Tucson Electric Power 10-Q 5 Nov 24 2024 Q3 Quarterly report Financial data

Cover Page

Cover Page - shares	9 Months Ended
	Sep. 30, 2024	Nov. 04, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2024
Document Transition Report	false
Entity File Number	1-5924
Entity Registrant Name	TUCSON ELECTRIC POWER CO
Entity Incorporation, State or Country Code	AZ
Entity Tax Identification Number	86-0062700
Entity Address, Address Line One	88 East Broadway Boulevard
Entity Address, City or Town	Tucson
Entity Address, State or Province	AZ
Entity Address, Postal Zip Code	85701
City Area Code	520
Local Phone Number	571-4000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		32,139,434
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q3
Entity Central Index Key	0000100122
Current Fiscal Year End Date	--12-31

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Income Statement [Abstract]
Operating Revenues	$ 551,632	$ 593,247	$ 1,433,934	$ 1,447,336
Operating Expenses
Fuel	92,063	107,917	257,165	296,617
Purchased Power	50,703	98,081	104,373	181,657
Transmission and Other PPFAC Recoverable Costs	18,904	29,517	52,371	61,478
Increase (Decrease) to Reflect PPFAC Recovery Treatment	26,114	7,659	97,349	42,156
Total Fuel and Purchased Power	187,784	243,174	511,258	581,908
Operations and Maintenance	105,877	103,991	330,143	332,033
Depreciation	56,942	49,901	168,913	144,465
Amortization	7,346	9,487	22,855	28,981
Taxes Other Than Income Taxes	17,384	17,068	53,629	51,448
Total Operating Expenses	375,333	423,621	1,086,798	1,138,835
Operating Income	176,299	169,626	347,136	308,501
Other Income (Expense)
Interest Expense	(27,189)	(23,986)	(75,442)	(71,474)
Allowance For Borrowed Funds	2,221	1,279	5,974	3,448
Allowance For Equity Funds	6,276	3,637	16,935	9,779
Unrealized Gains (Losses) on Investments	1,867	(1,331)	2,857	462
Other, Net	2,119	2,463	3,835	8,220
Total Other Income (Expense)	(14,706)	(17,938)	(45,841)	(49,565)
Income Before Income Tax Expense	161,593	151,688	301,295	258,936
Income Tax Expense	21,100	23,357	39,187	35,986
Net Income	$ 140,493	$ 128,331	$ 262,108	$ 222,950

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Cash Flows from Operating Activities
Net Income	$ 262,108	$ 222,950
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	168,913	144,465
Amortization Expense	22,855	28,981
Amortization of Debt Issuance Costs	2,338	2,304
Use of Renewable Energy Credits for Compliance	35,976	33,770
Deferred Income Taxes	28,638	28,649
Pension and Other Postretirement Benefits Expense	13,529	11,398
Pension and Other Postretirement Benefits Funding	(17,815)	(11,499)
Allowance for Equity Funds Used During Construction	(16,935)	(9,779)
Change in Long-Term Regulatory Assets and Liabilities	1,546	257
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(58,522)	43,869
Materials, Supplies, and Fuel Inventory	(22,790)	(21,826)
Regulatory Assets	47,446	32,204
Other Current Assets	(8,243)	(6,112)
Accounts Payable and Accrued Charges	29,976	(62,182)
Income Taxes Receivable/Payable	1,932	1,315
Regulatory Liabilities	53,448	(12)
Other, Net	(13,829)	(10,415)
Net Cash Flows—Operating Activities	530,571	428,337
Cash Flows from Investing Activities
Capital Expenditures	(459,635)	(345,470)
Purchase Intangibles, Renewable Energy Credits	(46,291)	(48,915)
Other Investments	0	2,935
Contributions in Aid of Construction	1,314	3,355
Net Cash Flows—Investing Activities	(504,612)	(388,095)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	25,000	0
Repayments of Borrowings, Revolving Credit Facility	(25,000)	0
Proceeds from Issuance, Long-Term Debt—Net of Discount	399,376	373,954
Repayments of Long-Term Debt	0	(240,745)
Dividend Paid to Parent	(85,000)	(55,000)
Payment of Debt Issuance Costs	(3,221)	(4,095)
Contribution from Parent	0	5,900
Other, Net	1,369	(383)
Net Cash Flows—Financing Activities	312,524	79,631
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	338,483	119,873
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	42,595	50,981
Cash, Cash Equivalents, and Restricted Cash, End of Period	$ 381,078	$ 170,854

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Utility Plant
Plant in Service	$ 8,258,271	$ 8,035,444
Construction Work in Progress	698,880	475,391
Total Utility Plant	8,957,151	8,510,835
Accumulated Depreciation and Amortization	(2,683,259)	(2,570,157)
Total Utility Plant, Net	6,273,892	5,940,678
Investments and Other Property	67,618	70,080
Current Assets
Cash and Cash Equivalents	354,347	8,616
Accounts Receivable (Net of Allowance for Credit Losses of $12,818 and $11,676 as of September 30, 2024 and December 31, 2023, respectively)	274,461	217,381
Fuel Inventory	36,025	34,475
Materials and Supplies	190,477	172,667
Regulatory Assets	88,905	147,389
Derivative Instruments	10,454	3,091
Other	38,082	30,450
Total Current Assets	992,751	614,069
Regulatory Assets	192,966	182,997
Derivative Instruments	22,980	31,614
Other Noncurrent Assets	149,028	134,196
Total Assets	7,699,235	6,973,634
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2024 and December 31, 2023)	1,696,539	1,696,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	1,340,029	1,162,921
Accumulated Other Comprehensive Loss	(3,638)	(3,829)
Total Common Stock Equity	3,026,573	2,849,274
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2024 and December 31, 2023)	0	0
Long-Term Debt, Net	2,494,363	2,396,542
Total Capitalization	5,520,936	5,245,816
Current Liabilities
Current Maturities of Long-Term Debt, Net	299,839	0
Accounts Payable	184,683	137,002
Accrued Taxes Other than Income Taxes	81,179	57,291
Accrued Employee Expenses	37,984	39,466
Accrued Interest	31,775	16,541
Regulatory Liabilities	146,556	92,740
Customer Deposits	15,734	15,833
Derivative Instruments	18,470	25,828
Other	41,404	36,312
Total Current Liabilities	857,624	421,013
Deferred Income Taxes, Net	694,281	647,730
Regulatory Liabilities	355,316	396,061
Pension and Other Postretirement Benefits	76,863	81,241
Derivative Instruments	6,709	4,338
Other Noncurrent Liabilities	187,506	177,435
Total Liabilities	2,178,299	1,727,818
Commitments and Contingencies
Total Capitalization and Liabilities	$ 7,699,235	$ 6,973,634

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Allowance for credit losses	$ 12,818	$ 11,676
Common stock, shares authorized (in shares)	75,000,000	75,000,000
Common stock, shares outstanding (in shares)	32,139,434	32,139,434
Preferred stock, shares authorized (in shares)	1,000,000	1,000,000
Preferred stock, shares outstanding (in shares)	0	0

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited) - USD ($) $ in Thousands	Total	Common Stock	Capital Stock Expense	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2022	$ 2,655,665	$ 1,696,539	$ (6,357)	$ 968,367	$ (2,884)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	222,950			222,950
Other Comprehensive Income (Loss), Net of Tax	83				83
Dividend Declared to Parent	(55,000)			(55,000)
Contribution from Parent	5,900	5,900
Ending balance at Sep. 30, 2023	2,829,598	1,702,439	(6,357)	1,136,317	(2,801)
Beginning balance at Jun. 30, 2023	2,701,239	1,702,439	(6,357)	1,007,986	(2,829)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	128,331			128,331
Other Comprehensive Income (Loss), Net of Tax	28				28
Ending balance at Sep. 30, 2023	2,829,598	1,702,439	(6,357)	1,136,317	(2,801)
Beginning balance at Dec. 31, 2023	2,849,274	1,696,539	(6,357)	1,162,921	(3,829)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	262,108			262,108
Other Comprehensive Income (Loss), Net of Tax	191				191
Dividend Declared to Parent	(85,000)			(85,000)
Ending balance at Sep. 30, 2024	3,026,573	1,696,539	(6,357)	1,340,029	(3,638)
Beginning balance at Jun. 30, 2024	2,970,981	1,696,539	(6,357)	1,284,536	(3,737)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	140,493			140,493
Other Comprehensive Income (Loss), Net of Tax	99				99
Dividend Declared to Parent	(85,000)			(85,000)
Ending balance at Sep. 30, 2024	$ 3,026,573	$ 1,696,539	$ (6,357)	$ 1,340,029	$ (3,638)

NATURE OF OPERATIONS AND FINANC

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	9 Months Ended
	Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 451,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis. BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the United States Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2023 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows. Variable Interest Entities A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is the primary beneficiary of the VIEs on a quarterly basis. As of September 30, 2024, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term renewable PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. Restricted Cash Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows: Nine Months Ended September 30, (in millions) 2024 2023 Cash and Cash Equivalents $ 354 $ 138 Restricted Cash included in: Investments and Other Property 18 20 Current Assets—Other 9 13 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 381 $ 171 Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan. Income Tax Expense TEP realized PTC benefits associated with Oso Grande of $10 million and $20 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2024, respectively, and $7 million and $16 million for the three and nine months ended September 30, 2023, respectively. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) and the SEC has not yet been adopted and is not 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. Income Tax Disclosures In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures. Reportable Segment Disclosures In November 2023, the FASB issued accounting guidance that requires disclosure of significant segment expenses and new disclosures for entities with a single reportable segment. The amendments are effective for annual periods beginning on January 1, 2024 and interim periods beginning on January 1, 2025 and are to be applied retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures. Climate-Related Disclosures In March 2024, the SEC issued a final rule that requires disclosure of: (i) financial statement impacts of severe weather events and other natural conditions; (ii) a roll forward of carbon offset and REC balances if material to the Company's plan to achieve climate-related targets or goals; and (iii) material impacts on estimates and assumptions in the financial statements. The rule is effective for TEP for annual periods beginning January 1, 2027 and is to be applied prospectively. In April 2024, the SEC issued an order staying the final rule pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit. TEP cannot predict what, if any, changes in scope or timing may occur as a result of the pending litigation. TEP continues its assessment to prepare for the new rule.

REGULATORY MATTERS

REGULATORY MATTERS	9 Months Ended
	Sep. 30, 2024
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period. The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Beginning of Period $ (31) $ 93 $ 55 $ 124 Deferred Fuel and Purchased Power Costs (1) 95 135 202 258 PPFAC and Base Power Recoveries (120) (140) (313) (294) End of Period $ (56) $ 88 $ (56) $ 88 (1) Includes costs eligible for recovery through the PPFAC and base power rates. Transmission Cost Adjustor The TCA allows for timely recovery or refund of actual costs, net of applicable credits, required to provide transmission services to retail customers. TEP files new TCA rates with the ACC in December each year based on changes in net costs required to provide transmission services to retail customers. New TCA rates take effect in January of each year. Renewable Energy Standard The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30% of the annual energy requirement. The renewable energy requirement in 2024 is 14% of retail electric sales. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. TEP recovers approved costs of carrying out this plan from retail customers through a RES tariff. In May 2024, the ACC approved an extension of the 2021 RES implementation with a budget of $66 million until further order of the ACC and an increase to the RES tariff to recover under-collected RES funds totaling $17 million. The ACC also waived for TEP the general requirement that Arizona utilities file an annual RES implementation plan. The approved amount funds: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Energy Efficiency Standards TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs of implementing DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. In the 2023 Rate Order, the ACC approved a 2023 energy efficiency implementation plan with a cumulative three-year budget of $72 million, which is collected through the DSM surcharge. In May 2024, the ACC approved refunding over-collected, uncommitted DSM surcharge funds totaling $10 million. The DSM refund credits were applied over the June and July 2024 billing periods. 2020 IRP Energy Efficiency Target In 2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings in each of the years 2023 through 2025. TEP will report its savings for these years in its first integrated resource plan following 2025 and in TEP's periodic energy efficiency filings. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues based on an estimate of lost retail kWh sales during the period. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below: ($ in millions) Remaining Recovery Period September 30, 2024 December 31, 2023 Regulatory Assets Pension and Other Postretirement Benefits (Note 8) Various $ 103 $ 107 Early Generation Retirement Costs Various 50 48 Lost Fixed Cost Recovery 1 31 35 Property Tax Deferrals (1) 1 31 30 Final Mine Reclamation (2) 15 20 6 Derivatives (Note 9) 5 14 26 Transmission Revenue Requirement Balancing Account 1 8 — Income Taxes Recoverable through Future Rates (3) Various 5 6 Unamortized Loss on Reacquired Debt Various 4 5 Under-Recovered Fuel and Purchased Energy Costs 1 — 55 Other Regulatory Assets Various 16 12 Total Regulatory Assets 282 330 Less Current Portion 1 89 147 Total Noncurrent Regulatory Assets $ 193 $ 183 Regulatory Liabilities Income Taxes Payable through Future Rates (3) Various $ 211 $ 229 Net Cost of Removal (4) Various 119 130 Renewable Energy Standard Various 84 77 Over-Recovered Fuel and Purchased Energy Costs 1 56 — Derivatives (Note 9) 5 17 28 Demand Side Management 1 6 9 Deferred Investment Tax Credits Various 5 6 Pension and Other Postretirement Benefits (Note 8) Various 4 4 Transmission Revenue Requirement Balancing Account 1 — 5 Other Regulatory Liabilities Various — 1 Total Regulatory Liabilities 502 489 Less Current Portion 1 147 93 Total Noncurrent Regulatory Liabilities $ 355 $ 396 (1) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. (2) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022. In March 2024, the San Juan reclamation oversight committee approved a new final mine reclamation study which resulted in a $15 million increase in the final mine reclamation regulatory asset. (3) Amortized over five years, 10 years, or the lives of the assets. (4) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general plant which are not yet expended. Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, Transmission Revenue Requirement Balancing Account, and Under-Recovered Fuel and Purchased Energy Costs, TEP does not earn a return on regulatory assets. TEP pays a return on the majority of its regulatory liability balances. Roadrunner Reserve I Application for Accounting Order In September 2023, TEP entered into an EPC agreement to develop Roadrunner Reserve I with an anticipated in-service date in 2025. On October 10, 2024, TEP filed an application with the ACC for an accounting order requesting authorization to defer for future recovery certain costs associated with owning, operating, and maintaining Roadrunner Reserve I, offset by future benefits associated with investment tax credits. TEP cannot predict the timing or outcome of this application.

REVENUE

REVENUE	9 Months Ended
	Sep. 30, 2024
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE DISAGGREGATION OF REVENUES TEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Retail $ 436 $ 445 $ 1,052 $ 975 Wholesale 72 101 212 291 Other Services 24 25 90 95 Revenues from Contracts with Customers 532 571 1,354 1,361 Alternative Revenues 11 7 30 28 Other 9 15 50 58 Total Operating Revenues $ 552 $ 593 $ 1,434 $ 1,447

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	9 Months Ended
	Sep. 30, 2024
Receivables [Abstract]
ACCOUNTS RECEIVABLE	ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2024 December 31, 2023 Retail $ 153 $ 109 Retail, Unbilled 69 57 Retail, Allowance for Credit Losses (13) (12) Wholesale (1) 31 37 Due from Affiliates (Note 5) 16 7 Other 18 19 Accounts Receivable $ 274 $ 217 (1) Includes $15 million as of September 30, 2024, and $10 million as of December 31, 2023, of receivables related to revenue from derivative instruments. ALLOWANCE FOR CREDIT LOSSES TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Beginning of Period $ (12) $ (9) $ (12) $ (9) Credit Loss Expense (2) (4) (5) (6) Write-offs 1 2 4 4 End of Period $ (13) $ (11) $ (13) $ (11)

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2024
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services. The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2024 December 31, 2023 Receivables from Related Parties UNS Electric $ 14 $ 5 UNS Gas 2 2 Total Due from Related Parties $ 16 $ 7 Payables to Related Parties UNS Energy $ 1 $ 1 UNS Electric 1 1 UNS Gas — 1 Total Due to Related Parties $ 2 $ 3 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Goods and Services Provided by TEP to Affiliates Wholesale Revenues, UNS Electric (1) $ 16 $ 22 $ 19 $ 35 Common Costs, UNS Energy Affiliates (2) 6 6 18 17 Transmission Revenues, UNS Electric (1) 2 2 6 6 Control Area Services, UNS Electric (3) 1 1 2 2 Goods and Services Provided by Affiliates to TEP Corporate Services, UNS Energy (4) 2 2 7 6 Corporate Services, UNS Energy Affiliates (5) — — 1 1 Capacity Charges, UNS Gas (6) — — 1 1 Purchased Power, UNS Electric (1) — — — 1 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT. (2) 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. (3) TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement. (4) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million and $6 million for the three and nine months ended September 30, 2024 and 2023, respectively. (5) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. (6) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.

DEBT AND CREDIT AGREEMENTS

DEBT AND CREDIT AGREEMENTS	9 Months Ended
	Sep. 30, 2024
Debt Disclosure [Abstract]
DEBT AND CREDIT AGREEMENTS	DEBT AND CREDIT AGREEMENTS There have been no significant changes to TEP's debt or credit agreements since December 31, 2023, except as noted below. DEBT Issuance and Redemptions In August 2024, TEP issued and sold $400 million aggregate principal amount of 5.20% senior unsecured notes due September 2034. TEP may redeem the notes prior to June 15, 2034, with a make-whole premium plus accrued interest. On or after June 15, 2034, TEP may redeem the notes at par plus accrued interest. On November 1, 2024, TEP issued a revocable notice to redeem at par on December 16, 2024, $300 million aggregate principal amount of its 3.05% senior unsecured notes. These notes have a maturity date of March 15, 2025. CREDIT AGREEMENT 2021 Credit Agreement In October 2024, the maturity date of TEP's 2021 Credit Agreement was extended one year to October 2027 as permitted by the agreement. The terms of the 2021 Credit Agreement are as follows: Sub-Limit Swingline (1) Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed Available Pricing (2) ($ in millions) September 30, 2024 Agreement $ 250 $ 15 $ 50 $ — $ 250 — % SOFR+ADJ 0.10%+1.050% or ABR+0.050% (1) ABR pricing would apply to swingline loans. (2) 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.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS There have been no significant changes to TEP's long-term commitments since December 31, 2023, except as noted below. EPC Agreement In August 2024, TEP entered into an EPC agreement to develop Roadrunner Reserve II at a cost of $268 million. TEP owns and will operate the facility, which will be located in southeast Tucson and 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 the second half of 2026. As of September 30, 2024, TEP has made payments of $74 million in connection with the construction and development of Roadrunner Reserve II. CONTINGENCIES Legal Matters TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. Mine Reclamation at Generation Facilities Not Operated by TEP TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation costs are subject to various assumptions, such as: estimations of reclamation costs; timing of when final reclamation will occur; and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP records its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability. TEP is liable for a portion of final mine reclamation costs for the mines at Four Corners and San Juan. TEP’s liability balance related to its share of final mine reclamation costs at Four Corners totaled $3 million and $4 million as of September 30, 2024, and December 31, 2023, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP expects to accrue an additional $1 million of final mine reclamation costs at Four Corners over the remaining term of the coal supply agreement, which expires in 2031. TEP ceased operations at San Juan upon expiration of the coal supply agreement in 2022. In March 2024, TEP increased the San Juan final mine reclamation liability by $15 million as a result of a new final mine reclamation study. TEP’s remaining final mine reclamation liability at San Juan was $34 million and $25 million as of September 30, 2024, and December 31, 2023, respectively, and was recorded in Current Liabilities—Other and Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2040. See Note 1 for additional information on restricted cash relating to TEP's share of final mine reclamation and decommissioning costs at San Juan. Performance Guarantees TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. There is no maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of September 30, 2024, there have been no such payment defaults under either of the participation agreements. The Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, the non-defaulting participants would seek financial recovery directly from the defaulting party. Environmental Matters TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	9 Months Ended
	Sep. 30, 2024
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2024 2023 2024 2023 Service Cost $ 4 $ 3 $ 1 $ 1 Non-Service Cost (1) Interest Cost 6 6 1 1 Expected Return on Plan Assets (8) (8) (1) — Amortization of Net Loss 1 1 — — Net Periodic Benefit Cost $ 3 $ 2 $ 1 $ 2 Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Service Cost $ 11 $ 9 $ 3 $ 3 Non-Service Cost (1) Interest Cost 18 17 3 3 Expected Return on Plan Assets (24) (22) (2) (1) Amortization of Net Loss 4 3 — — Net Periodic Benefit Cost $ 9 $ 7 $ 4 $ 5 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. CONTRIBUTIONS TEP contributed $14 million to the pension plans during the nine months ended September 30, 2024. No additional contributions are planned in 2024.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2024
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3. FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Total (in millions) September 30, 2024 Assets Cash Equivalents (1) $ 55 $ — $ 55 Restricted Cash (1) 27 — 27 Energy Derivative Contracts, Regulatory Recovery (2) — 27 27 Energy Derivative Contracts, No Regulatory Recovery (2) — 6 6 Total Assets 82 33 115 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (25) (25) Total Liabilities — (25) (25) Total Assets (Liabilities), Net $ 82 $ 8 $ 90 (in millions) December 31, 2023 Assets Restricted Cash (1) $ 34 $ — $ 34 Energy Derivative Contracts, Regulatory Recovery (2) — 32 32 Energy Derivative Contracts, No Regulatory Recovery (2) — 3 3 Total Assets 34 35 69 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (30) (30) Total Liabilities — (30) (30) Total Assets (Liabilities), Net $ 34 $ 5 $ 39 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) September 30, 2024 Derivative Assets Energy Derivative Contracts $ 33 $ 14 $ — $ 19 Derivative Liabilities Energy Derivative Contracts (25) (14) — (11) (in millions) December 31, 2023 Derivative Assets Energy Derivative Contracts $ 35 $ 15 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (30) (15) — (15) DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly. Energy Derivative Contracts, Regulatory Recovery TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or liability in the balance sheet: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Unrealized Net Gain (Loss) (1) $ 8 $ — $ — $ (47) (1) For the nine months ended September 30, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas. Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Operating Revenues $ 3 $ 1 $ 30 $ 18 Derivative Volumes As of September 30, 2024, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts: September 30, 2024 December 31, 2023 Power Contracts GWh 2,849 1,449 Gas Contracts BBtu 87,681 89,105 CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value. TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts. TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to individual contracts. The fair value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $24 million as of September 30, 2024, compared with $28 million as of December 31, 2023. TEP had no cash posted as collateral to provide credit enhancement as of September 30, 2024, and December 31, 2023. TEP would have been required to post $24 million and $28 million of collateral if the credit risk contingent features had been triggered on September 30, 2024, and December 31, 2023, respectively. TEP had $15 million and $13 million in outstanding net payable balances for settled positions as of September 30, 2024 , and December 31, 2023 , respectively. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) September 30, 2024 December 31, 2023 September 30, 2024 December 31, 2023 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,794 $ 2,397 $ 2,579 $ 2,127

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2024
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Nine Months Ended September 30, (in millions) 2024 2023 Interest Paid, Net of Amounts Capitalized $ 51 $ 48 NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: Nine Months Ended September 30, (in millions) 2024 2023 Accrued Capital Expenditures (1) $ 93 $ 32 Renewable Energy Credits 4 4 Asset Retirement Obligations Increase (Decrease) (2) (2) Net Cost of Removal Increase (Decrease) (2) (5) 98 (1) In 2024, primarily represents accrued capital expenditures related to Roadrunner Reserve I. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.

NATURE OF OPERATIONS AND FINA_2

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the United States Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2023 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows.
Variable Interest Entities	Variable Interest Entities A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is the primary beneficiary of the VIEs on a quarterly basis.
Restricted Cash	Restricted Cash Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan.
New Accounting Standards Issued and Not Yet Adopted	NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) and the SEC has not yet been adopted and is not 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. Income Tax Disclosures In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures. Reportable Segment Disclosures In November 2023, the FASB issued accounting guidance that requires disclosure of significant segment expenses and new disclosures for entities with a single reportable segment. The amendments are effective for annual periods beginning on January 1, 2024 and interim periods beginning on January 1, 2025 and are to be applied retrospectively. Early adoption is permitted. TEP does not expect the amendments to have a material impact on TEP's financial position, results of operations, cash flows or disclosures. Climate-Related Disclosures In March 2024, the SEC issued a final rule that requires disclosure of: (i) financial statement impacts of severe weather events and other natural conditions; (ii) a roll forward of carbon offset and REC balances if material to the Company's plan to achieve climate-related targets or goals; and (iii) material impacts on estimates and assumptions in the financial statements. The rule is effective for TEP for annual periods beginning January 1, 2027 and is to be applied prospectively. In April 2024, the SEC issued an order staying the final rule pending judicial review of consolidated challenges to the rules by the Court of Appeals for the Eighth Circuit. TEP cannot predict what, if any, changes in scope or timing may occur as a result of the pending litigation. TEP continues its assessment to prepare for the new rule.
Allowance for Credit Losses	ALLOWANCE FOR CREDIT LOSSES
Fair Value Measurement	TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3.
Derivative Instruments	DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Credit Risk	CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value. TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts. TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to individual contracts.

NATURE OF OPERATIONS AND FINA_3

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables)	9 Months Ended
	Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Cash, Cash Equivalents	The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows: Nine Months Ended September 30, (in millions) 2024 2023 Cash and Cash Equivalents $ 354 $ 138 Restricted Cash included in: Investments and Other Property 18 20 Current Assets—Other 9 13 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 381 $ 171
Schedule of Restricted Cash	The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows: Nine Months Ended September 30, (in millions) 2024 2023 Cash and Cash Equivalents $ 354 $ 138 Restricted Cash included in: Investments and Other Property 18 20 Current Assets—Other 9 13 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 381 $ 171

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 2024
Regulated Operations [Abstract]
Schedule of PPFAC Regulatory Asset Balance	The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Beginning of Period $ (31) $ 93 $ 55 $ 124 Deferred Fuel and Purchased Power Costs (1) 95 135 202 258 PPFAC and Base Power Recoveries (120) (140) (313) (294) End of Period $ (56) $ 88 $ (56) $ 88 (1) Includes costs eligible for recovery through the PPFAC and base power rates.
Schedule of PPFAC Regulatory Liability Balance	The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Beginning of Period $ (31) $ 93 $ 55 $ 124 Deferred Fuel and Purchased Power Costs (1) 95 135 202 258 PPFAC and Base Power Recoveries (120) (140) (313) (294) End of Period $ (56) $ 88 $ (56) $ 88 (1) Includes costs eligible for recovery through the PPFAC and base power rates.
Schedule of Regulatory Assets and Liabilities	Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below: ($ in millions) Remaining Recovery Period September 30, 2024 December 31, 2023 Regulatory Assets Pension and Other Postretirement Benefits (Note 8) Various $ 103 $ 107 Early Generation Retirement Costs Various 50 48 Lost Fixed Cost Recovery 1 31 35 Property Tax Deferrals (1) 1 31 30 Final Mine Reclamation (2) 15 20 6 Derivatives (Note 9) 5 14 26 Transmission Revenue Requirement Balancing Account 1 8 — Income Taxes Recoverable through Future Rates (3) Various 5 6 Unamortized Loss on Reacquired Debt Various 4 5 Under-Recovered Fuel and Purchased Energy Costs 1 — 55 Other Regulatory Assets Various 16 12 Total Regulatory Assets 282 330 Less Current Portion 1 89 147 Total Noncurrent Regulatory Assets $ 193 $ 183 Regulatory Liabilities Income Taxes Payable through Future Rates (3) Various $ 211 $ 229 Net Cost of Removal (4) Various 119 130 Renewable Energy Standard Various 84 77 Over-Recovered Fuel and Purchased Energy Costs 1 56 — Derivatives (Note 9) 5 17 28 Demand Side Management 1 6 9 Deferred Investment Tax Credits Various 5 6 Pension and Other Postretirement Benefits (Note 8) Various 4 4 Transmission Revenue Requirement Balancing Account 1 — 5 Other Regulatory Liabilities Various — 1 Total Regulatory Liabilities 502 489 Less Current Portion 1 147 93 Total Noncurrent Regulatory Liabilities $ 355 $ 396 (1) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. (2) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022. In March 2024, the San Juan reclamation oversight committee approved a new final mine reclamation study which resulted in a $15 million increase in the final mine reclamation regulatory asset. (3) Amortized over five years, 10 years, or the lives of the assets. (4) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general plant which are not yet expended.

REVENUE (Tables)

REVENUE (Tables)	9 Months Ended
	Sep. 30, 2024
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Retail $ 436 $ 445 $ 1,052 $ 975 Wholesale 72 101 212 291 Other Services 24 25 90 95 Revenues from Contracts with Customers 532 571 1,354 1,361 Alternative Revenues 11 7 30 28 Other 9 15 50 58 Total Operating Revenues $ 552 $ 593 $ 1,434 $ 1,447

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	9 Months Ended
	Sep. 30, 2024
Receivables [Abstract]
Schedule of Accounts Receivable	The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2024 December 31, 2023 Retail $ 153 $ 109 Retail, Unbilled 69 57 Retail, Allowance for Credit Losses (13) (12) Wholesale (1) 31 37 Due from Affiliates (Note 5) 16 7 Other 18 19 Accounts Receivable $ 274 $ 217 (1) Includes $15 million as of September 30, 2024, and $10 million as of December 31, 2023, of receivables related to revenue from derivative instruments.
Schedule of Allowance for Credit Losses	The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Beginning of Period $ (12) $ (9) $ (12) $ (9) Credit Loss Expense (2) (4) (5) (6) Write-offs 1 2 4 4 End of Period $ (13) $ (11) $ (13) $ (11)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	9 Months Ended
	Sep. 30, 2024
Related Party Transactions [Abstract]
Schedule of Related Party Balances and Transactions	The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2024 December 31, 2023 Receivables from Related Parties UNS Electric $ 14 $ 5 UNS Gas 2 2 Total Due from Related Parties $ 16 $ 7 Payables to Related Parties UNS Energy $ 1 $ 1 UNS Electric 1 1 UNS Gas — 1 Total Due to Related Parties $ 2 $ 3 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Goods and Services Provided by TEP to Affiliates Wholesale Revenues, UNS Electric (1) $ 16 $ 22 $ 19 $ 35 Common Costs, UNS Energy Affiliates (2) 6 6 18 17 Transmission Revenues, UNS Electric (1) 2 2 6 6 Control Area Services, UNS Electric (3) 1 1 2 2 Goods and Services Provided by Affiliates to TEP Corporate Services, UNS Energy (4) 2 2 7 6 Corporate Services, UNS Energy Affiliates (5) — — 1 1 Capacity Charges, UNS Gas (6) — — 1 1 Purchased Power, UNS Electric (1) — — — 1 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT. (2) 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. (3) TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement. (4) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million and $6 million for the three and nine months ended September 30, 2024 and 2023, respectively. (5) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. (6) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.

DEBT AND CREDIT AGREEMENTS (Tab

DEBT AND CREDIT AGREEMENTS (Tables)	9 Months Ended
	Sep. 30, 2024
Debt Disclosure [Abstract]
Schedule Of Line Of Credit Facilities	The terms of the 2021 Credit Agreement are as follows: Sub-Limit Swingline (1) Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed Available Pricing (2) ($ in millions) September 30, 2024 Agreement $ 250 $ 15 $ 50 $ — $ 250 — % SOFR+ADJ 0.10%+1.050% or ABR+0.050% (1) ABR pricing would apply to swingline loans. (2) 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.

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2024
Retirement Benefits [Abstract]
Schedule of Components of Net Periodic Benefit Cost	Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2024 2023 2024 2023 Service Cost $ 4 $ 3 $ 1 $ 1 Non-Service Cost (1) Interest Cost 6 6 1 1 Expected Return on Plan Assets (8) (8) (1) — Amortization of Net Loss 1 1 — — Net Periodic Benefit Cost $ 3 $ 2 $ 1 $ 2 Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Service Cost $ 11 $ 9 $ 3 $ 3 Non-Service Cost (1) Interest Cost 18 17 3 3 Expected Return on Plan Assets (24) (22) (2) (1) Amortization of Net Loss 4 3 — — Net Periodic Benefit Cost $ 9 $ 7 $ 4 $ 5 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

FAIR VALUE MEASUREMENTS AND D_2

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2024
Fair Value Disclosures [Abstract]
Schedule of Financial Instruments Measured at Fair Value on Recurring Basis	The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Total (in millions) September 30, 2024 Assets Cash Equivalents (1) $ 55 $ — $ 55 Restricted Cash (1) 27 — 27 Energy Derivative Contracts, Regulatory Recovery (2) — 27 27 Energy Derivative Contracts, No Regulatory Recovery (2) — 6 6 Total Assets 82 33 115 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (25) (25) Total Liabilities — (25) (25) Total Assets (Liabilities), Net $ 82 $ 8 $ 90 (in millions) December 31, 2023 Assets Restricted Cash (1) $ 34 $ — $ 34 Energy Derivative Contracts, Regulatory Recovery (2) — 32 32 Energy Derivative Contracts, No Regulatory Recovery (2) — 3 3 Total Assets 34 35 69 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (30) (30) Total Liabilities — (30) (30) Total Assets (Liabilities), Net $ 34 $ 5 $ 39 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
Schedule of Potential Offset of Assets by Counterparty Netting and Cash Collateral	The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) September 30, 2024 Derivative Assets Energy Derivative Contracts $ 33 $ 14 $ — $ 19 Derivative Liabilities Energy Derivative Contracts (25) (14) — (11) (in millions) December 31, 2023 Derivative Assets Energy Derivative Contracts $ 35 $ 15 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (30) (15) — (15)
Schedule of Potential Offset of Liabilities by Counterparty Netting and Cash Collateral	The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) September 30, 2024 Derivative Assets Energy Derivative Contracts $ 33 $ 14 $ — $ 19 Derivative Liabilities Energy Derivative Contracts (25) (14) — (11) (in millions) December 31, 2023 Derivative Assets Energy Derivative Contracts $ 35 $ 15 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (30) (15) — (15)
Schedule of Financial Impact of Energy Contracts	The table below presents the unrealized gains and losses recorded to a regulatory asset or liability in the balance sheet: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Unrealized Net Gain (Loss) (1) $ 8 $ — $ — $ (47) (1) For the nine months ended September 30, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas. Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2024 2023 2024 2023 Operating Revenues $ 3 $ 1 $ 30 $ 18
Schedule of Derivative Volumes	The following table presents volumes associated with the energy contracts: September 30, 2024 December 31, 2023 Power Contracts GWh 2,849 1,449 Gas Contracts BBtu 87,681 89,105
Schedule of Face Value and Estimated Fair Value of Long-Term Debt	The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) September 30, 2024 December 31, 2023 September 30, 2024 December 31, 2023 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,794 $ 2,397 $ 2,579 $ 2,127

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2024
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	CASH TRANSACTIONS Nine Months Ended September 30, (in millions) 2024 2023 Interest Paid, Net of Amounts Capitalized $ 51 $ 48 NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: Nine Months Ended September 30, (in millions) 2024 2023 Accrued Capital Expenditures (1) $ 93 $ 32 Renewable Energy Credits 4 4 Asset Retirement Obligations Increase (Decrease) (2) (2) Net Cost of Removal Increase (Decrease) (2) (5) 98 (1) In 2024, primarily represents accrued capital expenditures related to Roadrunner Reserve I. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In September 2023, the Net Cost of Removal reserve was rebalanced as part of the 2023 Rate Order.

NATURE OF OPERATIONS AND FINA_4

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Narrative) (Details) customer in Thousands, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2024 USD ($) customer	Sep. 30, 2023 USD ($)	Sep. 30, 2024 USD ($) mi² customer	Sep. 30, 2023 USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of retail customers | customer	451		451
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi²			1,155
PTC benefits | $	$ 10	$ 7	$ 20	$ 16

NATURE OF OPERATIONS AND FINA_5

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023	Sep. 30, 2023	Dec. 31, 2022
Cash and Cash Equivalents [Line Items]
Cash and Cash Equivalents	$ 354,347	$ 8,616	$ 138,000
Restricted Cash included in:
Cash, Cash Equivalents, and Restricted Cash, End of Period	381,078	$ 42,595	170,854	$ 50,981
Investments and Other Property
Restricted Cash included in:
Restricted cash	18,000		20,000
Current Assets—Other
Restricted Cash included in:
Restricted cash	$ 9,000		$ 13,000

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	May 31, 2024	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023	Dec. 31, 2025	Dec. 31, 2023	Dec. 31, 2021	Jun. 30, 2022
Effective 1/1/2024-12/31/2026
Regulatory Assets [Roll Forward]
Energy efficiency implementation plan term							3 years
Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified				12 months
Regulatory Assets [Roll Forward]
Beginning of Period		$ (31)	$ 93	$ 55	$ 124		$ 124
Deferred Fuel and Purchased Power Costs		95	135	202	258
PPFAC and Base Power Recoveries		(120)	(140)	(313)	(294)
End of Period		$ (56)	$ 88	$ (56)	$ 88		55
Renewable Energy Standard
Regulatory Assets [Roll Forward]
Renewable Energy Required Percentage				14%
Approved spending budget for the years of 2021 and 2022								$ 66
Approved renewable energy standard increase in tariff amount	$ 17
Renewable Energy Standard | Scenario, Forecast
Regulatory Assets [Roll Forward]
Renewable energy target percentage						15%
Distributed generation requirement percent of target percentage (percentage)						30%
Energy Efficiency Standards
Regulatory Assets [Roll Forward]
Approved refund for over-collected balance	$ 10
Annual energy efficiency target, percentage									1.30%
Energy Efficiency Standards | Effective 1/1/2024-12/31/2026
Regulatory Assets [Roll Forward]
Approved recovery of spending budget							$ 72
Lost Fixed Cost Recovery
Regulatory Assets [Roll Forward]
Cap on increase in lost fixed cost recovery rate (percentage)				2%

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 282,000	$ 330,000
Less Current Portion	88,905	147,389
Total Noncurrent Regulatory Assets	192,966	182,997
Pension and Other Postretirement Benefits (Note 8)
Regulatory Assets [Line Items]
Total Regulatory Assets	103,000	107,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 50,000	48,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 31,000	35,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 31,000	30,000
Final Mine Reclamation
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	15 years
Total Regulatory Assets	$ 20,000	6,000
Derivatives (Note 9)
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	5 years
Total Regulatory Assets	$ 14,000	26,000
Transmission Revenue Requirement Balancing Account
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 8,000	0
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	5,000	6,000
Unamortized Loss on Reacquired Debt
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 4,000	5,000
Under-Recovered Fuel and Purchased Energy Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 0	55,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 16,000	$ 12,000

REGULATORY MATTERS (Regulator_2

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Dec. 31, 2023
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 502,000	$ 489,000
Less Current Portion	146,556	92,740
Total Noncurrent Regulatory Liabilities	355,316	396,061
Income Taxes Payable through Future Rates
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	211,000	229,000
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	119,000	130,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 84,000	77,000
Over-Recovered Fuel and Purchased Energy Costs
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 56,000	0
Derivatives (Note 9)
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	5 years
Total Regulatory Liabilities	$ 17,000	28,000
Demand Side Management
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 6,000	9,000
Deferred Investment Tax Credits
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	5,000	6,000
Pension and Other Postretirement Benefits (Note 8)
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 4,000	4,000
Transmission Revenue Requirement Balancing Account
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 0	5,000
Other Regulatory Assets
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 0	$ 1,000

REGULATORY MATTERS (Regulator_3

REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Mar. 31, 2024	Sep. 30, 2024	Sep. 30, 2023
Regulatory Assets [Line Items]
Increase in regulatory asset		$ (1,546)	$ (257)
Final Mine Reclamation
Regulatory Assets [Line Items]
Increase in regulatory asset	$ 15,000
Income Taxes Recoverable (Payable) through Future Rates | Minimum
Regulatory Assets [Line Items]
Amortization period		5 years
Income Taxes Recoverable (Payable) through Future Rates | Maximum
Regulatory Assets [Line Items]
Amortization period		10 years

REVENUE (Details)

REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 532,000	$ 571,000	$ 1,354,000	$ 1,361,000
Alternative Revenues	11,000	7,000	30,000	28,000
Other	9,000	15,000	50,000	58,000
Total Operating Revenues	551,632	593,247	1,433,934	1,447,336
Retail
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	436,000	445,000	1,052,000	975,000
Wholesale
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	72,000	101,000	212,000	291,000
Other Services
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 24,000	$ 25,000	$ 90,000	$ 95,000

ACCOUNTS RECEIVABLE (Components

ACCOUNTS RECEIVABLE (Components) (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Jun. 30, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Retail, Allowance for Credit Losses	$ (12,818)	$ (12,000)	$ (11,676)	$ (11,000)	$ (9,000)	$ (9,000)
Accounts Receivable	274,461		217,381
Due from Affiliates
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable	16,000		7,000
Wholesale | Derivatives
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	15,000		10,000
Trade Accounts Receivable | Retail
Accounts, Notes, Loans and Financing Receivable [Line Items]
Retail, Allowance for Credit Losses	(13,000)		(12,000)
Trade Accounts Receivable | Wholesale
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	31,000		37,000
Trade Accounts Receivable | Retail | Retail
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	153,000		109,000
Trade Accounts Receivable | Retail, Unbilled | Retail
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	69,000		57,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable	$ 18,000		$ 19,000

ACCOUNTS RECEIVABLE (Allowance

ACCOUNTS RECEIVABLE (Allowance for credit losses) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning of Period	$ (12,000)	$ (9,000)	$ (11,676)	$ (9,000)
Credit Loss Expense	(2,000)	(4,000)	(5,000)	(6,000)
Write-offs	1,000	2,000	4,000	4,000
End of Period	$ (12,818)	$ (11,000)	$ (12,818)	$ (11,000)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023	Dec. 31, 2023
Related Party Transaction [Line Items]
Accounts Receivable	$ 274,461		$ 274,461		$ 217,381
Accounts Payable	184,683		184,683		137,002
Operating Revenues	551,632	$ 593,247	1,433,934	$ 1,447,336
Other	9,000	15,000	50,000	58,000
Related Party
Related Party Transaction [Line Items]
Accounts Receivable	16,000		16,000		7,000
Accounts Payable	2,000		2,000		3,000
Related Party | Wholesale Revenues, UNS Electric
Related Party Transaction [Line Items]
Operating Revenues	16,000	22,000	19,000	35,000
Related Party | Common Costs, UNS Energy Affiliates
Related Party Transaction [Line Items]
Common Costs	6,000	6,000	18,000	17,000
Related Party | Transmission Revenues, UNS Electric
Related Party Transaction [Line Items]
Operating Revenues	2,000	2,000	6,000	6,000
Related Party | Control Area Services, UNS Electric
Related Party Transaction [Line Items]
Other	1,000	1,000	2,000	2,000
Related Party | Corporate Services, UNS Energy
Related Party Transaction [Line Items]
Corporate Services	2,000	2,000	$ 7,000	6,000
Massachusetts formula - TEP's allocation (percentage)			85%
Management fee	2,000	2,000	$ 6,000	6,000
Related Party | Corporate Services, UNS Energy Affiliates
Related Party Transaction [Line Items]
Corporate Services	0	0	1,000	1,000
Related Party | Capacity Charges , UNS Gas
Related Party Transaction [Line Items]
Capacity Charges, UNS Gas	0	0	1,000	1,000
Related Party | Purchased Power, UNS Electric
Related Party Transaction [Line Items]
Purchased Power, UNS Electric	0	$ 0	0	$ 1,000
Related Party | UNS Electric
Related Party Transaction [Line Items]
Accounts Receivable	14,000		14,000		5,000
Accounts Payable	1,000		1,000		1,000
Related Party | UNS Gas
Related Party Transaction [Line Items]
Accounts Receivable	2,000		2,000		2,000
Accounts Payable	0		0		1,000
Related Party | UNS Energy
Related Party Transaction [Line Items]
Accounts Payable	$ 1,000		$ 1,000		$ 1,000

DEBT AND CREDIT AGREEMENTS (Nar

DEBT AND CREDIT AGREEMENTS (Narrative) (Details) - USD ($)		1 Months Ended
	Nov. 01, 2024	Oct. 31, 2024	Aug. 31, 2024	Nov. 04, 2024	Sep. 30, 2024
2021 Agreement | Line of Credit
Debt Instrument [Line Items]
Available					$ 250,000,000
2021 Agreement | Line of Credit | Subsequent Event
Debt Instrument [Line Items]
Extension period		1 year
Available				$ 238,000,000
Unsecured Debt | 5.20% Senior Unsecured Notes Due September 2034
Debt Instrument [Line Items]
Proceeds from issuance of debt			$ 400,000,000
Debt instrument, face amount			$ 400,000,000
Interest rate			5.20%
Unsecured Debt | 3.05% Senior Unsecured Notes | Subsequent Event
Debt Instrument [Line Items]
Interest rate	3.05%
Unsecured Debt | 3.05% Senior Unsecured Notes | Subsequent Event | Plan
Debt Instrument [Line Items]
Debt redemption	$ 300,000,000

DEBT AND CREDIT AGREEMENTS (Sch

DEBT AND CREDIT AGREEMENTS (Schedule Of Line Of Credit Facilities) (Details) - 2021 Agreement - Line of Credit $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2024 USD ($)	Sep. 30, 2024 USD ($)
Debt Instrument [Line Items]
Borrowed	$ 0	$ 0
Available	250	250
Revolver
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 250	$ 250
Weighted average interest rate (in percentage)	0%	0%
Line of credit facility, spread price adjusted, average recordable incident rate period	3 years
Revolver | SOFR
Debt Instrument [Line Items]
Basis of variable spread (in percentage)		1.05%
Revolver | Base Rate
Debt Instrument [Line Items]
Basis of variable spread (in percentage)		0.05%
Margin		0.10%
Sub-Limit Swingline
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 15	$ 15
Sub-limit LOC
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 50	$ 50

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (EPC Agreement) (Details) - Capital Addition Purchase Commitments $ in Millions	1 Months Ended
	Aug. 31, 2024 USD ($) MWh MW	Sep. 30, 2024 USD ($)
Long-term Purchase Commitment [Line Items]
Long-term purchase commitment	$ 268
Nominal capacity | MW	200
Storage capacity | MWh	800
Payments		$ 74

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Mine Reclamation) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2024	Dec. 31, 2023
Four Corners
Jointly Owned Utility Plant Interests [Line Items]
Reclamation anticipated costs	$ 3	$ 4
Four Corners | Over the Remaining Term of Agreement
Jointly Owned Utility Plant Interests [Line Items]
Expect to accrue additional cost	1
San Juan
Jointly Owned Utility Plant Interests [Line Items]
Reclamation anticipated costs	34	$ 25
Increase in other noncurrent liabilities	$ 15

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee	Sep. 30, 2024 USD ($)
Guarantor Obligations [Line Items]
Current carrying value	$ 0
Luna
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	0
Four Corners
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	$ 250,000,000

EMPLOYEE BENEFIT PLANS (Schedul

EMPLOYEE BENEFIT PLANS (Schedule of Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Pension Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 4	$ 3	$ 11	$ 9
Non-Service Cost
Interest Cost	6	6	18	17
Expected Return on Plan Assets	(8)	(8)	(24)	(22)
Amortization of Net Loss	1	1	4	3
Net Periodic Benefit Cost	3	2	9	7
Other Postretirement Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1	3	3
Non-Service Cost
Interest Cost	1	1	3	3
Expected Return on Plan Assets	(1)	0	(2)	(1)
Amortization of Net Loss	0	0	0	0
Net Periodic Benefit Cost	$ 1	$ 2	$ 4	$ 5

EMPLOYEE BENEFIT PLANS (Narrati

EMPLOYEE BENEFIT PLANS (Narrative) (Details)	9 Months Ended
	Sep. 30, 2024 USD ($)
Retirement Benefits [Abstract]
Contributions by employer	$ 14,000,000
Expected future employer contributions, remainder of fiscal year	$ 0

FAIR VALUE MEASUREMENTS AND D_3

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Recurring - USD ($)	Sep. 30, 2024	Dec. 31, 2023
Assets
Cash equivalents	$ 55,000,000
Restricted cash	27,000,000	$ 34,000,000
Energy derivative contract assets - regulatory recovery	27,000,000	32,000,000
Energy derivative contract assets - no regulatory recovery	6,000,000	3,000,000
Total Assets	115,000,000	69,000,000
Liabilities
Energy derivative contract liabilities - regulatory recovery	(25,000,000)	(30,000,000)
Total Liabilities	(25,000,000)	(30,000,000)
Total Assets (Liabilities), Net	90,000,000	39,000,000
Level 1
Assets
Cash equivalents	55,000,000
Restricted cash	27,000,000	34,000,000
Energy derivative contract assets - regulatory recovery	0	0
Energy derivative contract assets - no regulatory recovery	0	0
Total Assets	82,000,000	34,000,000
Liabilities
Energy derivative contract liabilities - regulatory recovery	0	0
Total Liabilities	0	0
Total Assets (Liabilities), Net	82,000,000	34,000,000
Level 2
Assets
Cash equivalents	0
Restricted cash	0	0
Energy derivative contract assets - regulatory recovery	27,000,000	32,000,000
Energy derivative contract assets - no regulatory recovery	6,000,000	3,000,000
Total Assets	33,000,000	35,000,000
Liabilities
Energy derivative contract liabilities - regulatory recovery	(25,000,000)	(30,000,000)
Total Liabilities	(25,000,000)	(30,000,000)
Total Assets (Liabilities), Net	8,000,000	$ 5,000,000
Level 3
Liabilities
Total Assets (Liabilities), Net	$ 0

FAIR VALUE MEASUREMENTS AND D_4

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative Contracts - USD ($) $ in Millions	Sep. 30, 2024	Dec. 31, 2023
Derivative Assets
Gross Amount Recognized in the Balance Sheets	$ 33	$ 35
Counterparty Netting of Energy Contracts	14	15
Cash Collateral Received/Posted	0	0
Net Amount	19	20
Derivative Liabilities
Gross Amount Recognized in the Balance Sheets	(25)	(30)
Counterparty Netting of Energy Contracts	(14)	(15)
Cash Collateral Received/Posted	0	0
Net Amount	$ (11)	$ (15)

FAIR VALUE MEASUREMENTS AND D_5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss)			$ (1,546)	$ (257)
Percent of long-term trading contract gains shared with customers (percentage)			10%
Operating Revenues	$ 551,632	$ 593,247	$ 1,433,934	1,447,336
Energy Derivative Contracts | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss)	8,000	0	0	(47,000)
Operating Revenues	$ 3,000	$ 1,000	$ 30,000	$ 18,000

FAIR VALUE MEASUREMENTS AND D_6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Billions	9 Months Ended	12 Months Ended
	Sep. 30, 2024 GWh BTU	Dec. 31, 2023 GWh BTU
Power Contracts GWh
Derivative Volume [Line Items]
Derivative, energy measure | GWh	2,849	1,449
Gas Contracts BBtu
Derivative Volume [Line Items]
Derivative, energy measure | BTU	87,681	89,105

FAIR VALUE MEASUREMENTS AND D_7

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Sep. 30, 2024	Dec. 31, 2023
Fair Value Disclosures [Abstract]
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale	$ 24,000,000	$ 28,000,000
Collateral posted	0	0
Additional collateral required to post if credit-risk contingent features are triggered	24,000,000	28,000,000
Assets needed for immediate settlement, aggregate fair value	$ 15,000,000	$ 13,000,000

FAIR VALUE MEASUREMENTS AND D_8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions	Sep. 30, 2024	Dec. 31, 2023
Net Carrying Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,794	$ 2,397
Fair Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,579	$ 2,127

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Cash Transactions) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Interest Paid, Net of Amounts Capitalized	$ 51	$ 48

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Supplemental Cash Flow Information [Abstract]
Accrued Capital Expenditures	$ 93	$ 32
Renewable Energy Credits	4	4
Asset Retirement Obligations Increase (Decrease)	(2)	(2)
Net Cost of Removal Increase (Decrease)	$ (5)	$ 98