Tucson Electric Power 10-Q 29 Oct 21 2021 Q3 Quarterly report Financial data

Cover Page

Cover Page - shares	9 Months Ended
	Sep. 30, 2021	Oct. 28, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
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	2021
Document Fiscal Period Focus	Q3
Amendment Flag	false

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Income Statement [Abstract]
Operating Revenues	$ 507,584	$ 471,672	$ 1,235,788	$ 1,089,933
Operating Expenses
Fuel	120,972	90,900	292,627	216,896
Purchased Power	87,943	71,562	169,762	118,713
Transmission and Other PPFAC Recoverable Costs	19,780	16,966	49,341	39,566
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(25,108)	(83)	(50,068)	5,113
Total Fuel and Purchased Power	203,587	179,345	461,662	380,288
Operations and Maintenance	94,771	88,504	300,865	259,991
Depreciation	51,744	47,462	149,200	141,084
Amortization	10,800	7,330	31,971	21,328
Taxes Other Than Income Taxes	15,210	14,571	46,004	44,123
Total Operating Expenses	376,112	337,212	989,702	846,814
Operating Income	131,472	134,460	246,086	243,119
Other Income (Expense)
Interest Expense	(22,774)	(23,159)	(66,970)	(66,212)
Allowance For Borrowed Funds	978	2,246	5,579	7,141
Allowance For Equity Funds	2,635	5,823	14,737	16,046
Unrealized Gains (Losses) on Investments	(350)	842	3,205	(2,309)
Other, Net	1,934	1,278	7,504	3,470
Total Other Income (Expense)	(17,577)	(12,970)	(35,945)	(41,864)
Income Before Income Tax Expense	113,895	121,490	210,141	201,255
Income Tax Expense	17,027	21,029	26,979	35,386
Net Income	$ 96,868	$ 100,461	$ 183,162	$ 165,869

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash Flows from Operating Activities
Net Income	$ 183,162	$ 165,869
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	149,200	141,084
Amortization Expense	31,971	21,328
Amortization of Debt Issuance Costs	2,141	2,010
Use of Renewable Energy Credits for Compliance	35,762	32,672
Deferred Income Taxes	23,782	38,809
Pension and Other Postretirement Benefits Expense	11,506	11,162
Pension and Other Postretirement Benefits Funding	(15,391)	(14,503)
Allowance for Equity Funds Used During Construction	(14,737)	(16,046)
Regulatory Deferral, ACC Refund Order	0	16,364
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(74,525)	(57,208)
Materials, Supplies, and Fuel Inventory	(18,634)	(8,392)
Regulatory Assets	(41,638)	4,948
Other Current Assets	(6,324)	(5,100)
Accounts Payable and Accrued Charges	74,242	(939)
Income Taxes Payable, Net	1,095	6,865
Regulatory Liabilities	(9,157)	8,944
Other, Net	10,234	7,260
Net Cash Flows—Operating Activities	342,689	355,127
Cash Flows from Investing Activities
Capital Expenditures	(360,374)	(597,375)
Purchase Intangibles, Renewable Energy Credits	(42,267)	(41,117)
Purchase, Other Investments	0	(8,500)
Contributions in Aid of Construction	4,360	2,816
Net Cash Flows—Investing Activities	(398,281)	(644,176)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	35,000	105,000
Repayments of Borrowings, Revolving Credit Facility	(35,000)	(105,000)
Proceeds from Borrowings, Term Loan	0	60,000
Repayments of Borrowings, Term Loan	0	(225,000)
Proceeds from Issuance, Long-Term Debt—Net of Discount	322,231	645,768
Repayments of Long-Term Debt	(250,000)	(180,410)
Dividend Paid to Parent	(37,500)	(37,500)
Payments of Finance Lease Obligations	0	(17,086)
Contribution from Parent	50,000	200,000
Other, Net	(1,645)	(4,731)
Net Cash Flows—Financing Activities	83,086	441,041
Net Increase in Cash, Cash Equivalents, and Restricted Cash	27,494	151,992
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	82,003	28,472
Cash, Cash Equivalents, and Restricted Cash, End of Period	$ 109,497	$ 180,464

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020
Utility Plant
Plant in Service	$ 7,665,815	$ 7,073,292
Construction Work in Progress	314,461	627,382
Total Utility Plant	7,980,276	7,700,674
Accumulated Depreciation and Amortization	(2,739,834)	(2,645,333)
Total Utility Plant, Net	5,240,442	5,055,341
Investments and Other Property	77,714	76,299
Current Assets
Cash and Cash Equivalents	90,338	60,960
Accounts Receivable (Net of Allowance for Credit Losses of $12,731 and $13,260)	247,641	173,412
Fuel Inventory	29,780	21,946
Materials and Supplies	138,690	126,788
Regulatory Assets	187,265	123,588
Derivative Instruments	52,753	16,094
Other	34,261	23,895
Total Current Assets	780,728	546,683
Regulatory and Other Assets
Regulatory Assets	247,548	318,474
Derivative Instruments	17,585	725
Other	88,213	92,605
Total Regulatory and Other Assets	353,346	411,804
Total Assets	6,452,230	6,090,127
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2021 and December 31, 2020)	1,696,539	1,646,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	857,859	712,197
Accumulated Other Comprehensive Loss	(10,285)	(10,942)
Total Common Stock Equity	2,537,756	2,341,437
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2021 and December 31, 2020)	0	0
Long-Term Debt, Net	2,134,086	1,814,059
Total Capitalization	4,671,842	4,155,496
Current Liabilities
Current Maturities of Long-Term Debt, Net	0	249,752
Accounts Payable	183,561	109,461
Accrued Taxes Other than Income Taxes	75,131	50,278
Accrued Employee Expenses	33,974	35,129
Accrued Interest	16,329	16,337
Regulatory Liabilities	168,202	151,189
Customer Deposits	12,304	16,450
Derivative Instruments	56,853	27,789
Other	22,016	22,031
Total Current Liabilities	568,370	678,416
Regulatory and Other Liabilities
Deferred Income Taxes, Net	529,913	492,919
Regulatory Liabilities	340,054	390,164
Pension and Other Postretirement Benefits	152,885	163,652
Derivative Instruments	3,267	37,958
Other	185,899	171,522
Total Regulatory and Other Liabilities	1,212,018	1,256,215
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 6,452,230	$ 6,090,127

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Allowance for Credit Losses	$ 12,731	$ 13,260
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, 2019	$ 1,978,203	$ 1,396,539	$ (6,357)	$ 595,792	$ (7,771)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	165,869			165,869
Other Comprehensive Income, Net of Tax	405				405
Dividend Declared to Parent	(37,500)			(37,500)
Contribution from Parent	200,000	200,000
Ending balance at Sep. 30, 2020	2,306,977	1,596,539	(6,357)	724,161	(7,366)
Beginning balance at Jun. 30, 2020	2,243,881	1,596,539	(6,357)	661,200	(7,501)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	100,461			100,461
Other Comprehensive Income, Net of Tax	135				135
Dividend Declared to Parent	(37,500)			(37,500)
Ending balance at Sep. 30, 2020	2,306,977	1,596,539	(6,357)	724,161	(7,366)
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	183,162			183,162
Other Comprehensive Income, Net of Tax	657				657
Dividend Declared to Parent	(37,500)			(37,500)
Contribution from Parent	50,000	50,000
Ending balance at Sep. 30, 2021	2,537,756	1,696,539	(6,357)	857,859	(10,285)
Beginning balance at Jun. 30, 2021	2,478,169	1,696,539	(6,357)	798,491	(10,504)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	96,868			96,868
Other Comprehensive Income, Net of Tax	219				219
Dividend Declared to Parent	(37,500)			(37,500)
Ending balance at Sep. 30, 2021	$ 2,537,756	$ 1,696,539	$ (6,357)	$ 857,859	$ (10,285)

NATURE OF OPERATIONS AND FINANC

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	9 Months Ended
	Sep. 30, 2021
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 438,000 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 Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and 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 2020 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. 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 September 30, 2021, 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: September 30, (in millions) 2021 2020 Cash and Cash Equivalents $ 90 $ 163 Restricted Cash included in: Investments and Other Property 17 15 Current Assets—Other 2 2 Total Cash, Cash Equivalents, and Restricted Cash $ 109 $ 180 Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. Uncertain Tax Position In February 2021, TEP received approval from the IRS for a change in accounting method on uncertain tax positions, resulting in a $17 million decrease in uncertain tax position obligations on a prospective basis. Income Tax Expense TEP realized PTC benefits of $2 million and $8 million in Income Tax Expense in the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2021, respectively, as a result of Oso Grande being placed in service in May 2021. Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. As part of the 2020 Rate Order, the ACC approved new annual depreciation rates based on a 2018 depreciation study for the major classes of Plant in Service, except transmission, effective January 1, 2021. In March 2021, TEP transferred $33 million from Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of the revised depreciation rates on estimated cost of removal. 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	9 Months Ended
	Sep. 30, 2021
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 TEP'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 2020 Rate Order In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. Provisions of the 2020 Rate Order include, but are not limited to: • a non-fuel retail revenue increase of $58 million over test year retail revenues; • a 7.04% return on original cost rate base of $2.7 billion, which includes a cost of equity of 9.15% and an average cost of debt of 4.65%; and • a capital structure for rate-making purposes of approximately 53% common equity and 47% long-term debt. In addition, the 2020 Rate Order 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 January 2021, the ACC staff opened a generic docket related to this matter and will consider additional evidence or recommendations in Phase 2. In the first nine months of 2021, there has been limited activity in this docket. TEP expects more activity related to Phase 2 during 2022. TEP cannot predict the outcome of these proceedings. 2019 FERC Rate Case In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. Provisions of the order include, but are not limited to: • replacing TEP's stated transmission rates with a forward-looking formula rate; • a 10.4% 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. The requested forward-looking formula rate is intended to allow for a more timely recovery of transmission-related costs. As part of the order, the FERC established hearing and settlement procedures. In February 2021, a Presiding Judge was appointed to continue the formula rate case proceeding after the settlement procedures resulted in an impasse. In August 2021, TEP filed an unopposed motion requesting that the Chief Judge suspend the litigation procedural schedule to allow the parties time to prepare and file a comprehensive settlement package, as parties in the proceeding reached a settlement in principle. The motion was granted and the parties are continuing their negotiations to finalize the terms and conditions of the settlement. All rates charged under the revised OATT pursuant to the FERC order are subject to refund until the proceeding concludes. TEP reserved $24 million as of September 30, 2021, and $15 million as of December 31, 2020, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP cannot predict the outcome of the proceeding. 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 will cover 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 more 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 reconciles the difference between actual costs and those recovered in the preceding 12-month period. The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Beginning of Period $ 47 $ 28 $ 23 $ 36 Deferred Fuel and Purchased Power Costs (1) 119 109 269 224 PPFAC and Base Power Recoveries (2) (94) (110) (220) (233) End of Period $ 72 $ 27 $ 72 $ 27 (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. Tax Expense Adjustor Mechanism The TEAM allows for the timely recovery of future significant income tax changes. The TEAM provides the Company the ability to pass through as a kWh surcharge: (i) the TCJA Regulatory Deferral balance to the initial 2021 TEAM rate; (ii) the change in EDIT compared to the test year; and (iii) the income tax effects of tax legislation that materially impacts TEP's 2018 test year revenue requirements. The TEAM went into effect January 1, 2021, as approved in the 2020 Rate Order. TEP's regulatory liability balance related to the TEAM is $2 million as of September 30, 2021 and $29 million as of December 31, 2020 in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP refunded $27 million to customers in the nine months ended September 30, 2021. Federal Tax Legislation In 2018, the ACC approved TEP’s proposal to return savings from TEP’s federal corporate income tax rate under the TCJA to its customers through a combination of customer bill credits and a regulatory liability deferral that reflected the return of a portion of the savings. TEP recognized a reduction in Operating Revenues on the Condensed Consolidated Statements of Income of $15 million and $31 million in the three and nine months ended September 30, 2020, respectively, related to the ACC approved refunds. As part of the 2020 Rate Order, the balances in the regulatory liability deferral and TCJA balancing account were moved to the TEAM regulatory account in December 2020. Renewable Energy Standard The ACC’s RES requires Arizona-regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2021 is 11% of retail electric sales, which will increase annually until renewable retail sales represent at least 15% by 2025. The RES also requires that DG account for 30% of the renewable energy requirement. Arizona utilities are required to file annual RES implementation plans for review and approval by the ACC. In September 2021, the ACC approved TEP's RES implementation plan for the years 2021 and 2022 with a budget amount 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 TEP's RES tariff. 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. TEP recorded $2 million in both 2021 and 2020 related to the performance incentive in Operating Revenues on the Condensed Consolidated Statements of Income. 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. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans. In June 2021, TEP filed its 2022 energy efficiency implementation plan with a budget of $23 million. 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. The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 LFCR Revenues (1) $ 6 $ 12 $ 15 $ 34 (1) Decrease in LFCR revenues is primarily due to a rate adjustment as approved in the 2020 Rate Order. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: ($ in millions) Remaining Recovery Period September 30, 2021 December 31, 2020 Regulatory Assets Pension and Other Postretirement Benefits Various $ 160 $ 166 Under Recovered Purchased Energy Costs 1 72 23 Lost Fixed Cost Recovery 2 41 59 Derivatives (Note 9) 8 39 55 Early Generation Retirement Costs Various 39 43 Property Tax Deferrals (1) 1 26 26 Final Mine Reclamation and Retiree Healthcare Costs (2) 7 21 20 Income Taxes Recoverable through Future Rates (3) Various 17 27 Springerville Unit 1 Leasehold Improvements (4) 2 5 7 Other Regulatory Assets Various 15 16 Total Regulatory Assets 435 442 Less Current Portion 1 187 124 Total Non-Current Regulatory Assets $ 248 $ 318 Regulatory Liabilities Income Taxes Payable through Future Rates (3) Various $ 270 $ 298 Net Cost of Removal (5) Various 83 125 Renewable Energy Standard Various 64 63 Derivatives (Note 9) 8 44 4 Transmission Revenue Subject to Refund—FERC Various 24 15 Other Regulatory Liabilities Various 21 7 Tax Reform Bill Credit Various 2 29 Total Regulatory Liabilities 508 541 Less Current Portion 1 168 151 Total Non-Current Regulatory Liabilities $ 340 $ 390 (1) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. (2) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. (3) Amortized over five years, 10 years, or the lives of the assets. (4) 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. (5) 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. As a result of the 2020 Rate Order, TEP transferred costs from Net Cost of Removal to Accumulated Depreciation and Amortization. See Note 1 for additional information related to new depreciation rates approved as part of the 2020 Rate Order. 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 In 2019, TEP entered into a BTA to develop Oso Grande. In May 2021, Oso Grande was placed in service, adding 250 MW of wind-powered electric generation, increasing TEP's total renewable nominal generation capacity, including PPAs and owned utility-scale generation, to over 600 MW. As of September 30, 2021, there was $442 million in costs related to Oso Grande in Plant in Service on the Condensed Consolidated Balance Sheets.

REVENUE

REVENUE	9 Months Ended
	Sep. 30, 2021
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 September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Retail (1) $ 355 $ 361 $ 867 $ 818 Wholesale (2) 86 61 189 127 Other Services 24 24 85 71 Revenues from Contracts with Customers 465 446 1,141 1,016 Alternative Revenues 5 12 15 36 Other 38 14 80 38 Total Operating Revenues $ 508 $ 472 $ 1,236 $ 1,090 (1) In 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. See Note 2 for more information regarding the 2020 Rate Order. (2) In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP recognizes a provision for revenues subject to refund for the estimate of revenues that are probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Case.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	9 Months Ended
	Sep. 30, 2021
Receivables [Abstract]
ACCOUNTS RECEIVABLE	ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2021 December 31, 2020 Retail $ 115 $ 90 Retail, Unbilled 54 41 Retail, Allowance for Credit Losses (13) (13) Wholesale (1) 48 33 Due from Affiliates (Note 5) 21 9 Other 23 13 Accounts Receivable $ 248 $ 173 (1) Includes $21 million as of September 30, 2021, and $7 million as of December 31, 2020, of receivables related to revenue from derivative instruments. ALLOWANCE FOR CREDIT LOSSES TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Beginning of Period $ (13) $ (7) $ (13) $ (6) Credit Loss Expense (1) (3) (2) (5) Write-offs 1 — 2 1 End of Period $ (13) $ (10) $ (13) $ (10) Service Disconnection Moratoriums In 2019, the ACC enacted the Summer Moratorium. The Summer Moratorium has remained in effect for 2020 and 2021 to date and will remain in effect each year until the ACC permanently adopts new rules regarding electric service disconnections. In addition, as a result of the COVID-19 pandemic, TEP voluntarily suspended service disconnections and late fees from March 2020 through January 2021 for all customers who would have otherwise been disconnected. In December 2020, the ACC enacted a bill credit and payment program for residential customers who are behind on their electric bills as a result of the COVID-19 pandemic. For qualifying customers, the program included: (i) an upfront bill credit applied to their December 2020 bill; and (ii) automatic enrollment into an eight-month payment plan. TEP also voluntarily created payment arrangements for commercial customers similarly affected by the COVID-19 pandemic during this period. In the second quarter of 2021, TEP began experiencing accounts receivable collection activity consistent with pre-COVID-19 pandemic conditions and has made significant progress towards collecting aged accounts receivable from customers impacted by the COVID-19 pandemic. TEP will continue to monitor collection activity and adjust its allowance for credit losses as needed.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2021
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONSTEP 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. Effective January 1, 2021, TEP hired SES's employees and will no longer utilize SES's services. The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2021 December 31, 2020 Receivables from Related Parties UNS Electric $ 19 $ 6 UNS Gas 2 1 UNS Energy — 2 Total Due from Related Parties $ 21 $ 9 Payables to Related Parties UNS Electric $ 4 $ — UNS Energy 1 1 SES — 4 Total Due to Related Parties $ 5 $ 5 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 3 $ 3 $ 9 $ 7 Wholesale Revenues, UNS Electric (2) 16 1 21 1 Control Area Services, UNS Electric (3) 1 1 4 3 Common Costs, UNS Energy Affiliates (4) 6 5 16 14 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) $ — $ — $ 1 $ — Supplemental Workforce, SES (5) — 3 — 10 Corporate Services, UNS Energy (6) 1 1 5 4 Corporate Services, UNS Energy Affiliates (7) 1 1 3 3 (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) In the second quarter of 2021, TEP began charging UNS Electric for capacity, power, and ancillary services under a tolling PPA. See Note 7 for additional information related to the tolling PPA. (3) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (4) 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. (5) SES provided supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges were based on cost of services performed and deemed reasonable by management. (6) 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 $5 million for the three and nine months ended September 30, 2021, respectively, and $1 million and $4 million for the three and nine months ended September 30, 2020, respectively. (7) 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.

DEBT AND CREDIT AGREEMENTS

DEBT AND CREDIT AGREEMENTS	9 Months Ended
	Sep. 30, 2021
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 2020 Annual Report on Form 10-K, except as noted below. DEBT Issuance and Redemption In May 2021, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2051. TEP may redeem the debt prior to November 1, 2050, with a make-whole premium plus accrued interest. On or after November 1, 2050, TEP may redeem the debt at par plus accrued interest. TEP used the net proceeds to redeem debt in August 2021 and for general corporate purposes. In August 2021, TEP redeemed at par $250 million aggregate principal amount of 5.15% senior unsecured notes prior to the maturity of the notes. CREDIT AGREEMENTS Amounts borrowed under the credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets. 2015 Credit Agreement In January 2020, $12 million in LOCs with fees accruing at a rate of 1.00% per annum were issued pursuant to various Oso Grande agreements. In May 2021, Oso Grande was placed in service and a $2 million LOC was cancelled. The remaining $10 million LOC was outstanding as of September 30, 2021, and was subsequently cancelled on October 8, 2021. On October 15, 2021, the 2015 Credit Agreement revolving credit and LOC facility was amended and restated as described below (see 2021 Credit Agreement). 2019 Credit Agreement In December 2019, TEP entered into an unsecured credit agreement with a maturity date of December 2020 that provided for $225 million in term loans (2019 Credit Agreement), of which $165 million was borrowed as of December 2019. In March 2020, TEP borrowed the remaining available balance of $60 million. Amounts borrowed were used: (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the outstanding term loans and the agreement was terminated. 2021 Credit Agreement On October 15, 2021, the 2015 Credit Agreement was amended and restated. The amended and restated credit agreement is an unsecured credit agreement with a maturity date of October 2026 that provides for revolving credit and LOC facilities (2021 Credit Agreement). The 2021 Credit Agreement allows for two one On October 20, 2021, TEP arranged for the issuance of a $10 million LOC with fees accruing at a rate of 1.00% per annum in relation to an Oso Grande transmission agreement. As of October 28, 2021, there was $240 million available under the 2021 Credit Agreement revolving commitment and LOC facility.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS In addition to those reported in its 2020 Annual Report on Form 10-K, TEP entered into the following long-term commitments through September 30, 2021: (in millions) 2021 2022 2023 2024 2025 Thereafter Total Minimum Purchase Commitments Fuel, Including Transportation $ — $ 21 $ 16 $ — $ — $ — $ 37 Purchased Power 5 47 47 — — — 99 Purchase Commitments Renewable Power Purchase Agreements 2 8 8 8 8 111 145 Total Commitments $ 7 $ 76 $ 71 $ 8 $ 8 $ 111 $ 281 Costs for Purchased Power and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of renewable PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms. Fuel, Including Transportation In June 2021, TEP entered into natural gas commodity purchase agreements at market prices that expire through the fourth quarter of 2023. The commitment amounts included in the table above are based on projected market prices as of September 30, 2021. Purchased Power In June 2021, TEP entered into tolling PPAs to purchase and receive up to 300 MW of capacity, power, and ancillary services from June 15 through October 15 in 2021, 2022, and 2023. TEP will pay monthly capacity charges and variable power charges. TEP entered into tolling PPAs with UNS Electric in June and July 2021 to sell and deliver up to 150 MW of the capacity, power, and ancillary services over the same time periods. UNS Electric will pay TEP monthly capacity charges equal to 50% of TEP's monthly capacity charges and variable power charges. TEP's commitment does not reflect any reduction for the subsequent sale of capacity. Renewable Power Purchase Agreements TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. In April 2021, one of these facilities and the associated battery storage achieved commercial operation. The PPA expires in April 2041. While TEP is not required to make payments under this agreement if power is not delivered, estimated future payments, excluding battery storage, are included in the table above. 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. TEP’s estimated share of final mine reclamation costs at both mines is $45 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $39 million as of September 30, 2021, and $40 million as of December 31, 2020, was recorded in Other on the Condensed Consolidated Balance Sheets. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. See Note 1 and Note 2 for additional information related to final mine reclamation costs. 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 September 30, 2021, 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. Collectively, these landfills were in operation from 1953 and 1973. 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	9 Months Ended
	Sep. 30, 2021
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended September 30, (in millions) 2021 2020 2021 2020 Service Cost $ 5 $ 4 $ 2 $ 1 Non-Service Cost (1) Interest Cost 3 4 — — Expected Return on Plan Assets (8) (7) — — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 2 $ 3 $ 2 $ 1 Pension Benefits Other Postretirement Benefits Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Service Cost $ 15 $ 12 $ 5 $ 3 Non-Service Cost (1) Interest Cost 10 12 1 1 Expected Return on Plan Assets (25) (22) (1) (1) Amortization of Net Loss 7 6 — — Net Periodic Benefit Cost $ 7 $ 8 $ 5 $ 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	9 Months Ended
	Sep. 30, 2021
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) September 30, 2021 Assets Restricted Cash (1) $ 19 $ — $ 19 Energy Derivative Contracts, Regulatory Recovery (2) — 64 64 Energy Derivative Contracts, No Regulatory Recovery (2) — 6 6 Total Assets 19 70 89 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (60) (60) Total Liabilities — (60) (60) Total Assets (Liabilities), Net $ 19 $ 10 $ 29 (in millions) December 31, 2020 Assets Restricted Cash (1) $ 21 $ — $ 21 Energy Derivative Contracts, Regulatory Recovery (2) — 14 14 Energy Derivative Contracts, No Regulatory Recovery (2) — 3 3 Total Assets 21 17 38 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (66) (66) Total Liabilities — (66) (66) Total Assets (Liabilities), Net $ 21 $ (49) $ (28) (1) Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the 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 (in millions) September 30, 2021 Derivative Assets Energy Derivative Contracts $ 70 $ 34 $ — $ 36 Derivative Liabilities Energy Derivative Contracts (60) (34) (9) (17) (in millions) December 31, 2020 Derivative Assets Energy Derivative Contracts $ 17 $ 14 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (66) (14) (7) (45) 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 September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Unrealized Net Gain (1) $ 43 $ 13 $ 56 $ 28 (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 September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Operating Revenues $ 6 $ — $ 7 $ 5 Derivative Volumes As of September 30, 2021, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts: September 30, 2021 December 31, 2020 Power Contracts GWh 4,471 4,143 Gas Contracts BBtu 118,793 111,585 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 $57 million as of September 30, 2021, compared with $60 million as of December 31, 2020. As of September 30, 2021, TEP had $9 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets—Other on the Condensed Consolidated Balance Sheets. If the credit risk contingent features were triggered on September 30, 2021, TEP would have been required to post an additional $48 million of collateral of which $40 million relates to 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) September 30, 2021 December 31, 2020 September 30, 2021 December 31, 2020 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,134 $ 2,064 $ 2,379 $ 2,363

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2021
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: Nine Months Ended September 30, (in millions) 2021 2020 Accrued Capital Expenditures $ 43 $ 26 Asset Retirement Obligations Increase (Decrease) (1) 11 (2) Renewable Energy Credits 4 4 Net Cost of Removal Decrease (2) (37) (9) (1) The non-cash additions to Asset Retirement Obligations and related capitalized assets primarily represent a new obligation related to Oso Grande. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. See Note 1 for additional information related to new depreciation rates approved as part of the 2020 Rate Order.

NATURE OF OPERATIONS AND FINA_2

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2021
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 Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and 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 2020 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation.
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 September 30, 2021, 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 included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.
Depreciation	Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC.
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)	9 Months Ended
	Sep. 30, 2021
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: September 30, (in millions) 2021 2020 Cash and Cash Equivalents $ 90 $ 163 Restricted Cash included in: Investments and Other Property 17 15 Current Assets—Other 2 2 Total Cash, Cash Equivalents, and Restricted Cash $ 109 $ 180
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: September 30, (in millions) 2021 2020 Cash and Cash Equivalents $ 90 $ 163 Restricted Cash included in: Investments and Other Property 17 15 Current Assets—Other 2 2 Total Cash, Cash Equivalents, and Restricted Cash $ 109 $ 180

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 2021
Regulated Operations [Abstract]
Schedule of Purchased Power and Fuel Adjustment Rates	The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Beginning of Period $ 47 $ 28 $ 23 $ 36 Deferred Fuel and Purchased Power Costs (1) 119 109 269 224 PPFAC and Base Power Recoveries (2) (94) (110) (220) (233) End of Period $ 72 $ 27 $ 72 $ 27 (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.
Schedule of Regulated Operating Revenue	The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 LFCR Revenues (1) $ 6 $ 12 $ 15 $ 34 (1) Decrease in LFCR revenues is primarily due to a rate adjustment as approved in the 2020 Rate Order.
Schedule of Regulatory Assets and Liabilities	Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: ($ in millions) Remaining Recovery Period September 30, 2021 December 31, 2020 Regulatory Assets Pension and Other Postretirement Benefits Various $ 160 $ 166 Under Recovered Purchased Energy Costs 1 72 23 Lost Fixed Cost Recovery 2 41 59 Derivatives (Note 9) 8 39 55 Early Generation Retirement Costs Various 39 43 Property Tax Deferrals (1) 1 26 26 Final Mine Reclamation and Retiree Healthcare Costs (2) 7 21 20 Income Taxes Recoverable through Future Rates (3) Various 17 27 Springerville Unit 1 Leasehold Improvements (4) 2 5 7 Other Regulatory Assets Various 15 16 Total Regulatory Assets 435 442 Less Current Portion 1 187 124 Total Non-Current Regulatory Assets $ 248 $ 318 Regulatory Liabilities Income Taxes Payable through Future Rates (3) Various $ 270 $ 298 Net Cost of Removal (5) Various 83 125 Renewable Energy Standard Various 64 63 Derivatives (Note 9) 8 44 4 Transmission Revenue Subject to Refund—FERC Various 24 15 Other Regulatory Liabilities Various 21 7 Tax Reform Bill Credit Various 2 29 Total Regulatory Liabilities 508 541 Less Current Portion 1 168 151 Total Non-Current Regulatory Liabilities $ 340 $ 390 (1) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. (2) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. (3) Amortized over five years, 10 years, or the lives of the assets. (4) 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. (5) 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. As a result of the 2020 Rate Order, TEP transferred costs from Net Cost of Removal to Accumulated Depreciation and Amortization. See Note 1 for additional information related to new depreciation rates approved as part of the 2020 Rate Order.

REVENUE (Tables)

REVENUE (Tables)	9 Months Ended
	Sep. 30, 2021
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 September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Retail (1) $ 355 $ 361 $ 867 $ 818 Wholesale (2) 86 61 189 127 Other Services 24 24 85 71 Revenues from Contracts with Customers 465 446 1,141 1,016 Alternative Revenues 5 12 15 36 Other 38 14 80 38 Total Operating Revenues $ 508 $ 472 $ 1,236 $ 1,090 (1) In 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. See Note 2 for more information regarding the 2020 Rate Order. (2) In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP recognizes a provision for revenues subject to refund for the estimate of revenues that are probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Case.

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	9 Months Ended
	Sep. 30, 2021
Receivables [Abstract]
Accounts Receivable	The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2021 December 31, 2020 Retail $ 115 $ 90 Retail, Unbilled 54 41 Retail, Allowance for Credit Losses (13) (13) Wholesale (1) 48 33 Due from Affiliates (Note 5) 21 9 Other 23 13 Accounts Receivable $ 248 $ 173 (1) Includes $21 million as of September 30, 2021, and $7 million as of December 31, 2020, of receivables related to revenue from derivative instruments.
Schedule of Allowance for Credit Losses	The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Beginning of Period $ (13) $ (7) $ (13) $ (6) Credit Loss Expense (1) (3) (2) (5) Write-offs 1 — 2 1 End of Period $ (13) $ (10) $ (13) $ (10)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	9 Months Ended
	Sep. 30, 2021
Related Party Transactions [Abstract]
Schedule of Related Party Balances and Transactions	The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) September 30, 2021 December 31, 2020 Receivables from Related Parties UNS Electric $ 19 $ 6 UNS Gas 2 1 UNS Energy — 2 Total Due from Related Parties $ 21 $ 9 Payables to Related Parties UNS Electric $ 4 $ — UNS Energy 1 1 SES — 4 Total Due to Related Parties $ 5 $ 5 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 3 $ 3 $ 9 $ 7 Wholesale Revenues, UNS Electric (2) 16 1 21 1 Control Area Services, UNS Electric (3) 1 1 4 3 Common Costs, UNS Energy Affiliates (4) 6 5 16 14 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) $ — $ — $ 1 $ — Supplemental Workforce, SES (5) — 3 — 10 Corporate Services, UNS Energy (6) 1 1 5 4 Corporate Services, UNS Energy Affiliates (7) 1 1 3 3 (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) In the second quarter of 2021, TEP began charging UNS Electric for capacity, power, and ancillary services under a tolling PPA. See Note 7 for additional information related to the tolling PPA. (3) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (4) 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. (5) SES provided supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges were based on cost of services performed and deemed reasonable by management. (6) 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 $5 million for the three and nine months ended September 30, 2021, respectively, and $1 million and $4 million for the three and nine months ended September 30, 2020, respectively. (7) 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.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	9 Months Ended
	Sep. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments	In addition to those reported in its 2020 Annual Report on Form 10-K, TEP entered into the following long-term commitments through September 30, 2021: (in millions) 2021 2022 2023 2024 2025 Thereafter Total Minimum Purchase Commitments Fuel, Including Transportation $ — $ 21 $ 16 $ — $ — $ — $ 37 Purchased Power 5 47 47 — — — 99 Purchase Commitments Renewable Power Purchase Agreements 2 8 8 8 8 111 145 Total Commitments $ 7 $ 76 $ 71 $ 8 $ 8 $ 111 $ 281

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2021
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 September 30, (in millions) 2021 2020 2021 2020 Service Cost $ 5 $ 4 $ 2 $ 1 Non-Service Cost (1) Interest Cost 3 4 — — Expected Return on Plan Assets (8) (7) — — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 2 $ 3 $ 2 $ 1 Pension Benefits Other Postretirement Benefits Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Service Cost $ 15 $ 12 $ 5 $ 3 Non-Service Cost (1) Interest Cost 10 12 1 1 Expected Return on Plan Assets (25) (22) (1) (1) Amortization of Net Loss 7 6 — — Net Periodic Benefit Cost $ 7 $ 8 $ 5 $ 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)	9 Months Ended
	Sep. 30, 2021
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) September 30, 2021 Assets Restricted Cash (1) $ 19 $ — $ 19 Energy Derivative Contracts, Regulatory Recovery (2) — 64 64 Energy Derivative Contracts, No Regulatory Recovery (2) — 6 6 Total Assets 19 70 89 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (60) (60) Total Liabilities — (60) (60) Total Assets (Liabilities), Net $ 19 $ 10 $ 29 (in millions) December 31, 2020 Assets Restricted Cash (1) $ 21 $ — $ 21 Energy Derivative Contracts, Regulatory Recovery (2) — 14 14 Energy Derivative Contracts, No Regulatory Recovery (2) — 3 3 Total Assets 21 17 38 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (66) (66) Total Liabilities — (66) (66) Total Assets (Liabilities), Net $ 21 $ (49) $ (28) (1) Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the 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	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 (in millions) September 30, 2021 Derivative Assets Energy Derivative Contracts $ 70 $ 34 $ — $ 36 Derivative Liabilities Energy Derivative Contracts (60) (34) (9) (17) (in millions) December 31, 2020 Derivative Assets Energy Derivative Contracts $ 17 $ 14 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (66) (14) (7) (45)
Potential Offset of Liabilities by Counterparty Netting and Cash Collateral	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 (in millions) September 30, 2021 Derivative Assets Energy Derivative Contracts $ 70 $ 34 $ — $ 36 Derivative Liabilities Energy Derivative Contracts (60) (34) (9) (17) (in millions) December 31, 2020 Derivative Assets Energy Derivative Contracts $ 17 $ 14 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (66) (14) (7) (45)
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 September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Unrealized Net Gain (1) $ 43 $ 13 $ 56 $ 28 (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 September 30, Nine Months Ended September 30, (in millions) 2021 2020 2021 2020 Operating Revenues $ 6 $ — $ 7 $ 5
Derivative Volumes	The following table presents volumes associated with the energy contracts: September 30, 2021 December 31, 2020 Power Contracts GWh 4,471 4,143 Gas Contracts BBtu 118,793 111,585
Face Value and Estimated Fair Value of Long-Term Debt	The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) September 30, 2021 December 31, 2020 September 30, 2021 December 31, 2020 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,134 $ 2,064 $ 2,379 $ 2,363

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2021
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: Nine Months Ended September 30, (in millions) 2021 2020 Accrued Capital Expenditures $ 43 $ 26 Asset Retirement Obligations Increase (Decrease) (1) 11 (2) Renewable Energy Credits 4 4 Net Cost of Removal Decrease (2) (37) (9) (1) The non-cash additions to Asset Retirement Obligations and related capitalized assets primarily represent a new obligation related to Oso Grande. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. See Note 1 for additional information related to new depreciation rates approved as part of the 2020 Rate Order.

NATURE OF OPERATIONS AND FINA_4

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Narrative) (Details) customer in Thousands, $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended
	Mar. 31, 2021USD ($)	Feb. 28, 2021USD ($)	Sep. 30, 2021USD ($)customer	Sep. 30, 2021USD ($)mi²customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of retail customers | customer			438	438
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi²				1,155
Decrease in uncertain tax position		$ 17
Production tax credit benefits			$ 2	$ 8
Amount transferred from net cost of removal to accumulated depreciation and amortization	$ 33

NATURE OF OPERATIONS AND FINA_5

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Cash and Cash Equivalents [Line Items]
Cash and Cash Equivalents	$ 90,338	$ 60,960	$ 163,000
Total Cash, Cash Equivalents, and Restricted Cash	109,497	$ 82,003	180,464	$ 28,472
Investments and Other Property
Cash and Cash Equivalents [Line Items]
Restricted Cash	17,000		15,000
Current Assets—Other
Cash and Cash Equivalents [Line Items]
Restricted Cash	$ 2,000		$ 2,000

REGULATORY MATTERS (2020 Rate O

REGULATORY MATTERS (2020 Rate Order) (Details) - Arizona Corporation Commission - Non-fuel Component of Base Rate $ in Millions	1 Months Ended
	Dec. 31, 2020USD ($)
Public Utilities, General Disclosures [Line Items]
Non-fuel base rate increase (decrease)	$ 58
Original cost rate base (percentage)	7.04%
Original cost rate base	$ 2,700
Original cost of equity (percentage)	9.15%
Average original cost of debt (percentage)	4.65%
Common equity (percentage)	53.00%
Long-term debt (percentage)	47.00%

REGULATORY MATTERS (2019 FERC R

REGULATORY MATTERS (2019 FERC Rate Case) (Details) - USD ($) $ in Thousands	Aug. 01, 2019	Sep. 30, 2021	Dec. 31, 2020
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 168,202	$ 151,189
FERC | Transmission Services Rate
Public Utilities, General Disclosures [Line Items]
Return on equity (percentage)	10.40%
FERC | Transmission Services Rate | Revenue Subject to Refund
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 24,000	$ 15,000

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2025	Dec. 31, 2019	Dec. 31, 2020
Regulatory Assets [Roll Forward]
Regulatory liability	$ 168,202		$ 168,202		$ 168,202				$ 151,189
Arizona Corporation Commission | Revenue Refund
Regulatory Assets [Roll Forward]
Decrease in regulated operating revenue				$ 15,000		$ 31,000
TEAM
Regulatory Assets [Roll Forward]
Regulatory liability	2,000		2,000		2,000				$ 29,000
Customer refunds					$ 27,000
Recovered Purchased Energy Costs
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified					12 months
Regulatory Assets [Roll Forward]
Beginning of Period			47,000	28,000	$ 23,000	36,000
Deferred Fuel and Purchased Power Costs			119,000	109,000	269,000	224,000
PPFAC and Base Power Recoveries			(94,000)	(110,000)	(220,000)	(233,000)
End of Period	72,000	$ 47,000	72,000	27,000	$ 72,000	27,000		$ 36,000
Renewable Energy Standard
Regulatory Assets [Roll Forward]
Renewable energy target percentage					11.00%
Distributed generation requirement percent of target percentage (percentage)					30.00%
Approved spending budget for the years of 2021 and 2022	$ 66,000
Renewable Energy Standard | Scenario, Forecast
Regulatory Assets [Roll Forward]
Renewable energy target percentage							15.00%
Demand Side Management
Regulatory Assets [Roll Forward]
Recovery revenue					$ 2,000	2,000
Energy Efficiency Standards
Regulatory Assets [Roll Forward]
Approved recovery of spending budget								$ 23,000
Recovery of spending budget, requested amount		$ 23,000
Lost Fixed Cost Recovery
Regulatory Assets [Roll Forward]
Recovery revenue			$ 6,000	$ 12,000	$ 15,000	$ 34,000
Cap on increase in lost fixed cost recovery rate (percentage)					2.00%

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 435,000	$ 442,000
Less Current Portion	187,265	123,588
Total Non-Current Regulatory Assets	247,548	318,474
Pension and Other Postretirement Benefits
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 160,000	166,000
Under Recovered Purchased Energy Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 72,000	23,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	2 years
Total Regulatory Assets	$ 41,000	59,000
Derivatives
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	8 years
Total Regulatory Assets	$ 39,000	55,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 39,000	43,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Assets	$ 26,000	26,000
Final Mine Reclamation and Retiree Healthcare Costs
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	7 years
Total Regulatory Assets	$ 21,000	20,000
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 17,000	27,000
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Remaining Recovery Period (years)	2 years
Total Regulatory Assets	$ 5,000	7,000
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 15,000	$ 16,000

REGULATORY MATTERS (Regulator_2

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	1 year
Total Regulatory Liabilities	$ 508,000	$ 541,000
Less Current Portion	168,202	151,189
Total Non-Current Regulatory Liabilities	340,054	390,164
Income Taxes Payable through Future Rates
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	270,000	298,000
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	83,000	125,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 64,000	63,000
Derivatives
Regulatory Liabilities [Line Items]
Remaining Recovery Period (years)	8 years
Total Regulatory Liabilities	$ 44,000	4,000
Transmission Revenue Subject to Refund—FERC
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	24,000	15,000
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	21,000	7,000
Tax Reform Bill Credit
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 2,000	$ 29,000

REGULATORY MATTERS (Regulator_3

REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details)	9 Months Ended
	Sep. 30, 2021
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
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining recovery period	6 months
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) $ in Thousands	Sep. 30, 2021USD ($)	May 31, 2021MWh	Dec. 31, 2020USD ($)
Public Utilities, General Disclosures [Line Items]
Plant in service | $	$ 7,665,815		$ 7,073,292
Minimum
Public Utilities, General Disclosures [Line Items]
Renewable nominal generation capacity, including PPAs, in MWs | MWh		600
Oso Grande
Public Utilities, General Disclosures [Line Items]
Generating capacity placed in service, in MWs | MWh		250
Plant in service | $	$ 442,000

REVENUE (Details)

REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 465,000	$ 446,000	$ 1,141,000	$ 1,016,000
Alternative Revenues	5,000	12,000	15,000	36,000
Other	38,000	14,000	80,000	38,000
Total Operating Revenues	507,584	471,672	1,235,788	1,089,933
Retail
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	355,000	361,000	867,000	818,000
Wholesale
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	86,000	61,000	189,000	127,000
Other Services
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 24,000	$ 24,000	$ 85,000	$ 71,000

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 115,000		$ 115,000		$ 90,000
Allowance for Credit Losses	(12,731)	$ (10,000)	(12,731)	$ (10,000)	(13,260)
Accounts Receivable	247,641		247,641		173,412
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning of Period	(13,000)	(7,000)	(13,260)	(6,000)
Credit Loss Expense	(1,000)	(3,000)	(2,000)	(5,000)
Write-offs	1,000	0	2,000	1,000
End of Period	(12,731)	$ (10,000)	(12,731)	$ (10,000)
Wholesale
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	48,000		48,000		33,000
Wholesale | Derivatives
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	21,000		21,000		7,000
Trade Accounts | Due from Affiliates
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	21,000		21,000		9,000
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	23,000		23,000		13,000
Unbilled
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 54,000		$ 54,000		$ 41,000

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	$ 21,000		$ 21,000		$ 9,000
Due to related parties	5,000		5,000		5,000
Wholesale revenues	507,584	$ 471,672	1,235,788	$ 1,089,933
Transmission Revenues, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Revenue from related party	3,000	3,000	9,000	7,000
Wholesale Revenues, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Revenue from related party	16,000	1,000	21,000	1,000
Wholesale revenues	0	0	1,000	0
Control Area Services, UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Control area services	1,000	1,000	4,000	3,000
Common Costs, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Common costs	6,000	5,000	16,000	14,000
Supplemental Workforce, SES
Related Party Transaction, Due to/from Related Party [Abstract]
Supplemental workforce	0	3,000	0	10,000
Corporate Services, UNS Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate services	1,000	1,000	$ 5,000	4,000
Massachusetts Formula - TEP's allocation (percentage)			85.00%
Management fee	2,000	1,000	$ 5,000	4,000
Corporate Services, UNS Energy Affiliates
Related Party Transaction, Due to/from Related Party [Abstract]
Corporate services	1,000	$ 1,000	3,000	$ 3,000
UNS Electric
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	19,000		19,000		6,000
Due to related parties	4,000		4,000		0
UNS Gas
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	2,000		2,000		1,000
UNS Energy
Related Party Transaction, Due to/from Related Party [Abstract]
Due from related parties	0		0		2,000
Due to related parties	1,000		1,000		1,000
SES
Related Party Transaction, Due to/from Related Party [Abstract]
Due to related parties	$ 0		$ 0		$ 4,000

DEBT AND CREDIT AGREEMENTS (Det

DEBT AND CREDIT AGREEMENTS (Details)	Oct. 15, 2021USD ($)extension_option	Aug. 31, 2021USD ($)	May 31, 2021USD ($)	Oct. 28, 2021USD ($)	Oct. 20, 2021USD ($)	Oct. 08, 2021USD ($)	Sep. 30, 2021USD ($)	Mar. 31, 2020USD ($)	Jan. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Line of Credit | Sub-Limit LOC
Debt Instrument [Line Items]
Debt extinguishment			$ 2,000,000
Borrowed							$ 10,000,000		$ 12,000,000
Line of Credit | Sub-Limit LOC | Subsequent Event
Debt Instrument [Line Items]
Borrowed						$ 0
Line of Credit | Revolver
Debt Instrument [Line Items]
Weighted average interest rate (in percentage)									1.00%
Line of Credit | 2019 Credit Agreement
Debt Instrument [Line Items]
Borrowed								$ 60,000,000		$ 165,000,000
Line of credit facility borrowing capacity										$ 225,000,000
3.25% Senior Unsecured Notes due May 2051 | 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%
5.15% Senior Unsecured Notes due November 15, 2021 | Unsecured Debt
Debt Instrument [Line Items]
Interest rate		5.15%
Debt extinguishment		$ 250,000,000
2021 Credit Agreement | Line of Credit | Subsequent Event
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 250,000,000
Possible number of extensions | extension_option	2
Possible extension period	1 year
Available				$ 240,000,000
2021 Credit Agreement | Line of Credit | Sub-Limit LOC | Subsequent Event
Debt Instrument [Line Items]
Borrowed					$ 10,000,000
Line of credit facility borrowing capacity	$ 50,000,000
2021 Credit Agreement | Line of Credit | Swingline Sublimit | Subsequent Event
Debt Instrument [Line Items]
Line of credit facility borrowing capacity	$ 15,000,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Millions	Sep. 30, 2021USD ($)	Jul. 31, 2021MW	Jun. 30, 2021MW
Purchase Obligation, Fiscal Year Maturity [Abstract]
2021	$ 7
2022	76
2023	71
2024	8
2025	8
Thereafter	111
Total	$ 281
Purchase Obligation [Line Items]
Renewable power purchase agreements, percent to purchase	100.00%
UNS Electric
Purchase Obligation [Line Items]
Power delivery agreement, in MW | MW		150
Monthly capacity charge as percent of company's total charge		50.00%
Capacity, Power, and Ancillary Services | Maximum
Purchase Obligation [Line Items]
Power purchase agreement, in MW | MW			300
Fuel, Including Transportation
Purchase Obligation, Fiscal Year Maturity [Abstract]
2021	$ 0
2022	21
2023	16
2024	0
2025	0
Thereafter	0
Total	37
Purchased Power
Purchase Obligation, Fiscal Year Maturity [Abstract]
2021	5
2022	47
2023	47
2024	0
2025	0
Thereafter	0
Total	99
Renewable Power Purchase Agreements
Purchase Obligation, Fiscal Year Maturity [Abstract]
2021	2
2022	8
2023	8
2024	8
2025	8
Thereafter	111
Total	$ 145

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - San Juan and Four Corners - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Commitments And Contingencies [Line Items]
Reclamation costs	$ 45
Other Liabilities
Commitments And Contingencies [Line Items]
Reclamation costs accrued	$ 39	$ 40

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee	Sep. 30, 2021USD ($)
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		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Pension Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 5	$ 4	$ 15	$ 12
Non-Service Cost
Interest Cost	3	4	10	12
Expected Return on Plan Assets	(8)	(7)	(25)	(22)
Amortization of Net Loss	2	2	7	6
Net Periodic Benefit Cost	2	3	7	8
Other Postretirement Benefits
Components of Net Periodic Benefit Plan Cost
Service Cost	2	1	5	3
Non-Service Cost
Interest Cost	0	0	1	1
Expected Return on Plan Assets	0	0	(1)	(1)
Amortization of Net Loss	0	0	0	0
Net Periodic Benefit Cost	$ 2	$ 1	$ 5	$ 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 ($)	Sep. 30, 2021	Dec. 31, 2020
Assets
Restricted Cash	$ 19,000,000	$ 21,000,000
Energy Derivative Contract Assets - Regulatory Recovery	64,000,000	14,000,000
Energy Derivative Contract Assets - No Regulatory Recovery	6,000,000	3,000,000
Total Assets	89,000,000	38,000,000
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(60,000,000)	(66,000,000)
Total Liabilities	(60,000,000)	(66,000,000)
Total Assets (Liabilities), Net	29,000,000	(28,000,000)
Level 1
Assets
Restricted Cash	19,000,000	21,000,000
Energy Derivative Contract Assets - Regulatory Recovery	0	0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	19,000,000	21,000,000
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Total Liabilities	0	0
Total Assets (Liabilities), Net	19,000,000	21,000,000
Level 2
Assets
Restricted Cash	0	0
Energy Derivative Contract Assets - Regulatory Recovery	64,000,000	14,000,000
Energy Derivative Contract Assets - No Regulatory Recovery	6,000,000	3,000,000
Total Assets	70,000,000	17,000,000
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(60,000,000)	(66,000,000)
Total Liabilities	(60,000,000)	(66,000,000)
Total Assets (Liabilities), Net	10,000,000	$ (49,000,000)
Level 3
Liabilities
Total Assets (Liabilities), Net	$ 0

FAIR VALUE MEASUREMENTS AND D_4

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative Contracts - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative Assets
Gross Amount Recognized in the Balance Sheets	$ 70	$ 17
Counterparty Netting of Energy Contracts	34	14
Cash Collateral Received/Posted	0	0
Net Amount	36	3
Derivative Liabilities
Gross Amount Recognized in the Balance Sheets	(60)	(66)
Counterparty Netting of Energy Contracts	(34)	(14)
Cash Collateral Received/Posted	(9)	(7)
Net Amount	$ (17)	$ (45)

FAIR VALUE MEASUREMENTS AND D_5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Percent of long-term trading contract gains shared with customers (percentage)			10.00%
Operating Revenues	$ 507,584	$ 471,672	$ 1,235,788	$ 1,089,933
Energy Derivative Contracts | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain	43,000	13,000	56,000	28,000
Operating Revenues	$ 6,000	$ 0	$ 7,000	$ 5,000

FAIR VALUE MEASUREMENTS AND D_6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Billions	9 Months Ended	12 Months Ended
	Sep. 30, 2021BTUGWh	Dec. 31, 2020BTUGWh
Power Contracts GWh
Derivative Volume [Line Items]
Derivative, energy measure | GWh	4,471	4,143
Gas Contracts BBtu
Derivative Volume [Line Items]
Derivative, energy measure | BTU	118,793	111,585

FAIR VALUE MEASUREMENTS AND D_7

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale	$ 57	$ 60
Collateral posted	9
Additional collateral required to post if credit-risk contingent features are triggered	48
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	$ 40

FAIR VALUE MEASUREMENTS AND D_8

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Net Carrying Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,134	$ 2,064
Fair Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,379	$ 2,363

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Supplemental Cash Flow Information [Abstract]
Accrued Capital Expenditures	$ 43	$ 26
Asset Retirement Obligations Increase (Decrease)	11	(2)
Renewable Energy Credits	4	4
Net Cost of Removal Decrease	$ (37)	$ (9)