Tucson Electric Power Co.
02/12/2026 | Press release | Distributed by Public on 02/12/2026 05:20
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
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 primarily discusses 2025 and 2024 items and year-to-year comparisons between these years. Discussions of 2023 activity and year-to-year comparisons between 2024 and 2023 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, 2024.
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 to "we," "our," and "us" refer to TEP.
OUTLOOK AND STRATEGIES
Our financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws, regulations, and policies; and (iv) other regulatory and legislative actions, and changes in governmental policies, programs, and priorities, such as energy policy, as well as their impact on the factors listed above. Our plans and strategies include:
•Maintaining affordable rates and reliable service for our customers while promoting economic development within our service territory to enable prosperity in the communities we serve.
•Achieving constructive outcomes in our regulatory proceedings that will provide us more timely cost recovery and an opportunity to earn an appropriate return on our rate base investments.
•Continuing our transition to a less carbon-intensive energy portfolio while complying with regulatory requirements and maintaining financial strength. We have established an aspirational goal of net zero direct GHG emissions by 2050 emphasizing our commitment to decarbonize while preserving customer reliability and affordability. While we still intend to exit all ownership interests in coal-fired generation by 2032, we are reevaluating our interim goal which aimed to reduce carbon emissions by 80% (compared to 2005) by 2035. Our ability to achieve these goals could be impacted by various federal and state energy policies, significant load growth, and the pace of clean-energy technology development.
•Focusing on our core utility business through operational excellence, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
Performance - 2025 Compared with 2024
We reported net income of $283 million in 2025 compared with $289 million in 2024. The decrease of $6 million, or 2%, was primarily due to (net of tax):
•$13 million in higher interest expense primarily due to the issuance of debt in August 2024 and February 2025;
•$11 million in higher base operations and maintenance expenses primarily due to an increase in employee wages and benefits expenses and an increase in outside services expenses; partially offset by lower operation and maintenance expenses at our generation facilities;
•$8 million in higher depreciation expense primarily due to an increase in asset base;
•$6 million in lower margin from wholesale transactions primarily due to unfavorable market conditions resulting in a decrease in revenues from wholesale trading as defined in the PPFAC plan of administration;
•$6 million in lower other service revenue primarily due to lower fees earned for serving as the operator of Springerville Units 3 & 4; and
•$3 million in lower interest income due to lower cash balances in interest-bearing bank accounts in 2025.
The decrease was partially offset by:
•$19 million in higher AFUDC due to an increase in eligible construction expenditures;
•$17 million in higher margin from retail revenue primarily due to an increase in the retail component of our transmission revenue requirement due to a higher rate base and higher LFCR revenue; partially offset by lower usage as a result of milder temperatures moderated by customer growth; and
•$6 million in higher margin from transmission revenue due to an increase in our transmission revenue requirement due to a higher rate base.
FACTORS AFFECTING RESULTS OF OPERATIONS
The most significant factors affecting our current and future results of operations include regulatory matters, generation resource strategy, and sales growth and seasonality.
Regulatory Matters
We are subject to comprehensive regulation. The following discussion describes material regulatory developments, market participation initiatives, and government actions that affect our business.
2025 Rate Case
In June 2025, we filed a general rate case with the ACC based on a test year ended December 31, 2024.
Our key 2025 Rate Case proposals are described below:
•a $172 million net increase in retail revenues comprised of the following components:
◦a non-fuel retail revenue increase of $220 million over test year non-fuel retail revenues,
◦a $26 million decrease in fuel-related retail revenues, and
◦elimination of certain existing adjustor mechanisms, including the DSM surcharge, and, if a new proposed ARAM is approved, the ECA, TEAM, and LFCR mechanism, that results in a $22 million reduction in revenues collected from customers;
•a 7.73% return on original cost rate base of $4.3 billion, which includes a return on equity of 10.50% and an average cost of debt of 4.28%;
•a capital structure for ratemaking purposes of approximately 55% common equity and 45% long-term debt;
•a new ARAMthat is a formula rate adjustor designed to update rates annually based on historical changes in our revenue requirement;
◦if the proposed ARAM is not approved, a new SRB mechanism, which would help recover investments in significant generation resources, and a new LIRA, which would allow us to recover or refund differences between actual limited income tariff costs and the costs included in base rates; and
•a new CEM framework, which will support initiatives to achieve energy savings and load optimization. The framework will replace the existing energy efficiency implementation and transportation electrification plans. If approved, costs would be recovered through a CEM surcharge pending inclusion in the first ARAM adjustment.
We requested new rates to be implemented by September 1, 2026. We cannot predict the timing or outcome of this proceeding.
Roadrunner Reserve I Accounting Order
In April 2025, the ACC issued an accounting order allowing us to defer for future recovery in the 2025 Rate Case certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I, including depreciation and amortization, property taxes, operations and maintenance expense, interest expense, and ITC transaction costs. These costs will be partially offset by benefits associated with ITCs.
ACC Formula Rate Plan Policy
In December 2024, the ACC adopted a formula rate policy statement that provides a framework for regulated utilities to propose a formula rate plan in future rate cases. A formula rate plan, if approved by the ACC, would adjust rates annually based on a predetermined formula. Formula rate plans are expected to improve rate stability for customers, while also reducing regulatory lag and related costs, as well as reducing the reliance on and number of adjustor mechanisms. The Residential Utility Consumer Officer (RUCO) has challenged the ACC's authority to implement this framework through a policy statement, and in November 2025, the Arizona Court of Appeals ruled that the RUCO may proceed with its challenge. We are unable to predict the timing or outcome of these regulatory and legal processes. The ACC has previously approved adjustor mechanisms, including formula-based mechanisms, in rate cases.
Southwest Power Pool Markets+
In November 2024, we and other Arizona utilities announced plans to join Southwest Power Pool Markets+, a day-ahead and real-time wholesale energy market, with anticipated participation as early as 2027. The FERC conditionally approved the Markets+ tariff in January 2025. In April 2025, the FERC accepted the funding agreement signed by us and other participating utilities to support the market's development and implementation. Our participation in Markets+ is expected to (i) reduce our cost to serve customers; (ii) increase access to clean energy resources; and (iii) enhance system reliability.
Renewable Energy and Electric Energy Efficiency Standards Repeal
In January 2024, the ACC opened dockets to review the RES and EE Standards. Under the current RES rules, Arizona regulated electric utilities were required to gradually increase their use of renewable energy until it represented at least 15% of their total annual retail energy sales by the end of 2025, with a portion sourced from customer-sited DG. Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption.
In October 2025, a NOPR recommending the repeal of the RES rules was published in the Arizona Administrative Register. A second NOPR, proposing the repeal of the EE Standards, was also published in October 2025. We are unable to predict the timing or outcome of these rulemaking proceedings.
City of Tucson Energy Sourcing Study
The City of Tucson engaged a consulting and engineering firm to analyze alternatives to our provision of electric service, including a study of a potential municipal electric service utility. While an initial draft of the study, published in April 2025, suggests that a city-owned utility serving primarily Tucson customers could offer potential customer savings, the study also notes that the City of Tucson would assume significant risks and incur substantial costs if it pursued municipalization. These costs would include purchasing property and plant at fair value and separating our remaining electrical grid from the City of Tucson.
Before moving forward, the City of Tucson would need to authorize additional funding for extensive due diligence to demonstrate engineering and economic feasibility. Establishing a municipal electric service utility would ultimately require approval by a majority of the voters of the residents of the City of Tucson in a general or special municipal election. If voters approved municipalization, the City of Tucson would need to exercise its right of eminent domain by filing an action for condemnation in Pima County Superior Court, and any determination in such condemnation proceedings would be subject to appeal. In May 2025, the Tucson City Council voted to accept the study and has not taken further action to pursue municipalization at this time.
Securitization
In May 2025, Arizona's governor signed House Bill 2679, which allows for securitization bond financing by public power utility companies in Arizona. Under the legislation, bonds can be issued by a special purpose entity, the costs of which are payable by the utility company's customers through an irrevocable tariff charged by the utility company upon approval of the tariff by the ACC. The proceeds of such bonds are required to be used to finance the utility company's qualifying costs or investments including the remaining unrecovered book value of its assets retired or planned to be retired. This legislation allows for potentially lower overall financing costs to be recovered from customers than those charged through traditional rates. We do not currently have plans related to securitization bond financing.
Wildfire Mitigation Planning
In May 2025, Arizona's governor signed House Bill 2201 that requires us to submit a wildfire mitigation plan for approval by the Arizona Department of Forestry and Fire Management once every two years beginning in 2026. The plan will outline how we monitor and perform preventive actions to mitigate risk related to utility-caused wildfires. In the event of a wildfire in our service area, House Bill 2201 limits claims made against us if we are determined to be in compliance with our approved wildfire mitigation plan.
Generation Resource Strategy
Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while planning to exit ownership interests in coal-fired generation by 2032. Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply, and land lease contract extensions. Given these uncertainties and the need to economically replace such generation to support anticipated load identified in our 2023 IRP, we plan to convert Springerville Units 1 and 2 from coal-fired generation to natural gas-fired generation by 2030. This conversion allows us to leverage existing infrastructure with the development of replacement energy sources while also furthering our goals of ending our use of coal-fired generation and supporting both customer affordability and reliability. We will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of the conversion of Springerville Units 1 and 2 and our planned exit from Four Corners in 2031.
In 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards an aspirational goal of net zero direct GHG emissions by 2050. In October 2024, the ACC acknowledged our 2023 IRP and found it to be reasonable and in the public interest. Our plan to convert Springerville Units 1 and 2 from coal-fired generation is expected to increase natural gas-fired generation compared to our 2023 IRP. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings.
In 2022, we issued an ASRFP (2022 ASRFP), which allowed for all resource types, including, among others, new wind and solar generation, battery storage, and energy efficiency resources. As a result of our 2022 ASRFP, we entered into:
•an EPC agreement in September 2023 to develop Roadrunner Reserve I. Roadrunner Reserve I is a standalone BESS facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh that was placed in service in July 2025;
•a renewable PPA in January 2024 with 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. 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.
Production Tax Credits
PTCs are federal tax credits earned per-kWh of electricity generated using qualified energy resources for a 10-year period after a qualifying facility is placed in service. In 2021, Oso Grande, a qualifying energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in
taxable earnings. We recorded approximately $17 million and $21 million in PTCs related to Oso Grande in 2025 and 2024, respectively. The PTC rate published by the IRS for wind facilities placed in service prior to 2022 is $0.030 for 2025 and was $0.029 for 2024.
Electricity generated from Oso Grande depends heavily on wind conditions. If actual conditions differ from our estimates, or if operational constraints arise, including insufficient transmission capacity to deliver the electricity, then the project's generation and associated PTCs may vary significantly from prior periods.
Pipeline Expansion Agreement
In September 2025, as part of ongoing efforts to support system reliability and to meet future load growth, we entered into a long-term gas transportation precedent agreement to secure reliable access to natural gas. The agreement supports the development of a new third-party pipeline. Subject to the receipt of required regulatory approvals and other conditions, the pipeline is expected to be in service by late 2029.
Once the pipeline enters commercial operation, we will enter into a gas transportation service agreement with estimated purchase commitments of approximately $1.5 billion over 25 years.
Sales Growth and Seasonality
Our average retail sales growth has remained relatively flat over the past three years. Recently, we have experienced interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet above what is reflected in our 2023 IRP, as well as higher transmission and distribution infrastructure investments.
In addition to the ESA described below, we are analyzing additional requests from existing and potential new large retail customers and cannot predict the quantity or timing of the energy demand, if any, that may result.
Energy Supply Agreement
In 2025, we reached an agreement, subject to contractual contingencies, to serve a data center campus expected to be located in our service territory, requiring potential power demand of approximately 300 MW. In December 2025, the ACC approved the ESA. The ESA provides additional consumer protections such as establishing minimum monthly payment obligations that apply irrespective of customer energy use, authorizing termination fees supported by financial assurance mechanisms, and imposing credit standards designed to mitigate the risk of default. We also reached an agreement with respect to an accompanying construction project to design, engineer, procure, construct, install, and place into service transmission and switchyard facilities to provide retail electric service to the customer. In September 2025, the FERC approved the project construction agreement. The data center campus is projected to be operational as early as 2027, with a ramp schedule through 2029. We currently expect to serve this customer from our existing and planned generation resources.
Following the ACC's approval in December 2025, certain parties, including the Arizona Attorney General and the City of Tucson, contested the ACC's decision to approve the ESA and requested a rehearing by the ACC. The ACC did not respond to these requests and as a result they were deemed denied. The deadline for parties to file formal legal challenges is February 19, 2026. We cannot predict the timing or outcome of these proceedings.
Weather Patterns
Changing weather patterns and other factors cause seasonal fluctuations in power sales. Our retail sales are highest in the second and third quarters of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year, due to mild winter weather in our retail service territory. Our operating costs are generally consistent throughout the year, which produces higher operating income in the second and third quarters and lower operating income in the first and fourth quarters.
Interest Rates
See Part II, Item 7A. 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 2025 compared to 2024 presented on a pre-tax basis.
Operating Revenues
The following table provides a disaggregation of Operating Revenues:
| Years Ended December 31, | Increase (Decrease) | Year Ended December 31, | Increase (Decrease) | ||||||||||||||||||||||||||
| (in millions) | 2025 | 2024 | Percent | 2023 | Percent | ||||||||||||||||||||||||
| Operating Revenues | |||||||||||||||||||||||||||||
| Retail | $ | 1,250 | $ | 1,321 | (5.4) | % | $ | 1,283 | 3.0 | % | |||||||||||||||||||
| Wholesale, Long-Term | 60 | 57 | 5.3 | % | 76 | (25.0) | % | ||||||||||||||||||||||
|
Wholesale, Short-Term (1)
|
139 | 186 | (25.3) | % | 253 | (26.5) | % | ||||||||||||||||||||||
| Transmission | 61 | 55 | 10.9 | % | 56 | (1.8) | % | ||||||||||||||||||||||
| Springerville Units 3 and 4 Participant Billings | 89 | 106 | (16.0) | % | 111 | (4.5) | % | ||||||||||||||||||||||
| Other | 90 | 80 | 12.5 | % | 96 | (16.7) | % | ||||||||||||||||||||||
| Total Operating Revenues | $ | 1,689 | $ | 1,805 | (6.4) | % | $ | 1,875 | (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 $1,689 million in 2025 compared with $1,805 million in 2024. The decrease of $116 million, or 6%, was primarily due to:
•$71 million in lower retail revenue primarily due to lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate and lower usage as a result of milder temperatures moderated by customer growth; partially offset by an increase in the retail component of our transmission revenue requirement due to a higher rate base;
•$47 million in lower short-term wholesale revenue primarily due to a decrease in volume and price, and a decrease in revenue from wholesale trading as defined in the PPFAC plan of administration due to unfavorable market conditions; and
•$17 million in lower Springerville Unit 4 participant billings primarily due to higher reimbursable planned outage costs in 2024 and lower fees earned for serving as the operator of Springerville Units 3 and 4 in 2025.
The decrease was partially offset by:
•$10 million in higher other revenue primarily due to higher LFCR revenues; and
•$6 million in higher transmission revenue due to an increase in our transmission revenue requirement due to a higher rate base.
The following table provides key statistics impacting Operating Revenues:
| Years Ended December 31, | Increase (Decrease) | Year Ended December 31, | Increase (Decrease) | ||||||||||||||||||||||||||
| (kWh in millions) | 2025 | 2024 | Percent | 2023 | Percent | ||||||||||||||||||||||||
|
Electric Sales (kWh) (1)
|
|||||||||||||||||||||||||||||
|
Retail Sales
|
8,933 | 8,964 | (0.3) | % | 8,954 | 0.1 | % | ||||||||||||||||||||||
| Wholesale, Long-Term | 914 | 940 | (2.8) | % | 1,314 | (28.5) | % | ||||||||||||||||||||||
| Wholesale, Short-Term | 4,072 | 5,061 | (19.5) | % | 4,486 | 12.8 | % | ||||||||||||||||||||||
| Total Electric Sales | 13,919 | 14,965 | (7.0) | % | 14,754 | 1.4 | % | ||||||||||||||||||||||
|
Average Revenue(cents per kWh) (2)
|
|||||||||||||||||||||||||||||
| Retail | 13.99 | 14.74 | (5.1) | % | 14.33 | 2.9 | % | ||||||||||||||||||||||
| Wholesale, Long Term | 6.54 | 6.09 | 7.4 | % | 5.79 | 5.2 | % | ||||||||||||||||||||||
| Wholesale, Short-Term | 2.93 | 3.12 | (6.1) | % | 5.23 | (40.3) | % | ||||||||||||||||||||||
|
Total Retail Customers (3)
|
456,903 | 451,937 | 1.1 | % | 446,762 | 1.2 | % | ||||||||||||||||||||||
(1)These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.
(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
(3)This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining and non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.
Operating Expenses
Fuel and Purchased Power Expense
We reported Fuel and Purchased Power expense of $516 million in 2025 compared with $633 million in 2024. The decrease of $117 million, or 18%, was primarily due to lower PPFAC Recovery Treatment primarily due to a decrease in PPFAC recoveries and an increase in PPFAC eligible costs deferred as a regulatory asset for future recovery.
The following table provides key statistics impacting Fuel and Purchased Power:
| Years Ended December 31, | Increase (Decrease) | Year Ended December 31, | Increase (Decrease) | ||||||||||||||||||||||||||
| (kWh in millions) | 2025 | 2024 | Percent | 2023 | Percent | ||||||||||||||||||||||||
| Sources of Energy | |||||||||||||||||||||||||||||
| Coal-Fired Generation | 2,974 | 3,054 | (2.6) | % | 3,688 | (17.2) | % | ||||||||||||||||||||||
| Gas-Fired Generation | 7,705 | 8,679 | (11.2) | % | 7,336 | 18.3 | % | ||||||||||||||||||||||
| Utility-Owned Renewable Generation | 660 | 821 | (19.6) | % | 654 | 25.5 | % | ||||||||||||||||||||||
| Total Generation | 11,339 | 12,554 | (9.7) | % | 11,678 | 7.5 | % | ||||||||||||||||||||||
| Purchased Power | 3,135 | 2,938 | 6.7 | % | 3,630 | (19.1) | % | ||||||||||||||||||||||
|
Total Generation and Purchased Power (1)
|
14,474 | 15,492 | (6.6) | % | 15,308 | 1.2 | % | ||||||||||||||||||||||
| (cents per kWh) | |||||||||||||||||||||||||||||
| Average Cost of Generated and Purchased Power | |||||||||||||||||||||||||||||
|
Coal (2)(3)
|
4.46 | 4.51 | (1.1) | % | 3.17 | 42.3 | % | ||||||||||||||||||||||
|
Natural Gas (2)(4)
|
2.60 | 2.20 | 18.2 | % | 3.27 | (32.7) | % | ||||||||||||||||||||||
|
Purchased Power (5)
|
4.16 | 4.41 | (5.7) | % | 6.11 | (27.8) | % | ||||||||||||||||||||||
(1)This number represents the kWh generated from our generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.
(2)These metrics represent the fuel cost as cents per kWh for coal and natural gas generated power. These numbers are calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses these metrics to monitor rates and pricing as well as analyze the performance of generation facilities.
(3)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 purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh). Management uses this metric to compare and monitor the costs of purchased power.
Operations and Maintenance Expense
We reported Operations and Maintenance expense of $449 million in 2025 compared with $447 million in 2024. The increase of $2 million, or less than 1%, was primarily due to:
•$11 million increase in employee wages and benefits expenses; and
•$5 million in higher outside services expenses.
The increase was partially offset by:
•$10 million in lower reimbursable maintenance expense related to Springerville Unit 4 primarily due to higher planned outage costs in 2024; and
•$4 million in lower operations and maintenance expenses at our generation facilities.
Depreciation and Amortization Expense
We reported Depreciation and Amortization expense of $266 million in 2025 compared with $257 million in 2024. The increase of $9 million, or 4%, was primarily due to an increase in asset base.
Other Income (Expense)
We reported Other Expense of $56 million in 2025 compared with $63 million in 2024. The decrease of $7 million, or 11%, was primarily due to $22 million in higher AFUDC due to an increase in eligible construction expenditures.
The decrease was partially offset by:
•$15 million in higher interest expense due to the issuance of debt in August 2024 and February 2025; and
•$3 million in lower interest income due to lower cash balances in interest-bearing bank accounts in 2025.
Income Tax Expense
We reported Income Tax Expense of $45 million in 2025 compared with $44 million in 2024. The increase of $1 million, or 2%, was primarily due to $4 million in lower tax credits related to Oso Grande PTCs; partially offset by $3 million in lower tax expense due to higher AFUDC equity due to an increase in eligible construction expenditures.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Any extended period of economic disruption could affect our business, financial condition, and access to sources of liquidity. Cash flows vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to our summer peaking load. We face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. We use our revolving credit as needed to fund our business activities. We believe that we have sufficient liquidity under the 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.
Available Liquidity
| (in millions) | December 31, 2025 | ||||
| Cash and Cash Equivalents | $ | 26 | |||
|
Amount Available under Revolving Credit Agreement (1)
|
236 | ||||
| Total Liquidity | $ | 262 | |||
(1)The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively. In October 2025, the maturity date was extended one year to October 2028. 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 7 and Note 8 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) | ||||||||||||||||||||||||||
| (in millions) | 2025 | 2024 | Percent | 2023 | Percent | ||||||||||||||||||||||||
|
Operating Activities (1)
|
$ | 590 | $ | 663 | (11.0) | % | $ | 560 | 18.4 | % | |||||||||||||||||||
|
Investing Activities (1)
|
(872) | (788) | 10.7 | % | (633) | 24.5 | % | ||||||||||||||||||||||
|
Financing Activities (1)
|
289 | 131 | 120.6 | % | 65 | 101.5 | % | ||||||||||||||||||||||
| Net Increase (Decrease) | 7 | 6 | * | (8) | * | ||||||||||||||||||||||||
| Beginning of Period | 49 | 43 | 14.0 | % | 51 | (15.7) | % | ||||||||||||||||||||||
| End of Period | $ | 56 | $ | 49 | 14.3 | % | $ | 43 | 14.0 | % | |||||||||||||||||||
* Notmeaningful
(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 decreased by $73 million in 2025 compared with 2024 primarily due to lower PPFAC recoveries in 2025; partially offset by the receipt of proceeds from the sale of investment tax credits.
Investing Activities
Net cash flows used for investing activities increased by $84 million in 2025 compared with 2024 primarily due to an increase in cash paid for capital expenditures.
Financing Activities
Net cash flows provided by financing activities increased by $158 million in 2025 compared with 2024 primarily due to: (i) the redemption of long-term debt in 2024; (ii) dividends paid to UNS Energy in 2024, with no dividends paid to UNS Energy in 2025; and (iii) an increase in equity contributions from UNS Energy; partially offset by: (i) higher repayments of credit facility borrowings, net of proceeds; and (ii) lower proceeds from debt issuance.
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, 2025, we had no short-term investments.
Access to Credit
We have access to working capital through our credit agreement with lenders. Amounts borrowed from the 2021 Credit Agreement are used for working capital and other general corporate purposes. LOCs may be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of December 31, 2025, there was $236 million available under the 2021 Credit Agreement, which reflects no outstanding revolver borrowings and LOCs totaling $14 million issued with fees that accrue at a rate of 1.050% per annum.
See Note 7 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 March 2025, we filed with the SEC an automatic shelf registration statement on Form S-3 which expires in March 2028. In October 2025, the ACC issued an order granting us financing authority which took effect on January 1, 2026. The order provides authority through December 2030 for: (i) a maximum amount of outstanding long-term debt not to exceed $4.5 billion; (ii) parent equity contributions of up to $1.7 billion provided that no such equity infusion results in an increase to the equity portion of our capital structure of more than 50 basis points above the level approved in our rate order in effect at the time of the contribution; and (iii) credit facilities not to exceed $350 million in the aggregate.
We have, from time to time, refinanced or repurchased portions of our outstanding debt before scheduled maturity. Depending on market conditions, we may refinance or repurchase additional outstanding debt before its scheduled maturity.
In February 2025, we issued and sold $300 million aggregate principal amount of 5.90% senior unsecured notes due April 2055. We used the net proceeds to repay debt and for general corporate purposes.
We anticipate incurring debt in 2026.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of December 31, 2025, credit ratings from S&P Global Ratings and Moody's Investors Service for our senior unsecured debt were A- (stable) and A3 (stable), respectively.
Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold our securities. Each rating should be evaluated independently of any other ratings.
The 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, 2025, we were in compliance with these covenants.
We do not have any provisions in any of our debt agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
Contributions from Parent
We received equity contributions from UNS Energy of $65 million in 2025 and $50 million in 2024.
Dividends Declared and Paid to Parent
We did not declare or pay dividends to UNS Energy in 2025. We declared and paid $85 million in dividends to UNS Energy in 2024.
Master Trading Agreements
We conduct our wholesale marketing and risk management activities under certain master trading agreements. These agreements may require us to post credit enhancements in the form of cash or LOCs if our exposures exceed unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of December 31, 2025, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.
Capital Expenditures
Our routine capital expenditures support customer growth, system reinforcement, replacements and betterments, and compliance with environmental rules and regulations. In 2025, total capital expenditures of $828 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 II. 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.
Our forecasted capital expenditures presented below exclude amounts for AFUDC equity and other non-cash items:
| Years Ended December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2026 | 2027 | 2028 | 2029 | 2030 | ||||||||||||||||||||||||
| Generation Facilities: | |||||||||||||||||||||||||||||
|
New Energy Resources (1)
|
$ | 6 | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||
|
Other Generation Facilities (2)
|
90 | 62 | 97 | 120 | 346 | ||||||||||||||||||||||||
| Total Generation Facilities | 96 | 62 | 97 | 120 | 346 | ||||||||||||||||||||||||
|
Transmission and Distribution (3)
|
447 | 358 | 322 | 716 | 228 | ||||||||||||||||||||||||
|
General and Other (4)
|
98 | 73 | 75 | 90 | 71 | ||||||||||||||||||||||||
| Total Capital Expenditures | $ | 641 | $ | 493 | $ | 494 | $ | 926 | $ | 645 | |||||||||||||||||||
(1)Includes investments in renewable energy and Roadrunner Reserve II in alignment with our long-term strategy of transitioning to a less carbon-intensive energy portfolio.
(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 vary due to fluctuations in business and market conditions, including inflationary pressures, tariffs, construction schedules, supply chain constraints, labor shortages and/or labor strikes, potential early plant closures, shifts in generation resources, any changes to governmental programs, such as loans, grants, guarantees, and other subsidies, evolving environmental requirements, local, state or federal regulations and policies, and other factors. We continue to monitor government trade policies, particularly those related to tariffs, and assess their potential impact on our capital projects. Although there has been no material effect on our operations or financial performance in 2025, future increases in tariffs or related supply chain disruptions could significantly raise costs if mitigation efforts are unsuccessful. We expect to fund forecasted capital expenditures through a combination of internally generated cash and external financing, which may include long-term debt issuances, other borrowings, or equity contributions.
Roadrunner Reserve II
In August 2024, we entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. In 2025, change orders were issued that increased costs by $34 million, bringing the total EPC cost to $302 million. The facility is expected to be placed in service in 2026. As of December 31, 2025, total cost of construction incurred from inception was $302 million. The project costs incurred to date are recorded in Construction Work in Progress on the Consolidated Balance Sheets.
See Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the EPC agreement.
Income Tax Position
Tax Sharing Agreement
Under the terms of the tax sharing agreement with UNS Energy, we made $4 million in net tax sharing payments in 2025 and $13 million in 2024. Future cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.
Investment Tax Credits
Standalone battery storage systems that began construction before January 29, 2023, may qualify for a base federal tax credit equal to 30% of the eligible costs of the facility. Roadrunner Reserve I has qualified for the base federal tax credit. Based on current eligibility criteria, we anticipate Roadrunner Reserve II will also qualify. See Note 1 and Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for information related to the ITCs generated by Roadrunner Reserve I. The IRA provides an election to transfer (i.e., sell) some or all of certain tax credits generated by a qualifying facility to unrelated third parties in exchange for cash. Transfer elections must be made on a facility-by-facility and year-by-year basis. Any election to transfer tax credits must be made and cash must be received on or before the due date of the tax return for the year the facility is placed in service. Roadrunner Reserve I was placed in service in July 2025, and Roadrunner
Reserve II is expected to be placed in service in 2026. In December 2025, TEP received $46 million in cash proceeds for the sale of ITCs related to Roadrunner Reserve I.
One Big Beautiful Bill Act
In July 2025, the OBBBA was signed into law extending several expiring provisions of the 2017 Tax Cuts and Jobs Act and introducing additional business tax provisions. The OBBBA also accelerates the phase out of, and adds various restrictions to, the availability and use of PTCs and ITCs applicable to certain facilities per provisions generally enacted or extended as part of the IRA. The OBBBA did not have a material impact on TEP's financial position, results of operations, or cash flows.
Environmental Matters
The EPA has the authority to regulate emissions of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced from generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs.
We capitalized $2 million in 2025 and $3 million in 2024 in costs incurred 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 2025 and 2024. We expect environmental compliance related capital expenditures of $1 million in each year from 2026 through 2029 and $2 million in 2030. We will request and expect recovery of the costs of environmental compliance through Customer Rates and cost recovery mechanisms.
Regional Haze Regulations
The EPA's Regional Haze rule requires certain industrial facilities to reduce emissions that impair visibility in national parks and wilderness areas. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a SIP and must review and submit revisions to the SIP on a periodic basis.
In December 2016, the EPA signed a final rule that, among other things, moved the next deadline for Regional Haze SIP revisions from 2018 to 2021. Following this change, the ADEQ began developing a control strategy to make reasonable progress toward the national visibility goal. In July 2019, the ADEQ notified us that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluations. We conducted the potential emissions controls evaluations, commonly referred to as the four-factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP.
In December 2024, the EPA published a final rule partially approving and partially disapproving the ADEQ's Regional Haze SIP revision. The EPA disapproved the ADEQ's control strategy in the revised SIP, which relies, in part, on the compliance measures for Sundt Unit 3 and Springerville Units 1 and 2. The EPA also disapproved the ADEQ's selection of sources for potential emissions controls evaluations and requested further evaluation of Sundt Unit 4. The disapproval established a two-year deadline for the EPA to promulgate a FIP that contains EPA-required compliance measures for Springerville and Sundt, unless the EPA approves a subsequent SIP submission by the ADEQ curing the SIP deficiencies within that timeframe.
In February 2025, in response to the EPA's December 2024 final rule, TEP and SRP filed a joint Petition for Review with the U.S. Court of Appeals for the Ninth Circuit. In September 2025, the Court granted a motion filed by the Coalition to Protect America's National Parks, the National Parks Conservation Association, and Sierra Club to intervene in the case, which had the effect of taking the case out of abeyance and reinstating a briefing schedule. The petitioners (TEP, SRP, ASARCO, and Phoenix Cement) and respondents (the EPA) jointly filed a motion with the Court asking for the case to be held in abeyance, which the Court granted in December 2025.
In February 2025, TEP and SRP also concurrently filed a joint Petition for Administrative Reconsideration with the EPA. We requested that the EPA reconsider the final rule and act to approve the ADEQ's Regional Haze SIP revision. In July 2025, TEP and SRP filed a supplement to the Petition for Administrative Reconsideration, providing further justification for the EPA to reconsider the final rule, and the EPA granted the request for reconsideration. In October 2025, we filed a modification to the original and supplemental Petition for Administrative Reconsideration providing justification for the EPA's reconsideration with respect to Sundt Unit 3 and Springerville Units 1 and 2.
We cannot predict the outcome of this matter.
Greenhouse Gas Regulation
In May 2024, the EPA published final rules to regulate GHG emissions from two categories of fossil-based EGUs: (i) existing steam units (including coal- and natural gas-fired); and (ii) new natural gas-fired turbines.
The final rules established:
•emission guidelines for existing coal-fired steam EGUs, which are subcategorized based on federally enforceable retirement dates. These emission guidelines affect Springerville Units 1 and 2, as well as Four Corners Units 4 and 5;
•emission guidelines for existing natural gas- and oil-fired steam EGUs aligned with routine methods of operation and maintenance, which are subcategorized based on the annual capacity factor of each unit beginning January 1, 2030. These emission guidelines affect Sundt Units 3 and 4;
•a requirement for states to establish standards of performance that align with the emission guidelines in the form of emission limits. States must submit these standards of performance to the EPA for approval in the form of a state plan, which 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% CCS rate beginning on January 1, 2032.
Various legal challenges to the final rules are pending before the U.S. Court of Appeals for the District of Columbia Circuit. In April 2025, the Court granted the EPA's unopposed motion to hold the case in abeyance indefinitely (following a previous sixty-day stay), while the EPA conducts a rulemaking to reassess the rules. In June 2025, the EPA published a proposed rule containing two co-proposals to address the 2024 final rules. In the primary proposal, the EPA proposed to repeal the 2024 final rules in their entirety based on a determination that fossil-based electric generating units do not contribute significantly to GHG air pollution. In the alternative proposal, the EPA proposed to:
•repeal the Best System of Emission Reductions determinations, presumptive standards of performance, and all related requirements in the emission guidelines for existing long-term and medium-term coal-fired steam EGUs;
•repeal the requirements for existing natural gas- and oil-fired steam EGUs; and
•repeal the phase 2 CCS-based requirements for new base load combustion turbine EGUs.
We cannot predict the outcome of the rulemaking or the legal challenges at this time.
Coal Combustion Residuals Regulation
The EPA published final rules effective October 2015 (2015 CCR Rule) that established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The 2015 CCR Rule provides for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at Springerville. APS, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility. SRP, the operator of Navajo, is completing closure activities at the facility's CCR landfill. No corrective actions to comply with the 2015 CCR Rule have been identified at Springerville or Navajo. With regards to future corrective actions at Four Corners to comply with the 2015 CCR Rule, our share of costs to complete any corrective actions and to gather and perform remedial evaluations on groundwater at Units 4 and 5 is not expected to have a significant impact on our financial position, results of operations, or cash flows.
In May 2024, the EPA published the final Legacy CCR Surface Impoundments Rule that expands the scope of the 2015 CCR Rule to address the impacts from historical CCR management and placement activities that would have ceased prior to 2015. The EPA rule establishes two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCRMUs which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. A CCRMU includes not only historically closed landfills and surface impoundments, but also prior applications of CCR on land, such as for structural fill. The final rule also establishes assessment, groundwater monitoring, closure, and post-closure requirements for legacy CCR impoundments and CCRMUs.
We are analyzing the EPA's final rule for potential impacts to our operations. We anticipate CCRMUs will be identified at Springerville and Four Corners. The number, location, and size of these CCRMUs will be assessed in accordance with the compliance schedule outlined in the EPA's final rule; therefore, associated compliance costs cannot be accurately predicted at this time. SRP tentatively identified CCRMUs at Navajo. Our estimated cost to comply with the EPA's final rule at Navajo is not expected to have a significant impact on our financial position, results of operations, or cash flows. Legal challenges to the final rule are pending before the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this matter.
Good Neighbor Federal Implementation Plan
In September 2018, the ADEQ submitted to the EPA the Arizona SIP Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone NAAQS. In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.
In March 2023, the EPA released its final FIP to address the interstate transport of ozone (Good Neighbor FIP) with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOxemission 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 NOxemission reduction requirements. The EPA must take final action on Arizona's Ozone Transport SIP Revision by February 26, 2026, per consent decree entered in the U.S. District Court for the Northern District of California.
In June 2024, the U.S. Supreme Court granted a stay of the Good Neighbor FIP pending the disposition of the petitions for review of the Good Neighbor FIP currently pending in the U.S. Court of Appeals for the District of Columbia Circuit. In October 2024, the EPA issued an interim final rule administratively staying the effectiveness of the Good Neighbor FIP for all emissions sources subject to the plan as promulgated.
In September 2024, the U.S Court of Appeals for the District of Columbia Circuit Court granted the EPA's request to remand the Good Neighbor FIP rulemaking record and further respond to comments related to the issues addressed in the U.S. Supreme Court's stay. The EPA published its updated response to comments for the Good Neighbor FIP in December 2024.
In March 2025, the EPA filed a motion in the U.S. Court of Appeals for the District of Columbia Circuit indicating it plans to reconsider the Good Neighbor Rule. On January 30, 2026, the EPA published the first proposal of a two-phase plan to revise the interstate transport regulations for the 2015 ozone NAAQS. The EPA proposed to approve SIPs from eight states (including Arizona) based on a determination that emissions from these states do not significantly contribute to nonattainment or interfere with maintenance of the 2015 ozone NAAQS in downwind states. The public comment deadline is March 2, 2026. 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 8of 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, 2025, regulatory liabilities net of regulatory assets in the balance sheet totaled $269 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-Kfor 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. Depreciation rates for our generation, distribution, and general plant assets are approved by the ACC, and depreciation rates for our transmission, general plant, and intangible assets are subject to approval by FERC. The useful lives of plant assets are further detailed in Note 3 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 $358 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 and energy storage assets under the Resource Conservation and Recovery Act. We estimate our ARO related to the PV, energy storage, and wind assets to be approximately $59 million at the retirement dates. We have identified no other legal obligations to retire generation or energy storage 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 Asset Retirement Obligations was $180 million as of December 31, 2025. See Note 3 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, 2025, we discounted our future pension obligations at a rate of 5.8% and our other postretirement benefit obligations at a rate of 5.4%. 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 60thand 90thpercentile 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 sources including 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, 2025, we assumed that our pension plans' assets would generate a long-term rate of return of 7.3%.
Compensation Increases
As of December 31, 2025, 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, 2025.
Healthcare Cost Trend Rates
We used a current year healthcare cost trend rate range between 6.0% and 7.5% in valuing our other postretirement benefit obligation as of December 31, 2025. 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, 2025:
| Effect on Expense | Effect on Obligation | ||||||||||||||||||||||
| (in millions) | Increase | Decrease | Increase | Decrease | |||||||||||||||||||
| Change to Pension | |||||||||||||||||||||||
| Discount Rate | $ | (6) | $ | 8 | $ | (60) | $ | 74 | |||||||||||||||
| Long-Term Rate of Return on Plan Assets | (4) | 4 | N/A | N/A | |||||||||||||||||||
| Change to Other Postretirement Benefits | |||||||||||||||||||||||
| Discount Rate | (1) | 1 | (5) | 6 | |||||||||||||||||||
| Long-Term Rate of Return on Plan Assets | N/A | N/A | |||||||||||||||||||||
| Healthcare Cost Trend Rate | 1 | (1) | 5 | (4) | |||||||||||||||||||
In 2026, we will incur net periodic pension benefit costs of $11 million and net periodic other postretirement benefit costs of $1 million. We expect to record: (i) $14 million to operations and maintenance expense; and (ii) $4 million to capital. In 2026, we expect to make pension plan contributions of $12 million and other postretirement benefit payments of $4 million.
See Note 9 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, 2025, 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.
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