns on plan assets;
 • compensation increases;
 • mortality assumptions; and
 • healthcare cost trend rates.

 Discount Rates
 As of December 31, 2024, we discounted our future pension obligations at a rate of 5.9% and our other postretirement benefit obligations at a rate of 5.7%. The discount rate for future pension and other postretirement benefit obligations is determined annually based on the rates currently available on high-quality, non-callable, long-term bonds. The discount rate is based on a corporate yield curve using an average yield between the 60th and 90th percentile of AA-graded U.S. corporate bonds with future cash flows that match the timing and amount of expected future benefit payments.
 Expected Returns on Plan Assets
 To establish the expected return on assets assumption, we review the asset allocation and develop return assumptions for each asset class based on advice from an investment consultant and the pension's actuary that includes both historical performance analysis and forward-looking views of the financial markets. As of December 31, 2024, we assumed that our pension plans' assets would generate a long-term rate of return of 7.3%.
 Compensation Increases
 As of December 31, 2024, we used an age-based assumption with a weighted average compensation increase of 3.9% to measure pension obligations.
 Mortality
 The PRI-2012 mortality table projected with a version of improvement scale MP-2021 modified to remove improvements for 2020-2023 due to COVID-19 and with a 15-year convergence and a 0.75% long-term rate was utilized to measure pension obligations as of December 31, 2024.
 Healthcare Cost Trend Rates
 We used a current year healthcare cost trend rate range between 5.3% and 6.8% in valuing our other postretirement benefit obligation as of December 31, 2024. This rate reflects both market conditions and historical experience.
 Sensitivity Analysis
 The table below shows the effect on our expense and obligation of a 100-basis point change to its assumptions as of December 31, 2024:
 Effect on Expense
 Effect on Obligation

 Increase
 Decrease
 Increase
 Decrease

 Change to Pension

 Discount Rate
 $
 (6)
 $
 $
 (55)
 $

 Long-Term Rate of Return on Plan Assets
 (4)
 N/A
 N/A

 Change to Other Postretirement Benefits

 Discount Rate
 (1)
 (6)

 Long-Term Rate of Return on Plan Assets
 —
 —
 N/A
 N/A

 Healthcare Cost Trend Rate
 (1)
 (5)

 In 2025, we will incur net periodic pension benefit costs of $14 million and net periodic other postretirement benefit costs of $4 million. We expect to record: (i) $14 million to operations and maintenance expense; and (ii) $4 million to capital. In 2025, we expect to make pension plan contributions of $10 million and other postretirement benefit payments of $5 million.
 See Note 10 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for further details regarding TEP's pension and other postretirement benefit expenses and obligations.
 Accounting for Derivative Instruments and Hedging Activities
 Commodity Derivative Contracts
 We enter into forward contracts to purchase or sell capacity or energy at contract prices over a given period of time, typically for one month, three months, one year, or three years, within established limits to meet forecasted load requirements or to take advantage of favorable market opportunities. In general, we enter into forward purchase contracts when market conditions provide the opportunity to purchase energy for our load at prices that are below the marginal cost of our supply resources or to

 supplement our own resources (e.g., during plant outages and summer peaking periods). We enter into forward sales contracts when we forecast that we will have excess supply, and the market price of energy exceeds our marginal cost. We enter into forward natural gas commodity price swap agreements to lock in fixed prices on a portion of forecasted natural gas purchases and fixed price purchased power agreements to hedge the price risk associated with forward PPAs.
 For all commodity derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities in the balance sheet and measure those instruments at fair value. Unrealized gains and losses on commodity derivative contracts entered into for retail customer load are recorded as either a regulatory asset or liability in the balance sheet based on our ability to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets through the PPFAC mechanism.
 The market prices used to determine fair values for our derivative instruments as of December 31, 2024, are estimated based on various factors including broker quotes, exchange prices, over the counter prices, and time value.
 We manage the risk of counterparty default by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using a standardized agreement, which allows for the netting of current period exposures to and from a single counterparty.

 NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED OR NOT YET ADOPTED
 For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.

 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 TEP is exposed to certain market risks that can affect asset and liability fair value, results of operations, and cash flows. TEP's significant market risks are primarily associated with commodity prices, interest rates, and extension of credit to counterparties. TEP may enter into interest rate swaps and financing transactions to manage changes in interest rates. TEP has a Risk Management Committee (RMC) responsible for the oversight of commodity price risk and credit risk related to wholesale energy marketing and power procurement activities. To limit TEP's exposure to commodity price risk, the RMC sets trading and hedging policies and limits, which are reviewed frequently to respond to constantly changing market conditions. To limit TEP's exposure to credit risk, the RMC reviews counterparty credit exposure as well as credit policies and limits on a regular basis.
 Commodity Price Risk
 TEP is exposed to market fluctuations in electricity, natural gas, and coal prices as a result of its obligation to serve retail customer load in its regulated service territory and long-term wholesale contracts. Exposure to commodity prices consists primarily of variations in the price of fuel required to generate electricity that is purchased and sold in retail and wholesale markets. Commodity prices may be subject to significant price changes as supply and demand are impacted by, among other unpredictable factors, weather, market liquidity, generation facility availability, customer usage, energy storage, and transmission and transportation constraints. Under the guidance of its RMC, TEP mitigates a portion of commodity price risk using forwards, financial swaps, and other agreements, to effectively secure future supply, fix fluctuating commodity prices, or sell future production generally at fixed prices. TEP also mitigates exposure to commodity price risk with its ability to recover these costs in regulated rates through its PPFAC mechanism, which is subject to an annual review by the ACC. See Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information related to the PPFAC mechanism.
 Certain commodity contracts qualify as derivatives and are recorded at fair value. The changes in fair value of such contracts have a high correlation to price changes in the hedged commodities. The following table shows the changes in fair value of TEP's derivative positions:
 2024
 2023
 2022

 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities
 $
 $
 (81)
 $

 TEP's derivative contracts mature on various dates through 2029. The table below displays the valuation methodologies and maturities of derivative contracts by source of fair value:
 Unrealized Gain (Loss) of TEP's Hedging Activities

 Maturity 0 – 6 months
 Maturity 6 – 12 months
 Maturity over 1 yr.
 Total Unrealized Gain (Loss)

 Prices Actively Quoted
 $
 (7)
 $
 (9)
 $
 $

 Sensitivity Analysis of Derivatives
 TEP uses sensitivity analysis to measure the potential impact of favorable and unfavorable changes in market prices on the fair value of its derivative contracts. TEP primarily records unrealized gains and losses as either a regulatory asset or liability, respectively. As contracts settle, unrealized gains and losses are reversed and realized gains or losses are recorded to the PPFAC. For derivatives related to the purchase and sale of power, a 10% change in the market price of purchased power would affect unrealized positions reported as a regulatory asset or liability by approximately $1 million. For derivatives related to natural gas price hedges, a 10% change in the market price of energy would affect unrealized positions reported as a regulatory asset or liability by approximately $23 million.
 Coal Supply Agreements
 TEP is subject to fuel price risk from changes in the price of coal used to fuel its coal-fired generation facilities. Risk is mitigated by using long-term coal supply agreements with limited price movement. TEP's coal supply agreements expire in 2031. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources and Note 9 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
 Credit Risk
 TEP is exposed to credit risk in energy-related marketing activities related to potential non-performance by counterparties. Risk of counterparty default is managed by performing financial credit reviews, setting limits, monitoring exposures, requiring collateral when needed, and using standard agreements which allow for the netting of current period exposures to and from a single counterparty. Counterparty credit exposure is calculated by adding any outstanding receivable, net of amounts payable if a netting agreement exists, to the market value of any forward contracts. If exposure exceeds credit limits or contractual collateral thresholds, TEP may request that a counterparty provide credit enhancement in the form of cash collateral or an LOC.
 TEP enters into short-term and long-term transactions related to wholesale marketing and natural gas hedging activities with various counterparties. As of December 31, 2024, TEP's total credit exposure was approximately $27 million including approximately $1 million of exposure to non-investment grade counterparties.
 As of December 31, 2024, TEP had no cash posted as collateral to provide credit enhancement and held no collateral from wholesale counterparties.
 Interest Rate Risk
 Credit Agreement
 TEP is subject to interest rate risk resulting from changes in interest rates on borrowings under the 2021 Credit Agreement. Borrowings under the credit agreement are made at a rate based on either SOFR for the respective term plus an adjustment of 0.10% and an applicable margin, or ABR plus an applicable margin. TEP may experience significant volatility in variable interest rates paid on borrowings under its credit agreement.
 The 2021 Credit Agreement provides for: (i) $250 million in revolving credit commitments; (ii) a $15 million swingline sublimit; and (iii) a $50 million LOC sublimit. The agreement matures in October 2027. As of December 31, 2024, TEP had $82 million in outstanding borrowings under its credit facility.

 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 To the Stockholder and the Board of Directors of
 Tucson Electric Power Company
 Tucson, Arizona
 Opinion on the Financial Statements
 We have audited the accompanying consolidated balance sheets of Tucson Electric Power Company and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, changes in stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
 Basis for Opinion
 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 Critical Audit Matter
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit and risk committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 2 to the financial statements
 Critical Audit Matter Description
 The Company is subject to rate regulation by the Arizona Corporation Commission (the "ACC") and Federal Energy Regulatory Commission ("FERC"). The ACC has jurisdiction with respect to the rates of electric distribution companies in Arizona. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered by rates. Accounting for the economics of rate regulation impacts multiple financial statement

 line items and disclosures, such as utility plant; regulatory assets and liabilities; operating revenue; fuel expense; purchased power expense; operation and maintenance expense; and depreciation expense.

 We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, (3) potential refunds to customers and (4) probability of potential charges related to the abandonment of regulated plants. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the regulatory authorities will not approve full recovery of the costs incurred. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

 How the Critical Audit Matter Was Addressed in the Audit
 Our audit procedures related to the uncertainty of future decisions by the regulatory authorities included the following, among others:
 • We evaluated the effectiveness of management's controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory rate orders and settlements issued by the regulatory authorities for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the regulatory authorities' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's filings with the regulatory authorities and the filings with the regulatory authorities by intervenors that may impact the Company's future rates, for evidence that might contradict management's assertions.
 • We inquired of management about utility plant that may be abandoned or retired early. We inspected the capital-projects budget and construction-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the regulatory authorities to identify any evidence that may contradict management's assertion regarding recoverability of such costs.
 • We inspected regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. For significant projects that were over budget or if full recovery of project costs is being challenged by intervenors, we evaluated management's assessment of the probability of a disallowance of such costs.

 /s/ Deloitte & Touche LLP

 Tempe, Arizona

 We have served as the Company's auditor since 2017.

 CONSOLIDATED STATEMENTS OF INCOME
 (Amounts in thousands)

 2024
 2023
 2022

 Operating Revenues
 $
 1,804,772
 $
 1,875,448
 $
 1,808,082

 Operating Expenses

 Fuel
 334,369
 372,692
 504,757

 Purchased Power
 129,431
 221,781
 209,790

 Transmission and Other PPFAC Recoverable Costs
 68,061
 81,706
 84,323

 Increase (Decrease) to Reflect PPFAC Recovery Treatment
 101,157
 80,207
 ( 27,643)

 Total Fuel and Purchased Power
 633,018
 756,386
 771,227

 Operations and Maintenance
 447,287
 444,826
 405,438

 Depreciation
 226,051
 198,919
 211,008

 Amortization
 30,687
 36,876
 40,045

 Taxes Other Than Income Taxes
 71,493
 67,484
 63,706

 Total Operating Expenses
 1,408,536
 1,504,491
 1,491,424

 Operating Income
 396,236
 370,957
 316,658

 Other Income (Expense)

 Interest Expense
 ( 105,269)
 ( 95,389)
 ( 85,217)

 Allowance For Borrowed Funds
 9,368
 5,145
 2,756

 Allowance For Equity Funds
 25,516
 14,763
 8,170

 Unrealized Gains (Losses) on Investments
 1,945
 2,992
 ( 7,094)

 Interest Income
 8,820
 11,372
 2,186

 Other, Net
 ( 3,329)
 ( 1,957)
 12,228

 Total Other Income (Expense)
 ( 62,949)
 ( 63,074)
 ( 66,971)

 Income Before Income Tax Expense
 333,287
 307,883
 249,687

 Income Tax Expense
 44,295
 49,229
 32,262

 $
 288,992
 $
 258,654
 $
 217,425

 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Amounts in thousands)

 2024
 2023
 2022

 Cash Flows from Operating Activities

 $
 288,992
 $
 258,654
 $
 217,425

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 Depreciation Expense
 226,051
 198,919
 211,008

 Amortization Expense
 30,687
 36,876
 40,045

 Amortization of Debt Issuance Costs
 3,272
 3,067
 3,000

 Use of Renewable Energy Credits for Compliance
 47,800
 45,416
 44,762

 Deferred Income Taxes
 31,357
 41,618
 32,825

 Pension and Other Postretirement Benefits Expense
 18,038
 15,241
 12,207

 Pension and Other Postretirement Benefits Funding
 ( 20,873)
 ( 18,391)
 ( 17,818)

 Allowance for Equity Funds Used During Construction
 ( 25,516)
 ( 14,763)
 ( 8,170)

 Change in Long-Term Regulatory Assets and Liabilities
 12,501
 3,615
 55,522

 Changes in Current Assets and Current Liabilities:

 Accounts Receivable
 20,745
 95,724
 ( 120,780)

 Materials, Supplies, and Fuel Inventory
 ( 48,070)
 ( 19,381)
 ( 12,953)

 43,192
 62,827
 ( 76,900)

 Other Current Assets
 ( 3,089)
 ( 3,229)
 ( 2,205)

 Accounts Payable and Accrued Charges
 ( 918)
 ( 128,780)
 132,796

 50,076
 ( 7,545)
 ( 2,615)

 Other, Net
 ( 10,928)
 ( 10,317)
 1,261

 Net Cash Flows—Operating Activities
 663,317
 559,551
 509,410

 Cash Flows from Investing Activities

 Capital Expenditures
 ( 733,096)
 ( 577,766)
 ( 457,517)

 Purchase Intangibles, Renewable Energy Credits
 ( 59,521)
 ( 62,444)
 ( 63,738)

 Other Investments
 —
 2,935
 2,517

 Contributions in Aid of Construction
 4,850
 4,252
 8,131

 Net Cash Flows—Investing Activities
 ( 787,767)
 ( 633,023)
 ( 510,607)

 Cash Flows from Financing Activities

 Proceeds from Borrowings, Revolving Credit Facility
 95,000
 —
 5,000

 Repayments of Borrowings, Revolving Credit Facility
 ( 25,000)
 —
 ( 20,000)

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

 399,376
 373,954
 323,804

 Repayments of Long-Term Debt
 ( 300,000)
 ( 240,745)
 ( 193,465)

 Dividends Paid to Parent
 ( 85,000)
 ( 64,100)
 ( 100,000)

 Payment of Debt Issuance Costs
 ( 3,744)
 ( 4,095)
 ( 3,012)

 Contributions from Parent
 50,000
 —
 —

 Other, Net
 6,362

 Net Cash Flows—Financing Activities
 131,316
 65,086
 18,689

 Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash
 6,866
 ( 8,386)
 17,492

 Cash, Cash Equivalents, and Restricted Cash, Beginning of Period
 42,595
 50,981
 33,489

 Cash, Cash Equivalents, and Restricted Cash, End of Period
 $
 49,461
 $
 42,595
 $
 50,981

 CONSOLIDATED BALANCE SHEETS
 (Amounts in thousands, except share data)

 2024
 2023

 ASSETS

 Utility Plant

 Plant in Service
 $
 8,349,638
 $
 8,035,444

 Construction Work in Progress
 850,443
 475,391

 Total Utility Plant
 9,200,081
 8,510,835

 Accumulated Depreciation and Amortization
 ( 2,713,492)
 ( 2,570,157)

 Total Utility Plant, Net
 6,486,589
 5,940,678

 Investments and Other Property
 75,662
 70,080

 Current Assets

 Cash and Cash Equivalents
 14,063
 8,616

 Accounts Receivable (Net of Allowance for Credit Losses of $ 12,561 and $ 11,676 as of December 31, 2024 and December 31, 2023, respectively)

 196,194
 217,381

 Fuel Inventory
 55,267
 34,475

 Materials and Supplies
 196,515
 172,667

 97,720
 147,389

 Derivative Instruments
 9,732
 3,091

 Other
 31,597
 30,450

 Total Current Assets
 601,088
 614,069

 177,963
 182,997

 Derivative Instruments
 27,664
 31,614

 Other Noncurrent Assets
 152,557
 134,196

 Total Assets
 $
 7,521,523
 $
 6,973,634

 (Continued)

 CONSOLIDATED BALANCE SHEETS
 (Amounts in thousands, except share data)

 2024
 2023

 CAPITALIZATION AND LIABILITIES

 Capitalization

 Common Stock Equity:

 Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2024 and 2023)

 $
 1,746,539
 $
 1,696,539

 Capital Stock Expense

 Retained Earnings
 1,366,913
 1,162,921

 Accumulated Other Comprehensive Loss
 ( 4,015)
 ( 3,829)

 Total Common Stock Equity
 3,103,080
 2,849,274

 Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2024 and 2023)

 —
 —

 Long-Term Debt, Net
 2,494,600
 2,396,542

 Total Capitalization
 5,597,680
 5,245,816

 Current Liabilities

 Borrowings Under Credit Agreement
 70,000
 —

 Accounts Payable
 151,278
 137,002

 Accrued Taxes Other than Income Taxes
 57,847
 57,291

 Accrued Employee Expenses
 37,921
 39,466

 Accrued Interest
 22,260
 16,541

 142,844
 92,740

 Customer Deposits
 16,255
 15,833

 Derivative Instruments
 25,710
 25,828

 Other
 31,665
 36,312

 Total Current Liabilities
 555,780
 421,013

 Deferred Income Taxes, Net
 700,189
 647,730

 362,859
 396,061

 Pension and Other Postretirement Benefits
 68,816
 81,241

 Derivative Instruments
 6,099
 4,338

 Other Noncurrent Liabilities
 230,100
 177,435

 Total Liabilities
 1,923,843
 1,727,818

 Commitments and Contingencies

 Total Capitalization and Liabilities
 $
 7,521,523
 $
 6,973,634

 (Concluded)

 CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
 (Amounts in thousands)

 Common Stock
 Capital Stock Expense
 Retained Earnings
 Accumulated Other Comprehensive Loss
 Total Stockholder's Equity

 Balances as of December 31, 2021
 $
 1,696,539
 $
 $
 850,942
 $
 ( 9,915)
 $
 2,531,209

 217,425
 217,425

 Other Comprehensive Income (Loss), Net of Tax
 7,031
 7,031

 Dividends Declared to Parent
 ( 100,000)
 ( 100,000)

 Balances as of December 31, 2022
 $
 1,696,539
 $
 $
 968,367
 $
 ( 2,884)
 $
 2,655,665

 258,654
 258,654

 Other Comprehensive Income (Loss), Net of Tax
 ( 945)
 ( 945)

 Dividends Declared to Parent
 ( 64,100)
 ( 64,100)

 Balances as of December 31, 2023
 $
 1,696,539
 $
 $
 1,162,921
 $
 ( 3,829)
 $
 2,849,274

 288,992
 288,992

 Other Comprehensive Income (Loss), Net of Tax
 ( 186)
 ( 186)

 Dividends Declared to Parent
 ( 85,000)
 ( 85,000)

 Contributions from Parent
 50,000
 50,000

 Balances as of December 31, 2024
 $
 1,746,539
 $
 $
 1,366,913
 $
 ( 4,015)
 $
 3,103,080

 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 452,000 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 consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities on the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. TEP has reclassified Interest Income from Other, Net in the prior period to a separately disclosed line on the Consolidated Statements of Income to conform with the current period presentation. The reclassification had no impact on TEP's results of operation, financial position, or cash flows.
 Accounting for Regulated Operations
 TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates charged to retail customers or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods.
 Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters.
 TEP applies regulatory accounting as the following conditions exist:
 • an independent regulator sets rates;
 • the regulator sets the rates to recover the specific enterprise's costs of providing service; and
 • rates are set at levels that will recover the entity's costs and can be charged to and collected from ratepayers.
 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 December 31, 2024, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing

 the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
 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, 2024. Adoption of the new guidance had an insignificant impact on TEP's financial position, results of operations, cash flows, and disclosures.
 Reportable Segment Disclosures
 TEP adopted accounting guidance that requires disclosure of significant segment expenses and new disclosures for entities with a single reportable segment. See Note 3 for additional information.
 NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
 The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected in TEP's financial statements. Unless otherwise indicated, TEP is assessing the impact such guidance may have on TEP's financial position, results of operations, cash flows, and disclosures.
 Disaggregation of Income Statement Expenses
 In November 2024, the FASB issued accounting guidance that requires disaggregation of income statement expenses into specified categories in the footnotes to the financial statements. In January 2025, the FASB issued accounting guidance clarifying the effective date of this standard. The amendments are effective for annual periods beginning January 1, 2027, and interim reporting periods beginning after January 1, 2028. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted.
 Climate-Related Disclosures
 In March 2024, the SEC issued a final rule that requires disclosure of: (i) financial statement impacts of severe weather events and other natural conditions; (ii) a roll forward of carbon offset and REC balances if material to the Company's plan to achieve climate-related targets or goals; and (iii) material impacts on estimates and assumptions in the financial statements. The rule is effective for TEP for annual periods beginning January 1, 2027 and is to be applied prospectively. In April 2024, the SEC issued an order staying the final rule pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit. TEP cannot predict what, if any, changes in scope or timing may occur as a result of the pending litigation. TEP continues its assessment to prepare for the new rule.
 Income Tax Disclosures
 In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on its financial position, results of operations, cash flows or disclosures.
 USE OF ACCOUNTING ESTIMATES
 Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect:
 • assets and liabilities in the balance sheet at the dates of the financial statements;
 • disclosures about contingent assets and liabilities at the dates of the financial statements; and
 • revenues and expenses in the income statement during the periods presented.
 Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates.

 Asset Retirement Obligations
 TEP has identified legal AROs related to the retirement of certain assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if a reasonable estimate of the liability can be made. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP defers the accretion and depreciation expense associated with its legal AROs to a regulatory asset or liability account based on the ACC's approval of these costs in its depreciation rates.
 Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities.
 Contingencies
 Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable, and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these legal proceedings and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
 CASH AND CASH EQUIVALENTS
 TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
 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 Consolidated Statements of Cash Flows:

 2024
 2023
 2022

 Cash and Cash Equivalents
 $
 $
 $

 Restricted Cash included in:

 Investments and Other Property

 Current Assets—Other

 Total Cash, Cash Equivalents, and Restricted Cash
 $
 $
 $

 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.
 ALLOWANCE FOR CREDIT LOSSES
 TEP records an allowance for credit losses to reduce retail accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible.
 INVENTORY
 TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory

 will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.
 UTILITY PLANT
 Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation facilities and transmission and distribution systems. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction.
 The cost of repairs and maintenance, including planned generation facility overhauls, are expensed to Operations and Maintenance expense on the Consolidated Statements of Income as costs are incurred.
 When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost net of removal costs and any salvage value. There is no impact to the income statement.
 AFUDC and Capitalized Interest
 AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.
 The average AFUDC rates on regulated construction expenditures are included in the table below:
 2024
 2023
 2022

 Average AFUDC Rates
 7.01
 %
 6.91
 %
 6.74
 %

 Depreciation
 Depreciation is recorded for owned utility plant on a group method straight-line basis, excluding software intangible plant, at depreciation rates based on the economic lives of the assets, including estimates for salvage value and removal costs. The ACC approves depreciation rates for all generation facilities, distribution systems, and general plant assets. Transmission system assets are subject to the jurisdiction of the FERC.
 Below are the average annual depreciation rates for all utility plant:
 2024
 2023
 2022

 Average Annual Depreciation Rates
 3.22
 %
 3.01
 %
 3.24
 %

 Computer Software and Cloud Computing Costs
 Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Other Noncurrent Assets on the Consolidated Balance Sheets and amortized over three to five years. Amortization of implementation costs is presented in Operations and Maintenance expense on the Consolidated Statements of Income. If the associated software is impaired, the carrying value is reduced and recorded as an expense in the income statement.
 EVALUATION OF ASSETS FOR IMPAIRMENT
 Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company's intent to use the assets. TEP's intent to use or dispose of assets is subject to re-evaluation and can change over time.

 DEFERRED FINANCING COSTS
 Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters' commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and filing costs.
 TEP accounts for debt issuance costs related to credit facility arrangements as an asset.
 The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the life of the original debt.
 OPERATING REVENUES
 TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved or market-based tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date past due and charges the customer a late payment fee, except during service disconnection moratoriums. No component of the transaction price is allocated to unsatisfied performance obligations.
 TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which it expects to be entitled and recognizes a refund liability until it is certain it will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods.
 LEASES
 When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g. common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet.
 TEP has operating leases for office facilities, land, rail cars, and communication tower space that are included in the balance sheet as follows:

 2024
 2023

 Lease Assets

 Other Noncurrent Assets
 $
 $

 Lease Liabilities

 Current Liabilities, Other

 Other Noncurrent Liabilities

 As of December 31, 2024, TEP's future minimum operating lease payments, excluding payments to lessors for variable costs, are $ 1 million or less in each year from 2025 through 2029 and $ 2 million thereafter.
 TEP's variable lease costs primarily consist of capacity payments for the right to use energy storage facilities associated with certain renewable PPAs with terms through 2041. Variable lease costs totaled $ 3 million, $ 4 million, and $ 5 million for the years ended December 31, 2024, 2023 and 2022, respectively.
 PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE
 TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these

 costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities, and cost under-recoveries are deferred as regulatory assets.
 RENEWABLE ENERGY CREDITS
 The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power, or the REC purchase price, equals the REC cost recoverable through the RES tariff. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism.
 When RECs are purchased, TEP records the cost of the RECs, an indefinite-lived intangible asset, as other assets, and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and retail revenues in an equal amount. The table below summarizes the balance of TEP's RECs that are included in Other Noncurrent Assets on the Consolidated Balance Sheets:

 2024
 2023

 $
 $

 Purchased

 Used for Compliance
 ( 48)
 ( 45)

 $
 $

 TEP expenses the cost of internally developed RECs and PBI activity, which are not included in the table above. PBI costs are recoverable through the RES tariff.
 PENSION AND OTHER POSTRETIREMENT BENEFITS
 TEP sponsors noncontributory, defined benefit pension plans for substantially all employees hired before January 1, 2025. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees hired before January 1, 2025. Non-bargaining unit employees who commence service or are rehired on or after January 1, 2025, are not eligible to receive defined benefit pension and other postretirement benefits.
 The Company recognizes an asset for a defined benefit plan's overfunded status or a liability for a plan's underfunded status in the balance sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement benefit plans. TEP records changes in its pension and other postretirement benefit plans, not yet reflected in net periodic benefit costs, as a regulatory asset or liability, when such amounts are probable of future recovery or refund in rates charged to retail customers over the estimated service lives of employees.
 Additionally, TEP maintains a SERP for certain executive management. Changes in SERP benefit obligations not yet recognized in the income statement are recognized as a component of AOCL since SERP expense is not currently recoverable in rates. The SERP for certain executive management who commence service on or after January 1, 2025, will include enhanced defined contribution benefits.
 Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually.
 FAIR VALUE
 As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able, and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair

 value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
 DERIVATIVE INSTRUMENTS
 The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; and (ii) reduce exposure to energy commodity price volatility. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities in the balance sheet and are measured at fair value. The cash impacts of settled derivatives are recorded in Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity in the income statement.
 For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.
 TAXES OTHER THAN INCOME TAXES
 TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.
 INCOME TAXES
 Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities in the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized.
 Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income.
 Federal ITCs are deferred and amortized as a reduction to income tax expense over the life of the underlying asset. All other federal and state income tax credits, including PTCs, are treated as a reduction to income tax expense in the year the credit arises.

 NOTE 2. REGULATORY MATTERS
 The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.
 RATE CASE MATTERS
 2023 Rate Order
 In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the 2023 Rate Order include, but are not limited to:
 • a non-fuel retail revenue increase of $ 100 million over test year non-fuel retail revenues;

 • a 6.93 % return on original cost rate base of $ 3.6 billion, which includes a return on equity of 9.55 % and an average cost of debt of 3.82 %;
 • a capital structure for rate making purposes of approximately 54 % common equity and 46 % long-term debt; and
 • approval to recover costs of changes in generation resources, including the addition of Oso Grande in rates.
 COST RECOVERY MECHANISMS
 TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.
 Purchased Power and Fuel Adjustment Clause
 TEP's PPFAC rate is adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period.
 The table below summarizes the PPFAC regulatory asset (liability) balance:

 2024
 2023

 $
 $

 Deferred Fuel and Purchased Power Costs (1)

 PPFAC and Base Power Recoveries
 ( 381)
 ( 397)

 $
 ( 49)
 $

 (1)Includes costs eligible for recovery through the PPFAC and base power rates.
 Environmental Compliance Adjustor
 The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided they are not already recovered in base rates or recovered through another commission-approved mechanism. Costs eligible for the ECA are subject to a cap equal to 0.5 % of total annual retail revenue.
 Tax Expense Adjustor Mechanism
 The TEAM allows for the timely recovery of future significant income tax changes and provides TEP the ability to pass through as a kWh surcharge: (i) the change in EDIT compared to the test year; and (ii) the income tax effects of tax legislation that materially impacts TEP's authorized revenue requirement. TEP files an annual update to the TEAM rate in August each year. New TEAM rates take effect in January of each year.
 Transmission Cost Adjustor
 The TCA allows for timely recovery or refund of actual costs, net of applicable credits, required to provide transmission services to retail customers. TEP files new TCA rates with the ACC in December each year based on changes in net costs required to provide transmission services to retail customers. New TCA rates take effect in January of each year.
 Renewable Energy Standard
 The ACC's RES 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 2025. In 2024, TEP's retail kWh sales attributable to renewable energy exceeded the 2024 RES requirement of 14 %. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. TEP recovers approved costs of carrying out this plan from retail customers through a RES tariff.

 In May 2024, the ACC approved an extension of TEP's 2021 RES implementation with a budget of $ 66 million until further order of the ACC and an increase to the RES tariff to recover under-collected RES funds totaling $ 17 million. The ACC also 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. In May 2024, the ACC approved refunding over-collected, uncommitted DSM surcharge funds totaling $ 10 million. TEP credited customers' accounts for the over-collected funds in 2024.
 2020 IRP Energy Efficiency Target
 In 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3 % energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP periodically reports on its energy efficiency savings in filings with the ACC.
 Lost Fixed Cost Recovery Mechanism
 The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues based on an estimate of lost retail kWh sales during the period. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2 % of TEP's applicable retail revenues.

 REGULATORY ASSETS AND LIABILITIES
 Regulatory assets and liabilities recorded on the Consolidated Balance Sheets are summarized in the table below:
 Remaining Recovery Period (years)

 2024
 2023

 Pension and Other Postretirement Benefits (Note 10)

 $
 $

 Early Generation Retirement Costs

 Property Tax Deferrals (1)

 Lost Fixed Cost Recovery

 Derivatives (Note 13)

 Transmission Revenue Requirement Balancing Account
 —

 Final Mine Reclamation (2)

 Income Taxes Recoverable through Future Rates (3)

 Unamortized Loss on Reacquired Debt

 Under-Recovered Fuel and Purchased Energy Costs
 —

 Other Regulatory Assets

 Total Regulatory Assets

 Less Current Portion

 Total Non-Current Regulatory Assets
 $
 $

 Income Taxes Payable through Future Rates (3)

 $
 $

 Net Cost of Removal (4)

 Renewable Energy Standard

 Over-Recovered Purchased Energy Costs
 —

 Derivatives (Note 13)

 Pension and Other Postretirement Benefits (Note 10)

 Demand Side Management

 Deferred Investment Tax Credits

 Transmission Revenue Requirement Balancing Accounts
 —

 Other Regulatory Liabilities
 —

 Total Regulatory Liabilities

 Less Current Portion

 Total Non-Current Regulatory Liabilities
 $
 $

 (1)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes.
 (2)Represents costs associated with TEP's jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022. In March 2024, TEP increased its final mine reclamation regulatory asset by $ 15 million due to a new final mine reclamation study.
 (3)Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 14 for additional information regarding income taxes.
 (4)Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general plant which are not yet expended.

 Regulatory Assets and Liabilities
 Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, Transmission Revenue Requirement Balancing Account, and Under-Recovered Fuel and Purchased Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.
 Roadrunner Reserve I Application for Accounting Order
 In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I with an anticipated in-service date in 2025. In October 2024, TEP filed a request with the ACC for an accounting order to defer for future recovery certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I, offset by future benefits associated with investment tax credits. TEP cannot predict the timing or outcome of this application.
 IMPACTS OF REGULATORY ACCOUNTING
 If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.

 NOTE 3. REPORTABLE SEGMENTS
 TEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP has one operating segment, its regulated utility operations. TEP's chief operating decision maker (CODM) is Susan M. Gray who holds the position of President and Chief Executive Officer of TEP and its parent company, UNS Energy. The CODM uses net income to assess performance and decide how to allocate resources for UNS Energy overall (including employees and financial or capital resources) predominantly in the annual budget and forecasting process. Net income is reported on the 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 $ 343 million, $ 317 million, and $ 309 million for the years ended December 31, 2024, 2023, and 2022, respectively. Total assets, the measure of segment assets, is reported on the Consolidated Balance Sheets. Capital expenditures are reported on the Consolidated Statements of Cash Flows.

 NOTE 4. UTILITY PLANT AND JOINTLY-OWNED FACILITIES
 UTILITY PLANT
 The following table shows Plant in Service on the Consolidated Balance Sheets by major class:
 Annual Depreciation Rate (3)

 Average Remaining Life in Years (3)

 2024
 2023

 Plant in Service

 Generation
 3.05 %
 $
 3,651
 $
 3,536

 Distribution
 2.61 %
 2,407
 2,279

 Transmission
 1.69 %
 1,370
 1,323

 General Plant
 6.13 %

 Intangible Plant, Software Costs, and Other (1)

 Plant Held for Future Use
 —
 —

 Total Plant in Service (2)

 $
 8,350
 $
 8,035

 (1)Primarily represents computer software, which is being amortized over three to five years for smaller application software and 10 years for large enterprise software and has an average remaining life of three years.
 (2)Includes plant acquisition adjustments of $( 206) million as of December 31, 2024 and 2023.

 (3)With the exception of Transmission and Intangible Plant, based on the 2022 depreciation study available for the major classes of Plant in Service, effective September 1, 2023, as approved by the ACC as part of the 2023 Rate Order. TEP implemented new depreciation rates for Transmission based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 2022 Final FERC Rate Order.
 Accumulated Depreciation and Amortization
 Amortization of Intangible Plant
 Intangible Plant primarily consists of computer software. Accumulated amortization of computer software costs was $ 104 million and $ 100 million as of December 31, 2024 and 2023, respectively. Amortization of computer software costs totaled $ 25 million in 2024, $ 27 million in 2023, and $ 30 million in 2022. Future estimated amortization costs for existing computer software are $ 25 million in 2025, $ 22 million in 2026, $ 17 million in 2027, $ 13 million in 2028, and $ 8 million in 2029.
 Intangible Plant includes $( 4) million in acquisition discounts not subject to amortization as of December 31, 2024 and 2023.
 JOINTLY-OWNED FACILITIES
 As of December 31, 2024, TEP was a participant in the following jointly-owned generation facilities and transmission systems:
 Ownership Percentage
 Plant in Service
 Construction Work in Progress
 Accumulated Depreciation
 Net Book Value

 Four Corners Units 4 and 5
 7.0 %
 $
 $
 $
 ( 108)
 $

 Luna
 33.3 %

 Gila River Unit 3
 75.0 %
 ( 59)

 Gila River Common Facilities
 43.8 %
 ( 32)

 Springerville Coal Handling Facilities
 83.0 %
 —
 ( 107)

 Springerville Common Facilities
 86.0 %
 —
 ( 239)

 Transmission Facilities
 ( 242)

 Total
 $
 1,776
 $
 $
 ( 785)
 $
 1,018

 As a participant in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.
 ASSET RETIREMENT OBLIGATIONS
 The liability accrual of AROs is primarily related to generation assets and is included in Current Liabilities—Other and Other Noncurrent Liabilities on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets:

 2024
 2023

 $
 $

 Liabilities Settled (1)

 ( 2)
 ( 2)

 Regulatory Deferral/Accretion Expense

 Revisions to the Present Value of Estimated Cash Flows (2)

 ( 8)

 $
 $

 (1)Primarily related to the retirement of Navajo and San Juan.
 (2)In 2024, primarily related to revised cost estimates to close the Springerville coal ash landfill. In 2023, primarily related to revised decommissioning estimates for San Juan.

 NOTE 5. REVENUE
 TEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts

 with variable transaction pricing that require it to estimate the expected consideration.
 DISAGGREGATION OF REVENUES
 The following table presents the disaggregation of TEP's Operating Revenues on the Consolidated Statements of Income by type of service:

 2024
 2023
 2022

 Retail
 $
 1,321
 $
 1,283
 $
 1,140

 Wholesale

 Other Services

 Revenues from Contracts with Customers
 1,709
 1,771
 1,700

 Alternative Revenues

 Other

 Total Operating Revenues
 $
 1,805
 $
 1,875
 $
 1,808

 Retail Revenues
 TEP's tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management's judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during spring and summer months then decrease during fall and winter months due to the seasonal fluctuations of TEP's actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances. See Note 6 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.
 In August 2023, the ACC issued the 2023 Rate Order for new rates that took effect September 1, 2023. See Note 2 for more information regarding the 2023 Rate Order.
 Wholesale Revenues
 TEP's operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand for capacity or the reading of meters for power. For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income.
 Other Services Revenues
 Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, reimbursement of various operating expenses for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities by the lessee of Springerville Unit 3, and miscellaneous service-related revenues.
 Alternative Revenues
 Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR and ECA mechanisms, OATT and TCA balancing activity, and DSM performance incentive as alternative revenues. See Note 2 for additional information regarding these cost recovery mechanisms and performance incentive.
 Other Revenues
 Other Revenues include gains and losses on derivative contracts, asset management agreement optimization gains, common cost allocations to affiliates, and late and returned payment finance charges. See Note 7 for information regarding revenue from related parties and Note 13 for information regarding derivative instruments.

 NOTE 6. ACCOUNTS RECEIVABLE
 The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:

 2024
 2023

 Retail
 $
 $

 Retail, Unbilled

 Retail, Allowance for Credit Losses
 ( 13)
 ( 12)

 Wholesale (1)

 Due from Affiliates (Note 7)

 Other

 Accounts Receivable, Net
 $
 $

 (1)Includes $ 8 million and $ 10 million as of December 31, 2024 and 2023, 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 Consolidated Balance Sheets:

 2024
 2023
 2022

 $
 ( 12)
 $
 ( 9)
 $
 ( 10)

 Credit Loss Expense
 ( 6)
 ( 7)
 ( 5)

 Write-offs

 $
 ( 13)
 $
 ( 12)
 $
 ( 9)

 NOTE 7. RELATED PARTY TRANSACTIONS
 TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services.
 The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets:

 2024
 2023

 Receivables from Related Parties

 UNS Electric
 $
 $

 UNS Gas

 UNS Energy
 —

 Total Due from Related Parties
 $
 $

 Payables to Related Parties

 UNS Energy
 $
 $

 UNS Electric

 UNS Gas
 —

 Total Due to Related Parties
 $
 $

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

 2024
 2023
 2022

 Goods and Services Provided by TEP to Affiliates

 Common Costs, UNS Energy Affiliates (1)

 Wholesale Revenues, UNS Electric (2)

 Transmission Revenues, UNS Electric (2)

 Control Area Services, UNS Electric (3)

 Goods and Services Provided by Affiliates to TEP

 Corporate Services, UNS Energy (4)

 Corporate Services, UNS Energy Affiliates (5)

 Capacity Charges, UNS Gas (6)

 Purchased Power, UNS Electric (2)

 —

 (1)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.
 (2)TEP and UNS Electric sell power to each other, and TEP sells transmission services to UNS Electric. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT.
 (3)TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement.
 (4)Corporate Services, UNS Energy includes legal and audit, and Fortis' management fees. Costs for corporate services provided by UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85 % of UNS Energy's allocated costs. TEP's share of Fortis' management fees was $ 7 million in each of 2024, 2023, and 2022.
 (5)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
 (6)UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.

 NOTE 8. DEBT AND CREDIT AGREEMENT
 DEBT
 Long-term debt matures more than one year from the date of debt issuance. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets:

 Interest Rate
 Maturity Date
 2024
 2023

 Notes

 2015 Senior Notes
 3.05 %
 2025
 $
 —
 $

 2020 Senior Notes
 1.50 %
 2030

 2022 Senior Notes
 3.25 %
 2032

 2024 Senior Notes
 5.20 %
 2034
 —

 2014 Senior Notes
 5.00 %
 2044

 2018 Senior Notes
 4.85 %
 2048

 2020 Senior Notes
 4.00 %
 2050

 2021 Senior Notes
 3.25 %
 2051

 2023 Senior Notes
 5.50 %
 2053

 Total Long-Term Debt (1)

 2,525
 2,425

 Less Unamortized Discount and Debt Issuance Costs

 Less Current Maturities of Long-Term Debt
 —
 —

 Total Long-Term Debt, Net
 $
 2,495
 $
 2,397

 (1)As of December 31, 2024 and 2023, all of TEP's debt is unsecured.
 Debt Issuances and Redemptions
 In August 2024, TEP issued and sold $ 400 million aggregate principal amount of 5.20 % senior unsecured notes due September 2034. TEP may redeem the notes prior to June 15, 2034, with a make-whole premium plus accrued interest. On or after June 15, 2034, TEP may redeem the notes at par plus accrued interest.
 In December 2024, TEP redeemed at par prior to maturity $ 300 million aggregate principal amount of 3.05 % senior unsecured notes.
 In February 2023, TEP issued and sold $ 375 million aggregate principal amount of 5.50 % senior unsecured notes due April 2053. TEP may redeem the notes prior to October 15, 2052, with a make-whole premium plus accrued interest. On or after October 15, 2052, TEP may redeem the notes at par plus accrued interest.
 In March 2023, TEP repaid at maturity $ 150 million aggregate principal amount of 3.85 % senior unsecured notes.
 In March 2023, TEP redeemed at par prior to maturity $ 91 million aggregate principal amount of tax-exempt bonds bearing interest at a rate of 4.00 % per annum.

 Maturities
 Long-term debt matures on the following dates:
 Long-Term Debt (1)

 2025
 $
 —

 2026
 —

 2027
 —

 2028
 —

 2029
 —

 Thereafter
 2,525

 Total
 $
 2,525

 (1)Total long-term debt excludes $ 20 million of related unamortized debt issuance costs and $ 10 million of unamortized original issue discount.
 CREDIT AGREEMENT
 In October 2024, the maturity date of the 2021 Credit Agreement was extended to October 2027. The 2021 Credit Agreement provides for one additional one-year extension if certain conditions are satisfied. Amounts borrowed under the 2021 Credit Agreement are used for working capital and other general corporate purposes and are recorded in Borrowings Under Credit Agreement on the Consolidated Balance Sheets. Interest rates and fees are based on a pricing grid tied to TEP's credit rating.
 LOCs are issued from time to time to support energy procurement, hedging transactions, and other business activities.
 Terms are as follows:
 Sub-Limit Swingline(1)

 Sub-Limit LOC
 Weighted Average Interest Rate

 Capacity
 Borrowed(2)

 Available
 Pricing(3)

 Agreement
 $
 $
 $
 $
 $
 5.52
 %
 SOFR+ADJ 0.10 %+ 1.050 % or ABR+ 0.050 %

 December 31, 2023

 Agreement
 $
 $
 $
 $
 —
 $
 —
 %
 SOFR+ADJ 0.10 %+ 1.025 % or ABR+ 0.025 %

 (1)ABR pricing would apply to swingline loans.
 (2)The borrowed amount includes LOCs totaling $ 12 million at a rate of 1.050 % per annum issued in October and November 2024 to support interconnection requests. The LOCs expire in October and November 2025.
 (3)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 February 13, 2025, there was $ 138 million available under the 2021 Credit Agreement.

 NOTE 9. COMMITMENTS AND CONTINGENCIES
 COMMITMENTS
 As of December 31, 2024, TEP had the following commitments:
 2025
 2026
 2027
 2028
 2029
 Thereafter
 Total

 Minimum Purchase Commitments

 Fuel, Including Transportation
 $
 $
 $
 $
 $
 $
 $

 Non-Renewable Purchased Power
 —
 —
 —
 —
 —

 Transmission

 Purchase Commitments

 Renewable PPAs and Other - Commercially Operable
 1,009

 Renewable PPAs and Other - Non-Commercially Operable (1)

 RES Performance-Based Incentives

 Total Commitments
 $
 $
 $
 $
 $
 $
 1,299
 $
 2,210

 (1)Includes purchase commitments that are contingent upon the developers obtaining commercial operation. The non-commercially operable PPAs are expected to be placed in service in 2026 and 2027.
 Costs for Fuel, Including Transportation, Non-Renewable Purchased Power, and Transmission are recoverable from customers through the PPFAC mechanism. A portion of the costs of renewable PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.
 Minimum Purchase Commitments
 Fuel, Including Transportation
 TEP has long-term agreements for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs.
 TEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2025 and 2048.
 Non-Renewable Purchased Power
 TEP has contracts for purchased power to: (i) meet system load and energy requirements; (ii) replace generation from company-owned units under maintenance and during outages; and (iii) meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the third quarter of 2025. Certain of these contracts are at a fixed price per MWh and others are indexed to market prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2024.
 Transmission
 TEP has long-term firm point-to-point contracts to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2025 and 2030. In April 2024, TEP amended and extended to 2030 a point-to-point transmission service agreement.
 Purchase Commitments
 Renewable Power Purchase Agreements
 TEP enters into long-term renewable PPAs, which require TEP to purchase 100 % of certain renewable energy generation facilities' output and RECs associated with the output delivered once commercial operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2051.

 RES Performance-Based Incentives
 TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2025 and 2034.
 EPC Agreements
 In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $ 268 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. TEP made payments in connection with the construction and development of Roadrunner Reserve II of $ 76 million in 2024 and $ 5 million in January 2025.
 In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I at a cost of $ 294 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 I is expected to be placed in service in 2025. TEP made payments in connection with the construction and development of Roadrunner Reserve I of $ 179 million in 2024 and $ 90 million in 2023. In 2025, TEP made an additional $ 19 million payment. See Note 2 for information related to TEP's request to defer for future recovery certain incurred costs associated with Roadrunner Reserve I.
 CONTINGENCIES
 Legal Matters
 TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results.
 Mine Reclamation at Generation Facilities Not Operated by TEP
 TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP's PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.
 TEP is liable for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP's liability balance related to its share of final mine reclamation costs at Four Corners totaled $ 3 million and $ 4 million as of December 31, 2024, and 2023, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the 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. In March 2024, TEP increased the San Juan final mine reclamation liability by $ 15 million as a result of a new final mine reclamation study. TEP's remaining final mine reclamation liability at San Juan was $ 31 million and $ 25 million as of December 31, 2024 and 2023, respectively and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the 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. For additional information see Note 1, Restricted Cash.
 Performance Guarantees
 TEP has joint generation participation agreements with participants at Four Corners and 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 December 31, 2024, 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.

 NOTE 10. EMPLOYEE BENEFITS PLANS
 DEFINED BENEFIT PENSION PLANS
 TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under IRS regulations. TEP also maintains a SERP for certain executive management.
 In December 2024, TEP amended certain pension plans. As a result, non-bargaining unit employees, including executive management, who commence service or are rehired on or after January 1, 2025, are not eligible to receive defined benefit pensions.
 OTHER POSTRETIREMENT BENEFITS PLAN
 TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP.
 TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $ 4 million in 2024 and $ 2 million in each of 2023 and 2022. Other postretirement benefits for non-bargaining unit employees are self-funded.
 In December 2024, TEP amended its other postretirement benefits plan. As a result, non-bargaining unit employees who commence service or are rehired on or after January 1, 2025, are not eligible to receive other postretirement benefits.
 REGULATORY RECOVERY
 TEP records changes in non-SERP pension and other postretirement benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in AOCL since SERP expense is not recoverable in rates.

 The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet:

 2024
 2023
 2024
 2023

 $
 $
 $
 —
 $
 —

 —
 —
 ( 19)
 ( 4)

 Other Noncurrent Assets
 —
 —
 —

 Accrued Employee Expenses
 ( 1)
 ( 1)
 ( 2)
 ( 3)

 Pension and Other Postretirement Benefits
 ( 30)
 ( 28)
 ( 39)
 ( 53)

 Accumulated Other Comprehensive Loss
 —
 —

 Net Amount Recognized
 $
 $
 $
 ( 60)
 $
 ( 60)

 OBLIGATIONS AND FUNDED STATUS
 The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2024 and 2023. The table below presents the status of all TEP pension and other postretirement benefit plans.

 2024
 2023
 2024
 2023

 Change in Benefit Obligation

 $
 $
 $
 $

 Actuarial (Gain) Loss
 ( 19)
 ( 14)

 Interest Cost

 Service Cost

 Benefits Paid
 ( 25)
 ( 23)
 ( 6)
 ( 5)

 End of Period (1)

 Change in Fair Value of Plan Assets

 Actual Return on Plan Assets

 Benefits Paid
 ( 24)
 ( 22)
 ( 4)
 ( 2)

 Employer Contributions (2)

 Funded Status at End of Period
 $
 ( 23)
 $
 ( 29)
 $
 ( 41)
 $
 ( 56)

 (1)The decrease in pension and other postretirement benefit obligations was due to updated assumptions based on an experience study conducted in 2024 and increases in the discount rate.
 (2)TEP expects to contribute $ 10 million to the pension plans and $ 4 million to the VEBA trust in 2025.
 Two pension plans had a projected benefit obligation in excess of plan assets as of December 31, 2024, compared to all three pension plans as of December 31, 2023. For the two plans for which the projected benefit obligation exceeded plan assets as of December 31, 2024, the projected benefit obligation balances increased due to results of an experience study conducted in 2024. This impact was partially offset by higher discount rates. For the plan for which assets were in excess of the projected benefit obligation as of December 31, 2024, the projected benefit obligation balance decreased due to an increase in the discount rate and the results of the experience study. For plans with projected benefit obligations in excess of plan assets, total projected benefit obligations and plan assets were $ 288 million and $ 257 million, respectively, as of December 31, 2024, and $ 461 million and $ 432 million, respectively, as of December 31, 2023.
 The other postretirement benefits plan had an accumulated postretirement benefit obligation in excess of the fair value of plan assets as of December 31, 2024 and 2023.

 The accumulated benefit obligation aggregated for all pension plans was $ 399 million and $ 409 million as of December 31, 2024 and 2023, respectively. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2024 and 2023. The following table includes information for the pension plan with an accumulated benefit obligation in excess of pension plan assets:

 2024
 2023

 Accumulated Benefit Obligation
 $
 $

 Fair Value of Plan Assets
 —
 —

 The following table provides the components of TEP's regulatory assets, regulatory liabilities, and AOCL that have not been recognized as components of net periodic benefit cost as of the dates presented:

 2024
 2023
 2024
 2023

 Net Loss (Gain)
 $
 $
 $
 ( 18)
 $
 ( 3)

 Prior Service Cost (Benefit)
 ( 1)
 ( 1)

 The Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components:

 2024
 2023
 2022
 2024
 2023
 2022

 Service Cost
 $
 $
 $
 $
 $
 $

 Non-Service Cost

 Interest Cost

 Expected Return on Plan Assets
 ( 32)
 ( 29)
 ( 37)
 ( 2)
 ( 2)
 ( 1)

 Prior Service Benefit Amortization
 —
 —
 —
 —
 —
 ( 1)

 Amortization of Net Loss
 —
 —
 —

 Effect of Settlement
 —
 —
 —
 —
 —

 Net Periodic Benefit Cost
 $
 $
 $
 $
 $
 $

 TEP capitalized 22 % of service cost as a cost of construction in 2024 and 21 % in each of 2023 and 2022. The non-service components of net periodic benefit cost are primarily included in Other, Net on the Consolidated Statements of Income. In 2022, $ 3 million of the effect of settlement was deferred as a regulatory asset and recorded in Regulatory Assets on the Consolidated Balance Sheets.

 The changes in plan assets and benefit obligations recognized as regulatory assets, regulatory liabilities, or in AOCL were as follows:

 Regulatory Asset
 AOCL
 Regulatory Asset/Liability

 2024
 2023
 2022
 2024
 2023
 2022
 2024
 2023
 2022

 Current Year Actuarial Loss (Gain)
 $
 $
 $
 ( 27)
 $
 —
 $
 $
 ( 9)
 $
 ( 15)
 $
 $
 ( 11)

 Prior Service Benefit Amortization
 —
 —
 —
 —
 —
 —
 —
 —

 Amortization of Net Loss
 ( 6)
 ( 5)
 ( 6)
 —
 —
 ( 1)
 —
 —
 —

 Prior Service Cost
 —
 —
 —
 —
 —
 —
 —
 —

 Effect of Settlement
 —
 —
 ( 3)
 —
 —
 —
 —
 —
 —

 Total Recognized Loss (Gain)
 $
 ( 4)
 $
 $
 ( 36)
 $
 —
 $
 $
 ( 9)
 $
 ( 15)
 $
 $
 ( 10)

 For all pension plans, TEP amortizes prior service costs and benefits on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.
 Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time regarding these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.
 TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a "best-estimate" range over 20 years from the 25 th percentile to the 75 th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption for all asset classes, is based on forward-looking return expectations only.
 The following table includes the weighted average assumptions used to determine benefit obligations:

 2024
 2023
 2024
 2023

 Discount Rate
 5.9 %
 5.4 %
 5.7 %
 5.2 %

 Rate of Compensation Increase
 3.9 %
 3.2 %
 N/A
 N/A

 The following table includes the weighted average assumptions used to determine net periodic benefit costs:

 2024
 2023
 2022
 2024
 2023
 2022

 Discount Rate, Service Cost
 5.6 %
 5.9 %
 3.4 %
 5.3 %
 5.7 %
 3.2 %

 Discount Rate, Interest Cost
 5.2 %
 5.6 %
 2.7 %
 5.2 %
 5.5 %
 2.5 %

 Rate of Compensation Increase
 3.2 %
 2.9 %
 2.8 %
 N/A
 N/A
 N/A

 Expected Return on Plan Assets
 7.5 %
 7.5 %
 7.0 %
 7.5 %
 7.5 %
 7.0 %

 Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:

 2024
 2023

 Next Year (Pre-65)
 6.8 %
 7.3 %

 Next Year (Post-65)
 5.3 %
 5.8 %

 Ultimate Rate Assumed (Pre-65 and Post-65)
 4.5 %
 4.5 %

 Year Ultimate Rate is Reached (Pre-65)
 2034
 2034

 Year Ultimate Rate is Reached (Post-65)
 2028
 2028

 PENSION AND OTHER POSTRETIREMENT BENEFIT PLAN ASSETS
 TEP calculates the fair value of plan assets on December 31st, the measurement date. Asset allocations, by asset category, on the measurement date were as follows:
 Pension

 2024
 2023
 2024
 2023

 Asset Category

 Equity Securities
 %
 %
 %
 %

 Fixed Income Securities
 %
 %
 %
 %

 %
 %
 —
 %
 —
 %

 Other
 %
 %
 %
 %

 Total
 %
 %
 %
 %

 As of December 31, 2024, the fair value of VEBA trust assets was $ 30 million, of which $ 11 million were fixed income investments, $ 17 million were equities, and $ 2 million were cash and short-term investments. As of December 31, 2023, the fair value of VEBA trust assets was $ 27 million, of which $ 10 million were fixed income investments and $ 17 million were equities. The VEBA trust assets are primarily Level 1 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust.
 The following tables present the fair value measurements of pension plan assets/(liabilities) by level within the fair value hierarchy:
 Level 1
 Level 2
 Level 3
 Total

 Asset/(Liability) Category

 Cash Equivalents
 $
 $
 —
 $
 —
 $

 Equity Securities:

 United States Large Cap
 —
 —

 United States Small Cap
 —
 —

 Non-United States
 —
 —

 Global
 —
 —

 Fixed Income
 ( 2)
 —

 —
 —

 Private Equity
 —
 —

 Total
 $
 $
 $
 $

 December 31, 2023

 Asset Category

 Cash Equivalents
 $
 $
 —
 $
 —
 $

 Equity Securities:

 United States Large Cap
 —
 —

 United States Small Cap
 —
 —

 Non-United States
 —
 —

 Global
 —
 —

 Fixed Income
 —
 —

 —
 —

 Private Equity
 —
 —

 Total
 $
 $
 $
 $

 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. Level 1 fixed income investments are based on observable market prices and are comprised of futures contracts.
 • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.
 • Level 3 real estate investment values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of comparable properties.
 • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
 The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.
 Private Equity
 Total

 Balance as of December 31, 2022
 $
 $
 $

 Actual Return on Plan Assets:

 Assets Held at Reporting Date
 ( 1)
 ( 3)
 ( 4)

 Purchases, Sales, and Settlements
 —
 —
 —

 Balance as of December 31, 2023

 Actual Return on Plan Assets:

 Assets Held at Reporting Date
 —
 ( 2)
 ( 2)

 Purchases, Sales, and Settlements
 —
 —
 —

 Balance as of December 31, 2024
 $
 $
 $

 Pension Plan Investments
 Investment Goals
 Asset allocation is the principal method for achieving each pension plan's investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.

 Risk Management
 TEP recognizes the difficulty of achieving investment objectives considering the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan's long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return to achieve long-term objectives. TEP tracks each pension plan's portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.
 Relationship between Plan Assets and Benefit Obligations
 The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data but will be no less frequent than annually via actuarial valuation.
 Target Allocation Percentages
 The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced:
 Pension

 Cash/Treasury Bills
 2 %
 1 %

 Equity Securities:

 United States Large Cap
 16 %
 25 %

 United States Mid Cap
 — %
 8 %

 United States Small Cap
 6 %
 4 %

 Non-United States Developed
 — %
 15 %

 Non-United States Emerging
 — %
 8 %

 Global Equity
 28 %
 — %

 Global Infrastructure
 3 %
 — %

 Fixed Income
 38 %
 39 %

 6 %
 — %

 Private Equity
 1 %
 — %

 Total
 100 %
 100 %

 Pension Fund Descriptions
 For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-party funds.
 ESTIMATED FUTURE BENEFIT PAYMENTS
 TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate:
 2025
 2026
 2027
 2028
 2029
 2030-2034

 $
 $
 $
 $
 $
 $

 DEFINED CONTRIBUTION PLAN
 TEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant's contributions to the plan. Beginning January 1, 2025, the Company will make non-elective employer

 contributions for certain newly hired or rehired employees in addition to matching part of all participants' contributions to the plan. TEP made matching contributions to the plan of $ 9 million in 2024, $ 8 million in 2023, and $ 7 million in 2022.

 NOTE 11. SHARE-BASED COMPENSATION
 2024 FORTIS EXECUTIVE OMNIBUS EQUITY PLAN
 The Fortis Board of Directors ratified the Fortis Executive Omnibus Equity Plan (2024 Omnibus Plan) effective January 2024. Under the 2024 Omnibus Plan, certain executive management of Fortis and its subsidiaries may be granted PSUs and time-based RSUs, annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the New York Stock Exchange. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur.
 The following table represents PSUs and RSUs awarded by Fortis for UNS Energy:
 2024

 PSUs

 65,385

 RSUs
 32,693

 The awards are initially classified as liability awards because: (i) the participants have the option to elect settlement in cash or shares; and (ii) this election is contingent upon an event within the participants' control. The liability awards may be reclassified as equity awards if the participants elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $ 4 million as of December 31, 2024.
 TEP's allocated portion of compensation expense is recognized in Operations and Maintenance expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date. TEP recorded $ 2 million in 2024 based on its share of Fortis' compensation expense.
 2020 FORTIS RESTRICTED STOCK UNIT PLAN
 The Fortis Board of Directors ratified the 2020 Restricted Stock Unit Plan (2020 Plan) effective January 2020. Under the 2020 Plan, certain executive management of Fortis and its subsidiaries may be granted time-based RSUs annually, which may be settled in cash or shares. Each RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur.

 The following table represents RSUs awarded by Fortis for UNS Energy:
 2024
 2023
 2022

 RSUs (1)

 —
 26,980
 17,996

 (1)Effective January 2024, certain executive management RSU awards are issued through the 2024 Omnibus Plan.
 The awards are initially classified as liability awards because: (i) the participants have the option to elect settlement in cash or shares; and (ii) this election is contingent upon an event within the participants' control. The liability awards may be reclassified as equity awards if the participants elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $ 2 million and $ 2 million as of December 31, 2024 and 2023, respectively.
 TEP's allocated portion of compensation expense is recognized in Operations and Maintenance expense on the Consolidated Statements of Income. Compensation expense associated with unvested RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date. TEP recorded $ 1 million in 2024 and 2023, and no compensation expense in 2022, based on its share of Fortis' compensation expense.
 2015 SHARE UNIT PLAN
 The UNS Energy Human Resources and Governance Committee approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (2015 Plan) effective January 2015. Under the 2015 Plan, key employees may be granted PSUs and time-based RSUs annually. Each PSU and RSU granted prior to 2024 is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. Each PSU and RSU granted in 2024 and thereafter is valued based on one share of Fortis common stock traded on the New York Stock Exchange. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur.
 The following table represents PSUs and RSUs awarded by UNS Energy:
 2024
 2023
 2022

 PSUs (1)

 4,660
 58,237
 40,793

 RSUs (1)

 2,327
 2,146
 2,409

 (1) Effective January 2024, certain executive management PSU and RSU awards are issued through the 2024 Omnibus Plan. Certain key employees will continue to be awarded PSUs and RSUs through the 2015 Plan.
 The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $ 5 million and $ 6 million as of December 31, 2024 and 2023, respectively.
 TEP's allocated portion of compensation expense is recognized in Operations and Maintenance expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date. TEP recorded $ 2 million in 2024, $ 3 million in 2023, and $ 2 million in 2022 based on its share of UNS Energy's compensation expense.

 NOTE 12. SUPPLEMENTAL CASH FLOW INFORMATION
 CASH TRANSACTIONS

 2024
 2023
 2022

 Interest Paid, Net of Amounts Capitalized
 $
 $
 $

 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:

 2024
 2023
 2022

 Accrued Capital Expenditures (1)

 $
 $
 $

 Asset Retirement Obligations Increase (Decrease) (2)

 ( 5)
 ( 30)

 Renewable Energy Credits

 Net Cost of Removal Increase (Decrease) (3)

 ( 10)
 ( 49)

 (1)In 2024, primarily represents accrued capital expenditures related to Roadrunner Reserve I.
 (2)In 2024, increase is primarily related to revised decommissioning estimates at Springerville. In 2022, decrease is primarily related to the retirement of the San Juan asset retirement cost asset, which was retired concurrently with San Juan Unit 1 in June 2022.
 (3)Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset.

 NOTE 13. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
 TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.
 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

 Assets

 Restricted Cash (1)

 $
 $
 —
 $

 Energy Derivative Contracts, Regulatory Recovery (2)

 —

 Energy Derivative Contracts, No Regulatory Recovery (2)

 —

 Total Assets

 Liabilities

 Energy Derivative Contracts, Regulatory Recovery (2)

 —
 ( 31)
 ( 31)

 Energy Derivative Contracts, No Regulatory Recovery (2)

 —
 ( 1)
 ( 1)

 Total Liabilities
 —
 ( 32)
 ( 32)

 Total Assets (Liabilities), Net
 $
 $
 $

 December 31, 2023

 Assets

 Restricted Cash (1)

 $
 $
 —
 $

 Energy Derivative Contracts, Regulatory Recovery (2)

 —

 Energy Derivative Contracts, No Regulatory Recovery (2)

 —

 Total Assets

 Liabilities

 Energy Derivative Contracts, Regulatory Recovery (2)

 —
 ( 30)
 ( 30)

 Total Liabilities
 —
 ( 30)
 ( 30)

 Total Assets (Liabilities), Net
 $
 $
 $

 (1)Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Consolidated Balance Sheets.
 (2)Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the 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
 Net Amount

 Counterparty Netting of Energy Contracts
 Cash Collateral Received/Posted (1)

 Derivative Assets

 Energy Derivative Contracts
 $
 $
 $
 —
 $

 Derivative Liabilities

 Energy Derivative Contracts
 ( 32)
 ( 17)
 —
 ( 15)

 December 31, 2023

 Derivative Assets

 Energy Derivative Contracts
 $
 $
 $
 —
 $

 Derivative Liabilities

 Energy Derivative Contracts
 ( 30)
 ( 15)
 —
 ( 15)

 (1)TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Consolidated Balance Sheets. As of February 13, 2025, TEP had no cash held or posted as collateral to provide credit enhancement.
 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:

 2024
 2023 (1)

 2022 (2)

 Unrealized Net Gain (Loss)
 $
 $
 ( 81)
 $

 (1)Unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas.
 (2)Unrealized net gain on regulatory recoverable derivative contracts was primarily due to increases in forward market prices of natural gas.
 Energy Derivative Contracts, No Regulatory Recovery
 TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition 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 Consolidated Statements of Income:

 2024
 2023
 2022

 Operating Revenues
 $
 $
 $

 Derivative Volumes
 As of December 31, 2024, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:

 2024
 2023

 Power Contracts GWh
 1,634
 1,449

 Gas Contracts BBtu
 86,070
 89,105

 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 and non-derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $ 30 million as of December 31, 2024, compared with $ 28 million as of December 31, 2023. TEP had no cash posted as collateral to provide credit enhancement as of December 31, 2024 and 2023. TEP would have been required to post $ 30 million and $ 28 million of collateral if the credit risk contingent features had been triggered on December 31, 2024, and December 31, 2023, respectively. TEP had $ 15 million and $ 13 million in outstanding net payable balances for settled positions as of December 31, 2024, and December 31, 2023, 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:
 Net Carrying Value
 Fair Value

 Fair Value Hierarchy

 2024
 2023
 2024
 2023

 Liabilities

 Long-Term Debt, including Current Maturities
 Level 2
 $
 2,495
 $
 2,397
 $
 2,153
 $
 2,127

 NOTE 14. INCOME TAXES
 Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% to pre-tax income due to the following:

 2024
 2023
 2022

 Federal Income Tax Expense at Statutory Rate
 $
 $
 $

 State Income Tax Expense, Net of Federal Deduction

 Federal/State Tax Credits (1)

 ( 24)
 ( 17)
 ( 22)

 Allowance for Equity Funds Used During Construction
 ( 5)
 ( 3)
 ( 1)

 Excess Deferred Income Taxes
 ( 11)
 ( 8)
 ( 10)

 Other
 —

 Total Income Tax Expense
 $
 $
 $

 (1) TEP realized PTC benefits of $ 21 million in 2024, $ 15 million in 2023, and $ 19 million in 2022, related to Oso Grande.

 Income Tax Expense included on the Consolidated Statements of Income consists of the following:

 2024
 2023
 2022

 Current Income Tax Expense

 Federal
 $
 $
 $
 ( 1)

 State
 —

 Total Current Income Tax Expense
 ( 1)

 Deferred Income Tax Expense

 Federal

 Federal Investment Tax Credits
 ( 2)
 ( 2)
 ( 1)

 State

 Total Deferred Income Tax Expense

 Total Income Tax Expense
 $
 $
 $

 Changes in TEP's EDIT amortization are shared through the TEAM. The EDIT activity of $ 11 million, $ 8 million, and $ 10 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2024, 2023, and 2022, respectively.
 The significant components of deferred income tax assets and liabilities consist of the following:

 2024
 2023

 Gross Deferred Income Tax Assets

 Customer Advances and Contributions in Aid of Construction
 $
 $

 Federal General Business Credits (1)

 Income Taxes Payable Through Future Rates

 Other

 Total Gross Deferred Income Tax Assets

 Gross Deferred Income Tax Liabilities

 Plant, Net
 ( 843)
 ( 793)

 Pensions
 ( 20)
 ( 21)

 Income Taxes Recoverable Through Future Rates
 ( 1)
 ( 1)

 Other
 ( 50)
 ( 62)

 Total Gross Deferred Income Tax Liabilities
 ( 914)
 ( 877)

 Deferred Income Taxes, Net
 $
 ( 700)
 $
 ( 648)

 (1)Includes ITC and PTC carryovers.
 TEP recorded no valuation allowance against tax credit carryforward deferred income tax assets as of December 31, 2024 and 2023. Management believes TEP will produce sufficient taxable income in the future to realize credit carryforwards before they expire.
 As of December 31, 2024, TEP had the following carryforward amounts:
 Amount
 Expiring Year

 State Credits
 $
 2027 - 29

 Federal Production Tax Credits
 2042 - 44

 TEP recorded no interest expense in 2024 and 2023 related to uncertain tax positions. In addition, TEP had no interest payable, and no penalties accrued as of December 31, 2024 and 2023.
 TEP has been audited by the IRS through tax year 2010. TEP's 2014 to 2023 tax years are open for audit by federal and state tax agencies.

 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

 Included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets are current income taxes receivable and payable that are due from and to affiliates, respectively. TEP had no intercompany income taxes receivable or payable as of December 31, 2024 and 2023.

 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 None.

 ITEM 9A. CONTROLS AND PROCEDURES
 Evaluation of Disclosure Controls and Procedures
 TEP's Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP's evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP's periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP's Chief Executive Officer and Chief Financial Officer concluded that TEP's disclosure controls and procedures were effective as of December 31, 2024.
 Management's Report on Internal Control Over Financial Reporting
 TEP's management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 Management assessed the effectiveness of TEP's internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations Internal Control – Integrated Framework.
 Based on management's assessment using those criteria, management has concluded that, as of December 31, 2024, TEP's internal control over financial reporting was effective.
 Changes in Internal Control Over Financial Reporting
 There has been no change in TEP's internal control over financial reporting during the fourth quarter of 2024 that has materially affected, or is reasonably likely to materially affect, TEP's internal control over financial reporting.

 ITEM 9B. OTHER INFORMATION
 None.

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
 Not applicable.

 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

 ITEM 11. EXECUTIVE COMPENSATION
 Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
 Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) of Form 10-K.

 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
 Pre-Approved Policies and Procedures
 Rules adopted by the SEC in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. UNS Energy's Audit and Risk Committee has adopted a policy pursuant to which audit, audit-related, tax, and other services are pre-approved by category of service. Recognizing that situations may arise where it is in the Company's best interest for the auditor to perform services in addition to the annual audit of the Company's financial statements, the policy sets forth guidelines and procedures with respect to approval of the four categories of service designed to achieve the continued independence of the auditor when it is retained to perform such services for UNS Energy. The policy requires the Audit and Risk Committee to be informed of each service and does not include any delegation of the Audit and Risk Committee's responsibilities to management. The Audit and Risk Committee may delegate to the Chair of the Audit and Risk Committee the authority to grant pre-approvals of audit and non-audit services requiring Audit and Risk Committee approval where the Audit and Risk Committee Chair believes it is desirable to pre-approve such services prior to the next regularly scheduled Audit and Risk Committee meeting. The decisions of the Audit and Risk Committee Chair to pre-approve any such services from one regularly scheduled Audit Committee meeting to the next shall be reported to the Audit and Risk Committee.
 Fees
 The Audit and Risk Committee has considered whether the provision of services to TEP by Deloitte & Touche LLP, Public Company Accounting Oversight Board (United States) PCAOB ID No. 34 (Deloitte), beyond those rendered in connection with their audit and review of TEP's financial statements, is compatible with maintaining their independence as auditor.
 The following table details principal accountant fees paid to Deloitte for professional services:
 (in thousands)
 2024
 2023

 Audit Fees (1)

 $
 1,346
 $
 1,170

 Audit-Related Fees (2)

 Total
 $
 1,459
 $
 1,276

 (1)Audit Fees includes fees billed, or expected to be billed, by Deloitte, for professional services for the financial statement audits of TEP's consolidated financial statements included in its Annual Report on Form 10-K and review services of TEP's consolidated

 financial statements included in its Quarterly Reports on Form 10-Q. Audit Fees also includes services provided by Deloitte in connection with consents, and other services related to SEC matters, financing transactions, and statutory and regulatory audits.
 (2)Audit-Related Fees are fees billed, or expected to be billed, by Deloitte for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above. The fees are for additional procedures for nonrecurring material transactions, including comfort letters.
 All services performed by our principal accountant are approved in advance by the Audit and Risk Committee in accordance with the Audit and Risk Committee's pre-approval policy for services provided by the Independent Registered Public Accounting Firm.

 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 Page

 (a)
 (1)
 Consolidated Financial Statements as of December 31, 2024 and 2023, and for each of the three years in the period ended December 31, 2024:

 Report of Independent Registered Public Accounting Firm

 Consolidated Statements of Income

 Consolidated Statements of Cash Flows

 Consolidated Balance Sheets

 Consolidated Statement of Changes in Stockholder's Equity

 Notes to Consolidated Financial Statements

 (2)
 Financial Statement Schedule

 All schedules have been omitted because they are either not applicable, not required, or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.

 (3)
 Exhibits

 Reference is made to the Exhibit Index commencing on page 82.

 ITEM 16. FORM 10-K SUMMARY
 Not Applicable.

 Exhibit Index

 Exhibit No.
 Description

 3(a)

 Restated Articles of Incorporation of TEP, filed with the ACC on August 11, 1994, as amended by Amendment to Article Fourth of our Restated Articles of Incorporation, filed with the ACC on May 17, 1996. (Form 10-K for the year ended December 31, 1996, File No. 1-05924 - Exhibit No 3(a)).

 3(a)(1)

 TEP Articles of Amendment filed with the ACC on September 3, 2009 (Form 10-K for the year ended December 31, 2010, File No. 1-05924 - Exhibit 3(a)).

 3(b)

 Bylaws of TEP, as amended as of August 12, 2015 (Form 10-Q for the quarter ended September 30, 2015, File No. 1-05924 - Exhibit 3).

 3(c)

 Amendment to Articles of Incorporation of UNS Energy Corporation, creating series of Limited Voting Junior Preferred Stock (Form 8-K dated August 12, 2015, File No. 1-05924 - Exhibit 3.2).

 4(a)(1)

 Indenture, dated November 1, 2011, between Tucson Electric Power Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as trustee, authorizing unsecured Notes (Form 8-K dated November 8, 2011, File 1-05924 - Exhibit 4.1).

 4(a)(2)

 Supplemental Indenture No. 1, dated May 1, 2022, between Tucson Electric Power Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as trustee, authorizing unsecured Notes (Form S-3 dated May 5, 2022, File No. 333-264708 - Exhibit 4(c)(2)).

 4(a)(3)

 Officer's Certificate, dated March 10, 2014, establishing the terms of the 5.00% Senior Notes due 2044 (Form 8-K dated March 10, 2014, File No. 1-05924 - Exhibit 4.1).

 4(a)(4)

 Officer's Certificate, dated November 29, 2018, establishing the terms of the 4.85% Senior Notes due 2048 (Form 10-K for the year ended December 31, 2018, File No. 1-05924 - Exhibit 4(g)(6)).

 4(a)(5)

 Officer's Certificate, dated April 9, 2020, establishing the terms of the 4.00% Senior Notes due 2050 (Form 8-K dated April 9, 2020, File No. 1-05924 - Exhibit 4.1).

 4(a)(6)

 Officer's Certificate, dated August 10, 2020, establishing the terms of the 1.50% Senior Notes due 2030 (Form 8-K dated August 10, 2020, File No. 1-05924 - Exhibit 4.1).

 4(a)(7)

 Officer's Certificate, dated May 11, 2021, establishing the terms of the 3.25% Senior Notes due 2051 (Form 8-K dated May 11, 2021, File No. 1-05924 - Exhibit 4.1).

 4(a)(8)

 Officer's Certificate, dated February 17, 2022, establishing the terms of the 3.25% Senior Notes due 2032 (Form 8-K dated February 17, 2022, File No. 1-05924 - Exhibit 4.1).

 4(a)(9)

 Officer's Certificate, dated February 16, 2023, establishing the terms of the 5.50% Senior Notes due 2053 (Form 8-K dated February 16, 2023, File No. 1-05924 – Exhibit 4.1).

 4(a)(10)

 Officer's Certificate, dated August 9, 2024, establishing the terms of the 5.20% Senior Notes due 2034 (Form 8-K dated August 9, 2024, File No. 1-05924 – Exhibit 4.1).

 4(b)(1)

 Credit Agreement, dated as of October 15, 2021, among Tucson Electric Power Company, MUFG Union Bank, N.A. as Administrative Agent, and a group of lenders (Form 8-K dated October 15, 2021, File No. 1-05924 - Exhibit 4.1).

 4(b)(2)

 Amendment No. 1 to Amended and Restated Credit Agreement, dated as of June 8, 2023, by and among Tucson Electric Power Company, as Borrower, the Lenders party thereto and MUFG Bank, Ltd. (as successor by assignment from MUFG Union Bank, N.A.), as Administrative Agent (Form 10-Q for the quarter ended June 30, 2023, File No. 1-50924 - Exhibit 4.1).

 * 23

 Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm.

 * 24

 Power of Attorney.

 * 31(a)

 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Susan M. Gray.

 * 31(b)

 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by J. Caleb Adcock.

 **32

 Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).

 101.INS

 101.SCH

 101.CAL

 101.LAB

 101.PRE

 101.DEF

 *
 Filed herewith.

 **
 Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

 SIGNATURES
 Pursuant to the requirements of section 13 or 15(b) 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.

 (Registrant)

 Date:
 /s/ J. Caleb Adcock

 J. Caleb Adcock

 Chief Financial Officer and Vice President

 (Principal Financial Officer and Principal Accounting Officer)

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 Date:
 *

 Susan M. Gray

 President, Chief Executive Officer, and Director

 (Principal Executive Officer)

 Date:
 *

 Todd C. Hixon

 Director

 Date:
 *

 Frank P. Marino

 Director

 *By:
 /s/ J. Caleb Adcock

 J. Caleb Adcock

 Attorney-in-fact