Tucson Electric Power 10-Q 28 Jul 22 2022 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2022	Jul. 27, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
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
Entity Central Index Key	0000100122
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q2
Amendment Flag	false

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Statement [Abstract]
Operating Revenues	$ 439,527	$ 392,661	$ 776,253	$ 728,204
Operating Expenses
Fuel	105,809	80,497	188,773	171,655
Purchased Power	53,487	50,442	84,031	81,819
Transmission and Other PPFAC Recoverable Costs	20,911	15,660	37,746	29,561
Decrease to Reflect PPFAC Recovery Treatment	(2,365)	(7,968)	(14,246)	(24,960)
Total Fuel and Purchased Power	177,842	138,631	296,304	258,075
Operations and Maintenance	101,337	94,906	198,570	206,094
Depreciation	54,450	49,698	108,048	97,456
Amortization	9,939	10,540	19,857	21,171
Taxes Other Than Income Taxes	15,266	15,237	31,965	30,794
Total Operating Expenses	358,834	309,012	654,744	613,590
Operating Income	80,693	83,649	121,509	114,614
Other Income (Expense)
Interest Expense	(21,144)	(23,134)	(42,634)	(44,196)
Allowance For Borrowed Funds	803	1,899	1,413	4,601
Allowance For Equity Funds	2,370	5,008	4,041	12,102
Unrealized Gains (Losses) on Investments	(3,937)	1,691	(6,721)	3,555
Other, Net	3,436	2,762	6,422	5,570
Total Other Income (Expense)	(18,472)	(11,774)	(37,479)	(18,368)
Income Before Income Tax Expense	62,221	71,875	84,030	96,246
Income Tax Expense	7,247	8,125	9,636	9,952
Net Income	$ 54,974	$ 63,750	$ 74,394	$ 86,294

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Cash Flows from Operating Activities
Net Income	$ 74,394	$ 86,294
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	108,048	97,456
Amortization Expense	19,857	21,171
Amortization of Debt Issuance Costs	1,480	1,405
Use of Renewable Energy Credits for Compliance	23,237	24,209
Deferred Income Taxes	8,219	9,713
Pension and Other Postretirement Benefits Expense	5,824	7,671
Pension and Other Postretirement Benefits Funding	(6,027)	(6,190)
Allowance for Equity Funds Used During Construction	(4,041)	(12,102)
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(63,817)	(46,307)
Materials, Supplies, and Fuel Inventory	11,183	(14,439)
Regulatory Assets	(33,048)	(29,294)
Other Current Assets	236	(17,093)
Accounts Payable and Accrued Charges	85,946	41,625
Income Taxes Receivable	(51)	(353)
Regulatory Liabilities	1,066	(10,352)
Other, Net	26,564	14,942
Net Cash Flows—Operating Activities	259,070	168,356
Cash Flows from Investing Activities
Capital Expenditures	(211,663)	(239,970)
Purchase Intangibles, Renewable Energy Credits	(33,892)	(27,810)
Contributions in Aid of Construction	4,804	3,262
Net Cash Flows—Investing Activities	(240,751)	(264,518)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	5,000	35,000
Repayments of Borrowings, Revolving Credit Facility	(20,000)	(35,000)
Proceeds from Issuance, Long-Term Debt—Net of Discount	323,804	322,231
Repayments of Long-Term Debt	(193,465)	0
Payment of Debt Issuance Costs	(2,931)	(3,085)
Contribution from Parent	0	50,000
Other	3,764	757
Net Cash Flows—Financing Activities	116,172	369,903
Net Increase in Cash, Cash Equivalents, and Restricted Cash	134,491	273,741
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	33,489	82,003
Cash, Cash Equivalents, and Restricted Cash, End of Period	$ 167,980	$ 355,744

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Utility Plant
Plant in Service	$ 7,705,774	$ 7,797,935
Construction Work in Progress	195,799	320,931
Total Utility Plant	7,901,573	8,118,866
Accumulated Depreciation and Amortization	(2,567,492)	(2,786,839)
Total Utility Plant, Net	5,334,081	5,332,027
Investments and Other Property	72,100	81,958
Current Assets
Cash and Cash Equivalents	145,878	9,970
Accounts Receivable (Net of Allowance for Credit Losses of $8,227 and $10,044)	256,713	192,579
Fuel Inventory	20,779	26,971
Materials and Supplies	139,037	141,677
Regulatory Assets	141,147	116,442
Derivative Instruments	48,548	19,406
Other	18,850	24,229
Total Current Assets	770,952	531,274
Regulatory and Other Assets
Regulatory Assets	272,534	267,669
Derivative Instruments	80,742	14,392
Other	109,567	94,420
Total Regulatory and Other Assets	462,843	376,481
Total Assets	6,639,976	6,321,740
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2022 and December 31, 2021)	1,696,539	1,696,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	925,336	850,942
Accumulated Other Comprehensive Loss	(9,521)	(9,915)
Total Common Stock Equity	2,605,997	2,531,209
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2022 and December 31, 2021)	0	0
Long-Term Debt, Net	2,113,901	2,134,534
Total Capitalization	4,719,898	4,665,743
Current Liabilities
Current Maturities of Long-Term Debt, Net	150,000	0
Borrowings Under Credit Agreement	0	15,000
Accounts Payable	166,959	139,329
Accrued Taxes Other than Income Taxes	60,192	53,534
Accrued Employee Expenses	33,022	36,217
Accrued Interest	14,837	16,265
Regulatory Liabilities	141,430	111,356
Customer Deposits	13,909	12,791
Derivative Instruments	2,054	15,854
Other	71,017	25,358
Total Current Liabilities	653,420	425,704
Regulatory and Other Liabilities
Deferred Income Taxes, Net	559,013	548,750
Regulatory Liabilities	390,849	352,226
Pension and Other Postretirement Benefits	116,569	120,020
Derivative Instruments	557	3,848
Other	199,670	205,449
Total Regulatory and Other Liabilities	1,266,658	1,230,293
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 6,639,976	$ 6,321,740

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Allowance for Credit Losses	$ 8,227	$ 10,044
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, 2020	$ 2,341,437	$ 1,646,539	$ (6,357)	$ 712,197	$ (10,942)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	86,294			86,294
Other Comprehensive Income, Net of Tax	438				438
Contribution from Parent	50,000	50,000
Ending balance at Jun. 30, 2021	2,478,169	1,696,539	(6,357)	798,491	(10,504)
Beginning balance at Mar. 31, 2021	2,364,200	1,646,539	(6,357)	734,741	(10,723)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	63,750			63,750
Other Comprehensive Income, Net of Tax	219				219
Contribution from Parent	50,000	50,000
Ending balance at Jun. 30, 2021	2,478,169	1,696,539	(6,357)	798,491	(10,504)
Beginning balance at Dec. 31, 2021	2,531,209	1,696,539	(6,357)	850,942	(9,915)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	74,394			74,394
Other Comprehensive Income, Net of Tax	394				394
Ending balance at Jun. 30, 2022	2,605,997	1,696,539	(6,357)	925,336	(9,521)
Beginning balance at Mar. 31, 2022	2,550,826	1,696,539	(6,357)	870,362	(9,718)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	54,974			54,974
Other Comprehensive Income, Net of Tax	197				197
Ending balance at Jun. 30, 2022	$ 2,605,997	$ 1,696,539	$ (6,357)	$ 925,336	$ (9,521)

NATURE OF OPERATIONS AND FINANC

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	6 Months Ended
	Jun. 30, 2022
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 442,000 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 SEC's interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities 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 2021 Annual Report on Form 10-K/A. 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. Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (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 a primary beneficiary of the VIEs on a quarterly basis. As of June 30, 2022, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP 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 on the balance sheet and reconciles their sum to the cash flow statement: June 30, (in millions) 2022 2021 Cash and Cash Equivalents $ 146 $ 336 Restricted Cash included in: Investments and Other Property 19 18 Current Assets—Other 3 2 Total Cash, Cash Equivalents, and Restricted Cash $ 168 $ 356 Restricted cash represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan. Income Tax Expense TEP realized PTC benefits of $6 million and $8 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2022, respectively, and $4 million and $6 million for the three and six months ended June 30, 2021, respectively, as a result of Oso Grande being placed in service in May 2021. Asset Retirement Obligations The following table reconciles the beginning and ending aggregate carrying amounts of Asset Retirement Obligation (ARO) accruals included in Other on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2022 December 31, 2021 Beginning of Period $ 139 $ 96 Liabilities Incurred (1) 1 14 Liabilities Settled (2) (1) (2) Regulatory Deferral 2 4 Revisions to the Present Value of Estimated Cash Flows (3) (16) 27 End of Period $ 125 $ 139 (1) In 2021, TEP incurred an ARO for Oso Grande. In 2022, TEP incurred an ARO for new photovoltaic generation placed in service. (2) Primarily related to the retirement of Navajo. (3) Primarily related to revised decommissioning estimates for San Juan. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the Financial Accounting Standards Board was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

REGULATORY MATTERS

REGULATORY MATTERS	6 Months Ended
	Jun. 30, 2022
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERSThe 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 and transmission facilities, 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 and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. RATE CASE MATTERS 2022 Rate Case In June 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021. TEP's key 2022 Rate Case proposals are described below: • a $136 million net increase in retail revenues comprised of the following components: ◦ a non-fuel retail revenue increase of $159 million over test year non-fuel retail revenues; ◦ a $66 million increase in fuel-related retail revenues, offset by a $71 million reduction in PPFAC revenues; and ◦ changes in certain adjustor mechanisms, including DSM, ECA, and RES, that result in an $18 million reduction in revenues collected from customers. • a 7.31% return on original cost rate base of $3.6 billion, which includes a cost of equity of 10.25% and an average cost of debt of 3.82%; and • a new Resource Transition Mechanism adjustor that is designed to provide more timely recovery of TEP's clean energy investments and replace the ECA. TEP requested new rates to be implemented by September 1, 2023. TEP cannot predict the timing or outcome of this proceeding. 2020 ACC Phase 2 Proceedings In 2020, the ACC issued a rate order for new rates and established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. In January 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. TEP cannot predict the timing or outcome of these proceedings. 2019 FERC Rate Order In 2019, TEP filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for a more timely recovery of transmission-related costs. The FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement. Provisions of the settlement agreement include, but are not limited to: • replacing TEP's stated transmission rates with a single forward-looking formula rate; • a 9.79% return on equity; and • elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor. Increased rates charged under the 2019 FERC Rate Order were subject to refund and deferred as a regulatory liability. Amounts deferred as a regulatory liability in excess of the rates approved in the settlement agreement are being returned to customers. TEP had $10 million as of June 30, 2022, and $15 million as of December 31, 2021, of wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. OTHER FERC MATTERS In January 2021, the FERC notified TEP that it was commencing an audit that intends to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covers the period of January 1, 2018 to the present. The audit is ongoing and TEP cannot predict the outcome or findings, if any, of the FERC audit at this time. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. 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 typically 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. In April 2022, the ACC approved a rate adjustment for the PPFAC that sets the true-up component of the PPFAC rate to recover the existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which may result in future under-collection of PPFAC costs. The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Beginning of Period $ 102 $ 40 $ 91 $ 23 Deferred Fuel and Purchased Power Costs (1) 88 83 153 150 PPFAC and Base Power Recoveries (2) (87) (76) (141) (126) End of Period $ 103 $ 47 $ 103 $ 47 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021. The 2022 PPFAC rate adjustment became effective on April 29, 2022. Tax Expense Adjustor Mechanism The TEAM allows for the timely recovery of future significant income tax changes and provides the Company the ability to pass through as a kWh surcharge: (i) the change in excess deferred income taxes compared to the test year; and (ii) the income tax effects of tax legislation that materially impacts TEP's 2018 test year revenue requirements. Transmission Cost Adjustor The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January of each year. In February 2022, the ACC approved TEP's motion to modify the TCA plan of administration to reflect the terms of the 2019 FERC Rate Order settlement agreement. 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%. The renewable energy requirement in 2022 is 12% of retail electric sales. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES surcharge. In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal by July 1, 2022, to phase out the RES tariff. In June 2022, TEP filed a request with the ACC for approval of an extension of the 2021 RES implementation plan through the completion of the 2022 Rate Case. The rate case includes a proposal to transition away from the current RES surcharge and to recover the costs in base rates. Energy Efficiency Standards TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement 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 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of $23 million, which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standards. The 2018 plan has been effective from 2018 through the present and will remain in effect until another plan is approved. In 2021, TEP filed its 2022 energy efficiency implementation plan with a budget of $23 million. In March 2022, TEP filed an application with the ACC requesting the 2022 energy efficiency implementation plan be considered as its 2023 energy efficiency implementation plan. In June 2022, TEP filed a supplement to the 2022 energy efficiency implementation plan with the ACC to include a new pilot plan, which increases the budget of the plan to $24 million. TEP cannot predict the outcome of these proceedings. The 2022 Rate Case includes a proposal to transition away from the current DSM surcharge and to recover the costs in base rates. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below: ($ in millions) Remaining Recovery Period June 30, 2022 December 31, 2021 Regulatory Assets Pension and Other Postretirement Benefits Various $ 126 $ 128 Under Recovered Purchased Energy Costs 2 103 91 Early Generation Retirement Costs (1) Various 73 38 Lost Fixed Cost Recovery 1 31 37 Property Tax Deferrals (2) 1 28 27 Final Mine Reclamation and Retiree Healthcare Costs (3) 7 18 17 Income Taxes Recoverable through Future Rates (4) Various 13 17 Unamortized Loss on Reacquired Debt Various 6 5 Springerville Unit 1 Leasehold Improvements (5) 2 3 4 Derivatives (Note 9) 8 — 8 Other Regulatory Assets Various 13 12 Total Regulatory Assets 414 384 Less Current Portion 1 141 116 Total Non-Current Regulatory Assets $ 273 $ 268 Regulatory Liabilities Income Taxes Payable through Future Rates (4) Various $ 259 $ 268 Derivatives (Note 9) 8 118 19 Renewable Energy Standard Various 67 66 Net Cost of Removal (6) Various 48 73 Demand Side Management 1 15 12 Transmission Cost Adjustor 1 11 9 Transmission Revenue Subject to Refund—FERC 1 10 15 Other Regulatory Liabilities Various 4 1 Total Regulatory Liabilities 532 463 Less Current Portion 1 141 111 Total Non-Current Regulatory Liabilities $ 391 $ 352 (1) Increase in Early Generation Retirement Costs is primarily due to San Juan Unit 1 being retired in June 2022. (2) 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. (3) 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 2028. San Juan Unit 1 was retired June 2022. (4) Amortized over five years, 10 years, or the lives of the assets. (5) Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period. (6) 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 and intangible plant which are not yet expended. The decrease in Net Cost of Removal is primarily due to San Juan Unit 1 being retired June 2022. 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, and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. TEP pays a return on the majority of its regulatory liability balances. PLANT IN SERVICE On June 30, 2022, San Juan Unit 1 was retired by Public Service Company of New Mexico (PNM), the operator of San Juan. Contemporaneously, TEP's obligations ceased with respect to: (i) costs related to San Juan Unit 1 and Common Facilities stemming from continued operations at San Juan; and (ii) purchases under the coal supply agreement between PNM and San Juan Coal Company. Discussions with the remaining joint-participants in San Juan regarding decommissioning of the facilities are ongoing, with decommissioning to be scheduled at a later date. TEP recovers costs related to its ownership interest in San Juan in base rates and expects to collect the remaining net book value of San Juan by the end of 2022. As of June 30, 2022, there was a balance related to San Juan of $36 million in Regulatory and Other Assets—Regulatory Assets and $15 million in Regulatory and Other Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP requested recovery of unused materials and supplies costs related to San Juan in its 2022 Rate Case.

REVENUE

REVENUE	6 Months Ended
	Jun. 30, 2022
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE DISAGGREGATION OF REVENUES TEP earns the majority 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 June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Retail $ 306 $ 297 $ 524 $ 512 Wholesale (1) 99 47 155 103 Other Services 23 25 47 61 Revenues from Contracts with Customers 428 369 726 676 Alternative Revenues 2 3 13 10 Other 10 21 37 42 Total Operating Revenues $ 440 $ 393 $ 776 $ 728 (1) Pursuant to a FERC order, all rates charged under TEP's revised OATT were subject to refund until the 2019 FERC Rate Order proceedings concluded. Wholesale Revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Order.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	6 Months Ended
	Jun. 30, 2022
Receivables [Abstract]
ACCOUNTS RECEIVABLE	ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2022 December 31, 2021 Retail $ 97 $ 78 Retail, Unbilled 65 44 Retail, Allowance for Credit Losses (8) (10) Wholesale (1) 52 47 Due from Affiliates (Note 5) 24 17 Other 27 17 Accounts Receivable $ 257 $ 193 (1) Includes $15 million as of June 30, 2022, and $16 million as of December 31, 2021, 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 June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Beginning of Period $ (9) $ (13) $ (10) $ (13) Credit Loss Expense (1) — (1) (1) Write-offs 2 1 3 2 End of Period (1) $ (8) $ (12) $ (8) $ (12) (1) In 2021, the ACC adopted permanent rules that annually suspend service disconnections and late fees for electric residential customers who otherwise are eligible for service disconnection during the period from June 1 through October 15. TEP continuously monitors collection activity and adjusts its allowance for credit losses as needed. Customer Payment Assistance In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $4 million and $11 million in DES payment assistance funds in the three and six months ended June 30, 2022, respectively.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	6 Months Ended
	Jun. 30, 2022
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) June 30, 2022 December 31, 2021 Receivables from Related Parties UNS Electric $ 16 $ 8 UNS Energy 6 7 UNS Gas 2 2 Total Due from Related Parties $ 24 $ 17 Payables to Related Parties UNS Energy $ 2 $ 1 UNS Electric 1 — UNS Gas — 1 Total Due to Related Parties $ 3 $ 2 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 1 $ 3 $ 3 $ 6 Wholesale Revenues, UNS Electric (1) 9 4 10 5 Control Area Services, UNS Electric (2) 1 1 2 3 Common Costs, UNS Energy Affiliates (3) 6 5 11 10 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) $ — $ 1 $ — $ 1 Corporate Services, UNS Energy (4) 2 2 5 4 Corporate Services, UNS Energy Affiliates (5) 1 1 1 2 (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) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) 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. (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. The Corporate Services, UNS Energy line includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million and $4 million for the three and six months ended June 30, 2022, respectively, and $1 million and $3 million for the three and six months ended June 30, 2021, 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. DIVIDENDS DECLARED AND PAID TO PARENT On July 25, 2022, TEP declared a $50 million dividend to UNS Energy, to be paid on or before July 31, 2022.

DEBT AND CREDIT AGREEMENTS

DEBT AND CREDIT AGREEMENTS	6 Months Ended
	Jun. 30, 2022
Debt Disclosure [Abstract]
DEBT AND CREDIT AGREEMENTS	DEBT AND CREDIT AGREEMENTS There have been no significant changes to TEP's debt or credit agreements from those reported in its 2021 Annual Report on Form 10-K/A, except as noted below. DEBT Issuance and Redemptions In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt and for general corporate purposes. In March 2022, TEP redeemed at par prior to maturity $177 million in aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum. In June 2022, TEP redeemed at par prior to maturity $16 million in aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum. CREDIT AGREEMENT 2021 Credit Agreement

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	6 Months Ended
	Jun. 30, 2022
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS There have been no significant changes to TEP's long-term commitments from those reported in its 2021 Annual Report on Form 10-K/A. CONTINGENCIES Legal Matters TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. Mine Reclamation at Generation Facilities Not Operated by TEP TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP’s PPFAC allows the Company to pass through to retail customers final mine reclamation costs as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $40 million as of June 30, 2022 and December 31, 2021, was recorded in Other on the Condensed Consolidated Balance Sheets. TEP’s share of final mine reclamation costs at Four Corners is estimated to be $9 million u pon the expected expiration of the Four Corners coal supply agreement in 2031. On June 30, 2022, TEP’s estimated share of final mine reclamation costs at San Juan was $34 million . 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 2039. For additional information see Note 1, Restricted Cash and Note 2, Plant in Service . Performance Guarantees TEP has joint generation participation agreements with participants at San Juan, Four Corners, and Luna Generating Station, which expire in 2022, 2041, and 2046, respectively. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generation facility. The participants in each of the generation facilities, 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. Relative to Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments by the non-defaulting parties is $250 million at Four Corners. As of June 30, 2022, there have been no such payment defaults under any of the participation agreements. 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. Broadway-Pantano Site The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. These landfills were in operation from 1959 to 1972 and 1953 to 1962, respectively. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	6 Months Ended
	Jun. 30, 2022
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 June 30, (in millions) 2022 2021 2022 2021 Service Cost $ 5 $ 5 $ 2 $ 1 Non-Service Cost (1) Interest Cost 4 4 1 1 Expected Return on Plan Assets (10) (9) (1) (1) Amortization of Net Loss 2 3 — — Net Periodic Benefit Cost $ 1 $ 3 $ 2 $ 1 Pension Benefits Other Postretirement Benefits Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Service Cost $ 10 $ 10 $ 3 $ 3 Non-Service Cost (1) Interest Cost 8 7 1 1 Expected Return on Plan Assets (19) (17) (1) (1) Amortization of Net Loss 4 5 — — Net Periodic Benefit Cost $ 3 $ 5 $ 3 $ 3 (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 DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	6 Months Ended
	Jun. 30, 2022
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTSTEP 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) June 30, 2022 Assets Cash Equivalents (1) $ 110 $ — $ 110 Restricted Cash (1) 22 — 22 Energy Derivative Contracts, Regulatory Recovery (2) — 119 119 Energy Derivative Contracts, No Regulatory Recovery (2) — 10 10 Total Assets 132 129 261 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (3) (3) Total Liabilities — (3) (3) Total Assets (Liabilities), Net $ 132 $ 126 $ 258 (in millions) December 31, 2021 Assets Restricted Cash (1) $ 23 $ — $ 23 Energy Derivative Contracts, Regulatory Recovery (2) — 30 30 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 23 34 57 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (20) (20) Total Liabilities — (20) (20) Total Assets (Liabilities), Net $ 23 $ 14 $ 37 (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 on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (1) (in millions) June 30, 2022 Derivative Assets Energy Derivative Contracts $ 129 $ 3 $ 36 $ 90 Derivative Liabilities Energy Derivative Contracts (3) (3) — — (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (1) TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Condensed Consolidated Balance Sheets. As of July 27, 2022, there was $43 million of cash received as collateral to provide credit enhancement. DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and 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 the Company'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 a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Unrealized Net Gain (1) $ 18 $ 17 $ 107 $ 13 (1) Increase in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas. Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined 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 June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Operating Revenues $ 2 $ — $ 10 $ 1 Derivative Volumes As of June 30, 2022, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts: June 30, 2022 December 31, 2021 Power Contracts GWh 4,536 2,617 Gas Contracts BBtu 105,040 112,316 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. In the event that such credit events were to occur, TEP, or its counterparties, would 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 the individual contracts. The 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 $37 million as of June 30, 2022, compared with $26 million as of December 31, 2021. As of June 30, 2022, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on June 30, 2022, TEP would have been required to post $37 million of collateral. As of June 30, 2022, TEP had $41 million in outstanding net payable balances for settled positions. 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) June 30, 2022 December 31, 2021 June 30, 2022 December 31, 2021 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,264 $ 2,135 $ 2,042 $ 2,357

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	6 Months Ended
	Jun. 30, 2022
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION 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: Six Months Ended June 30, (in millions) 2022 2021 Accrued Capital Expenditures $ 25 $ 36 Renewable Energy Credits 5 5 Asset Retirement Obligation/Cost Increase (Decrease) (1) (28) 13 Net Cost of Removal Decrease (2) (46) (36) (1) In 2021, primarily represents a new obligation related to Oso Grande. In 2022, primarily represents the retirement of the San Juan asset retirement cost asset. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2021, TEP transferred a portion of the Net Cost of Removal recorded in Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of revised depreciation rates. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset.

NATURE OF OPERATIONS AND FINA_2

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	6 Months Ended
	Jun. 30, 2022
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 SEC's interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities 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 2021 Annual Report on Form 10-K/A. 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.
Variable Interest Entities	Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (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 a primary beneficiary of the VIEs on a quarterly basis. As of June 30, 2022, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
Restricted Cash	Restricted CashRestricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. Restricted cash represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED	NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the Financial Accounting Standards Board was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

NATURE OF OPERATIONS AND FINA_3

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables)	6 Months Ended
	Jun. 30, 2022
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 on the balance sheet and reconciles their sum to the cash flow statement: June 30, (in millions) 2022 2021 Cash and Cash Equivalents $ 146 $ 336 Restricted Cash included in: Investments and Other Property 19 18 Current Assets—Other 3 2 Total Cash, Cash Equivalents, and Restricted Cash $ 168 $ 356
Schedule of restricted cash	The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: June 30, (in millions) 2022 2021 Cash and Cash Equivalents $ 146 $ 336 Restricted Cash included in: Investments and Other Property 19 18 Current Assets—Other 3 2 Total Cash, Cash Equivalents, and Restricted Cash $ 168 $ 356
Schedule of asset retirement obligations	The following table reconciles the beginning and ending aggregate carrying amounts of Asset Retirement Obligation (ARO) accruals included in Other on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2022 December 31, 2021 Beginning of Period $ 139 $ 96 Liabilities Incurred (1) 1 14 Liabilities Settled (2) (1) (2) Regulatory Deferral 2 4 Revisions to the Present Value of Estimated Cash Flows (3) (16) 27 End of Period $ 125 $ 139 (1) In 2021, TEP incurred an ARO for Oso Grande. In 2022, TEP incurred an ARO for new photovoltaic generation placed in service. (2) Primarily related to the retirement of Navajo. (3) Primarily related to revised decommissioning estimates for San Juan.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	6 Months Ended
	Jun. 30, 2022
Regulated Operations [Abstract]
Schedule of Purchased Power and Fuel Adjustment Rates	The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Beginning of Period $ 102 $ 40 $ 91 $ 23 Deferred Fuel and Purchased Power Costs (1) 88 83 153 150 PPFAC and Base Power Recoveries (2) (87) (76) (141) (126) End of Period $ 103 $ 47 $ 103 $ 47 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021. The 2022 PPFAC rate adjustment became effective on April 29, 2022.
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 June 30, 2022 December 31, 2021 Regulatory Assets Pension and Other Postretirement Benefits Various $ 126 $ 128 Under Recovered Purchased Energy Costs 2 103 91 Early Generation Retirement Costs (1) Various 73 38 Lost Fixed Cost Recovery 1 31 37 Property Tax Deferrals (2) 1 28 27 Final Mine Reclamation and Retiree Healthcare Costs (3) 7 18 17 Income Taxes Recoverable through Future Rates (4) Various 13 17 Unamortized Loss on Reacquired Debt Various 6 5 Springerville Unit 1 Leasehold Improvements (5) 2 3 4 Derivatives (Note 9) 8 — 8 Other Regulatory Assets Various 13 12 Total Regulatory Assets 414 384 Less Current Portion 1 141 116 Total Non-Current Regulatory Assets $ 273 $ 268 Regulatory Liabilities Income Taxes Payable through Future Rates (4) Various $ 259 $ 268 Derivatives (Note 9) 8 118 19 Renewable Energy Standard Various 67 66 Net Cost of Removal (6) Various 48 73 Demand Side Management 1 15 12 Transmission Cost Adjustor 1 11 9 Transmission Revenue Subject to Refund—FERC 1 10 15 Other Regulatory Liabilities Various 4 1 Total Regulatory Liabilities 532 463 Less Current Portion 1 141 111 Total Non-Current Regulatory Liabilities $ 391 $ 352 (1) Increase in Early Generation Retirement Costs is primarily due to San Juan Unit 1 being retired in June 2022. (2) 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. (3) 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 2028. San Juan Unit 1 was retired June 2022. (4) Amortized over five years, 10 years, or the lives of the assets. (5) Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period. (6) 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 and intangible plant which are not yet expended. The decrease in Net Cost of Removal is primarily due to San Juan Unit 1 being retired June 2022.

REVENUE (Tables)

REVENUE (Tables)	6 Months Ended
	Jun. 30, 2022
Revenue from Contract with Customer [Abstract]
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 June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Retail $ 306 $ 297 $ 524 $ 512 Wholesale (1) 99 47 155 103 Other Services 23 25 47 61 Revenues from Contracts with Customers 428 369 726 676 Alternative Revenues 2 3 13 10 Other 10 21 37 42 Total Operating Revenues $ 440 $ 393 $ 776 $ 728 (1) Pursuant to a FERC order, all rates charged under TEP's revised OATT were subject to refund until the 2019 FERC Rate Order proceedings concluded. Wholesale Revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Order.

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	6 Months Ended
	Jun. 30, 2022
Receivables [Abstract]
Accounts Receivable	The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2022 December 31, 2021 Retail $ 97 $ 78 Retail, Unbilled 65 44 Retail, Allowance for Credit Losses (8) (10) Wholesale (1) 52 47 Due from Affiliates (Note 5) 24 17 Other 27 17 Accounts Receivable $ 257 $ 193 (1) Includes $15 million as of June 30, 2022, and $16 million as of December 31, 2021, of receivables related to revenue from derivative instruments.
Schedule of Allowance for Credit Loss	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 June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Beginning of Period $ (9) $ (13) $ (10) $ (13) Credit Loss Expense (1) — (1) (1) Write-offs 2 1 3 2 End of Period (1) $ (8) $ (12) $ (8) $ (12) (1) In 2021, the ACC adopted permanent rules that annually suspend service disconnections and late fees for electric residential customers who otherwise are eligible for service disconnection during the period from June 1 through October 15.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	6 Months Ended
	Jun. 30, 2022
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) June 30, 2022 December 31, 2021 Receivables from Related Parties UNS Electric $ 16 $ 8 UNS Energy 6 7 UNS Gas 2 2 Total Due from Related Parties $ 24 $ 17 Payables to Related Parties UNS Energy $ 2 $ 1 UNS Electric 1 — UNS Gas — 1 Total Due to Related Parties $ 3 $ 2 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 1 $ 3 $ 3 $ 6 Wholesale Revenues, UNS Electric (1) 9 4 10 5 Control Area Services, UNS Electric (2) 1 1 2 3 Common Costs, UNS Energy Affiliates (3) 6 5 11 10 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) $ — $ 1 $ — $ 1 Corporate Services, UNS Energy (4) 2 2 5 4 Corporate Services, UNS Energy Affiliates (5) 1 1 1 2 (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) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) 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. (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. The Corporate Services, UNS Energy line includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million and $4 million for the three and six months ended June 30, 2022, respectively, and $1 million and $3 million for the three and six months ended June 30, 2021, 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.

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	6 Months Ended
	Jun. 30, 2022
Retirement Benefits [Abstract]
Components of Net Periodic Benefit Cost	Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, (in millions) 2022 2021 2022 2021 Service Cost $ 5 $ 5 $ 2 $ 1 Non-Service Cost (1) Interest Cost 4 4 1 1 Expected Return on Plan Assets (10) (9) (1) (1) Amortization of Net Loss 2 3 — — Net Periodic Benefit Cost $ 1 $ 3 $ 2 $ 1 Pension Benefits Other Postretirement Benefits Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Service Cost $ 10 $ 10 $ 3 $ 3 Non-Service Cost (1) Interest Cost 8 7 1 1 Expected Return on Plan Assets (19) (17) (1) (1) Amortization of Net Loss 4 5 — — Net Periodic Benefit Cost $ 3 $ 5 $ 3 $ 3 (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)	6 Months Ended
	Jun. 30, 2022
Fair Value Disclosures [Abstract]
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) June 30, 2022 Assets Cash Equivalents (1) $ 110 $ — $ 110 Restricted Cash (1) 22 — 22 Energy Derivative Contracts, Regulatory Recovery (2) — 119 119 Energy Derivative Contracts, No Regulatory Recovery (2) — 10 10 Total Assets 132 129 261 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (3) (3) Total Liabilities — (3) (3) Total Assets (Liabilities), Net $ 132 $ 126 $ 258 (in millions) December 31, 2021 Assets Restricted Cash (1) $ 23 $ — $ 23 Energy Derivative Contracts, Regulatory Recovery (2) — 30 30 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 23 34 57 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (20) (20) Total Liabilities — (20) (20) Total Assets (Liabilities), Net $ 23 $ 14 $ 37 (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.
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 (1) (in millions) June 30, 2022 Derivative Assets Energy Derivative Contracts $ 129 $ 3 $ 36 $ 90 Derivative Liabilities Energy Derivative Contracts (3) (3) — — (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (1) TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Condensed Consolidated Balance Sheets. As of July 27, 2022, there was $43 million of cash received as collateral to provide credit enhancement.
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 (1) (in millions) June 30, 2022 Derivative Assets Energy Derivative Contracts $ 129 $ 3 $ 36 $ 90 Derivative Liabilities Energy Derivative Contracts (3) (3) — — (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (1) TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Condensed Consolidated Balance Sheets. As of July 27, 2022, there was $43 million of cash received as collateral to provide credit enhancement.
Financial Impact of Energy Contracts	The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Unrealized Net Gain (1) $ 18 $ 17 $ 107 $ 13 (1) Increase in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas. Three Months Ended June 30, Six Months Ended June 30, (in millions) 2022 2021 2022 2021 Operating Revenues $ 2 $ — $ 10 $ 1
Derivative Volumes	The following table presents volumes associated with the energy contracts: June 30, 2022 December 31, 2021 Power Contracts GWh 4,536 2,617 Gas Contracts BBtu 105,040 112,316
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) June 30, 2022 December 31, 2021 June 30, 2022 December 31, 2021 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,264 $ 2,135 $ 2,042 $ 2,357

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2022
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	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: Six Months Ended June 30, (in millions) 2022 2021 Accrued Capital Expenditures $ 25 $ 36 Renewable Energy Credits 5 5 Asset Retirement Obligation/Cost Increase (Decrease) (1) (28) 13 Net Cost of Removal Decrease (2) (46) (36) (1) In 2021, primarily represents a new obligation related to Oso Grande. In 2022, primarily represents the retirement of the San Juan asset retirement cost asset. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2021, TEP transferred a portion of the Net Cost of Removal recorded in Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of revised depreciation rates. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset.

NATURE OF OPERATIONS AND FINA_4

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Narrative) (Details) customer in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022 USD ($) customer	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($) mi² customer	Jun. 30, 2021 USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of retail customers | customer	442		442
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi²			1,155
PTC benefits | $	$ 6	$ 4	$ 8	$ 6

NATURE OF OPERATIONS AND FINA_5

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Cash and Cash Equivalents [Line Items]
Cash and Cash Equivalents	$ 145,878	$ 9,970	$ 336,000
Total Cash, Cash Equivalents, and Restricted Cash	167,980	$ 33,489	355,744	$ 82,003
Investments and Other Property
Cash and Cash Equivalents [Line Items]
Restricted Cash	19,000		18,000
Current Assets—Other
Cash and Cash Equivalents [Line Items]
Restricted Cash	$ 3,000		$ 2,000

NATURE OF OPERATIONS AND FINA_6

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Asset Retirement) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of Period	$ 139	$ 96
Liabilities Incurred	1	14
Liabilities Settled	(1)	(2)
Regulatory Deferral	2	4
Revisions to the Present Value of Estimated Cash Flows	(16)	27
End of Period	$ 125	$ 139

REGULATORY MATTERS (2022 Rate C

REGULATORY MATTERS (2022 Rate Case) (Details) - Arizona Corporation Commission $ in Millions	1 Months Ended
	Jun. 30, 2022 USD ($)
Public Utilities, General Disclosures [Line Items]
Original cost rate base (percentage)	7.31%
Original cost rate base	$ 3,600
Original cost of equity (percentage)	10.25%
Average original cost of debt (percentage)	3.82%
Retail Revenues
Public Utilities, General Disclosures [Line Items]
Base rate increase (decrease)	$ 136
Non-fuel Retail Revenues
Public Utilities, General Disclosures [Line Items]
Base rate increase (decrease)	159
Fuel-Related Retail Revenues
Public Utilities, General Disclosures [Line Items]
Base rate increase (decrease)	66
PPFAC Revenues
Public Utilities, General Disclosures [Line Items]
Base rate increase (decrease)	(71)
Revenues Collected from Customers
Public Utilities, General Disclosures [Line Items]
Base rate increase (decrease)	$ (18)

REGULATORY MATTERS (2019 FERC R

REGULATORY MATTERS (2019 FERC Rate Order) (Details) - USD ($) $ in Thousands	1 Months Ended
	Mar. 31, 2022	Jun. 30, 2022	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 141,430	$ 111,356
FERC | Transmission Services Rate
Public Utilities, General Disclosures [Line Items]
Approved return on equity (percentage)	9.79%
FERC | Transmission Services Rate | Revenue Subject to Refund
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 10,000	$ 15,000

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($)	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2022	Apr. 30, 2022	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2025	Dec. 31, 2021	Dec. 31, 2019
Regulatory Assets [Roll Forward]
Regulatory liability	$ 141,430,000		$ 141,430,000		$ 141,430,000			$ 111,356,000
Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified					12 months
Period of recovery of uncollected true-up balance, approved		18 months
Forward-looking component of PPFAC rate, approved		$ 0
Regulatory Assets [Roll Forward]
Beginning of Period		$ 102,000,000	102,000,000	$ 40,000,000	$ 91,000,000	$ 23,000,000		23,000,000
Deferred Fuel and Purchased Power Costs			88,000,000	83,000,000	153,000,000	150,000,000
PPFAC and Base Power Recoveries			(87,000,000)	(76,000,000)	(141,000,000)	(126,000,000)
End of Period	103,000,000		$ 103,000,000	$ 47,000,000	$ 103,000,000	$ 47,000,000		91,000,000
Renewable Energy Standard
Regulatory Assets [Roll Forward]
Renewable energy target percentage					12%
Distributed generation requirement percent of target percentage (percentage)					30%
Approved spending budget for the years of 2021 and 2022								66,000,000
Renewable Energy Standard | Scenario, Forecast
Regulatory Assets [Roll Forward]
Renewable energy target percentage							15%
Energy Efficiency Standards
Regulatory Assets [Roll Forward]
Approved recovery of spending budget									$ 23,000,000
Recovery of spending budget, requested amount	$ 24,000,000							$ 23,000,000
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	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 414,000	$ 384,000
Less Current Portion	141,147	116,442
Total Non-Current Regulatory Assets	272,534	267,669
Pension and Other Postretirement Benefits
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 126,000	128,000
Under Recovered Purchased Energy Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	2 years
Total Regulatory Assets	$ 103,000	91,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 73,000	38,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 31,000	37,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 28,000	27,000
Final Mine Reclamation and Retiree Healthcare Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	7 years
Total Regulatory Assets	$ 18,000	17,000
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	13,000	17,000
Unamortized Loss on Reacquired Debt
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 6,000	5,000
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	2 years
Total Regulatory Assets	$ 3,000	4,000
Derivatives
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	8 years
Total Regulatory Assets	$ 0	8,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 13,000	$ 12,000

REGULATORY MATTERS (Regulator_2

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 532,000	$ 463,000
Less Current Portion	141,430	111,356
Total Non-Current Regulatory Liabilities	390,849	352,226
Income Taxes Payable through Future Rates
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 259,000	268,000
Derivatives
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	8 years
Total Regulatory Liabilities	$ 118,000	19,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	67,000	66,000
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 48,000	73,000
Demand Side Management
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 15,000	12,000
Transmission Cost Adjustor
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 11,000	9,000
Transmission Revenue Subject to Refund—FERC
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 10,000	15,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 4,000	$ 1,000

REGULATORY MATTERS (Regulator_3

REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details)	6 Months Ended
	Jun. 30, 2022
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
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Useful life (in years)	10 years

REGULATORY MATTERS (Plant in Se

REGULATORY MATTERS (Plant in Service) (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Regulatory and Other Assets	$ 462,843	$ 376,481
Regulatory and Other Liabilities	1,266,658	$ 1,230,293
San Juan
Public Utilities, General Disclosures [Line Items]
Regulatory and Other Assets	36,000
Regulatory and Other Liabilities	$ 15,000

REVENUE (Details)

REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 428,000	$ 369,000	$ 726,000	$ 676,000
Alternative Revenues	2,000	3,000	13,000	10,000
Other	10,000	21,000	37,000	42,000
Total Operating Revenues	439,527	392,661	776,253	728,204
Retail
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	306,000	297,000	524,000	512,000
Wholesale
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	99,000	47,000	155,000	103,000
Other Services
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 23,000	$ 25,000	$ 47,000	$ 61,000

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Credit Losses	$ (8,227)	$ (12,000)	$ (8,227)	$ (12,000)	$ (10,044)
Accounts Receivable	256,713		256,713		192,579
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning of Period	(9,000)	(13,000)	(10,044)	(13,000)
Credit Loss Expense	(1,000)	0	(1,000)	(1,000)
Write-offs	2,000	1,000	3,000	2,000
End of Period	(8,227)	$ (12,000)	(8,227)	$ (12,000)
DES payment assistance funds	4,000		11,000
Due from Affiliates
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	24,000		24,000		17,000
Wholesale | Derivatives
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	15,000		15,000		16,000
Trade Accounts Receivable | Retail [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Credit Losses	(8,000)		(8,000)		(10,000)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning of Period			(10,000)
End of Period	(8,000)		(8,000)
Trade Accounts Receivable | Wholesale
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	52,000		52,000		47,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	27,000		27,000		17,000
Billed | Trade Accounts Receivable | Retail [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	97,000		97,000		78,000
Unbilled | Trade Accounts Receivable | Retail [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 65,000		$ 65,000		$ 44,000

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
	Jul. 25, 2022	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties		$ 24		$ 24		$ 17
Due to related parties		3		3		2
Transmission Revenues, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Revenue from related party		1	$ 3	3	$ 6
Wholesale Revenues, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Revenue from related party		9	4	10	5
Wholesale purchases		0	1	0	1
Control Area Services, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Control area services		1	1	2	3
Common Costs, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Common costs		6	5	11	10
Corporate Services, UNS Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate services		2	2	$ 5	4
Massachusetts Formula - TEP's allocation (percentage)				85%
Management fee		2	1	$ 4	3
Corporate Services, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate services		1	$ 1	1	$ 2
UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties		16		16		8
Due to related parties		1		1		0
UNS Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties		6		6		7
Due to related parties		2		2		1
UNS Energy | Subsequent Event
Related Party Transaction, Due to/from Related Party [Abstract]
Dividends declared and paid	$ 50
UNS Gas
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties		2		2		2
Due to related parties		$ 0		$ 0		$ 1

DEBT AND CREDIT AGREEMENTS (Det

DEBT AND CREDIT AGREEMENTS (Details) - USD ($)	1 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Feb. 28, 2022	Jul. 01, 2022	Oct. 31, 2021
3.25% Senior Unsecured Notes due May 2032 | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount			$ 325,000,000
Proceeds from issuance of debt			$ 325,000,000
Interest rate			3.25%
4.5% Tax-Exempt Bonds | Unsecured Debt
Debt Instrument [Line Items]
Interest rate	4.50%	4.50%
Debt extinguishment	$ 16,000,000	$ 177,000,000
2021 Agreement | Line of Credit | Revolver
Debt Instrument [Line Items]
Available	240,000,000
Borrowed	$ 0
2021 Agreement | Line of Credit | Sub-Limit LOC
Debt Instrument [Line Items]
Borrowed					$ 10,000,000
Weighted average interest rate (in percentage)					1%
2021 Agreement | Line of Credit | Sub-Limit LOC | Subsequent Event
Debt Instrument [Line Items]
Weighted average interest rate (in percentage)				1.025%

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Mine Reclamation) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
San Juan and Four Corners | Other Liabilities
Jointly Owned Utility Plant Interests [Line Items]
Reclamation costs accrued	$ 40	$ 40
Four Corners
Jointly Owned Utility Plant Interests [Line Items]
Reclamation anticipated costs	9
San Juan
Jointly Owned Utility Plant Interests [Line Items]
Reclamation anticipated costs	$ 34

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee	Jun. 30, 2022 USD ($)
Guarantor Obligations [Line Items]
Current carrying value	$ 0
Navajo, San Juan, Luna
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	0
Four Corners
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	$ 250,000,000

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Pension Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 5	$ 5	$ 10	$ 10
Non-Service Cost
Interest Cost	4	4	8	7
Expected Return on Plan Assets	(10)	(9)	(19)	(17)
Amortization of Net Loss	2	3	4	5
Net Periodic Benefit Cost	1	3	3	5
Other Postretirement Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	2	1	3	3
Non-Service Cost
Interest Cost	1	1	1	1
Expected Return on Plan Assets	(1)	(1)	(1)	(1)
Amortization of Net Loss	0	0	0	0
Net Periodic Benefit Cost	$ 2	$ 1	$ 3	$ 3

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 ($)	Jun. 30, 2022	Dec. 31, 2021
Assets
Cash Equivalents	$ 110,000,000
Restricted Cash	22,000,000	$ 23,000,000
Energy Derivative Contract Assets - Regulatory Recovery	119,000,000	30,000,000
Energy Derivative Contract Assets - No Regulatory Recovery	10,000,000	4,000,000
Total Assets	261,000,000	57,000,000
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(3,000,000)	(20,000,000)
Total Liabilities	(3,000,000)	(20,000,000)
Total Assets (Liabilities), Net	258,000,000	37,000,000
Level 1
Assets
Cash Equivalents	110,000,000
Restricted Cash	22,000,000	23,000,000
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	132,000,000	23,000,000
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Total Liabilities	0	0
Total Assets (Liabilities), Net	132,000,000	23,000,000
Level 2
Assets
Cash Equivalents	0
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	119,000,000	30,000,000
Energy Derivative Contract Assets - No Regulatory Recovery	10,000,000	4,000,000
Total Assets	129,000,000	34,000,000
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(3,000,000)	(20,000,000)
Total Liabilities	(3,000,000)	(20,000,000)
Total Assets (Liabilities), Net	126,000,000	$ 14,000,000
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	Jul. 27, 2022	Jun. 30, 2022	Dec. 31, 2021
Derivative Assets
Gross Amount Recognized in the Balance Sheets		$ 129	$ 34
Counterparty Netting of Energy Contracts		3	14
Cash Collateral Received/Posted		36	0
Net Amount		90	20
Derivative Liabilities
Gross Amount Recognized in the Balance Sheets		(3)	(20)
Counterparty Netting of Energy Contracts		(3)	(14)
Cash Collateral Received/Posted		0	0
Net Amount		$ 0	$ (6)
Subsequent Event
Derivative Liabilities
Cash Collateral Received/Posted	$ 43

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		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Percent of long-term trading contract gains shared with customers (percentage)			10%
Operating Revenues	$ 439,527	$ 392,661	$ 776,253	$ 728,204
Energy Derivative Contracts | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain	18,000	17,000	107,000	13,000
Operating Revenues	$ 2,000	$ 0	$ 10,000	$ 1,000

FAIR VALUE MEASUREMENTS AND D_6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Billions	6 Months Ended	12 Months Ended
	Jun. 30, 2022 GWh BTU	Dec. 31, 2021 BTU GWh
Power Contracts GWh
Derivative Volume [Line Items]
Derivative, energy measure | GWh	4,536	2,617
Gas Contracts BBtu
Derivative Volume [Line Items]
Derivative, energy measure | BTU	105,040	112,316

FAIR VALUE MEASUREMENTS AND D_7

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale	$ 37	$ 26
Collateral posted	0
Additional collateral required to post if credit-risk contingent features are triggered	37
Amount relating to outstanding net payable balances for settled positions
Derivative [Line Items]
Additional collateral required to post if credit-risk contingent features are triggered	$ 41

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	Jun. 30, 2022	Dec. 31, 2021
Net Carrying Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,264	$ 2,135
Fair Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,042	$ 2,357

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Supplemental Cash Flow Information [Abstract]
Accrued Capital Expenditures	$ 25	$ 36
Renewable Energy Credits	5	5
Asset Retirement Obligation/Cost Increase (Decrease)	(28)	13
Net Cost of Removal Decrease	$ (46)	$ (36)