Tucson Electric Power Co.
11/03/2026 | Press release | Distributed by Public on 11/03/2026 07:14
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis explains the results of operations, the financial condition, and the outlook for TEP. It includes the following:
•outlook and strategies;
•factors affecting results of operations;
•results of operations;
•liquidity and capital resources, including capital expenditures, income tax position, and environmental matters;
•critical accounting estimates; and
•new accounting standards issued and not yet adopted.
Management's Discussion and Analysis includes financial information prepared in accordance with GAAP.
Management's Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes in Part I, Item 1 of this Quarterly Report on Form 10-Q. For information on factors that may cause our actual future results to differ from those we currently anticipate, see Forward-Looking Information at the front of this Quarterly Report on Form 10-Q and Risk Factors in Part I, Item 1A of our 2025 Annual Report on Form 10-K, and in Part II, Item 1A of this Quarterly Report on Form 10-Q.
References in Management's Discussion and Analysis to "we," "our," and "us" are to TEP.
OUTLOOK AND STRATEGIES
Our financial performance and outlook are affected by many factors, including: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws, regulations, and policies; and (iv) other regulatory and legislative actions, and changes in governmental policies, programs, and priorities, such as energy policy, as well as their impact on the factors listed above. Our plans and strategies include:
•Maintaining affordable rates and reliable service for our customers while promoting economic development within our service territory to enable prosperity in the communities we serve.
•Achieving constructive outcomes in our regulatory proceedings that will provide us more timely cost recovery and an opportunity to earn an appropriate return on our rate base investments.
•Continuing our transition to a less carbon-intensive energy portfolio while complying with regulatory requirements and maintaining financial strength. We have established an aspirational goal of net zero direct GHG emissions by 2050 emphasizing our commitment to decarbonize while preserving customer reliability and affordability. While we still intend to exit all ownership interests in coal-fired generation by 2032, we will no longer meet our interim goal of reducing carbon emissions by 80% from 2005 levels by 2035 due to changing market conditions. Our ability to achieve net zero direct GHG emissions by 2050 could be impacted by various federal and state energy policies, significant load growth, and the pace of clean-energy technology development.
•Focusing on our core utility business through operational excellence, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
Performance - The third quarter of 2026 compared with the third quarter of 2025
We reported net income of $150 million in the third quarter of 2026 compared with net income of $144 million in the third quarter of 2025. The increase of $6 million, or 4%, was primarily due to (net of tax):
•$9 million in lower income tax expense due to higher amortization of ITCs;
•$4 million in higher margin from other revenue primarily due to the net impact of consenting to the use of certain transmission corridor rights, with the favorable impact expected to be substantially offset by related lower revenues through year-end;
•$3 million in lower base operations and maintenance expenses primarily due to lower employee benefits expenses driven in part by timing;
•$2 million in higher interest income associated with customer prepayments; and
•$2 million in higher margin from transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base.
The increase was partially offset by:
•$9 million in higher depreciation expense primarily due to an increase in asset base;
•$3 million in lower AFUDC due to a decrease in eligible construction expenditures;
•$2 million decrease due to unfavorable market conditions that decreased the value of investments used to support certain post-employment benefits; and
•$1 million in lower margin from retail revenue primarily due to milder weather; partially offset by an increase in industrial sales and customer growth.
Performance - The first nine months of 2026 compared with the first nine months of 2025
We reported net income of $255 million in the first nine months of 2026 compared with net income of $260 million in the first nine months of 2025. The decrease of $5 million, or 2%, was primarily due to (net of tax):
•$17 million in higher depreciation expense primarily due to an increase in asset base;
•$13 million in higher base operations and maintenance expenses primarily due to higher operation and maintenance expenses at our generation facilities, higher outside services expenses, and higher employee wages expenses net of a decrease in employee benefits expense;
•$8 million in lower margin from wholesale transactions primarily due to decreased long-term wholesale sales volumes due to unfavorable market conditions; and
•$4 million in lower AFUDC due to a decrease in eligible construction expenditures.
The decrease was partially offset by:
•$14 million in lower income tax expense due to higher amortization of ITCs;
•$7 million in higher margin from retail revenue primarily due to an increase in industrial sales and customer growth; partially offset by milder weather;
•$6 million in higher margin from other revenue primarily due to the net impact of consenting to the use of certain transmission corridor rights, with the favorable impact expected to be substantially offset by related lower revenues through year-end;
•$4 million in lower non-service components of net periodic benefit cost primarily due to a decrease in interest cost and an increase in expected return on plan assets;
•$3 million in higher margin from transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base; and
•$3 million in higher interest income associated with customer prepayments.
FACTORS AFFECTING RESULTS OF OPERATIONS
The most significant factors affecting our current and future results of operations include regulatory matters, generation resource strategy, and sales growth and seasonality.
Regulatory Matters
We are subject to comprehensive regulation. The following discussion describes material regulatory developments, market participation initiatives, and government actions that affect our business.
2025 Rate Case
In June 2025, we filed a general rate case with the ACC based on a test year ended December 31, 2024.
On October 20, 2026, an ACC ALJ issued a ROO in our 2025 Rate Case. Key recommendations of the ROO include:
•a $114 million net increase in retail revenues comprised of the following components:
◦a non-fuel retail revenue increase of $160 million over test year non-fuel retail revenues,
◦a $26 million decrease in fuel-related retail revenues;
◦an $18 million decrease in retail revenues collected from the discontinuation or modification of certain existing adjustor mechanisms; and
◦a $2 million decrease in retail revenues due to a reduction in service fees;
•a 7.25% return on original cost rate base of $4.3 billion, which includes a return on equity of 9.65% and an average cost of debt of 4.28%;
•a capital structure for ratemaking purposes of approximately 55% common equity and 45% long-term debt;
•a new ARAM that is a formula rate adjustor designed to update rates annually based on historical changes in our revenue requirement. The proposed ARAM includes:
◦an earnings test with a deadband of plus or minus 50 basis points around the allowed return;
◦the inclusion of six months of post-test year plant in the calculation; and
◦annual updates to the cost of debt and capital structure, while maintaining a fixed return on equity;
•an increase to the proportion of realized gains on trading transactions shared with retail customers through the PPFAC mechanism from 10% to 50%; and
•an accounting order to defer for future recovery certain incurred costs associated with owning, operating and maintaining Roadrunner Reserve II, offset by future benefits associated with ITCs.
The ROO also discontinues the TEAM and ECA mechanisms, continues the LFCR mechanism until all lost fixed costs incurred prior to the effective date of the new rates are fully recovered, and continues the DSM surcharge and RES tariff to recover remaining costs associated with the programs. The PPFAC and TCA mechanisms are largely unaffected by the ROO.
The ALJ issued an extension of the time allowed for the ACC to issue a final decision in the rate case, moving the deadline to November 17, 2026, and the ROO proposes new rates to be implemented by December 1, 2026. We cannot predict the 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. As of September 30, 2026, we have deferred $44 million of eligible costs, net of benefits under this accounting order.
ACC Formula Rate Plan Policy
In December 2024, the ACC adopted a formula rate policy statement that provides a framework for regulated utilities to propose a formula rate plan in future rate cases. A formula rate plan, if approved by the ACC, would adjust rates annually based
on a predetermined formula. Formula rate plans are expected to improve rate stability for customers, while also reducing regulatory lag and related costs, as well as reducing the reliance on and number of adjustor mechanisms.
In February 2026, the ACC approved the implementation of an ARAM as part of UNS Gas's rate case, representing the first approval of a formula rate mechanism under the policy. In May 2026, RUCO appealed the ACC's rate case decision, seeking to overturn the approval of UNS Gas's ARAM. The appeal is currently pending before the Arizona Court of Appeals.
Separately, RUCO has challenged the ACC's authority to implement the formula rate framework through a policy statement, and in November 2025, the Arizona Court of Appeals ruled that RUCO may proceed with its challenge. In September 2026, the Superior Court of Maricopa County stayed the proceeding pending resolution of the UNS Gas rate case appeal, and RUCO petitioned the Arizona Supreme Court to block implementation of the formula rate policy. We are unable to predict the timing or outcome of these regulatory and legal processes. The ACC has previously approved adjustor mechanisms, including formula-based mechanisms, in rate cases.
Southwest Power Pool Markets+
In November 2024, we and other Arizona utilities announced plans to join Southwest Power Pool Markets+, a day-ahead and real-time wholesale energy market, with anticipated participation as early as 2027. The FERC conditionally approved the Markets+ tariff in January 2025. In April 2025, the FERC accepted the funding agreement signed by us and other participating utilities to support the market's development and implementation. Our participation in Markets+ is expected to: (i) reduce our cost to serve customers; (ii) increase access to clean energy resources; and (iii) enhance system reliability.
Renewable Energy and Electric Energy Efficiency Standards Repeal
In January 2024, the ACC opened dockets to review the RES and EE Standards. The ACC's RES required Arizona regulated electric utilities to increase their use of renewable energy each year until it represented at least 15% of their total annual retail energy sales by the end of 2025, with a portion sourced from customer-sited DG. Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption.
In March 2026, the ACC issued an order repealing the RES. The order was submitted to the Arizona Attorney General for review, and in May 2026, the Arizona Attorney General provided notice of disapproval of the RES repeal. On October 7, 2026, an ACC ALJ issued a recommended order that would modify the March 2026 order and state that the Arizona Attorney General's approval is not required for the repeal. If approved, the ACC could submit the order repealing the RES directly to the Secretary of State of Arizona. We cannot predict the timing or outcome of this proceeding and are continuing to evaluate the potential impacts on our regulatory obligations and financial position. Until otherwise ordered, we will continue to operate under our existing RES implementation plan.
In July 2026, the ACC issued an order repealing the EE Standards which becomes effective on November 23, 2026. In September 2026, the Arizona Attorney General filed a legal challenge, now pending in the Superior Court of Maricopa County, contesting the order. Until otherwise ordered, we will continue to operate under our existing energy efficiency implementation plan. The DSM surcharge will remain in effect until further order of the ACC. We do not expect the order to have a significant impact on our financial position, results of operations, or cash flows.
City of Tucson Energy Sourcing Study
The City of Tucson engaged a consulting and engineering firm to analyze alternatives to our provision of electric service, including a study of a potential municipal electric utility. An initial draft of the study, published in April 2025, suggested that a city-owned utility serving primarily Tucson customers could offer potential customer savings, but also noted that the City of Tucson would assume significant risks and incur substantial costs if it pursued municipalization. These costs would include purchasing property and plant at fair value and separating our remaining electrical grid from the City of Tucson.
In February 2026, The Brattle Group released an analysis commissioned by us concluding that the establishment of a municipal electric utility would be expected to result in higher energy costs for city residents and businesses.
In March 2026, the Tucson Mayor and City Council rejected a proposal that would have directed city staff to pursue the creation of a municipal electric utility. Instead, the Mayor and Council voted to direct the City's Commission on Climate, Energy, and Sustainability to engage with stakeholders and evaluate that potential option, along with other public power alternatives, to inform future policy considerations.
Energy Collaboration Agreement
In April 2026, the City of Tucson approved an energy collaboration agreement with us that establishes a framework for collaboration on energy reliability, affordability, clean energy, and community resilience. The agreement is contingent upon voter approval of a new franchise agreement at the November 3, 2026 general election. Both the energy collaboration agreement and franchise agreement have 25-year terms. Under the energy collaboration agreement, our annual contributions will begin at $2 million and increase by 2% every year to support agreed-upon initiatives, with payments excluded from recovery through customer rates.
Generation Resource Strategy
Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while planning to exit ownership interests in coal-fired generation by 2032. Our existing coal-fired generation fleet faces a number of uncertainties affecting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply, and land lease contract extensions. Given these uncertainties and the need to economically replace such generation to support anticipated load, we plan to convert Springerville Units 1 and 2 from coal-fired generation to natural gas-fired generation by 2030. This conversion will allow us to leverage existing infrastructure with the development of replacement energy sources while also furthering our goals of ending our use of coal-fired generation and supporting both customer affordability and reliability. We will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of the conversion of Springerville Units 1 and 2 and our planned exit from Four Corners in 2031. In March 2026, the ACC approved an amendment to the facility's Certificate of Environmental Compatibility to permit the conversion of Springerville Units 1 and 2 from coal-fired to natural gas-fired generation. This regulatory approval advances our plans to extend the operational life of the units and support long-term system reliability.
On October 30, 2026, we filed with the ACC our 2026 IRP, which outlines our plan to meet customers' projected energy needs over the next fifteen years while maintaining reliability, supporting affordability, and continuing progress toward our aspirational goal of achieving net zero direct GHG emissions by 2050, as established in our 2023 IRP.
In March 2026, we issued an ASRFP to solicit capacity and energy resources for the purpose of supporting growth opportunities. We are in the process of evaluating the proposals.
Babacomari North was placed in service in March 2026 with 160 MW of solar capacity, and Wilmot II was placed in service in April 2026 with 100 MW of solar capacity and 100 MW of battery storage (400 MWh of energy capacity), both under existing power purchase agreements. Roadrunner Reserve II, a standalone BESS facility with a nominal capacity of 200 MW and energy capacity of 800 MWh, was placed in service in June 2026.
Nuclear Generation
In collaboration with other Arizona electric utilities, we are assessing the potential role of nuclear generation as a long-term carbon-free energy resource to support Arizona's growth in electricity demand. In April 2026, the utilities entered into a memorandum of understanding that establishes a framework for site evaluation and preliminary permitting activities. A siting study is currently underway and is expected to be complete by the end of the year. In May 2026, the utilities were notified that their previously filed application for a U.S. Department of Energy grant, intended to help support the multi-year site selection process and potential permitting preparation, was not selected. Once the current siting study concludes, we will evaluate technical, financial, and other factors before determining whether to develop and submit an Early Site Permit application to the U.S. Nuclear Regulatory Commission for approval. These efforts are in the early exploratory stage, are subject to regulatory approvals and funding availability, and may not result in the development of a nuclear facility.
Production Tax Credits
PTCs are federal tax credits earned per-kWh of electricity generated using qualified energy resources for a 10-year period after a qualifying facility is placed in service. In 2021, Oso Grande, a qualifying energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and are primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded approximately $11 million and $18 million in PTCs related to Oso Grande for the three and nine months ended September 30, 2026, respectively, and $9 million and $17 million for the three and nine months ended September 30, 2025, respectively. The PTC rate published by the IRS for wind facilities placed in service prior to 2022 is $0.031 for 2026 and was $0.030 for 2025.
Electricity generated from Oso Grande depends heavily on wind conditions. If actual conditions differ from our estimates, or if operational constraints arise, including insufficient transmission capacity to deliver the electricity, then the project's generation and associated PTCs may vary significantly from prior periods.
Pipeline Expansion Agreements
In April 2026, to support system reliability, facilitate the conversion of Springerville Units 1 and 2 to natural gas-fired generation, and meet future load growth, we entered into a 20-year gas transportation precedent agreement and amended an existing 25-year agreement to secure reliable access to natural gas. The agreements support the development of new third-party pipelines. Subject to the receipt of required regulatory approvals and other conditions, the pipelines are expected to be in service by late 2029.
Once the pipelines enter commercial operation, we will enter into related gas transportation service agreements with estimated purchase commitments of approximately $2.6 billion over 25 years and $1.0 billion over 20 years.
Sales Growth and Seasonality
Our average retail sales have remained relatively flat over the past three years. Recently, we have experienced interest from potential new large retail customers in the manufacturing, data center, and mining sectors with significant energy demands. This interest could result in a significant increase in retail sales growth compared to our historical averages. In addition, a significant increase in energy demand could require additions to our generation fleet and higher transmission and distribution infrastructure investments beyond those reflected in the base assumption of our 2026 IRP. Our 2026 IRP includes a high load factor customer scenario to evaluate the potential resource needs associated with significant load growth.
In addition to the ESA described below, we are analyzing additional requests from existing and potential new large retail customers and cannot predict the quantity or timing of the energy demand, if any, that may result.
Energy Supply Agreement
In 2025, we reached an agreement to serve a data center campus expected to be located in our service territory, requiring potential power demand of approximately 300 MW. The ACC approved the ESA in December 2025. The ESA provides additional consumer protections such as establishing minimum monthly payment obligations that apply irrespective of customer energy use, authorizing termination fees supported by financial assurance mechanisms, and imposing credit standards designed to mitigate the risk of default. In April 2026, the parties satisfied or waived all remaining contingencies and conditions precedent under the ESA. Under the terms of the ESA, a $40 million termination payment is required if the ESA is terminated by the customer prior to the commencement of electric service, which is secured by a $40 million LOC that we received in April 2026.
In February 2026, the Arizona Attorney General and the City of Tucson filed legal challenges, now pending in the Superior Court of Maricopa County, contesting the ACC's approval of the ESA. In June 2026, the ACC filed a motion to dismiss these proceedings, and in July 2026, we filed our own motion to dismiss. In September 2026, oral arguments were held, and on October 1, 2026, the Superior Court denied the motions to dismiss and ordered further briefing on the merits of the case. We cannot predict the timing or outcome of these proceedings.
Separately, we entered into a project construction agreement to develop transmission and switchyard facilities to provide retail electric service to the customer. The FERC accepted the original project construction agreement in September 2025. In April 2026, we executed an amended and restated project construction agreement to reflect the change of location of the switchyard. The amended and restated project construction agreement requires the customer to pre-fund all project costs. In June 2026, the FERC accepted the amended and restated project construction agreement, triggering a $20 million advance payment from the customer thereunder. The payment reduced construction work in progress by $17 million and resulted in the recognition of $3 million in interest income. In September 2026, we received an additional $24 million advance payment from the customer. The payment reduced construction work in progress by $21 million and resulted in the recognition of $3 million in interest income.
In August 2026, we executed a second amended and restated project construction agreement to reflect a revised scope of work and to include additional indemnity and insurance provisions. On October 26, 2026, the FERC accepted the second amended and restated project construction agreement.
The data center campus is projected to be operational as early as 2027, with a ramp schedule through 2029. We currently expect to serve this retail customer from our existing and planned generation resources.
Weather Patterns
Changing weather patterns and other factors cause seasonal fluctuations in power sales. Our retail sales are highest in the second and third quarters of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year, due to mild winter weather in our retail service territory. Our operating costs are generally consistent throughout the year, which produces higher operating income in the second and third quarters and lower operating income in the first and fourth quarters.
Interest Rates
See Part II, Item 7A in our 2025 Annual Report on Form 10-K and Part I, Item 3 of this Quarterly Report on Form 10-Q for information regarding interest rate risk and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of our results of operations that do not have a significant impact on net income include:
•Cost Recovery Mechanisms - We record operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchased power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, the RES tariff, and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for additional information on cost recovery mechanisms.
•Short-Term Wholesale Sales - Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC mechanism.
•Springerville Units 3 and 4 - Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.
The following discussion provides the significant items that affected our results of operations in the third quarter and first nine months of 2026 compared with the same periods in 2025 presented on a pre-tax basis.
Operating Revenues
The following table provides a disaggregation of Operating Revenues:
| Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | ||||||||||||||||||||||||||||||||
| (in millions) | 2026 | 2025 | Percent | 2026 | 2025 | Percent | |||||||||||||||||||||||||||||
| Operating Revenues | |||||||||||||||||||||||||||||||||||
| Retail | $ | 433 | $ | 434 | (0.2) | % | $ | 1,006 | $ | 994 | 1.2 | % | |||||||||||||||||||||||
| Wholesale, Long-Term | 8 | 15 | (46.7) | % | 27 | 43 | (37.2) | % | |||||||||||||||||||||||||||
|
Wholesale, Short-Term (1)
|
57 | 33 | 72.7 | % | 112 | 100 | 12.0 | % | |||||||||||||||||||||||||||
| Transmission | 17 | 15 | 13.3 | % | 47 | 45 | 4.4 | % | |||||||||||||||||||||||||||
| Springerville Units 3 and 4 Participant Billings | 26 | 23 | 13.0 | % | 82 | 64 | 28.1 | % | |||||||||||||||||||||||||||
| Other | 25 | 25 | - | % | 63 | 71 | (11.3) | % | |||||||||||||||||||||||||||
| Total Operating Revenues | $ | 566 | $ | 545 | 3.9 | % | $ | 1,337 | $ | 1,317 | 1.5 | % | |||||||||||||||||||||||
(1)Includes revenue realized from wholesale trading as defined in the PPFAC plan of administration of $6 million and $21 million for the three and nine months ended September 30, 2026, respectively, and $2 million and $23 million for the three and nine months ended September 30, 2025, respectively. We share 10% of any realized gains on trading transactions with retail customers through the PPFAC mechanism. The 2025 Rate Case includes a proposed increase in the proportion of realized wholesale trading gains shared with retail customers through the PPFAC mechanism from 10% to 50%, which would reduce the amount of such gains retained by TEP in 2027 and future periods. In addition, 2026 wholesale trading revenues were higher than historical levels due to market conditions that may not continue. As trading revenues are influenced by market factors outside our control, including price volatility and regional supply and demand, 2026 results may not be indicative of future periods.
We reported Operating Revenues of $566 million in the third quarter of 2026 compared with $545 million in the same period for 2025. The increase of $21 million, or 4%, was primarily due to:
•$24 million in higher short-term wholesale revenue primarily due to an increase in price, an increase in volume due to an increase in generation capacity available under PPAs and battery resources, and an increase in revenues from wholesale trading, as defined in the PPFAC plan of administration;
•$3 million in higher Springerville Unit 4 participant billings primarily due to higher reimbursable repair and maintenance costs; and
•$2 million in higher transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base.
The increase was partially offset by:
•$7 million in lower long-term wholesale revenue primarily due to a decrease in volume due to unfavorable market conditions resulting in lower demand from certain customers and a decrease in price; and
•$1 million in lower retail revenue primarily due to milder weather; partially offset by an increase in industrial sales and customer growth.
We reported Operating Revenues of $1,337 million for the first nine months of 2026 compared with $1,317 million in the same period for 2025. The increase of $20 million, or 2%, was primarily due to:
•$18 million in higher Springerville Unit 3 and Unit 4 participant billings primarily due to higher reimbursable repair and maintenance costs primarily for a Unit 3 planned outage;
•$12 million in higher retail revenue primarily due to an increase in industrial sales and customer growth; partially offset by milder weather, lower PPFAC cost recoveries as a result of a decrease in the PPFAC rate, and a decrease in RES tariff and DSM surcharge revenues due to lower program expenses;
•$12 million in higher short-term wholesale revenue primarily due to higher volumes as a result of an increase in generation capacity available under PPAs and battery resources; and
•$2 million in higher transmission revenue due to an increase in our transmission revenue requirement resulting from a higher rate base.
The increase was partially offset by:
•$16 million in lower long-term wholesale revenue primarily due to a decrease in volume due to unfavorable market conditions resulting in lower demand from certain customers; and
•$8 million in lower other revenue primarily due to lower TCA revenue.
The following table provides key statistics impacting Operating Revenues:
| Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | ||||||||||||||||||||||||||||||||
| (kWh in millions) | 2026 | 2025 | Percent | 2026 | 2025 | Percent | |||||||||||||||||||||||||||||
|
Electric Sales (kWh) (1)
|
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| Retail Sales | 3,037 | 3,057 | (0.7) | % | 7,149 | 7,030 | 1.7 | % | |||||||||||||||||||||||||||
| Wholesale, Long-Term | 126 | 195 | (35.4) | % | 370 | 642 | (42.4) | % | |||||||||||||||||||||||||||
| Wholesale, Short-Term | 1,311 | 1,126 | 16.4 | % | 3,323 | 2,840 | 17.0 | % | |||||||||||||||||||||||||||
| Total Electric Sales | 4,474 | 4,378 | 2.2 | % | 10,842 | 10,512 | 3.1 | % | |||||||||||||||||||||||||||
|
Average Revenue (cents per kWh) (2)
|
|||||||||||||||||||||||||||||||||||
| Retail | 14.27 | 14.20 | 0.5 | % | 14.07 | 14.15 | (0.6) | % | |||||||||||||||||||||||||||
| Wholesale, Long-Term | 6.05 | 7.66 | (21.0) | % | 7.24 | 6.71 | 7.9 | % | |||||||||||||||||||||||||||
| Wholesale, Short-Term | 3.88 | 3.14 | 23.6 | % | 2.74 | 2.87 | (4.5) | % | |||||||||||||||||||||||||||
|
Total Retail Customers (3)
|
459,247 | 456,330 | 0.6 | % | |||||||||||||||||||||||||||||||
(1)These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.
(2)This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
(3)This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining and non-mining), and other. The customer count is based on the average number of active service agreements during each period. Management uses this count to monitor the growth of retail customers.
Operating Expenses
Fuel and Purchased Power Expense
We reported Fuel and Purchased Power expense of $177 million in the third quarter of 2026 compared with $162 million in the same period for 2025. The increase of $15 million, or 9%, was primarily due to:
•$8 million in higher PPFAC recovery treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery; and
•$7 million in higher transmission and other PPFAC recoverable costs primarily due to an increase in energy storage expense and an increase in transmission service expense.
The increase was partially offset by $3 million in lower purchased power expense primarily due to a decrease in short-term volumes; partially offset by an increase in renewable PPA purchases.
We reported Fuel and Purchased Power expense of $392 million for the first nine months of 2026 compared with $394 million for the same period for 2025. The decrease of $2 million, or 1%, was primarily due to $29 million in lower fuel expenses primarily due to a decrease in gas prices and a decrease in Gas-Fired Generation volumes; partially offset by higher realized losses on natural gas swaps and an increase in Coal-Fired Generation volumes.
The decrease was partially offset by:
•$20 million in higher transmission and other PPFAC recoverable costs primarily due to an increase in transmission service expenses related to a FERC rate case credit that was received in January 2025 and an increase in energy storage expense;
•$3 million in higher PPFAC recovery treatment primarily due to a decrease in PPFAC eligible costs deferred as a regulatory asset for future recovery, partially offset by a decrease in PPFAC recoveries; and
•$3 million in higher purchased power expense primarily due to an increase in renewable PPA purchases; partially offset by a decrease in short-term volumes.
The following table provides key statistics impacting Fuel and Purchased Power:
| Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | ||||||||||||||||||||||||||||||||
| (kWh in millions) | 2026 | 2025 | Percent | 2026 | 2025 | Percent | |||||||||||||||||||||||||||||
| Sources of Energy | |||||||||||||||||||||||||||||||||||
| Coal-Fired Generation | 1,063 | 1,011 | 5.1 | % | 2,379 | 2,135 | 11.4 | % | |||||||||||||||||||||||||||
| Gas-Fired Generation | 2,577 | 2,584 | (0.3) | % | 5,553 | 5,794 | (4.2) | % | |||||||||||||||||||||||||||
| Utility-Owned Renewable Generation | 156 | 146 | 6.8 | % | 540 | 514 | 5.1 | % | |||||||||||||||||||||||||||
| Total Generation | 3,796 | 3,741 | 1.5 | % | 8,472 | 8,443 | 0.3 | % | |||||||||||||||||||||||||||
| Purchased Power | 904 | 815 | 10.9 | % | 2,901 | 2,527 | 14.8 | % | |||||||||||||||||||||||||||
|
Total Generation and Purchased Power (1)
|
4,700 | 4,556 | 3.2 | % | 11,373 | 10,970 | 3.7 | % | |||||||||||||||||||||||||||
| (cents per kWh) | |||||||||||||||||||||||||||||||||||
| Average Cost of Generated and Purchased Power | |||||||||||||||||||||||||||||||||||
|
Coal (2)
|
4.42 | 4.32 | 2.3 | % | 4.50 | 4.52 | (0.4) | % | |||||||||||||||||||||||||||
|
Natural Gas (2)(3)
|
2.20 | 2.27 | (3.1) | % | 1.98 | 2.57 | (23.0) | % | |||||||||||||||||||||||||||
|
Purchased Power (4)
|
4.34 | 5.16 | (15.9) | % | 3.68 | 4.11 | (10.5) | % | |||||||||||||||||||||||||||
(1)This number represents the kWh generated from our generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.
(2)These metrics represent the fuel cost as cents per kWh for coal and natural gas generated power. These numbers are calculated as fuel cost divided by Total Generation (kWh) for each respective generation source. Management uses these metrics to monitor rates and pricing as well as analyze the performance of generation facilities.
(3)Includes realized gains and losses from hedging activity.
(4)This metric represents cost as cents per kWh for purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh). Management uses this metric to compare and monitor the costs of purchased power.
Operations and Maintenance Expense
We reported Operations and Maintenance expense of $113 million in the third quarter of 2026 compared with $116 million in the same period for 2025. The decrease of $3 million, or 3%, was primarily due to:
•$5 million in lower employee benefits expenses driven in part by timing; and
•$3 million in lower RES tariff and DSM expenses primarily due to lower program expenses.
The decrease was partially offset by $3 million in higher reimbursable materials and maintenance expenses related to Springerville Unit 4.
We reported Operations and Maintenance expense of $354 million for the first nine months of 2026 compared with $327 million for the same period for 2025. The increase of $27 million, or 8%, was primarily due to:
•$17 million in higher reimbursable materials and maintenance expenses related to Springerville Units 3 and 4;
•$8 million in higher operations and maintenance expenses at our generation facilities;
•$4 million in higher outside services expenses; and
•$3 million in higher employee wages expense net of a decrease in employee benefits expense.
The increase was partially offset by $4 million in lower RES tariff and DSM expenses primarily due to lower program expenses.
Depreciation and Amortization Expense
We reported Depreciation and Amortization expense of $77 million in the third quarter of 2026 compared with $67 million in the same period for 2025. The increase of $10 million, or 15%, was primarily due to an increase in asset base.
We reported Depreciation and Amortization expense of $217 million for the first nine months of 2026 compared with $198 million for the same period for 2025. The increase of $19 million, or 10%, was primarily due to an increase in asset base.
Other Income (Expense)
We reported Other Expense of $18 million in the third quarter of 2026 compared with $15 million in the same period for 2025. The increase of $3 million, or 20%, was primarily due to:
•$3 million in lower AFUDC due to a decrease in eligible construction expenditures; and
•$2 million increase due to unfavorable market conditions that decreased the value of investments used to support certain post-employment benefits.
The increase was partially offset by:
•$2 million in higher interest income associated with customer prepayments; and
•$2 million in lower non-service components of net periodic benefit cost primarily due to a decrease in interest cost and an increase in expected return on plan assets.
We reported Other Expense of $40 million for the first nine months of 2026 compared with $43 million in the same period for 2025. The decrease of $3 million, or 7%, was primarily due to:
•$5 million in lower non-service components of net periodic benefit cost primarily due to a decrease in interest cost and an increase in expected return on plan assets;
•$3 million in higher interest income associated with customer prepayments; and
•$3 million in lower interest expense primarily due to the deferral of interest expense associated with Roadrunner Reserve I.
The decrease was partially offset by:
•$4 million in lower AFUDC due to a decrease in eligible construction expenditures; and
•$2 million increase due to unfavorable market conditions that decreased the value of investments used to support certain post-employment benefits.
Income Tax Expense
We reported Income Tax Expense of $14 million in the third quarter of 2026 compared with $23 million in the same period for 2025. The decrease of $9 million, or 39%, was primarily due to higher amortization of ITCs.
We reported Income Tax Expense of $25 million for the first nine months of 2026 compared with $40 million for the same period for 2025. The decrease of $15 million, or 38%, was primarily due to higher amortization of ITCs.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Any extended period of economic disruption could affect our business, financial condition, and access to sources of liquidity. Cash flows vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to our summer peaking load. We face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of commodity prices or their volatility. We use our revolving credit as needed to fund our business activities. We believe that we have sufficient liquidity under the 2026 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which we have access to external financing depend on a variety of factors, including our credit ratings and conditions in the bank and capital markets.
Available Liquidity
| (in millions) | September 30, 2026 | ||||
| Cash and Cash Equivalents | $ | 81 | |||
|
Amount Available under Revolving Credit Agreement (1)
|
241 | ||||
| Total Liquidity | $ | 322 | |||
(1)The 2021 Credit Agreement provided for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and was amended and restated on October 15, 2026 by the 2026 Credit Agreement. The 2026 Credit Agreement provides for $350 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and expires in October 2031. See Access to Credit below.
Future Liquidity Requirements
We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include but are not limited to: (i) dividend payments; (ii) debt maturities; (iii) employee benefit obligations; and (iv) known commitments and other contractual obligations including forecasted capital expenditures.
See Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk of this Quarterly Report on Form 10-Q for additional information regarding our market risks. See Note 1, Note 7, and Note 8 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2025 Annual Report on Form 10-K for additional information regarding our leases, financing arrangements, and purchase commitments, respectively.
Summary of Cash Flows
The table below presents net cash provided by (used for) operating, investing, and financing activities:
| Nine Months Ended September 30, | Increase (Decrease) | ||||||||||||||||
| (in millions) | 2026 | 2025 | Percent | ||||||||||||||
|
Operating Activities (1)
|
$ | 547 | $ | 454 | 20.5 | % | |||||||||||
|
Investing Activities (1)
|
(444) | (728) | (39.0) | % | |||||||||||||
|
Financing Activities (1)
|
(54) | 295 | (118.3) | % | |||||||||||||
| Net Increase (Decrease) | 49 | 21 | * | ||||||||||||||
| Beginning of Period | 56 | 49 | 14.3 | % | |||||||||||||
| End of Period | $ | 105 | $ | 70 | 50.0 | % | |||||||||||
*Not meaningful
(1)Calculated on rounded data and may not correspond exactly to amounts on the Condensed Consolidated Statements of Cash Flows.
Operating Activities
Net cash flows provided by operating activities increased by $93 million in the first nine months of 2026 compared with the same period in 2025 primarily due to the receipt of proceeds from the sale of ITCs.
Investing Activities
Net cash flows used for investing activities decreased by $284 million in the first nine months of 2026 compared with the same period in 2025 primarily due to a decrease in cash paid for capital expenditures.
Financing Activities
Net cash flows used for financing activities was $54 million in the first nine months of 2026, compared with net cash flows provided by financing activities of $295 million in the same period for 2025. The $349 million change was primarily due to lower proceeds from debt issuance and an increase in dividends paid to UNS Energy; partially offset by an increase in equity contributions from UNS Energy.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of September 30, 2026, our short-term investments were deposited in money market accounts.
Access to Credit
We have access to working capital through our credit agreement with lenders. LOCs may be issued from time to time to support energy procurement, hedging transactions, and other business activities. As of September 30, 2026, there was $241 million available under the 2021 Credit Agreement, which reflected no outstanding revolver borrowings and LOCs totaling $9 million issued with fees that accrued at a rate of 1.025% per annum.
On October 15, 2026, the 2021 Credit Agreement was amended and restated by the 2026 Credit Agreement. On October 22, 2026, TEP amended and reduced a $1 million LOC with fees accruing at a rate of 1.000% per annum to less than $1 million. As of November 2, 2026, there was $342 million available under the 2026 Credit Agreement, which reflects no outstanding revolver borrowings and $8 million of LOCs, with fees accruing at a rate of 1.000% per annum. Amounts borrowed from the 2026 Credit Agreement are used for working capital and other general corporate purposes.
See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding our 2026 Credit Agreement. See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2025 Annual Report on Form 10-K for additional information regarding our 2021 Credit Agreement.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. Our cost of capital is also affected by our credit ratings. In March 2025, we filed with the SEC an automatic shelf registration statement on Form S-3 which expires in March 2028. In October 2025, the ACC issued an order granting us financing authority which took effect on January 1, 2026. The order provides authority through December 2030 for: (i) a maximum amount of outstanding long-term debt not to exceed $4.5 billion; (ii) parent equity contributions of up to $1.7 billion, provided that no such equity infusion results in an increase to the equity portion of our capital structure of more than 50 basis points above the level approved in our rate order in effect at the time of the contribution; and (iii) credit facilities not to exceed $350 million in the aggregate.
We have, from time to time, refinanced or repurchased portions of our outstanding debt before scheduled maturity. Depending on market conditions, we may refinance or repurchase additional outstanding debt before its scheduled maturity.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of September 30, 2026, credit ratings from S&P Global Ratings and Moody's Investors Service for our senior unsecured debt were A- (stable) and A3 (stable), respectively.
Our credit ratings depend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold our securities. Each rating should be evaluated independently of any other ratings.
The 2026 Credit Agreement contains pricing based on our credit ratings. A change in our credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.
Debt Covenants
Under certain agreements, should we fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2026, we were in compliance with these covenants.
We do not have any provisions in any of our debt agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
Contributions from Parent
We received no equity contributions from UNS Energy in the third quarter of 2026 and received equity contributions of $95 million in the first nine months of 2026. We received no equity contributions from UNS Energy in the third quarter or first nine months of 2025.
Dividends Declared and Paid to Parent
We did not declare or pay dividends to UNS Energy in the third quarter of 2026. We declared and paid $150 million in dividends to UNS Energy in the first nine months of 2026. We did not declare or pay dividends to UNS Energy in the third quarter or first nine months of 2025.
Master Trading Agreements
We conduct our wholesale marketing and risk management activities under certain master trading agreements. These agreements may require us to post credit enhancements in the form of cash or LOCs if our exposures exceed unsecured credit limits established for us based on changes in: (i) contract values; (ii) our credit ratings; or (iii) material changes in our creditworthiness. As of September 30, 2026, we had no cash posted as collateral to provide credit enhancement related to our wholesale marketing or risk management activities.
Capital Expenditures
Our routine capital expenditures support customer growth, system reinforcement, replacements and betterments, and compliance with environmental rules and regulations. We prioritize capital projects that mitigate supply chain risks, particularly in light of ongoing geopolitical instability and global supply chain challenges. Capital expenditures for the first nine months of 2026 were $453 million.
Our forecasted capital expenditures presented below exclude amounts for AFUDC equity and other non-cash items:
| Years Ended December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2026 | 2027 | 2028 | 2029 | 2030 | ||||||||||||||||||||||||
|
Generation Facilities (1)
|
$ | 131 | $ | 86 | $ | 138 | $ | 213 | $ | 187 | |||||||||||||||||||
|
Transmission and Distribution (2)
|
461 | 424 | 390 | 703 | 439 | ||||||||||||||||||||||||
|
General and Other (3)
|
93 | 86 | 78 | 95 | 75 | ||||||||||||||||||||||||
| Total Capital Expenditures | $ | 685 | $ | 596 | $ | 606 | $ | 1,011 | $ | 701 | |||||||||||||||||||
(1)Includes investments in existing facilities, including upgrades and ongoing maintenance to ensure reliability.
(2)Investments in transmission capacity and distribution system reliability.
(3)Includes costs for information technology, fleet, facilities, and communication equipment.
These estimates are subject to continuing review and adjustment. Actual capital expenditures may vary due to fluctuations in business and market conditions, including inflationary pressures, tariffs, construction schedules, supply chain constraints, labor shortages and/or labor strikes, potential early plant closures, shifts in generation resources, any changes to governmental programs, such as loans, grants, guarantees, and other subsidies, evolving environmental requirements, local, state or federal regulations and policies, and other factors. We continue to monitor government trade policies, particularly those related to tariffs, and assess their potential impact on our capital projects. We expect to fund forecasted capital expenditures through a combination of internally generated cash and external financing, which may include long-term debt issuances, other borrowings, or equity contributions.
Income Tax Position
Tax Sharing Agreement
Under the terms of the tax sharing agreement with UNS Energy, we made $3 million in net tax sharing payments for the first nine months of 2026 and 2025. Future cash flows are subject to change and are not expected to have a significant impact on our operating cash flows.
Investment Tax Credits
Standalone battery storage systems that began construction before January 29, 2023, may qualify for a base federal tax credit equal to 30% of the eligible costs of the facility. In addition, projects located in qualifying energy communities may be eligible for an additional 10% bonus credit. Roadrunner Reserve I and II qualify for federal ITCs; Roadrunner Reserve II also qualifies for the energy community bonus credit, increasing its total federal investment tax credit to 40% of eligible project costs. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the ITCs generated by Roadrunner Reserve I and II. The IRA provides an election to transfer (i.e., sell) some or all of certain tax credits generated by a qualifying facility to unrelated third parties in exchange for cash. Transfer elections must be made on a facility-by-facility and year-by-year basis. Any election to transfer tax credits must be made and cash must be received on or before the due date of the tax return for the year the facility is placed in service.
In April 2026, we received the final $46 million of cash proceeds from the sale of ITCs related to Roadrunner Reserve I.
Roadrunner Reserve II was placed in service in June 2026. In March 2026, we entered into an agreement to transfer ITCs related to Roadrunner Reserve II in the second half of 2026. In July 2026, we transferred $50 million of ITCs and received $46 million in cash proceeds from the sale of ITCs related to Roadrunner Reserve II. On October 1, 2026, we transferred $40 million of additional ITCs related to Roadrunner Reserve II and received $37 million in cash proceeds.
Environmental Matters
The EPA has the authority to regulate emissions of SO2, NOx, CO2, particulate matter, mercury, and other by-products produced from generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs.
Regional Haze Regulations
The EPA's Regional Haze rule requires certain industrial facilities to reduce emissions that impair visibility in national parks and wilderness areas. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a SIP and must review and submit revisions to the SIP on a periodic basis.
In December 2016, the EPA signed a final rule that, among other things, moved the next deadline for Regional Haze SIP revisions from 2018 to 2021. Following this change, the ADEQ began developing a control strategy to make reasonable progress toward the national visibility goal. In July 2019, the ADEQ notified us that Sundt Unit 3 and Springerville Units 1 and 2 had been selected for potential emissions controls evaluations. We conducted the potential emissions controls evaluations, commonly referred to as the four-factor analysis, for the three units. These evaluations were submitted to the ADEQ in March 2020 and compliance measures for the three units were included in the revised SIP.
In December 2024, the EPA published a final rule partially approving and partially disapproving the ADEQ's Regional Haze SIP revision. The EPA disapproved the ADEQ's control strategy in the revised SIP, which relies, in part, on the compliance measures for Sundt Unit 3 and Springerville Units 1 and 2. The EPA also disapproved the ADEQ's selection of sources for potential emissions controls evaluations and requested further evaluation of Sundt Unit 4. The disapproval established a two-year deadline for the EPA to promulgate a FIP that contains EPA-required compliance measures for Springerville and Sundt, unless the EPA approves a subsequent SIP submission by the ADEQ curing the SIP deficiencies within that timeframe.
In February 2025, in response to the EPA's December 2024 final rule, TEP and SRP filed a joint Petition for Review with the U.S. Court of Appeals for the Ninth Circuit. In September 2025, the Court granted a motion filed by the Coalition to Protect America's National Parks, the National Parks Conservation Association, and Sierra Club to intervene in the case, which had the effect of taking the case out of abeyance and reinstating a briefing schedule. The petitioners (TEP, SRP, ASARCO, and
Phoenix Cement) and respondents (the EPA) jointly filed a motion with the Court asking for the case to be held in abeyance, which the Court granted in December 2025.
In February 2025, TEP and SRP also concurrently filed a joint Petition for Administrative Reconsideration with the EPA. We requested that the EPA reconsider the final rule and act to approve the ADEQ's Regional Haze SIP revision. In July 2025, TEP and SRP filed a supplement to the Petition for Administrative Reconsideration, providing further justification for the EPA to reconsider the final rule, and the EPA granted the request for reconsideration. In October 2025, we filed a modification to the original and supplemental Petition for Administrative Reconsideration providing justification for the EPA's reconsideration with respect to Sundt Unit 3 and Springerville Units 1 and 2.
We cannot predict the outcome of this matter.
Greenhouse Gas Regulation
In May 2024, the EPA published final rules to regulate GHG emissions from two categories of fossil-based EGUs: (i) existing steam units (including coal- and natural gas-fired); and (ii) new natural gas-fired turbines.
The final rules established:
•emission guidelines for existing coal-fired steam EGUs, which are subcategorized based on federally enforceable retirement dates. These emission guidelines affect Springerville Units 1 and 2, as well as Four Corners Units 4 and 5;
•emission guidelines for existing natural gas- and oil-fired steam EGUs aligned with routine methods of operation and maintenance, which are subcategorized based on the annual capacity factor of each unit beginning January 1, 2030. These emission guidelines affect Sundt Units 3 and 4;
•a requirement for states to establish standards of performance that align with the emission guidelines in the form of emission limits. States must submit these standards of performance to the EPA for approval in the form of a state plan, which was due to the EPA in May 2026; and
•new source performance standards for new stationary natural gas-fired combustion turbines, which are subcategorized based on the annual capacity factor for each unit. For base load units (i.e., units with an annual capacity factor greater than 40%), the EPA established a two-phased performance standard. For phase 1, new base load units must initially meet performance standards based on the use of highly efficient combined cycle generation with the best operating and maintenance practices. For phase 2, the final rule requires that such base load units achieve emissions reductions aligned with a 90% CCS rate beginning on January 1, 2032.
Various legal challenges to the final rules are pending before the U.S. Court of Appeals for the District of Columbia Circuit. In April 2025, the Court granted the EPA's unopposed motion to hold the case in abeyance indefinitely (following a previous sixty-day stay), while the EPA conducts a rulemaking to reassess the rules. In June 2025, the EPA published a proposed rule containing two co-proposals to address the 2024 final rules. In the primary proposal, the EPA proposed to repeal the 2024 final rules in their entirety based on a determination that fossil-based EGUs do not contribute significantly to GHG air pollution. In the alternative proposal, the EPA proposed to:
•repeal the Best System of Emission Reductions determinations, presumptive standards of performance, and all related requirements in the emission guidelines for existing long-term and medium-term coal-fired steam EGUs;
•repeal the requirements for existing natural gas- and oil-fired steam EGUs; and
•repeal the phase 2 CCS-based requirements for new base load combustion turbine EGUs.
In September 2026, the EPA published a final rule adopting the alternative proposal and also issued a supplemental proposal seeking additional comment on the primary proposal. On the same day, legal challenges to the final rule were filed in the U.S. Court of Appeals for the District of Columbia Circuit.
We cannot predict the outcome of the rulemaking or the legal challenges at this time.
Coal Combustion Residuals Regulation
The EPA published final rules effective October 2015 (2015 CCR Rule) that established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act. The 2015 CCR Rule provides for the safe disposal of coal ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at Springerville.
APS, the operator of Four Corners, currently disposes of CCR in ash ponds and dry storage areas located at the facility. SRP, the operator of Navajo, is completing closure activities at the facility's CCR landfill. No corrective actions to comply with the 2015 CCR Rule have been identified at Springerville or Navajo. With regards to future corrective actions at Four Corners to comply with the 2015 CCR Rule, our share of costs to complete any corrective actions and to gather and perform remedial evaluations on groundwater at Units 4 and 5 is not expected to have a significant impact on our financial position, results of operations, or cash flows.
In May 2024, the EPA published the final Legacy CCR Surface Impoundments Rule that expands the scope of the 2015 CCR Rule to address the impacts from historical CCR management and placement activities that would have ceased prior to 2015. The 2024 EPA rule establishes two new categories of federally regulated CCR: (i) legacy surface impoundments, which are inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCRMUs which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. A CCRMU includes not only historically closed landfills and surface impoundments, but also prior applications of CCR on land, such as for structural fill. The final rule also establishes assessment, groundwater monitoring, closure, and post-closure requirements for legacy CCR impoundments and CCRMUs.
We anticipate CCRMUs will be identified at Springerville and Four Corners; however, our assessment is ongoing and therefore associated compliance costs cannot be accurately predicted at this time. SRP tentatively identified CCRMUs at Navajo. Our estimated cost to comply with the EPA's final rule at Navajo is not expected to have a significant impact on our financial position, results of operations, or cash flows. Legal challenges to the final rule are pending before the U.S. Court of Appeals for the District of Columbia Circuit.
In April 2026, the EPA published a proposed rule that reconsiders many requirements that were established by the Legacy CCR Surface Impoundments Rule and the 2015 CCR Rule. The proposed rule includes multiple proposals including potential removal of all requirements associated with CCRMUs or up to seven alternative amendments to the CCRMU requirements. The proposed rule also includes incorporating site-specific risk provisions into the 2015 CCR Rule requirements for CCR units. Public comment on the proposed rule closed in June 2026. We are analyzing the EPA's proposed rule.
In May 2026, the EPA announced the reopening of the public comment period for the proposed federal CCR permitting program that was originally published in February 2020. Public comment on the proposed rule closed in July 2026. TEP does not anticipate a material impact on operations or financial results from the proposed rule.
We cannot predict the outcome of the proposed rulemakings or any of the legal challenges at this time.
Good Neighbor Federal Implementation Plan
In September 2018, the ADEQ submitted to the EPA the Arizona SIP Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone NAAQS. In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.
In March 2023, the EPA released its final FIP to address the interstate transport of ozone (Good Neighbor FIP) with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.
In February 2024, the EPA published a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona's inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOx emission reduction requirements. The EPA must take final action on Arizona's Ozone Transport SIP Revision by December 15, 2026, per consent decree entered in the U.S. District Court for the Northern District of California.
In June 2024, the U.S. Supreme Court granted a stay of the Good Neighbor FIP pending the disposition of the petitions for review of the Good Neighbor FIP currently pending in the U.S. Court of Appeals for the District of Columbia Circuit. In October 2024, the EPA issued an interim final rule administratively staying the effectiveness of the Good Neighbor FIP for all emissions sources subject to the plan as promulgated.
In September 2024, the U.S Court of Appeals for the District of Columbia Circuit Court granted the EPA's request to remand the Good Neighbor FIP rulemaking record and further respond to comments related to the issues addressed in the U.S. Supreme Court's stay. The EPA published its updated response to comments for the Good Neighbor FIP in December 2024.
In March 2025, the EPA filed a motion in the U.S. Court of Appeals for the District of Columbia Circuit indicating it plans to reconsider the Good Neighbor Rule. In January 2026, the EPA published the first proposal of a two-phase plan to revise the interstate transport regulations for the 2015 ozone NAAQS. The EPA proposed to approve SIPs from eight states (including Arizona) based on a determination that emissions from these states do not significantly contribute to nonattainment or interfere with maintenance of the 2015 ozone NAAQS in downwind states. We cannot predict the outcome of this matter.
CRITICAL ACCOUNTING ESTIMATES
Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates, judgments, and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that there have been no significant changes during the nine months ended September 30, 2026, to the items that we disclosed as our critical accounting estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2025 Annual Report on Form 10-K.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
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