{"url_path":"/sec/cik-0000100122/10-k/2026/item-8","section_key":"item-8","section_title":"Item 8 CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA","topic":"sec","document":{"doc_type":"10-K","doc_date":"2026-02-12","source_url":"https://www.sec.gov/Archives/edgar/data/100122/0000100122-26-000006-index.html","accession_number":"0000100122-26-000006","cik":"0000100122","ticker":null,"issuer_name":"TUCSON ELECTRIC POWER CO","edgar_url":"https://www.sec.gov/Archives/edgar/data/100122/0000100122-26-000006-index.html","primary_entity_key":"0000100122","primary_entity_name":"TUCSON ELECTRIC POWER CO"},"word_count":18513,"has_tables":true,"body_markdown":"ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA\n\nREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM\n\nTo the Stockholder and the Board of Directors of\n\nTucson Electric Power Company\n\nOpinion on the Financial Statements\n\nWe have audited the accompanying consolidated balance sheets of Tucson Electric Power Company and subsidiaries (the \"Company\") as of December 31, 2025 and 2024, the related consolidated statements of income, changes in stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the \"financial statements\"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.\n\nBasis for Opinion\n\nThese financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.\n\nWe conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.\n\nOur audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.\n\nCritical Audit Matter\n\nThe critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.\n\nImpact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 2 to the financial statements\n\nCritical Audit Matter Description\n\nThe Company is subject to rate regulation by the Arizona Corporation Commission (“ACC”) and Federal Energy Regulatory Commission (“FERC”). The ACC has jurisdiction with respect to the rates of electric distribution companies in Arizona. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as utility plant; regulatory assets and liabilities; operating revenues; total fuel expense and purchased\n\n41\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\npower expense; increase (decrease) to reflect PPFAC recovery treatment; operation and maintenance expense; and depreciation expense.\n\nWe identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, (3) potential refunds to customers and (4) probability of potential charges related to the abandonment of regulated plants. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the regulatory authorities will not approve full recovery of the costs incurred. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.\n\nHow the Critical Audit Matter Was Addressed in the Audit\n\nOur audit procedures related to the uncertainty of future decisions by the regulatory authorities included the following, among others:\n\n•We evaluated the effectiveness of management’s controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.\n\n•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.\n\n•We read relevant regulatory rate orders and settlements issued by the regulatory authorities for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the regulatory authorities’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.\n\n•For regulatory matters in process, we inspected the Company’s filings with the regulatory authorities and the filings with the regulatory authorities by intervenors that may impact the Company’s future rates, for evidence that might contradict management’s assertions.\n\n•We inquired of management about utility plant that may be abandoned or retired early. We inspected the capital-projects budget and construction-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the regulatory authorities to identify any evidence that may contradict management’s assertion regarding recoverability of such costs.\n\n•We inspected regulatory orders for any evidence that intervenors are challenging full recovery of the cost of any capital projects. For significant projects that were over budget or if full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance of such costs.\n\n/s/ Deloitte & Touche LLP\n\nTempe, Arizona\n\nFebruary 11, 2026\n\nWe have served as the Company's auditor since 2017.\n\n42\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nTUCSON ELECTRIC POWER COMPANY\n\nCONSOLIDATED STATEMENTS OF INCOME\n\n(Amounts in thousands)\n\nYears Ended December 31,\n\n202520242023\n\nOperating Revenues$1,688,702 $1,804,772 $1,875,448 \n\nOperating Expenses\n\nFuel339,573 334,369 372,692 \n\nPurchased Power130,297 129,431 221,781 \n\nTransmission and Other PPFAC Recoverable Costs59,871 68,061 81,706 \n\nIncrease (Decrease) to Reflect PPFAC Recovery Treatment(13,955)101,157 80,207 \n\nTotal Fuel and Purchased Power515,786 633,018 756,386 \n\nOperations and Maintenance449,004 447,287 444,826 \n\nDepreciation234,596 226,051 198,919 \n\nAmortization31,244 30,687 36,876 \n\nTaxes Other Than Income Taxes73,588 71,493 67,484 \n\nTotal Operating Expenses1,304,218 1,408,536 1,504,491 \n\nOperating Income384,484 396,236 370,957 \n\nOther Income (Expense)\n\nInterest Expense(120,271)(105,269)(95,389)\n\nAllowance For Borrowed Funds17,306 9,368 5,145 \n\nAllowance For Equity Funds39,778 25,516 14,763 \n\nUnrealized Gains (Losses) on Investments3,328 1,945 2,992 \n\nInterest Income5,827 8,820 11,372 \n\nOther, Net(1,797)(3,329)(1,957)\n\nTotal Other Income (Expense)(55,829)(62,949)(63,074)\n\nIncome Before Income Tax Expense328,655 333,287 307,883 \n\nIncome Tax Expense45,273 44,295 49,229 \n\nNet Income$283,382 $288,992 $258,654 \n\nThe accompanying notes are an integral part of these financial statements.\n\n43\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nTUCSON ELECTRIC POWER COMPANY\n\nCONSOLIDATED STATEMENTS OF CASH FLOWS\n\n(Amounts in thousands)\n\nYears Ended December 31,\n\n202520242023\n\nCash Flows from Operating Activities\n\nNet Income$283,382 $288,992 $258,654 \n\nAdjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:\n\nDepreciation Expense234,596 226,051 198,919 \n\nAmortization Expense31,244 30,687 36,876 \n\nAmortization of Debt Issuance Costs3,168 3,272 3,067 \n\nUse of Renewable Energy Credits for Compliance50,129 47,800 45,416 \n\nDeferred Income Taxes39,902 31,357 41,618 \n\nPension and Other Postretirement Benefits Expense16,618 18,038 15,241 \n\nPension and Other Postretirement Benefits Funding(14,660)(20,873)(18,391)\n\nAllowance for Equity Funds Used During Construction(39,778)(25,516)(14,763)\n\nChange in Long-Term Regulatory Assets and Liabilities(3,810)12,501 3,615 \n\nSales of Investment Tax Credits45,730 — — \n\nChanges in Current Assets and Current Liabilities:\n\nAccounts Receivable227 20,745 95,724 \n\nMaterials, Supplies, and Fuel Inventory(22,239)(48,070)(19,381)\n\nRegulatory Assets(24,428)43,192 62,827 \n\nOther Current Assets(826)(3,089)(3,229)\n\nAccounts Payable and Accrued Charges(15,025)(918)(128,780)\n\nRegulatory Liabilities1,136 50,076 (7,545)\n\nOther, Net4,742 (10,928)(10,317)\n\nNet Cash Flows—Operating Activities590,108 663,317 559,551 \n\nCash Flows from Investing Activities\n\nCapital Expenditures(827,896)(733,096)(577,766)\n\nPurchase Intangibles, Renewable Energy Credits(56,165)(59,521)(62,444)\n\nOther Investments— — 2,935 \n\nContributions in Aid of Construction11,831 4,850 4,252 \n\nNet Cash Flows—Investing Activities(872,230)(787,767)(633,023)\n\nCash Flows from Financing Activities\n\nProceeds from Borrowings, Revolving Credit Facility100,000 95,000 — \n\nRepayments of Borrowings, Revolving Credit Facility(170,000)(25,000)— \n\nProceeds from Issuance, Long-Term Debt—Net of Discount\n299,322 399,376 373,954 \n\nRepayments of Long-Term Debt— (300,000)(240,745)\n\nDividends Paid to Parent— (85,000)(64,100)\n\nPayment of Debt Issuance Costs(3,693)(3,744)(4,095)\n\nContributions from Parent65,000 50,000 — \n\nOther, Net(1,576)684 72 \n\nNet Cash Flows—Financing Activities289,053 131,316 65,086 \n\nNet Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash6,931 6,866 (8,386)\n\nCash, Cash Equivalents, and Restricted Cash, Beginning of Period49,461 42,595 50,981 \n\nCash, Cash Equivalents, and Restricted Cash, End of Period$56,392 $49,461 $42,595 \n\nThe accompanying notes are an integral part of these financial statements.\n\n44\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nTUCSON ELECTRIC POWER COMPANY\n\nCONSOLIDATED BALANCE SHEETS\n\n(Amounts in thousands, except share data)\n\nDecember 31,\n\n20252024\n\nASSETS\n\nUtility Plant\n\nPlant in Service$9,000,669 $8,349,638 \n\nConstruction Work in Progress890,095 850,443 \n\nTotal Utility Plant9,890,764 9,200,081 \n\nAccumulated Depreciation and Amortization(2,837,619)(2,713,492)\n\nTotal Utility Plant, Net7,053,145 6,486,589 \n\nInvestments and Other Property75,717 75,662 \n\nCurrent Assets\n\nCash and Cash Equivalents26,192 14,063 \n\nAccounts Receivable (Net of Allowance for Credit Losses of $13,827 and $12,561 as of December 31, 2025 and December 31, 2024, respectively)\n195,923 196,194 \n\nFuel Inventory59,281 55,267 \n\nMaterials and Supplies211,555 196,515 \n\nRegulatory Assets126,836 97,720 \n\nDerivative Instruments9,187 9,732 \n\nOther31,864 31,597 \n\nTotal Current Assets660,838 601,088 \n\nRegulatory Assets167,108 177,963 \n\nDerivative Instruments21,123 27,664 \n\nOther Noncurrent Assets161,339 152,557 \n\nTotal Assets$8,139,270 $7,521,523 \n\nThe accompanying notes are an integral part of these financial statements.\n\n(Continued)\n\n45\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nTUCSON ELECTRIC POWER COMPANY\n\nCONSOLIDATED BALANCE SHEETS\n\n(Amounts in thousands, except share data)\n\nDecember 31,\n\n20252024\n\nCAPITALIZATION AND LIABILITIES\n\nCapitalization\n\nCommon Stock Equity:\n\nCommon Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2025 and 2024)\n$1,811,539 $1,746,539 \n\nCapital Stock Expense(6,357)(6,357)\n\nRetained Earnings1,650,295 1,366,913 \n\nAccumulated Other Comprehensive Loss(6,930)(4,015)\n\nTotal Common Stock Equity3,448,547 3,103,080 \n\nPreferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2025 and 2024)\n— — \n\nLong-Term Debt, Net2,792,642 2,494,600 \n\nTotal Capitalization6,241,189 5,597,680 \n\nCurrent Liabilities\n\nBorrowings Under Credit Agreement— 70,000 \n\nAccounts Payable128,540 151,278 \n\nAccrued Taxes Other than Income Taxes58,410 57,847 \n\nAccrued Employee Expenses42,383 37,921 \n\nAccrued Interest23,627 22,260 \n\nRegulatory Liabilities143,851 142,844 \n\nCustomer Deposits17,508 16,255 \n\nDerivative Instruments31,143 25,710 \n\nOther29,743 31,665 \n\nTotal Current Liabilities475,205 555,780 \n\nDeferred Income Taxes, Net704,199 700,189 \n\nRegulatory Liabilities419,132 362,859 \n\nPension and Other Postretirement Benefits54,158 68,816 \n\nDerivative Instruments1,750 6,099 \n\nAsset Retirement Obligations175,128 159,056 \n\nOther Noncurrent Liabilities68,509 71,044 \n\nTotal Liabilities1,898,081 1,923,843 \n\nCommitments and Contingencies\n\nTotal Capitalization and Liabilities$8,139,270 $7,521,523 \n\nThe accompanying notes are an integral part of these financial statements.\n\n(Concluded)\n\n46\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nTUCSON ELECTRIC POWER COMPANY\n\nCONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY\n\n(Amounts in thousands)\n\nCommon StockCapital Stock ExpenseRetained EarningsAccumulated Other Comprehensive LossTotal Stockholder's Equity\n\nBalances as of December 31, 2022$1,696,539 $(6,357)$968,367 $(2,884)$2,655,665 \n\nNet Income258,654 258,654 \n\nOther Comprehensive Income (Loss), Net of Tax(945)(945)\n\nDividends Declared to Parent(64,100)(64,100)\n\nBalances as of December 31, 2023$1,696,539 $(6,357)$1,162,921 $(3,829)$2,849,274 \n\nNet Income288,992 288,992 \n\nOther Comprehensive Income (Loss), Net of Tax(186)(186)\n\nDividends Declared to Parent(85,000)(85,000)\n\nContributions from Parent50,000 50,000 \n\nBalances as of December 31, 2024$1,746,539 $(6,357)$1,366,913 $(4,015)$3,103,080 \n\nNet Income283,382 283,382 \n\nOther Comprehensive Income (Loss), Net of Tax(2,915)(2,915)\n\nContributions from Parent65,000 65,000 \n\nBalances as of December 31, 2025$1,811,539 $(6,357)$1,650,295 $(6,930)$3,448,547 \n\nThe accompanying notes are an integral part of these financial statements.\n\n47\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS\n\nNOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES\n\nTEP is a regulated utility that generates, transmits, and distributes electricity to approximately 457,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the Western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.\n\nBASIS OF PRESENTATION\n\nTEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities on the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. TEP has reclassified Asset Retirement Obligations from Other Noncurrent Liabilities in the prior period to a separately disclosed line on the Consolidated Balance Sheets to conform with the current period presentation. The reclassification had no impact on TEP’s results of operation, financial position, or cash flows.\n\nAccounting for Regulated Operations\n\nTEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Customer Rates charged to retail customers or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods.\n\nEstimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters.\n\nTEP applies regulatory accounting as the following conditions exist:\n\n•an independent regulator sets rates;\n\n•the regulator sets the rates to recover the specific enterprise’s costs of providing service; and\n\n•rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers.\n\nVariable Interest Entities\n\nA VIE is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.\n\nTEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP regularly evaluates its primary beneficiary conclusions to determine if changes have occurred that impact its VIE assessment.\n\nAs of December 31, 2025, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing\n\n48\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nthe power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.\n\nREPORTABLE SEGMENTS\n\nTEP's principal business operations include generating, transmitting, and distributing electricity to its retail customers. In addition to retail sales, TEP sells electricity, transmission, and ancillary services to other utilities, municipalities, and energy marketing companies on a wholesale basis. TEP has one operating segment, its regulated utility operations. TEP’s CODM is Susan M. Gray who holds the position of Chief Executive Officer of TEP and its parent company, UNS Energy. The CODM uses net income to assess performance and decide how to allocate resources for UNS Energy overall (including employees and financial or capital resources) predominantly in the annual budget and forecasting process. Net income is reported on the Consolidated Statements of Income. Operations and Maintenance expense includes expenses reimbursed by third-parties and expenses related to customer-funded RES and DSM programs. Operations and Maintenance expense excluding these reimbursable and customer funded expenses totaled $355 million, $343 million, and $317 million for the years ended December 31, 2025, 2024, and 2023, respectively. Total assets, the measure of segment assets, is reported on the Consolidated Balance Sheets. Capital expenditures are reported on the Consolidated Statements of Cash Flows.\n\nNEW ACCOUNTING STANDARDS ISSUED AND ADOPTED\n\nThe following new authoritative accounting guidance issued by the FASB was adopted in 2025. Adoption of the new guidance had an insignificant impact on TEP's financial position, results of operations, cash flows, and disclosures.\n\nIncome Tax Disclosures\n\nIn December 2023, the FASB issued accounting guidance that requires additional annual disclosure of disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. TEP adopted the guidance as of January 1, 2025, and applied the standard retrospectively. See Note 13 for additional disclosures related to income taxes.\n\nNEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED\n\nStandards Recently Issued by the FASB\n\nThe following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected in TEP’s financial statements. Unless otherwise indicated, TEP is assessing the impact such guidance may have on TEP’s financial position, results of operations, cash flows, and disclosures.\n\nGovernment Grants\n\nIn December 2025, the FASB issued accounting guidance that establishes recognition, measurement, and presentation requirements for government grants for business entities. The update applies to transfers of monetary or tangible nonmonetary assets from a government to a business entity, excluding certain transaction types such as tax incentives. The recognition, measurement, and presentation of a government grant is dependent on the classification of the grant as either related to an asset or related to income. Grants cannot be recognized until it is probable that the entity will comply with the conditions attached to the grant and that the grant will be received. The amendments are effective for annual and interim reporting periods beginning after January 1, 2029, for public business entities. The guidance may be applied using a modified prospective, modified retrospective, or full retrospective approach. Early adoption is permitted.\n\nTargeted Improvements to the Accounting for Internal-Use Software\n\nIn September 2025, the FASB issued accounting guidance that updates the recognition criteria for internal-use software. The update removes references to software development project stages and requires capitalization of software costs once: (i) management has authorized and committed to funding the project; and (ii) it is probable that the project will be completed and the software will perform its intended function. Evaluating the probability that the project will be completed includes an assessment of whether significant development uncertainty exists. The amendment requires entities to apply the disclosure requirements applicable to property, plant, and equipment to all capitalized internal-use software costs, irrespective of financial statement presentation. The amendments are effective for annual and interim reporting periods beginning after January 1, 2028. The guidance may be applied prospectively, retrospectively, or using a modified transition approach. Early adoption is permitted.\n\n49\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nDisaggregation of Income Statement Expenses\n\nIn November 2024, the FASB issued accounting guidance that requires disaggregation of income statement expenses into specified categories in the footnotes to the financial statements. In January 2025, the FASB issued accounting guidance clarifying the effective date of this standard. The amendments are effective for annual periods beginning January 1, 2027, and interim reporting periods beginning after January 1, 2028. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted.\n\nSEC Climate-Related Disclosures\n\nThe following final SEC rules regarding climate-related disclosures are pending further action by the SEC.\n\nIn March 2024, the SEC issued final rules that require disclosure of climate related risks and greenhouse gas emissions. In April 2024, the SEC issued an order staying the final rules pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit (Eighth Circuit). In March 2025, the SEC voted to end its defense of the rules and sent a letter to the Court stating that the SEC withdraws its defense. In April 2025, the Eighth Circuit ordered the litigation to be suspended and directed the SEC to indicate within 90 days whether the SEC will reconsider or review the climate disclosure rules. In July 2025, the SEC filed a response with the Eighth Circuit, indicating that the SEC does not intend to review or reconsider the climate disclosure rules at this time and requesting the court to lift the suspension on the litigation and issue a ruling. In September 2025, the Eighth Circuit paused its consideration of legal challenges against the rules, pending further action by the SEC. TEP awaits the SEC's decision whether it will defend, amend, or withdraw the rules, the timing of which TEP cannot currently predict.\n\nUSE OF ACCOUNTING ESTIMATES\n\nManagement uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect:\n\n•assets and liabilities in the balance sheet at the dates of the financial statements;\n\n•disclosures about contingent assets and liabilities at the dates of the financial statements; and\n\n•revenues and expenses in the income statement during the periods presented.\n\nBecause these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates.\n\nAsset Retirement Obligations\n\nTEP has identified legal AROs related to the retirement of certain assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if a reasonable estimate of the liability can be made. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP defers the accretion and depreciation expense associated with its legal AROs to a regulatory asset or liability account based on the ACC's approval of these costs in its depreciation rates.\n\nDepreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Customer Rates and records an obligation for estimated costs of removal as regulatory liabilities.\n\nContingencies\n\nReserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable, and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these legal proceedings and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.\n\n50\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nCASH AND CASH EQUIVALENTS\n\nTEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.\n\nRESTRICTED CASH\n\nRestricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Consolidated Statements of Cash Flows:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nCash and Cash Equivalents$26 $14 $9 \n\nRestricted Cash included in:\n\nInvestments and Other Property23 28 24 \n\nCurrent Assets—Other7 7 10 \n\nTotal Cash, Cash Equivalents, and Restricted Cash$56 $49 $43 \n\nRestricted cash primarily represents cash contractually required to be set aside to pay TEP's share of final mine reclamation and decommissioning costs at San Juan.\n\nALLOWANCE FOR CREDIT LOSSES\n\nTEP records an allowance for credit losses to reduce retail accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible.\n\nINVENTORY\n\nTEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in Customer Rates. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.\n\nUTILITY PLANT\n\nUtility plant includes the business property and equipment that supports electric service, consisting primarily of generation facilities and transmission and distribution systems. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction.\n\nThe cost of repairs and maintenance, including planned generation facility overhauls, are expensed to Operations and Maintenance expense on the Consolidated Statements of Income as costs are incurred.\n\nWhen TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost net of removal costs and any salvage value. There is no impact to the income statement.\n\nAFUDC and Capitalized Interest\n\nAFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.\n\n51\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nThe average AFUDC rates on regulated construction expenditures are included in the table below:\n\n202520242023\n\nAverage AFUDC Rates7.11 %7.01 %6.91 %\n\nDepreciation\n\nDepreciation is recorded for owned utility plant on a group method straight-line basis, excluding software intangible plant, at depreciation rates based on the economic lives of the assets, including estimates for salvage value and removal costs. Depreciation rates for TEP's generation, distribution, and general plant assets are approved by the ACC, and depreciation rates for TEP's transmission, general plant, and intangible assets are subject to approval by FERC.\n\nBelow are the average annual depreciation rates for all utility plant:\n\n202520242023\n\nAverage Annual Depreciation Rates3.28 %3.22 %3.01 %\n\nComputer Software and Cloud Computing Costs\n\nCosts incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Other Noncurrent Assets on the Consolidated Balance Sheets and amortized over three to five years. Amortization of implementation costs is presented in Operations and Maintenance expense on the Consolidated Statements of Income. If the associated software is impaired, the carrying value is reduced and recorded as an expense in the income statement.\n\nEVALUATION OF ASSETS FOR IMPAIRMENT\n\nLong-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time.\n\nDEFERRED FINANCING COSTS\n\nCosts to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and filing costs.\n\nTEP accounts for debt issuance costs related to credit facility arrangements as an asset.\n\nThe gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the life of the original debt.\n\nOPERATING REVENUES\n\nTEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved or market-based tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date past due and charges the customer a late payment fee, except during service disconnection moratoriums. No component of the transaction price is allocated to unsatisfied performance obligations.\n\nTEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which it expects to be entitled and recognizes a refund liability until it is certain it will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods.\n\n52\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nLEASES\n\nWhen a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g. common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.\n\nTEP has operating leases for office facilities, land, rail cars, and communication tower space that are included in the balance sheet as follows:\n\nDecember 31,\n\n(in millions)20252024\n\nLease Assets\n\nOther Noncurrent Assets$4 $4 \n\nLease Liabilities\n\nCurrent Liabilities, Other1 1 \n\nOther Noncurrent Liabilities3 3 \n\nAs of December 31, 2025, TEP's future minimum operating lease payments, excluding payments to lessors for variable costs, are $1 million or less in each year from 2026 through 2030 and $2 million thereafter.\n\nTEP's variable lease costs primarily consist of capacity payments for the right to use energy storage facilities associated with certain renewable PPAs with terms through 2041. Variable lease costs totaled $4 million, $3 million, and $4 million for the years ended December 31, 2025, 2024, and 2023, respectively.\n\nPURCHASED POWER AND FUEL ADJUSTMENT CLAUSE\n\nTEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities, and cost under-recoveries are deferred as regulatory assets.\n\nRENEWABLE ENERGY CREDITS\n\nThe ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional generation constitutes the REC cost. For PPAs that achieved commercial operation prior to the filing of the 2024 RES implementation plan, these REC costs are recoverable through the RES tariff. For PPAs that achieved commercial operation after the filing of the 2024 RES implementation plan, the market cost of conventional power and all associated PPA costs, including renewable energy premiums, are recoverable through the PPFAC mechanism.\n\n53\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nWhen RECs are purchased, TEP records the cost of the RECs, an indefinite-lived intangible asset, as other assets, and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and retail revenues in an equal amount.\n\nThe table below summarizes the balance of TEP's RECs that are included in Other Noncurrent Assets on the Consolidated Balance Sheets:\n\nDecember 31,\n\n(in millions)20252024\n\nBeginning of Period$101 $94 \n\nPurchased51 55 \n\nUsed for Compliance(50)(48)\n\nEnd of Period$102 $101 \n\nTEP expenses the cost of internally developed RECs and PBI activity, which are not included in the table above. PBI costs are recoverable through the RES tariff.\n\nIn October 2025, a NOPR recommending the repeal of the RES rules was published in the Arizona Administrative Register. TEP is unable to predict the timing or outcome of this rulemaking proceeding.\n\nPENSION AND OTHER POSTRETIREMENT BENEFITS\n\nTEP sponsors noncontributory, defined benefit pension plans for substantially all employees hired before January 1, 2025. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees hired before January 1, 2025. Employees in non-bargaining roles and specified bargaining units hired on or after January 1, 2025, are not eligible for pension benefits.\n\nThe Company recognizes an asset for a defined benefit plan's overfunded status or a liability for a plan's underfunded status in the balance sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement benefit plans. TEP records changes in its pension and other postretirement benefit plans, not yet reflected in net periodic benefit costs, as a regulatory asset or liability, when such amounts are probable of future recovery or refund in rates charged to retail customers over the estimated service lives of employees.\n\nAdditionally, TEP maintains a SERP for certain executive management. Changes in SERP benefit obligations not yet recognized in the income statement are recognized as a component of AOCL since SERP expense is not currently recoverable in rates. The SERP for certain executive management who commence service on or after January 1, 2025, will include enhanced defined contribution benefits.\n\nPension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually.\n\nFAIR VALUE\n\nAs defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able, and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.\n\nDERIVATIVE INSTRUMENTS\n\nThe Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; and (ii) reduce exposure to energy commodity price volatility. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Derivative instruments that do not meet the normal purchase or normal sale scope exception are\n\n54\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nrecognized as either assets or liabilities in the balance sheet and are measured at fair value. The cash impacts of settled derivatives are recorded in Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity in the income statement.\n\nFor derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.\n\nTAXES OTHER THAN INCOME TAXES\n\nTEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.\n\nINCOME TAXES\n\nDue to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities in the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized.\n\nTax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income.\n\nFederal ITCs are deferred and amortized as a reduction to income tax expense over a time period approved by the ACC. All other federal and state income tax credits, including PTCs, are treated as a reduction to income tax expense in the year the credit arises.\n\nCurrent and deferred income tax expense is calculated using the separate-return method, as if TEP filed its own tax return. Under the tax sharing agreement with UNS Energy, TEP makes payments to UNS Energy using this same method.\n\nInvestment Tax Credits\n\nTEP has elected to apply ASC 740, Income Taxes, to nonrefundable, transferable ITCs. TEP also presents any gain or loss from the sale of these credits as a component of Income Tax Expense and considers the expected proceeds from such sales in evaluating the realizability of deferred tax assets associated with the credits.\n\nThe ACC approved TEP's request to defer recognition of Roadrunner Reserve I ITC-related amounts that would otherwise be included in Income Tax Expense. On the effective date of new rates, TEP expects to amortize the deferred ITC as a reduction to Income Tax Expense over five years.\n\nNOTE 2. REGULATORY MATTERS\n\nThe ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce.\n\n55\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nRATE CASE MATTERS\n\n2025 Rate Case\n\nIn June 2025, TEP filed a general rate case with the ACC based on a test year ended December 31, 2024.\n\nTEP's key 2025 Rate Case proposals are described below:\n\n•a $172 million net increase in retail revenues comprised of the following components:\n\n◦a non-fuel retail revenue increase of $220 million over test year non-fuel retail revenues,\n\n◦a $26 million decrease in fuel-related retail revenues, and\n\n◦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;\n\n•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%;\n\n•a capital structure for ratemaking purposes of approximately 55% common equity and 45% long-term debt;\n\n•a new ARAM that is a formula rate adjustor designed to update rates annually based on historical changes in TEP's revenue requirement;\n\n◦if the proposed ARAM is not approved, a new SRB mechanism, which would help recover investments in significant generation resources, and a new LIRA, which would allow TEP to recover or refund differences between actual limited income tariff costs and the costs included in base rates; and\n\n•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.\n\nTEP requested new rates to be implemented by September 1, 2026. TEP cannot predict the timing or outcome of this proceeding.\n\nCOST RECOVERY MECHANISMS\n\nTEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.\n\nPurchased Power and Fuel Adjustment Clause\n\nTEP's PPFAC rate is adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Customer Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period.\n\nThe table below summarizes the PPFAC regulatory asset (liability) balance:\n\nYears Ended December 31,\n\n(in millions)20252024\n\nBeginning of Period$(49)$55 \n\nDeferred Fuel and Purchased Power Costs (1)\n312 277 \n\nPPFAC and Base Power Recoveries(295)(381)\n\nEnd of Period$(32)$(49)\n\n(1)Includes costs eligible for recovery through the PPFAC and base power rates.\n\n56\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nEnvironmental Compliance Adjustor\n\nThe ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided they are not already recovered in base rates or recovered through another commission-approved mechanism. Costs eligible for the ECA are subject to a cap equal to 0.5% of total annual retail revenue.\n\nTax Expense Adjustor Mechanism\n\nThe TEAM allows for the timely recovery of future significant income tax changes and provides TEP the ability to pass through as a kWh surcharge: (i) the change in EDIT compared to the test year; and (ii) the income tax effects of tax legislation that materially impacts TEP's authorized revenue requirement. TEP files an annual update to the TEAM rate in August each year. New TEAM rates take effect in January of each year.\n\nTransmission Cost Adjustor\n\nThe TCA allows for timely recovery or refund of actual costs, net of applicable credits, required to provide transmission services to retail customers. TEP files new TCA rates with the ACC in December each year based on changes in net costs required to provide transmission services to retail customers. New TCA rates take effect in January of each year.\n\nRenewable Energy Standard\n\nThe 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. In 2025, TEP's retail kWh sales attributable to renewable energy met the 2025 RES requirement of 15%. Consistent with prior years, TEP met these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. TEP recovers approved costs of meeting the requirements from retail customers through a RES tariff.\n\nIn May 2024, the ACC approved an extension of TEP's 2021 RES implementation plan with a budget of $66 million until further order of the ACC and an increase to the RES tariff to recover under-collected RES funds totaling $17 million. The ACC also waived for TEP the general requirement that Arizona utilities file an annual RES implementation plan. The approved amount funds: (i) above market cost for renewable power purchases under agreements that were operational when the implementation plans were filed; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.\n\nIn October 2025, a NOPR recommending the repeal of the RES rules was published in the Arizona Administrative Register. TEP is unable to predict the timing or outcome of this rulemaking proceeding.\n\nEnergy Efficiency Standards\n\nTEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs of implementing DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year.\n\nIn the 2023 Rate Order, the ACC approved a 2023 energy efficiency implementation plan with a cumulative three-year budget of $72 million, which is collected through the DSM surcharge.\n\nIn October 2025, a NOPR recommending the repeal of the EE Standards was published in the Arizona Administrative Register. TEP is unable to predict the timing or outcome of this rulemaking proceeding.\n\n2020 IRP Energy Efficiency Target\n\nIn 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP periodically reports on its energy efficiency savings in filings with the ACC.\n\nLost Fixed Cost Recovery Mechanism\n\nThe LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues based on an estimate of lost retail kWh sales during the period. TEP is required to make an annual\n\n57\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nfiling with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.\n\nREGULATORY ASSETS AND LIABILITIES\n\nRegulatory assets and liabilities recorded on the Consolidated Balance Sheets are summarized in the table below:\n\nRemaining Recovery Period (years)December 31,\n\n($ in millions)20252024\n\nRegulatory Assets\n\nPension and Other Postretirement Benefits (Note 9)\nVarious$91 $103 \n\nEarly Generation Retirement CostsVarious36 46 \n\nLost Fixed Cost Recovery133 31 \n\nProperty Tax Deferrals (1)\n132 32 \n\nTransmission Revenue Requirement Balancing Account132 11 \n\nDerivatives (Note 12)\n423 19 \n\nRoadrunner Reserve I Accounting Order (2)\nVarious16 — \n\nSelf-Insured Medical & Short-Term Disability17 4 \n\nIncome Taxes Recoverable through Future Rates (3)\nVarious4 5 \n\nFinal Mine Reclamation (4)\n144 9 \n\nUnamortized Loss on Reacquired DebtVarious3 4 \n\nOther Regulatory AssetsVarious13 12 \n\nTotal Regulatory Assets294 276 \n\nLess Current Portion1127 98 \n\nTotal Noncurrent Regulatory Assets$167 $178 \n\nRegulatory Liabilities\n\nIncome Taxes Payable through Future Rates (3)\nVarious$199 $209 \n\nRenewable Energy StandardVarious102 88 \n\nDeferred Investment Tax Credits (5)\nVarious94 4 \n\nNet Cost of Removal (6)\nVarious75 110 \n\nPension and Other Postretirement Benefits (Note 9)\nVarious32 19 \n\nOver-Recovered Fuel and Purchased Energy Costs132 49 \n\nDerivatives (Note 12)\n420 22 \n\nDemand Side Management19 5 \n\nTotal Regulatory Liabilities563 506 \n\nLess Current Portion1144 143 \n\nTotal Noncurrent Regulatory Liabilities$419 $363 \n\n(1)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes.\n\n(2)In April 2025, the ACC issued an accounting order allowing TEP to defer for future recovery in the 2025 Rate Case certain incurred costs associated with owning, operating, and maintaining Roadrunner Reserve I, including depreciation and amortization, property taxes, operations and maintenance expense, interest expense, and ITC transaction costs. These costs will be partially offset by benefits associated with ITCs.\n\n(3)Amortized over 10 years or the lives of the assets. See Note 1 and Note 13 for additional information regarding income taxes.\n\n(4)Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022.\n\n58\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\n(5)As federal ITCs are deferred, TEP records a regulatory liability to be refunded to customers. On the effective date of new rates, TEP expects to begin amortizing the portion of the deferred ITCs related to Roadrunner Reserve I over five years.\n\n(6)Represents an estimate of the future cost of retirement, net of salvage value. The reserve is funded through ACC‑approved depreciation rates for transmission, distribution, generation, and general plant assets. These amounts are billed to customers but will not be spent until the assets are retired.\n\nRegulatory assets are either being collected or are expected to be collected through Customer Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Transmission Revenue Requirement Balancing Account, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances.\n\nIMPACTS OF REGULATORY ACCOUNTING\n\nIf TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.\n\nNOTE 3. UTILITY PLANT AND JOINTLY-OWNED FACILITIES\n\nUTILITY PLANT\n\nThe following table shows Plant in Service on the Consolidated Balance Sheets by major class:\n\nAnnual Depreciation Rate (4)\n\nAverage Remaining Life in Years (4)\nDecember 31,\n\n($ in millions)20252024\n\nPlant in Service\n\nGeneration3.05%20$3,731 $3,651 \n\nDistribution2.61%442,617 2,407 \n\nTransmission1.69%311,519 1,370 \n\nEnergy Storage (1)\n6.77%15355 — \n\nGeneral Plant6.13%7590 703 \n\nIntangible Plant, Software Costs, and Other (2)\nVariousVarious180 210 \n\nPlant Held for Future Use——9 9 \n\nTotal Plant in Service (3)\n$9,001 $8,350 \n\n(1)In July 2025, TEP placed in service Roadrunner Reserve I. Annual Depreciation Rate and Average Remaining Life in Years are based on an industry study and reflect rates requested for approval in the 2025 Rate Case. TEP is deferring depreciation expense for future recovery as part of the Roadrunner Reserve I Accounting Order.\n\n(2)Primarily represents computer software, which is being amortized over three to five years for smaller application software and 10 years for large enterprise software and has an average remaining life of three years.\n\n(3)Includes plant acquisition adjustments of $(206) million as of December 31, 2025 and 2024.\n\n(4)With the exception of Transmission, Energy Storage, and Intangible Plant, based on the 2022 depreciation study available for the major classes of Plant in Service, effective September 1, 2023, as approved by the ACC as part of the 2023 Rate Order. TEP implemented new depreciation rates for Transmission based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 2022 Final FERC Rate Order.\n\nRoadrunner Reserve I\n\nIn July 2025, TEP placed in service Roadrunner Reserve I, a standalone battery energy storage system facility with a nominal capacity rating of 200 MW and energy capacity of 800 MWh, located in southeast Tucson. As of December 31, 2025, there was $355 million in costs related to Roadrunner Reserve I in Plant in Service on the Consolidated Balance Sheets.\n\n59\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nAmortization of Intangible Plant\n\nIntangible Plant primarily consists of computer software. Accumulated amortization of computer software costs was $64 million and $104 million as of December 31, 2025 and 2024, respectively. Amortization of computer software costs totaled $26 million in 2025, $25 million in 2024, and $27 million in 2023. Future estimated amortization costs for existing computer software are $30 million in 2026, $25 million in 2027, $20 million in 2028, $16 million in 2029, and $11 million in 2030.\n\nIntangible Plant includes $(4) million in acquisition discounts not subject to amortization as of December 31, 2025 and 2024.\n\nJOINTLY-OWNED FACILITIES\n\nAs of December 31, 2025, TEP was a participant in the following jointly-owned generation facilities and transmission systems:\n\n($ in millions)Ownership PercentagePlant in ServiceConstruction Work in ProgressAccumulated DepreciationNet Book Value\n\nFour Corners Units 4 and 57.0%$213 $2 $(114)$101 \n\nLuna 33.3%72 1 6 79 \n\nGila River Unit 375.0%237 4 (64)177 \n\nGila River Common Facilities43.8%84 — (33)51 \n\nSpringerville Coal Handling Facilities83.0%207 1 (109)99 \n\nSpringerville Common Facilities86.0%407 1 (249)159 \n\nTransmission FacilitiesVarious601 26 (247)380 \n\nTotal$1,821 $35 $(810)$1,046 \n\nAs a participant in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.\n\nASSET RETIREMENT OBLIGATIONS\n\nThe liability for AROs, primarily related to TEP's generation assets, is included in Current Liabilities—Other and Asset Retirement Obligations on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of TEP's ARO liabilities:\n\nDecember 31,\n\n(in millions)20252024\n\nBeginning of Period$168 $114 \n\nLiabilities Incurred (1)\n9 — \n\nLiabilities Settled (2)\n(3)(2)\n\nRegulatory Deferral/Accretion Expense8 6 \n\nRevisions to the Present Value of Estimated Cash Flows (3)\n(2)50 \n\nEnd of Period$180 $168 \n\n(1)In 2025, TEP incurred an ARO for Roadrunner Reserve I.\n\n(2)Primarily related to the retirement of Navajo and San Juan.\n\n(3)In 2025, primarily related to revised decommissioning estimates for San Juan and Four Corners. In 2024, primarily related to revised cost estimates to close the Springerville coal ash landfill.\n\nNOTE 4. REVENUE\n\nTEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration.\n\n60\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nDISAGGREGATION OF REVENUES\n\nThe following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nRetail$1,250 $1,321 $1,283 \n\nWholesale234 268 364 \n\nOther Services102 120 124 \n\nRevenues from Contracts with Customers1,586 1,709 1,771 \n\nAlternative Revenues48 39 38 \n\nOther55 57 66 \n\nTotal Operating Revenues$1,689 $1,805 $1,875 \n\nRetail Revenues\n\nTEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Customer Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during spring and summer months then decrease during fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets.\n\nWholesale Revenues\n\nTEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand for capacity or the reading of meters for power. For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income.\n\nOther Services Revenues\n\nOther Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, reimbursement of various operating expenses for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities by the lessee of Springerville Unit 3, and miscellaneous service-related revenues.\n\nAlternative Revenues\n\nAlternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR and ECA mechanisms, OATT and TCA balancing activity, and DSM performance incentive as alternative revenues. See Note 2 for additional information regarding these cost recovery mechanisms and performance incentive.\n\nOther Revenues\n\nOther Revenues include gains and losses on derivative contracts, common cost allocations to affiliates, and late and returned payment finance charges. See Note 6 for information regarding revenue from related parties and Note 12 for information regarding derivative instruments.\n\n61\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nNOTE 5. ACCOUNTS RECEIVABLE\n\nThe following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:\n\nDecember 31,\n\n(in millions)20252024\n\nRetail$107 $112 \n\nRetail, Unbilled47 43 \n\nRetail, Allowance for Credit Losses(14)(13)\n\nWholesale (1)\n33 24 \n\nDue from Affiliates (Note 6)\n9 10 \n\nOther14 20 \n\nAccounts Receivable, Net$196 $196 \n\n(1)Includes $10 million and $8 million as of December 31, 2025 and 2024, respectively, of receivables related to revenue from derivative instruments.\n\nALLOWANCE FOR CREDIT LOSSES\n\nTEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable, Net on the Consolidated Balance Sheets:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nBeginning of Period$(13)$(12)$(9)\n\nCredit Loss Expense(8)(6)(7)\n\nWrite-offs7 5 4 \n\nEnd of Period$(14)$(13)$(12)\n\nNOTE 6. RELATED PARTY TRANSACTIONS\n\nTEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services.\n\nThe following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets:\n\nDecember 31,\n\n(in millions)20252024\n\nReceivables from Related Parties\n\nUNS Electric$7 $7 \n\nUNS Gas2 2 \n\nUNS Energy— 1 \n\nTotal Due from Related Parties$9 $10 \n\nPayables to Related Parties\n\nUNS Energy$4 $1 \n\nUNS Electric1 1 \n\nTotal Due to Related Parties$5 $2 \n\n62\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nThe following table presents the components of related party transactions included on the Consolidated Statements of Income:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nGoods and Services Provided by TEP to Affiliates\n\nCommon Costs, UNS Energy Affiliates (1)\n$26 $25 $23 \n\nTransmission Revenues, UNS Electric (2)\n7 8 8 \n\nWholesale Revenues, UNS Electric (2)\n3 20 39 \n\nControl Area Services, UNS Electric (3)\n2 2 2 \n\nGoods and Services Provided by Affiliates to TEP\n\nCorporate Services, UNS Energy (4)\n$9 $9 $8 \n\nPurchased Power, UNS Electric (2)\n3 — 2 \n\nCorporate Services, UNS Energy Affiliates (5)\n1 2 1 \n\nCapacity Charges, UNS Gas (6)\n1 1 2 \n\n(1)Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.\n\n(2)TEP and UNS Electric sell power to each other, and TEP sells transmission services to UNS Electric. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT.\n\n(3)TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement.\n\n(4)Corporate Services, UNS Energy includes legal and audit, and Fortis' management fees. Costs for corporate services provided by UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 84% of UNS Energy's allocated costs. TEP's share of Fortis' management fees was $8 million in 2025, and $7 million in each of 2024 and 2023.\n\n(5)Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.\n\n(6)UNS Gas charges TEP for natural gas capacity used to supply Gila River.\n\n63\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nNOTE 7. DEBT AND CREDIT AGREEMENT\n\nDEBT\n\nLong-term debt matures more than one year from the date of debt issuance. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets:\n\nDecember 31,\n\n($ in millions)Interest RateMaturity Date20252024\n\nNotes\n\n2020 Senior Notes1.50%2030$300 $300 \n\n2022 Senior Notes3.25%2032325 325 \n\n2024 Senior Notes5.20%2034400 400 \n\n2014 Senior Notes5.00%2044150 150 \n\n2018 Senior Notes4.85%2048300 300 \n\n2020 Senior Notes4.00%2050350 350 \n\n2021 Senior Notes3.25%2051325 325 \n\n2023 Senior Notes5.50%2053375 375 \n\n2025 Senior Notes5.90%2055300 — \n\nTotal Long-Term Debt (1)\n2,825 2,525 \n\nLess Unamortized Discount and Debt Issuance Costs32 30 \n\nLess Current Maturities of Long-Term Debt— — \n\nTotal Long-Term Debt, Net$2,793 $2,495 \n\n(1)As of December 31, 2025 and 2024, all of TEP's debt is unsecured.\n\nDebt Issuances and Redemptions\n\nIn February 2025, TEP issued and sold $300 million aggregate principal amount of 5.90% senior unsecured notes due April 2055. TEP may redeem the notes prior to October 15, 2054, with a make-whole premium plus accrued interest. On or after October 15, 2054, TEP may redeem the notes at par plus accrued interest.\n\nIn August 2024, TEP issued and sold $400 million aggregate principal amount of 5.20% senior unsecured notes due September 2034. TEP may redeem the notes prior to June 15, 2034, with a make-whole premium plus accrued interest. On or after June 15, 2034, TEP may redeem the notes at par plus accrued interest.\n\nIn December 2024, TEP redeemed at par prior to maturity $300 million aggregate principal amount of 3.05% senior unsecured notes.\n\nMaturities\n\nLong-term debt matures on the following dates:\n\n($ in millions)\nLong-Term Debt (1)\n\n2026$— \n\n2027— \n\n2028— \n\n2029— \n\n2030300 \n\nThereafter2,525 \n\nTotal$2,825 \n\n(1)Total long-term debt excludes $23 million of related unamortized debt issuance costs and $9 million of unamortized original issue discount.\n\n64\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nCREDIT AGREEMENT\n\nIn October 2025, the maturity date of the 2021 Credit Agreement was extended to October 2028. The original credit agreement provided for two optional one-year extensions if certain conditions were satisfied. Both optional one-year extensions have been exercised. Amounts borrowed under the 2021 Credit Agreement are used for working capital and other general corporate purposes and are recorded in Borrowings Under Credit Agreement on the Consolidated Balance Sheets. Interest rates and fees are based on a pricing grid tied to TEP's credit rating.\n\nLOCs are issued from time to time to support energy procurement, hedging transactions, and other business activities.\n\nThe terms of the 2021 Credit Agreement are as follows:\n\nSub-Limit Swingline(1)\nSub-Limit LOC\nWeighted Average Interest Rate(3)\n\nCapacity\nBorrowed(2)\nAvailable\nPricing(4)\n\n($ in millions)December 31, 2025\n\nAgreement$250 $15 $50 $14 $236 — %\nSOFR+ADJ 0.10%+1.050% or ABR+0.050%\n\n($ in millions)December 31, 2024\n\nAgreement$250 $15 $50 $82 $168 5.52 %\nSOFR+ADJ 0.10%+1.050% or ABR+0.050%\n\n(1)ABR pricing would apply to swingline loans.\n\n(2)The borrowed amount includes LOCs totaling $14 million at a rate of 1.050% per annum issued in October and November 2024 to support interconnection requests, and in May 2025 to support TEP's participation in Markets+. Upon TEP's request, LOCs totaling $6 million issued in October 2024 were canceled in October 2025. The remaining LOCs expire at various dates between October 2026 and May 2027.\n\n(3)The weighted average interest rate is calculated on outstanding revolver borrowings.\n\n(4)TEP's pricing through October 15, 2026, may be adjusted based on performance measured using two sustainability targets: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage.\n\nNOTE 8. COMMITMENTS AND CONTINGENCIES\n\nCOMMITMENTS\n\nAs of December 31, 2025, TEP had the following commitments:\n\n(in millions)20262027202820292030ThereafterTotal\n\nMinimum Purchase Commitments\n\nFuel, Including Transportation$70 $70 $59 $59 $50 $175 $483 \n\nTransmission31 24 24 13 7 — 99 \n\nPurchase Commitments\n\nRenewable PPAs and Other - Commercially Operable 81 80 82 82 79 531 935 \n\nRenewable PPAs and Other - Non-Commercially Operable (1)\n20 31 32 24 31 465 603 \n\nRES Performance-Based Incentives4 4 4 4 4 7 27 \n\nTotal Commitments$206 $209 $201 $182 $171 $1,178 $2,147 \n\n(1)Includes purchase commitments that are contingent upon the developers obtaining commercial operation. The non-commercially operable PPAs are expected to be placed in service in 2026 and 2027.\n\nCosts for Fuel, Including Transportation, Non-Renewable Purchased Power, and Transmission are recoverable from customers through the PPFAC mechanism. Costs for PPAs commercially operable prior to the filing of the 2024 RES implementation plans are recovered through both the PPFAC and the RES tariff, while costs for PPAs commercially operable after the filing are\n\n65\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nrecovered through the PPFAC. PBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.\n\nMinimum Purchase Commitments\n\nFuel, Including Transportation\n\nTEP has long-term agreements for the purchase and delivery of coal with expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs.\n\nTEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2029 and 2048. In September 2025, TEP amended and extended a firm gas transportation agreement, securing capacity through 2040 to support long-term fuel supply for generation.\n\nTransmission\n\nTEP maintains long-term firm contracts for point-to-point transmission services over lines within the Western Interconnection, a regional U.S. grid. These agreements currently expire in various years between 2026 and 2031. In January 2025, TEP amended and extended one agreement to 2031 and entered into a new agreement with the same expiration date. In February 2025, TEP amended and extended another agreement to 2029. On February 8, 2026, TEP amended and extended another agreement through 2029. Estimated future payments related to this agreement, which are not included in the table above, are $6 million per year for each of the years from 2027 through 2029.\n\nPurchase Commitments\n\nRenewable Power Purchase Agreements\n\nTEP has entered into long-term renewable PPAs that require TEP to purchase 100% of the output and associated RECs from specified renewable generation facilities once those facilities achieve commercial operation. Although TEP is not obligated to make payments if power is not delivered, estimated future payments under those agreements are reflected in the table above. These agreements have varying expiration dates ranging from 2027 to 2051.\n\nRES Performance-Based Incentives\n\nTEP has entered into agreements to purchase RECs, which represent the environmental attributes of solar energy generated by retail customers. Payments for these RECs, called PBIs, are made at agreed intervals (typically quarterly) based on metered renewable energy production. These agreements have varying expiration dates ranging from 2026 to 2034.\n\nEPC Agreement\n\nIn August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. In 2025, change orders were issued that increased costs by $34 million, bringing the total EPC cost to $302 million. TEP will own and operate the facility, which will be located in southeast Tucson and will have a nominal capacity rating of 200 MW and energy capacity of 800 MWh. Roadrunner Reserve II is expected to be placed in service in 2026. TEP made payments in connection with the construction and development of Roadrunner Reserve II of $226 million in 2025 and $76 million in 2024.\n\nCONTINGENCIES\n\nLegal Matters\n\nTEP is involved in various legal proceedings that arise in the ordinary course of business. These matters include, from time to time, claims for punitive or exemplary damages. Based on currently available information, TEP does not believe that the outcome of these proceedings will have a material adverse effect on TEP's financial position, results of operations, or cash flows.\n\nMine Reclamation at Generation Facilities Not Operated by TEP\n\nTEP pays ongoing mine reclamation costs for coal mines that supply generation facilities where TEP holds an ownership interest but is not the operator. The estimated liability for final mine reclamation depends on assumptions such as projected costs, timing, and inflation. When these assumptions change, TEP adjusts future expense recognition over the remaining term of the applicable coal supply agreement.\n\n66\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nTEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as part of fuel costs. Therefore, TEP defers these expenses by recording a regulatory asset and a reclamation liability over the remaining life of the respective coal supply agreement. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, any changes in the estimated liability are recorded to both the regulatory asset and reclamation liability.\n\nTEP is responsible for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP's liability related to Four Corners totaled $3 million as of December 31, 2025 and 2024, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Consolidated Balance Sheets. TEP's Four Corners coal supply agreement expires in 2031.\n\nTEP ceased operations at San Juan in 2022 following expiration of its coal supply agreement. TEP's remaining final mine reclamation liability at San Juan was $23 million and $31 million as of December 31, 2025 and 2024, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan that will remain in effect until reclamation activities are completed, which are currently projected to be completed in 2040. See Note 1 for additional information on restricted cash related to reclamation and decommissioning costs at San Juan.\n\nPerformance Guarantees\n\nTEP participates in joint generation agreements at Four Corners and Luna, which expire in 2041 and 2046, respectively. Under these agreements, all participants, including TEP, guarantee certain performance obligations. If a participant defaults on payment, the non-defaulting participants must cover the defaulting party's share of expenses based on their ownership percentage. In return, the non-defaulting participants are entitled to receive a proportionate share of the defaulting participant's generation capacity. For Luna, there is no maximum potential payment under this guarantee. For Four Corners, the maximum potential payment for non-defaulting participants is $250 million. As of December 31, 2025, no payment defaults have occurred under either agreement.\n\nThe Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default on these continuing obligations, the non-defaulting participants are entitled to seek financial recovery directly from the defaulting party.\n\nEnvironmental Matters\n\nTEP operates under federal, state, and local environmental laws and regulations covering air and water quality, renewable portfolio standards, emissions performance, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. These requirements are subject to interpretation and may be clarified by the court decisions. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations or consolidated financial results. TEP expects to recover environmental compliance costs through customer rates. TEP believes it is in material compliance with applicable environmental laws and regulations.\n\nNOTE 9. EMPLOYEE BENEFITS PLANS\n\nDEFINED BENEFIT PENSION PLANS\n\nTEP sponsors three noncontributory, defined benefit pension plans, with benefits determined by years of service and average compensation. Two plans cover non-bargaining employees, bargaining unit employees, and executive management hired on or before December 31, 2024, collectively encompassing most of the Company's workforce. Employees in non-bargaining roles and specified bargaining units hired on or after January 1, 2025, are not eligible for pension benefits. The Company funds these plans in compliance with IRS minimum contribution requirements. Additionally, TEP maintains a SERP for eligible executive management.\n\nOTHER POSTRETIREMENT BENEFITS PLAN\n\nTEP provides limited healthcare and life insurance benefits for retirees. Employees hired on or before December 31, 2024, are eligible to receive postretirement benefits upon retiring from TEP. Employees in non-bargaining roles and specified bargaining units hired on or after January 1, 2025, are not eligible for postretirement benefits.\n\n67\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nTEP funds its other postretirement benefits for bargaining unit employees through a VEBA. Other postretirement benefits for non-bargaining unit employees are self-funded.\n\nREGULATORY RECOVERY\n\nTEP records changes in non-SERP pension and other postretirement benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in AOCL since SERP expense is not recoverable in rates.\n\nThe following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet:\n\nPension BenefitsOther Postretirement Benefits\n\nDecember 31,\n\n(in millions)2025202420252024\n\nRegulatory Assets$91 $103 $— $— \n\nRegulatory Liabilities— — (32)(19)\n\nOther Noncurrent Assets11 8 7 — \n\nAccrued Employee Expenses(1)(1)(2)(2)\n\nPension and Other Postretirement Benefits(27)(30)(27)(39)\n\nAccumulated Other Comprehensive Loss9 5 — — \n\nNet Amount Recognized$83 $85 $(54)$(60)\n\nOBLIGATIONS AND FUNDED STATUS\n\nThe Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2025 and 2024. The table below presents the status of all TEP pension and other postretirement benefit plans.\n\nPension BenefitsOther Postretirement Benefits\n\nYears Ended December 31,\n\n(in millions)2025202420252024\n\nChange in Benefit Obligation\n\nBeginning of Period$456 $461 $71 $83 \n\nActuarial Loss (Gain)24 (19)(12)(14)\n\nInterest Cost25 24 4 4 \n\nService Cost14 15 4 4 \n\nBenefits Paid(26)(25)(5)(6)\n\nOther Adjustment (1)\n— — (6)— \n\nEnd of Period (2)\n493 456 56 71 \n\nChange in Fair Value of Plan Assets\n\nBeginning of Period433 432 30 27 \n\nActual Return on Plan Assets58 11 5 3 \n\nBenefits Paid(25)(24)(2)(4)\n\nEmployer Contributions (3)\n10 14 1 4 \n\nEnd of Period (4)\n476 433 34 30 \n\nFunded Status at End of Period$(17)$(23)$(22)$(41)\n\n(1)Reclassified continuation of healthcare benefits for a limited population to a separate liability.\n\n(2)The increase in the pension benefit obligation was primarily due to a decrease in the discount rate. The decrease in the other postretirement benefit obligation resulted from a change in actuarial assumption that eliminated a certain benefit accrual for active participants. This change was recognized as an increase in TEP's regulatory liabilities.\n\n(3)TEP expects to contribute approximately $12 million to the pension plans and does not anticipate making any contributions to the VEBA trust in 2026.\n\n68\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\n(4)The increase in pension and other postretirement benefit plan assets was primarily due to positive equity and fixed income returns.\n\nAs of December 31, 2025, one pension plan had a projected benefit obligation in excess of plan assets, compared to two pension plans as of December 31, 2024. For the single plan in 2025, the projected benefit obligation balance increased due to a decrease in discount rates. The plan's total projected benefit obligation was $28 million and there were no plan assets. As of December 31, 2024, the two plans with projected benefit obligations in excess of plan assets had total projected benefit obligations and plan assets of $288 million and $257 million, respectively.\n\nThe other postretirement benefits plan had an accumulated postretirement benefit obligation in excess of the fair value of plan assets as of December 31, 2025 and 2024.\n\nThe accumulated benefit obligation for all pension plans was $432 million and $399 million as of December 31, 2025 and 2024, respectively. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2025 and 2024. The following table includes information for the pension plan with an accumulated benefit obligation in excess of pension plan assets:\n\nDecember 31,\n\n(in millions)20252024\n\nAccumulated Benefit Obligation $23 $20 \n\nFair Value of Plan Assets — — \n\nThe following table provides the components of TEP’s regulatory assets, regulatory liabilities, and AOCL that have not been recognized as components of net periodic benefit cost as of the dates presented:\n\nPension BenefitsOther Postretirement Benefits\n\nDecember 31,\n\n(in millions)2025202420252024\n\nNet Loss (Gain)$99 $107 $(31)$(18)\n\nPrior Service Cost (Benefit)1 1 (1)(1)\n\nThe Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components:\n\nPension BenefitsOther Postretirement Benefits\n\nYears Ended December 31,\n\n(in millions)202520242023202520242023\n\nService Cost$14 $15 $12 $4 $4 $4 \n\nNon-Service Cost\n\nInterest Cost25 24 22 4 4 4 \n\nExpected Return on Plan Assets(31)(32)(29)(3)(2)(2)\n\nAmortization of Net Loss (Gain)5 6 5 (1)— — \n\nOther Adjustment (1)\n— — — (1)— — \n\nNet Periodic Benefit Cost$13 $13 $10 $3 $6 $6 \n\n(1)Reclassification of continuation of healthcare benefits for a limited population reduced current year net periodic benefit cost.\n\nTEP capitalized 22% of service cost as construction cost in each of 2025 and 2024, and 21% in 2023. The non-service components of net periodic benefit cost are primarily included in Other, Net on the Consolidated Statements of Income.\n\n69\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nThe changes in plan assets and benefit obligations recognized as regulatory assets, regulatory liabilities, or in AOCL were as follows:\n\nPension BenefitsOther Postretirement Benefits\n\nRegulatory AssetAOCLRegulatory Asset/Liability\n\n(in millions)202520242023202520242023202520242023\n\nCurrent Year Actuarial (Gain) Loss$(7)$2 $22 $4 $— $1 $(14)$(15)$4 \n\nAmortization of Net (Loss) Gain(5)(6)(5)— — — 1 — — \n\nTotal Recognized (Gain) Loss$(12)$(4)$17 $4 $— $1 $(13)$(15)$4 \n\nFor all pension plans, TEP amortizes prior service costs and benefits on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.\n\nNet periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time regarding these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost.\n\nTEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption for all asset classes, is based on forward-looking return expectations only.\n\nThe following table includes the weighted average assumptions used to determine benefit obligations:\n\nPension BenefitsOther Postretirement Benefits\n\n2025202420252024\n\nDiscount Rate5.8%5.9%5.4%5.7%\n\nRate of Compensation Increase3.9%3.9%N/AN/A\n\nThe following table includes the weighted average assumptions used to determine net periodic benefit costs:\n\nPension BenefitsOther Postretirement Benefits\n\n202520242023202520242023\n\nDiscount Rate, Service Cost6.1%5.6%5.9%5.9%5.3%5.7%\n\nDiscount Rate, Interest Cost5.6%5.2%5.6%5.4%5.2%5.5%\n\nRate of Compensation Increase3.9%3.2%2.9%N/AN/AN/A\n\nExpected Return on Plan Assets7.3%7.5%7.5%7.3%7.5%7.5%\n\nHealthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached:\n\nDecember 31,\n\n20252024\n\nNext Year (Pre-65)7.5%6.8%\n\nNext Year (Post-65)6.0%5.3%\n\nUltimate Rate Assumed (Pre-65 and Post-65)4.5%4.5%\n\nYear Ultimate Rate is Reached (Pre-65)20342034\n\nYear Ultimate Rate is Reached (Post-65)20302028\n\n70\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nPENSION AND OTHER POSTRETIREMENT BENEFIT PLAN ASSETS\n\nTEP calculates the fair value of plan assets on December 31st, the measurement date. Asset allocations, by asset category, on the measurement date were as follows:\n\nPensionOther Postretirement Benefits\n\n2025202420252024\n\nAsset Category\n\nEquity Securities55%55%61%56%\n\nFixed Income Securities39%38%38%38%\n\nReal Estate5%6%—%—%\n\nOther1%1%1%6%\n\nTotal100%100%100%100%\n\nAs of December 31, 2025, the fair value of VEBA trust assets was $34 million, of which $13 million were fixed income investments and $21 million were equities. As of December 31, 2024, the fair value of VEBA trust assets was $30 million, of which $11 million were fixed income investments, $17 million were equities, and $2 million were cash and short-term investments. The VEBA trust assets are primarily Level 1 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust.\n\nThe following tables present the fair value measurements of pension plan assets/(liabilities) by level within the fair value hierarchy:\n\nLevel 1Level 2Level 3Total\n\n(in millions)December 31, 2025\n\nAsset/(Liability) Category\n\nCash Equivalents$3 $— $— $3 \n\nEquity Securities:\n\nUnited States Large Cap— 81 — 81 \n\nUnited States Small Cap— 29 — 29 \n\nNon-United States— 77 — 77 \n\nGlobal— 76 — 76 \n\nFixed Income(1)185 — 184 \n\nReal Estate— — 25 25 \n\nPrivate Equity— — 1 1 \n\nTotal$2 $448 $26 $476 \n\n(in millions)December 31, 2024\n\nAsset/(Liability) Category\n\nCash Equivalents$5 $— $— $5 \n\nEquity Securities:\n\nUnited States Large Cap— 77 — 77 \n\nUnited States Small Cap— 26 — 26 \n\nNon-United States— 67 — 67 \n\nGlobal— 68 — 68 \n\nFixed Income(2)165 — 163 \n\nReal Estate— — 25 25 \n\nPrivate Equity— — 2 2 \n\nTotal$3 $403 $27 $433 \n\n•Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. Level 1 fixed income investments are based on observable market prices and are comprised of futures contracts.\n\n71\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\n•Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund.\n\n•Level 3 real estate investment values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of comparable properties.\n\n•Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.\n\nThe following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3.\n\n(in millions)Private EquityReal EstateTotal\n\nBalance as of December 31, 2023$2 $27 $29 \n\nActual Return on Plan Assets:\n\nAssets Held at Reporting Date— (2)(2)\n\nPurchases, Sales, and Settlements— — — \n\nBalance as of December 31, 20242 25 27 \n\nActual Return on Plan Assets:\n\nAssets Held at Reporting Date— — — \n\nPurchases, Sales, and Settlements(1)— (1)\n\nBalance as of December 31, 2025$1 $25 $26 \n\nPension Plan Investments\n\nInvestment Goals\n\nAsset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk.\n\nRisk Management\n\nTEP recognizes the difficulty of achieving investment objectives considering the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes.\n\nRelationship between Plan Assets and Benefit Obligations\n\nThe overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data but will be no less frequent than annually via actuarial valuation.\n\n72\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nTarget Allocation Percentages\n\nThe current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced:\n\nPensionOther Postretirement Benefits\n\nDecember 31, 2025\n\nCash/Treasury Bills2%1%\n\nEquity Securities:\n\nUnited States Large Cap16%25%\n\nUnited States Mid Cap—%8%\n\nUnited States Small Cap6%4%\n\nNon-United States Developed—%15%\n\nNon-United States Emerging—%8%\n\nGlobal Equity28%—%\n\nGlobal Infrastructure3%—%\n\nFixed Income38%39%\n\nReal Estate6%—%\n\nPrivate Equity1%—%\n\nTotal100%100%\n\nPension Fund Descriptions\n\nFor each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-party funds.\n\nESTIMATED FUTURE BENEFIT PAYMENTS\n\nTEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate:\n\n(in millions)202620272028202920302031-2035\n\nPension Benefits$29 $29 $30 $31 $31 $171 \n\nOther Postretirement Benefits4 4 4 4 4 23 \n\nDEFINED CONTRIBUTION PLAN\n\nTEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. Effective January 1, 2025, the Company began making non-elective employer contributions for certain newly hired or rehired employees in addition to matching part of all participants’ contributions to the plan. TEP made matching contributions to the plan of $10 million in 2025, $9 million in 2024, and $8 million in 2023.\n\nNOTE 10. SHARE-BASED COMPENSATION\n\n2024 FORTIS EXECUTIVE OMNIBUS EQUITY PLAN\n\nThe Fortis Board of Directors ratified the Fortis Executive Omnibus Equity Plan (2024 Omnibus Plan) effective January 2024. Under the 2024 Omnibus Plan, certain executive management of Fortis and its subsidiaries may be granted PSUs and time-based RSUs, annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the New York Stock Exchange. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur.\n\n73\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nThe following table represents PSUs and RSUs awarded by Fortis for UNS Energy:\n\n20252024\n\nPSUs\n73,513 65,385 \n\nRSUs36,757 32,693 \n\nThe awards are initially classified as liability awards because: (i) the participants have the option to elect settlement in cash or shares; and (ii) this election is contingent upon an event within the participants' control. The liability awards may be reclassified as equity awards if the participants elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis’ common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $10 million and $4 million as of December 31, 2025 and 2024, respectively.\n\nTEP's allocated portion of compensation expense is recognized in Operations and Maintenance expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date. TEP recorded $4 million and $2 million in 2025 and 2024, respectively, based on its share of Fortis' compensation expense.\n\n2020 FORTIS RESTRICTED STOCK UNIT PLAN\n\nThe Fortis Board of Directors ratified the 2020 Restricted Stock Unit Plan (2020 Plan) effective January 2020. Under the 2020 Plan, certain executive management of Fortis and its subsidiaries were granted time-based RSUs annually, which may be settled in cash or shares. Each RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur.\n\nThe following table represents RSUs awarded by Fortis for UNS Energy:\n\n202520242023\n\nRSUs (1)\n— — 26,980 \n\n(1)Effective January 2024, certain executive management RSU awards are issued through the 2024 Omnibus Plan. RSU awards are no longer issued through the 2020 Plan.\n\nThe awards were initially classified as liability awards because: (i) the participants have the option to elect settlement in cash or shares; and (ii) this election is contingent upon an event within the participants' control. The liability awards may be reclassified as equity awards if the participants elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $1 million and $2 million as of December 31, 2025 and 2024, respectively.\n\nTEP's allocated portion of compensation expense is recognized in Operations and Maintenance expense on the Consolidated Statements of Income. Compensation expense associated with unvested RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date. TEP recorded less than $1 million in 2025 and $1 million in each of 2024 and 2023, based on its share of Fortis' compensation expense.\n\n2015 SHARE UNIT PLAN\n\nThe UNS Energy Human Resources and Governance Committee approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (2015 Plan) effective January 2015. Under the 2015 Plan, key employees may be granted PSUs and time-based RSUs annually. Each PSU and RSU granted prior to 2024 is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. Each PSU and RSU granted in 2024 and thereafter is valued based on one share of Fortis common stock traded on the New York Stock Exchange. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur.\n\n74\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nThe following table represents PSUs and RSUs awarded by UNS Energy:\n\n202520242023\n\nPSUs (1)\n5,705 4,660 58,237 \n\nRSUs (1)\n2,848 2,327 2,146 \n\n(1)Effective January 2024, certain executive management PSU and RSU awards are issued through the 2024 Omnibus Plan. Certain key employees will continue to be awarded PSUs and RSUs through the 2015 Plan.\n\nThe awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $6 million and $5 million as of December 31, 2025 and 2024, respectively.\n\nTEP's allocated portion of compensation expense is recognized in Operations and Maintenance expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date. TEP recorded $3 million in 2025, $2 million in 2024, and $3 million in 2023 based on its share of UNS Energy's compensation expense.\n\nNOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION\n\nCASH TRANSACTIONS\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nInterest Paid, Net of Amounts Capitalized$102 $85 $85 \n\nIncome Taxes Paid (Refunds) (1)\n\nFederal (2)\n(42)12 6 \n\nState — 1 — \n\n(1)Reflects payments to UNS Energy under a tax sharing agreement.\n\n(2)In December 2025, TEP sold ITCs related to Roadrunner Reserve I and received $46 million in cash proceeds. See Note 13 for additional information regarding income taxes and ITCs.\n\nIncome taxes paid (net of refunds) exceeded 5% of total income taxes paid (net of refunds) in the following jurisdictions:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nState\n\nNew Mexico— 1 — \n\nNON-CASH TRANSACTIONS\n\nOther significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nAccrued Capital Expenditures $47 $51 $38 \n\nAsset Retirement Obligations Increase (Decrease) (1)\n6 44 (5)\n\nRenewable Energy Credits3 4 3 \n\nNet Cost of Removal Increase (Decrease) (2)\n(21)(10)91 \n\n(1)In 2024, increase is primarily related to revised decommissioning estimates at Springerville Generating Station.\n\n(2)Represents the change in accrual for future retirement costs, net of salvage values. This change does not impact earnings. In 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.\n\n75\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nNOTE 12. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS\n\nTEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.\n\nFINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS\n\nThe following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement:\n\nLevel 1Level 2Total\n\n(in millions)December 31, 2025\n\nAssets\n\nRestricted Cash (1)\n$30 $— $30 \n\nEnergy Derivative Contracts, Regulatory Recovery (2)\n— 28 28 \n\nEnergy Derivative Contracts, No Regulatory Recovery (2)\n— 2 2 \n\nTotal Assets30 30 60 \n\nLiabilities\n\nEnergy Derivative Contracts, Regulatory Recovery (2)\n— (33)(33)\n\nTotal Liabilities— (33)(33)\n\nTotal Assets (Liabilities), Net$30 $(3)$27 \n\n(in millions)December 31, 2024\n\nAssets\n\nRestricted Cash (1)\n$35 $— $35 \n\nEnergy Derivative Contracts, Regulatory Recovery (2)\n— 33 33 \n\nEnergy Derivative Contracts, No Regulatory Recovery (2)\n— 4 4 \n\nTotal Assets35 37 72 \n\nLiabilities\n\nEnergy Derivative Contracts, Regulatory Recovery (2)\n— (31)(31)\n\nEnergy Derivative Contracts, No Regulatory Recovery(2)\n— (1)(1)\n\nTotal Liabilities— (32)(32)\n\nTotal Assets (Liabilities), Net$35 $5 $40 \n\n(1)Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Consolidated Balance Sheets.\n\n(2)Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets.\n\n76\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nAll energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral:\n\nGross Amount Recognized in the Balance SheetsGross Amount Not Offset in the Balance SheetsNet Amount\n\nCounterparty Netting of Energy ContractsCash Collateral Received/Posted\n\n(in millions)December 31, 2025\n\nDerivative Assets\n\nEnergy Derivative Contracts$30 $17 $— $13 \n\nDerivative Liabilities\n\nEnergy Derivative Contracts(33)(17)— (16)\n\n(in millions)December 31, 2024\n\nDerivative Assets\n\nEnergy Derivative Contracts$37 $17 $— $20 \n\nDerivative Liabilities\n\nEnergy Derivative Contracts(32)(17)— (15)\n\nDERIVATIVE INSTRUMENTS\n\nTEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers.\n\nTEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.\n\nFor both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.\n\nPublished prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses.\n\nTEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.\n\nThe inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP evaluates the assumptions underlying its price curves monthly.\n\n77\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nEnergy Derivative Contracts, Regulatory Recovery\n\nTEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or liability in the balance sheet:\n\nYears Ended December 31,\n\n(in millions)20252024\n2023 (1)\n\nUnrealized Net Gain (Loss)$(7)$1 $(81)\n\n(1)Unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas.\n\nEnergy Derivative Contracts, No Regulatory Recovery\n\nTEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nOperating Revenues$23 $30 $18 \n\nDerivative Volumes\n\nAs of December 31, 2025, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:\n\nDecember 31,\n\n20252024\n\nPower Contracts GWh1,4301,634 \n\nGas Contracts BBtu72,95986,070 \n\nCREDIT RISK\n\nThe use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value.\n\nTEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.\n\nTEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to individual contracts.\n\nThe fair value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $31 million as of December 31, 2025, compared with $30 million as of December 31, 2024. TEP had no cash posted as collateral to provide credit enhancement as of December 31, 2025 and 2024. TEP would have been required to post an additional $31 million and $30 million of collateral if the credit risk contingent features had been triggered on December 31, 2025 and 2024, respectively. TEP had $16 million and $15 million in outstanding net payable balances for settled positions as of December 31, 2025 and 2024, respectively.\n\n78\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)\n\nFINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE\n\nThe fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below.\n\nThe use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt:\n\nNet Carrying ValueFair Value\n\nFair Value HierarchyDecember 31,\n\n(in millions)2025202420252024\n\nLiabilities\n\nLong-Term Debt, including Current MaturitiesLevel 2$2,793 $2,495 $2,532 $2,153 \n\nNOTE 13. INCOME TAXES\n\nIncome tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% to pre-tax income due to the following:\n\nYears Ended December 31,\n\n($ in millions)202520242023\n\nFederal Income Tax Expense at Statutory Rate$69 21 %$70 21 %$65 21 %\n\nState and Local Income Tax Expense, Net of Federal Income Tax Effect (1)\n10 3 %10 3 %11 4 %\n\nTax Credits - Energy-related (2)(3)\n(18)(6)%(22)(7)%(17)(6)%\n\nExcess Deferred Income Taxes (3)\n(11)(3)%(10)(3)%(8)(2)%\n\nAllowance for Equity Funds Used During Construction(7)(2)%(5)(1)%(2)(1)%\n\nOther2 1 %1 — %— — %\n\nTotal Income Tax Expense$45 14 %$44 13 %$49 16 %\n\n(1)Arizona state taxes represented greater than 50% of the tax effect in this category.\n\n(2)TEP realized PTC benefits of $17 million in 2025, $21 million in 2024, and $15 million in 2023, related to Oso Grande.\n\n(3)TEP provides customers with the benefit of tax credits and ACC-jurisdictional EDIT.\n\nIncome Tax Expense included on the Consolidated Statements of Income consists of the following:\n\nYears Ended December 31,\n\n(in millions)202520242023\n\nCurrent Income Tax Expense\n\nFederal$5 $12 $7 \n\nState— 1 1 \n\nTotal Current Income Tax Expense5 13 8 \n\nDeferred Income Tax Expense\n\nFederal30 22 31 \n\nFederal Investment Tax Credits(1)(2)(2)\n\nState11 11 12 \n\nTotal Deferred Income Tax Expense40 31 41 \n\nTotal Income Tax Expense$45 $44 $49 \n\n79\n\nNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)\n\nThe significant components of deferred income tax assets and liabilities consist of the following:\n\nDecember 31,\n\n(in millions)20252024\n\nGross Deferred Income Tax Assets\n\nCustomer Advances and Contributions in Aid of Construction$22 $22 \n\nFederal General Business Credits (1)\n90 39 \n\nIncome Taxes Payable Through Future Rates42 52 \n\nOther130 101 \n\nTotal Gross Deferred Income Tax Assets284 214 \n\nDeferred Tax Assets Valuation Allowance(3)— \n\nGross Deferred Income Tax Liabilities\n\nPlant, Net(913)(843)\n\nPensions(19)(20)\n\nIncome Taxes Recoverable Through Future Rates(1)(1)\n\nOther(52)(50)\n\nTotal Gross Deferred Income Tax Liabilities(985)(914)\n\nDeferred Income Taxes, Net$(704)$(700)\n\n(1)Includes ITC and PTC carryovers.\n\nAs of December 31, 2025, TEP had the following carryforward amounts:\n\n($ in millions)AmountExpiring Year\n\nState Credits$2 2028 - 2030\n\nFederal Production Tax Credits 41 2043 - 2045\n\nFederal Investment Tax Credits492045\n\nRoadrunner Reserve I, which was placed in service in July 2025, generated $98 million of ITCs. In December 2025, TEP entered into an agreement to transfer ITCs, under which it transferred $49 million of ITCs and received $46 million in cash proceeds. The transfer resulted in the derecognition of the related deferred tax asset and valuation allowance. As of December 31, 2025, the remaining $49 million of ITCs are recorded in Deferred Income Taxes, Net on the Consolidated Balance Sheets, along with a corresponding regulatory liability of $91 million in Regulatory Liabilities on the Consolidated Balance Sheets to reflect the expected return of benefits to customers on the effective date of new rates. Amortization of the regulatory liability will reduce income tax expense. As of December 31, 2025, TEP recorded a $3 million valuation allowance against the deferred tax asset recognized for transferable ITCs, reflecting the expected discount in proceeds from a third-party sale.\n\nTEP recorded no valuation allowance against other tax credit carryforward deferred income tax assets as of December 31, 2025 and 2024. Management believes TEP will produce sufficient taxable income in the future to realize credit carryforwards before they expire.\n\nIncluded in Accounts Payable on the Consolidated Balance Sheets are intercompany balances related to current income taxes payable of $1 million as of December 31, 2025, and less than $1 million as of December 31, 2024.\n\nOne Big Beautiful Bill Act\n\nIn 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 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.\n\n80\n\n[Table of Contents](#iaa4bfb93949147c689d89e1563a40f0a_7)"}