Tucson Electric Power 10-K/A 20 May 22 2021 FY Annual report (amended) Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 10, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K/A
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
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 Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
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
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		32,139,434
Documents Incorporated by Reference	None
Entity Central Index Key	0000100122
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	true
Amendment Description	Tucson Electric Power (TEP) filed its Annual Report on Form 10-K for the fiscal year ended December 31, 2021 (Original Filing) with the U.S. Securities and Exchange Commission (SEC) on February 11, 2022. TEP is filing this Amendment No. 1 (Amendment) to the Original Filing solely for the purpose of filing revised versions of Exhibits 31(a), 31(b), and 32 submitted with the Original Filing (Exhibits). In the Original Filing, each of the Exhibits makes reference to the "quarterly report on Form 10-Q for the quarter ended December 31, 2021" rather than the "annual report on Form 10-K for the year ended December 31, 2021." The Exhibits have been modified in this Amendment solely to revise the references to the “annual report on Form 10-K for the year ended December 31, 2021” in each case and to reflect the date of filing of this Amendment. TEP has included in this Amendment a complete copy of the Original Filing, as amended per the above, and as modified to update the Exhibit Index included in Item 15 to indicate that Exhibit 23 and Exhibit 24 were filed with the Original Filing and are not being refiled as part of this Amendment.No attempt has been made in this Amendment to amend, modify, or update any financial information or other disclosure presented in the Original Filing, nor does this Amendment reflect events occurring after the filing of the Original Filing or amend, modify, or update those disclosures, including the exhibits to the Original Filing and the Exhibit Index included in Item 15, except as described in the immediately preceding paragraph. Information described herein reflects the disclosures made at the time of the Original Filing on February 11, 2022. Accordingly, this Amendment should be read in conjunction with our filings made with the SEC subsequent to the filing of the Original Filing, including any amendments to those filings.

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	Deloitte & Touche LLP
Auditor Location	Phoenix, Arizona
Auditor Firm ID	34

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Operating Revenues	$ 1,592,586	$ 1,424,741	$ 1,418,338
Operating Expenses
Fuel	399,914	302,637	358,394
Purchased Power	204,264	146,968	137,977
Transmission and Other PPFAC Recoverable Costs	65,583	52,860	52,261
Increase (Decrease) to Reflect PPFAC Recovery Treatment	(64,155)	12,565	(42,836)
Total Fuel and Purchased Power	605,606	515,030	505,796
Operations and Maintenance	397,095	351,584	377,563
Depreciation	201,524	189,051	169,042
Amortization	43,995	28,754	27,706
Taxes Other Than Income Taxes	62,010	58,222	55,642
Total Operating Expenses	1,310,230	1,142,641	1,135,749
Operating Income	282,356	282,100	282,589
Other Income (Expense)
Interest Expense	(86,865)	(88,214)	(88,511)
Allowance For Borrowed Funds	6,624	9,480	5,744
Allowance For Equity Funds	17,885	22,847	15,222
Unrealized Gains on Investments	3,898	1,741	6,015
Other, Net	9,823	4,903	(491)
Total Other Income (Expense)	(48,635)	(49,243)	(62,021)
Income Before Income Tax Expense	233,721	232,857	220,568
Income Tax Expense	32,476	41,452	34,053
Net Income	$ 201,245	$ 191,405	$ 186,515

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities
Net Income	$ 201,245	$ 191,405	$ 186,515
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense	201,524	189,051	169,042
Amortization Expense	43,995	28,754	27,706
Amortization of Debt Issuance Costs	2,829	2,721	2,326
Use of Renewable Energy Credits for Compliance	45,815	44,517	37,141
Deferred Income Taxes	37,217	39,408	41,614
Pension and Other Postretirement Benefits Expense	15,342	14,883	17,762
Pension and Other Postretirement Benefits Funding	(20,806)	(21,018)	(16,749)
Allowance for Equity Funds Used During Construction	(17,885)	(22,847)	(15,222)
Regulatory Deferral, ACC Refund Order	0	(7,705)	7,705
Changes in Current Assets and Current Liabilities:
Accounts Receivable	(18,738)	(19,019)	9,238
Materials, Supplies, and Fuel Inventory	(18,445)	(3,460)	(16,236)
Regulatory Assets	(59,542)	5,339	(20,934)
Other Current Assets	4,670	(8,311)	(475)
Accounts Payable and Accrued Charges	14,979	(20,885)	(27,776)
Income Taxes Payable	(3,271)	10,245	6,072
Regulatory Liabilities	(9,599)	41,287	(1,626)
Other, Net	8,724	1,689	8,140
Net Cash Flows—Operating Activities	428,054	466,054	414,243
Cash Flows from Investing Activities
Capital Expenditures	(499,405)	(839,958)	(607,593)
Proceeds from Sale, Springerville Common Facilities	0	29,569	0
Purchase Intangibles, Renewable Energy Credits	(55,297)	(53,509)	(51,699)
Purchase, Other Investments	0	(8,500)	0
Contributions in Aid of Construction	5,678	4,615	6,607
Note Receivable	0	0	(1,000)
Net Cash Flows—Investing Activities	(549,024)	(867,783)	(653,685)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility	50,000	105,000	0
Repayments of Borrowings, Revolving Credit Facility	(35,000)	(105,000)	0
Proceeds from Borrowings, Term Loan	0	60,000	165,000
Repayments of Borrowings, Term Loan	0	(225,000)	0
Proceeds from Issuance, Long-Term Debt—Net of Discount	322,231	645,768	0
Repayments of Long-Term Debt	(250,000)	(180,410)	(14,700)
Dividends Paid to Parent	(62,500)	(75,000)	(75,000)
Payments of Finance Lease Obligations	0	(17,087)	(10,890)
Payment of Debt Issuance Costs	(4,382)	(6,327)	(757)
Contributions from Parent	50,000	250,000	50,000
Other	2,107	3,316	1,514
Net Cash Flows—Financing Activities	72,456	455,260	115,167
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(48,514)	53,531	(124,275)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period	82,003	28,472	152,747
Cash, Cash Equivalents, and Restricted Cash, End of Period	$ 33,489	$ 82,003	$ 28,472

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Utility Plant
Plant in Service	$ 7,797,935	$ 7,073,292
Construction Work in Progress	320,931	627,382
Total Utility Plant	8,118,866	7,700,674
Accumulated Depreciation and Amortization	(2,786,839)	(2,645,333)
Total Utility Plant, Net	5,332,027	5,055,341
Investments and Other Property	81,958	76,299
Current Assets
Cash and Cash Equivalents	9,970	60,960
Accounts Receivable (Net of Allowance for Credit Losses of $10,044 and $13,260)	192,579	173,412
Fuel Inventory	26,971	21,946
Materials and Supplies	141,677	126,788
Less Current Portion	116,442	123,588
Derivative Instruments	19,406	16,094
Other	24,229	23,895
Total Current Assets	531,274	546,683
Regulatory and Other Assets
Regulatory Assets	267,669	318,474
Derivative Instruments	14,392	725
Other	94,420	92,605
Total Regulatory and Other Assets	376,481	411,804
Total Assets	6,321,740	6,090,127
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2021 and 2020)	1,696,539	1,646,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	850,942	712,197
Accumulated Other Comprehensive Loss	(9,915)	(10,942)
Total Common Stock Equity	2,531,209	2,341,437
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2021 and 2020)	0	0
Long-Term Debt, Net	2,134,534	1,814,059
Total Capitalization	4,665,743	4,155,496
Current Liabilities
Current Maturities of Long-Term Debt, Net	0	249,752
Borrowings Under Credit Agreement	15,000	0
Accounts Payable	139,329	109,461
Accrued Taxes Other than Income Taxes	53,534	50,278
Accrued Employee Expenses	36,217	35,129
Accrued Interest	16,265	16,337
Regulatory Liabilities	111,356	151,189
Customer Deposits	12,791	16,450
Derivative Instruments	15,854	27,789
Other	25,358	22,031
Total Current Liabilities	425,704	678,416
Regulatory and Other Liabilities
Deferred Income Taxes, Net	548,750	492,919
Regulatory Liabilities	352,226	390,164
Pension and Other Postretirement Benefits	120,020	163,652
Derivative Instruments	3,848	37,958
Other	205,449	171,522
Total Regulatory and Other Liabilities	1,230,293	1,256,215
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 6,321,740	$ 6,090,127

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Accounts Receivable, Allowance for Credit Loss, Current	$ 10,044	$ 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

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Capital Stock Expense	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2018	$ 1,819,745	$ 1,346,539	$ (6,357)	$ 484,277	$ (4,714)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income	186,515			186,515
Other Comprehensive Income (Loss), Net of Tax	(3,057)				(3,057)
Dividends Declared to Parent	(75,000)			(75,000)
Contribution from Parent	50,000	50,000
Ending Balances 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	191,405			191,405
Other Comprehensive Income (Loss), Net of Tax	(3,171)				(3,171)
Dividends Declared to Parent	(75,000)			(75,000)
Contribution from Parent	250,000	250,000
Ending Balances 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	201,245			201,245
Other Comprehensive Income (Loss), Net of Tax	1,027				1,027
Dividends Declared to Parent	(62,500)			(62,500)
Contribution from Parent	50,000	50,000
Ending Balances at Dec. 31, 2021	$ 2,531,209	$ 1,696,539	$ (6,357)	$ 850,942	$ (9,915)

NATURE OF OPERATIONS AND SUMMAR

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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 consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Accounting for Regulated Operations TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates charged to retail customers or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers. 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 the primary beneficiary of the VIEs on a quarterly basis. As of December 31, 2021, the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the FASB 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. USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheet at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statement during the periods presented. Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates. Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset or liability account based on the ACC's approval of these costs in its depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities. Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these legal proceedings and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. 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: Years Ended December 31, (in millions) 2021 2020 2019 Cash and Cash Equivalents $ 10 $ 61 $ 10 Restricted Cash included in: Investments and Other Property 20 19 16 Current Assets—Other 3 2 2 Total Cash, Cash Equivalents, and Restricted Cash $ 33 $ 82 $ 28 Restricted cash included in Investments and Other Property on the 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. ALLOWANCE FOR CREDIT LOSSES TEP records an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical credit loss patterns, sales, current conditions, and reasonable and supportable forecasts. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible. See Note 5 for information regarding collection activity and adjustments to the allowance for credit losses related to the COVID-19 pandemic. INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory. UTILITY PLANT Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement. AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income. The average AFUDC rates on regulated construction expenditures are included in the table below: 2021 2020 2019 Average AFUDC Rates 6.88 % 6.63 % 7.86 % Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis, excluding software intangible plant, at depreciation rates based on the economic lives of the assets, including estimates for salvage value and removal costs. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation, distribution, and general plant assets. Transmission assets are subject to the jurisdiction of the FERC. Below are the summarized average annual depreciation rates for all utility plant: 2021 2020 2019 Average Annual Depreciation Rates 3.30 % 3.15 % 3.08 % Computer Software and Cloud Computing Costs Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over three EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time. DEFERRED FINANCING COSTS Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to credit facility arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt. LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet. OPERATING REVENUES TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date delinquent and charges the customer a late payment fee, except during service disconnection moratoriums. Generally, customers are not charged a late payment fee when service disconnection moratoriums are in effect. No component of the transaction price is allocated to unsatisfied performance obligations. TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which it expects to be entitled and recognizes a refund liability until it is certain it will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods. See Note 4 for the disaggregation of TEP's Operating Revenues. PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities, and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters. RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file annual RES implementation plans for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through a RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the LFCR mechanism. 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 of February 10, 2022, the ACC has not set annual target retail kWh savings requirements for future years. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism. Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Operating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power or the REC purchase price equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power or contract price for power is recoverable through the PPFAC mechanism. When RECs are purchased, TEP records the cost of the RECs, an indefinite-lived intangible asset, as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and retail revenues in an equal amount. See Note 2 for additional information regarding regulatory matters. The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Beginning of Period $ 66 $ 63 Purchased 49 48 Used for Compliance (46) (45) End of Period $ 69 $ 66 TEP expenses the cost of internally developed RECs, including PBI activity that is not included in the table above and recoverable through the RES surcharge. TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement. Payroll Tax In response to the COVID-19 pandemic, the CARES Act was signed into law on March 27, 2020. As permitted by the CARES Act, TEP deferred payment of the employer's portion of social security taxes. In 2020, TEP recorded total deferred deposits of $7 million in Accrued Taxes Other than Income Taxes and Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. TEP paid $3 million in December 2021 and expects to pay the remaining deferred deposits to the IRS in 2022. INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income. TEP accounts for federal energy credits generated prior to 2013 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. TEP had an aggregate liability balance of $5 million and $6 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $1 million and $2 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS. PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement plan. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 10 for additional information regarding the employee benefit plans. FAIR VALUE As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 13 for additional information regarding fair value. DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; and (ii) reduce exposure to energy commodity price volatility. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities on the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity on the income statement. For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 13 for additional information regarding derivative instruments.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. RATE CASE MATTERS 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 2021, there was limited activity in this docket. On January 19, 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. TEP cannot predict the timing or outcome of these proceedings. 2019 FERC Rate 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 single 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 in December 2021 the settlement agreement was filed with the FERC. On February 1, 2022, the Presiding Judge certified and recommended approval by the FERC of the proposed settlement. Provisions of the proposed settlement include, but are not limited to: • replacing TEP's stated transmission rates with a single forward-looking formula rate; • a 9.79% return on equity; • elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor; • a direct assignment of 25% of transmission costs allocated to retail customers and 75% allocated between wholesale and retail customers beginning January 1, 2022, through the date that is the later of: (i) December 31, 2031; or (ii) the date on which TEP has no Industrial Development Revenue Bonds outstanding; • a refund of the difference in rates for the period commencing August 1, 2019 through December 31, 2021; and • $4 million in costs related to the abandoned Nogales transmission line to be amortized over 10 years. As a result of the proposed settlement, in December 2021 TEP recognized: (i) $12 million of wholesale revenue, which includes $4 million and $3 million for transmission service provided in 2020 and 2019, respectively; and (ii) a decrease of $3 million in alternative revenues. The agreement does not go into effect until final approval from the FERC is received. TEP cannot predict the final timing of the proceedings. All rates charged under the revised OATT pursuant to the FERC order are subject to refund until the proceeding concludes. TEP had $15 million of wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020. OTHER FERC MATTERS In January 2021, the FERC notified TEP that it was commencing an audit that intends to evaluate TEP's compliance with: (i) the accounting requirements of the Uniform System of Accounts; and (ii) the reporting requirements of the FERC Form 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports. The audit covers the period of January 1, 2018 to the present. The audit is ongoing and TEP cannot predict the outcome or findings, if any, of the FERC audit at this time. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period. On February 1, 2022, TEP filed a request with the ACC for approval of a rate adjustment for the PPFAC. The request presents two additional scenarios whereby the true-up component of the PPFAC rate is reset to reflect the recovery of the uncollected true-up balance over 18 and 24-month timeframes. TEP cannot predict the outcome of the proceeding. The table below summarizes the PPFAC regulatory asset (liability) balance: Years Ended December 31, (in millions) 2021 2020 Beginning of Period $ 23 $ 36 Deferred Fuel and Purchased Power Costs (1) 343 283 PPFAC and Base Power Recoveries (2) (275) (296) End of Period $ 91 $ 23 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2021 and 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021 and June 1, 2020. Environmental Compliance Adjustor The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided that they are not already recovered in base rates or recovered through another commission-approved mechanism. The eligible costs for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. Beginning January 2021, the difference between costs recovered through rates and actual ECA eligible costs is deferred to a balancing account as approved as part of the 2020 Rate Order. Tax Expense Adjustor Mechanism The TEAM allows for the timely recovery of future significant income tax changes. It 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. In 2021, TEP refunded $29 million to customers through the TEAM. 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. 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. Transmission Cost Adjustor The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January. The TCA went into effect January 1, 2021, as approved in the 2020 Rate Order. On February 8, 2022, the ACC approved TEP's motion to modify the TCA Plan of Administration to reflect the terms of the 2019 FERC Rate Case proposed settlement agreement, pending the conclusion of that proceeding. Renewable Energy Standard Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. The renewable energy requirement in 2021 was 11% of retail electric sales. In 2021, the percentage of TEP's retail kWh sales attributable to the RES was approximately 26%. In September 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal by July 1, 2022, to phase out the RES tariff. Energy Efficiency Standards Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. As of December 31, 2021, TEP's cumulative annual energy savings was approximately 23%. The annual DSM performance incentive for the prior calendar year is recorded in the first quarter of each year. In 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of $23 million, which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standards. 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 approximately $23 million. TEP cannot predict the outcome of the proceeding. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. In 2021, LFCR revenues decreased as a result of a rate adjustment as approved in the 2020 Rate Order. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2021 2020 Regulatory Assets Pension and Other Postretirement Benefits (Note 10) Various $ 128 $ 166 Under Recovered Purchased Energy Costs 2 91 23 Early Generation Retirement Costs Various 38 43 Lost Fixed Cost Recovery 1 37 59 Property Tax Deferrals (1) 1 27 26 Income Taxes Recoverable through Future Rates (2) Various 17 27 Final Mine Reclamation and Retiree Healthcare Costs (3) 7 17 20 Derivatives (Note 13) 8 8 55 Springerville Unit 1 Leasehold Improvements (4) 2 4 7 Tax Expense Adjustor Mechanism 1 3 — Other Regulatory Assets Various 14 16 Total Regulatory Assets 384 442 Less Current Portion 1 116 124 Total Non-Current Regulatory Assets $ 268 $ 318 Regulatory Liabilities Income Taxes Payable through Future Rates (2) Various $ 268 $ 298 Net Cost of Removal (5) Various 73 125 Renewable Energy Standard Various 66 63 Derivatives (Note 13) 8 19 4 Transmission Revenue Subject to Refund—FERC 1 15 15 Demand Side Management 1 12 6 Transmission Cost Adjustor 1 9 — Tax Expense Adjustor Mechanism 1 — 29 Other Regulatory Liabilities Various 1 1 Total Regulatory Liabilities 463 541 Less Current Portion 1 111 151 Total Non-Current Regulatory Liabilities $ 352 $ 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) Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 14 for additional information regarding income taxes. (3) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. (4) Represents investments TEP made, which were previously recorded in Plant in Service on the 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 3 for additional information related to new depreciation rates approved as part of the 2020 Rate Order. Regulatory Assets and Liabilities 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. TEP pays a return on the majority of its regulatory liability balances. IMPACTS OF REGULATORY ACCOUNTING If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements.

UTILITY PLANT AND JOINTLY-OWNED

UTILITY PLANT AND JOINTLY-OWNED FACILITIES	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
UTILITY PLANT AND JOINTLY-OWNED FACILITIES	UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (3) Average Remaining Life in Years (3) December 31, ($ in millions) 2021 2020 Plant in Service Generation Plant 3.11% 18 $ 3,753 $ 3,279 Distribution Plant 1.93% 33 2,024 1,906 Transmission Plant 1.69% 35 1,210 1,090 General Plant 6.01% 7 540 503 Intangible Plant, Software Costs, and Other (1) Various Various 268 291 Plant Held for Future Use — — 3 4 Total Plant in Service (2) $ 7,798 $ 7,073 (1) Primarily represents computer software, which is amortized over three (2) Includes plant acquisition adjustments of $(206) million and $(202) million as of December 31, 2021 and 2020, respectively. (3) Based on the 2018 depreciation study available for the major classes of Plant in Service, effective January 1, 2021, as approved as part of the 2020 Rate Order. Transmission Plant depreciation rates are based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 2019 FERC Rate Case. Generation Plant Oso Grande 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 700 MW. As of December 31, 2021, there was $444 million in costs related to Oso Grande in Plant in Service on the Consolidated Balance Sheets. Springerville Common Facilities In 2020, due to expiring leases, TEP purchased 32.2% in undivided interests in facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities) at a total fixed purchase price of $68 million. The transaction resulted in an increase in Plant in Service and a decrease in Utility Plant Under Finance Leases on the Consolidated Balance Sheets. As a condition of the purchase, Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, purchased a 14% undivided interest in the Springerville Common Facilities for $30 million in 2020. Also, Tri-State, the lessee of Springerville Unit 3, was obligated to either: (i) buy a 14% undivided interest in the facilities for $30 million by December 31, 2021; or (ii) continue to make payments to TEP for the use of these facilities. Tri-State did not exercise its purchase option and therefore will continue to make payments to TEP. RICE Units Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed into service 10 natural gas RICE units with a total nominal generation capacity of 188 MW in 2020. As of December 31, 2021, there was $187 million related to the Sundt RICE units recorded in Plant in Service on the Consolidated Balance Sheets. Accumulated Depreciation and Amortization TEP Depreciation Rates As part of the 2020 Rate Order, effective January 2021, TEP reclassified $33 million from Regulatory and Other Liabilities—Regulatory Liabilities to Accumulated Depreciation and Amortization on the Consolidated Balance Sheets to reflect the impact of the revised depreciation rates on estimated cost of removal. Amortization of Intangible Plant Intangible Plant primarily consists of computer software. Accumulated amortization of computer software costs were $169 million and $199 million as of December 31, 2021 and 2020, respectively. Amortization of computer software costs totaled $33 million in 2021, $29 million in 2020, and $26 million in 2019. Future estimated amortization costs for existing computer software are $26 million in 2022, $19 million in 2023, $12 million in 2024, $7 million in 2025, and $4 million in 2026. Intangible Plant includes $(4) million in acquisition discounts not subject to amortization as of December 31, 2021, and none in 2020. JOINTLY-OWNED FACILITIES As of December 31, 2021, TEP was a participant in the following jointly-owned generation facilities and transmission systems: ($ in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Unit 1 50.0% $ 285 $ 1 $ (269) $ 17 Four Corners Units 4 and 5 7.0% 188 4 (81) 111 Luna 33.3% 59 1 (3) 57 Gila River Unit 3 75.0% 206 — (65) 141 Gila River Common Facilities 43.8% 75 1 (26) 50 Springerville Coal Handling Facilities 83.0% 209 — (95) 114 Springerville Common Facilities 86.0% 399 — (207) 192 Transmission Facilities Various 462 20 (229) 253 Total $ 1,883 $ 27 $ (975) $ 935 As a participant in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation. ASSET RETIREMENT OBLIGATIONS The liability accrual of AROs is primarily related to generation assets and is included in Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Beginning of Period $ 96 $ 107 Liabilities Incurred (1) 14 — Liabilities Settled (2) (2) (5) Regulatory Deferral/Accretion Expense 4 4 Revisions to the Present Value of Estimated Cash Flows (3) 27 (10) End of Period $ 139 $ 96 (1) Asset retirement obligation for Oso Grande, placed in service in May 2021. (2) Primarily related to the retirement of Navajo. (3) Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of San Juan and changes in ownership of Springerville Common Facilities.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration. DISAGGREGATION OF REVENUES The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service: Years Ended December 31, (in millions) 2021 2020 2019 Retail $ 1,088 $ 1,039 $ 972 Wholesale 278 190 247 Other Services 114 95 124 Revenues from Contracts with Customers 1,480 1,324 1,343 Alternative Revenues 12 48 35 Other 101 53 40 Total Operating Revenues $ 1,593 $ 1,425 $ 1,418 Retail Revenues TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during the spring and summer months and decrease during the fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances. See Note 5 for components of Accounts Receivable on the Consolidated Balance Sheets. In December 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. Wholesale Revenues TEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand (for capacity) or the reading of meters (for power). For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income. Pursuant to a FERC order, all rates charged under TEP's revised OATT are subject to refund until the 2019 FERC Rate Case proceedings conclude. Wholesale Revenues exclude an estimate of revenues probable of refund. See Note 2 for more information regarding the 2019 FERC Rate Case. Other Services Revenues Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, miscellaneous service-related revenues, and reimbursement of various operating expenses for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities by the operator of Springerville Unit 3. When TEP recognizes revenue for reimbursement of Springerville Common Facilities and Springerville Coal Handling Facilities' operating expenses, the associated expenses are recorded in their respective line items on the income statement based on the nature of services provided. Alternative Revenues Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR, TCA, and ECA mechanisms and DSM performance incentive as alternative revenues. See Note 2 for additional information regarding these cost recovery mechanisms and performance incentive. Other Revenues Other Revenues include gains and losses on derivative contracts, common cost allocations to affiliates, and asset management agreement service fees and optimization gains. See Note 6 for information regarding revenue from related parties and Note 13 for information regarding derivative instruments.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
ACCOUNTS RECEIVABLE	ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Retail $ 78 $ 90 Retail, Unbilled 44 41 Retail, Allowance for Credit Losses (10) (13) Wholesale (1) 47 33 Due from Affiliates (Note 6) 17 9 Other 17 13 Accounts Receivable $ 193 $ 173 (1) Includes $16 million and $7 million as of December 31, 2021 and 2020, respectively, 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 Consolidated Balance Sheets: Years Ended December 31, (in millions) 2021 2020 Beginning of Period $ (13) $ (6) Credit Loss Expense — (10) Write-offs 3 3 End of Period $ (10) $ (13) Service Disconnection Moratoriums In 2019, the ACC enacted emergency rules that suspended service disconnections and late fees for electric residential customers who would have otherwise been eligible for service disconnection during the period from June 1 through October 15 (Summer Moratorium). The Summer Moratorium remained in effect for 2020 and 2021, and was permanently adopted by the ACC in November 2021. 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 eligible for disconnection. 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 affected by the COVID-19 pandemic. 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 these customers. TEP is continuing to monitor collection activity and adjusting its allowance for credit losses as needed.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services. Effective January 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 Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Receivables from Related Parties UNS Electric $ 8 $ 6 UNS Energy 7 2 UNS Gas 2 1 Total Due from Related Parties $ 17 $ 9 Payables to Related Parties UNS Energy $ 1 $ 1 UNS Gas 1 — SES — 4 Total Due to Related Parties $ 2 $ 5 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2021 2020 2019 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 11 $ 9 $ 7 Wholesale Revenues, UNS Electric (1)(2) 25 1 1 Control Area Services, UNS Electric (3) 6 4 4 Common Costs, UNS Energy Affiliates (4) 21 19 19 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) 1 — — Supplemental Workforce, SES (5) — 14 15 Corporate Services, UNS Energy (6) 7 5 6 Corporate Services, UNS Energy Affiliates (7) 3 4 4 Capacity Charges, UNS Gas (8) — — 1 Corporate Services, Fortis Affiliates (9) — 1 — (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT. (2) In the second quarter of 2021, TEP began charging UNS Electric for capacity, power, and ancillary services under a tolling PPA. See Note 9 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. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $6 million in 2021, 2020, and 2019. (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. (8) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities. (9) Fortis charges TEP for its share of payroll tax, insurance, and other costs paid by Fortis for affiliated employees.

DEBT AND CREDIT AGREEMENTS

DEBT AND CREDIT AGREEMENTS	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
DEBT AND CREDIT AGREEMENTS	DEBT AND CREDIT AGREEMENTS DEBT Long-term debt matures more than one year from the date of debt issuance. The following table presents the components of long-term debt, which includes Long-Term Debt, Net and Current Maturities of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2021 2020 Notes 2011 Senior Notes 5.15% 2021 $ — $ 250 2012 Senior Notes (1) 3.85% 2023 150 150 2014 Senior Notes 5.00% 2044 150 150 2015 Senior Notes 3.05% 2025 300 300 2018 Senior Notes 4.85% 2048 300 300 2020 Senior Notes 4.00% 2050 350 350 2020 Senior Notes 1.50% 2030 300 300 2021 Senior Notes 3.25% 2051 325 — Tax-Exempt Local Furnishings Bonds (2) 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 Tax-Exempt Pollution Control Bonds 2012 Apache A (3) 4.50% 2030 177 177 Total Long-Term Debt (4) 2,159 2,084 Less Unamortized Discount and Debt Issuance Costs 24 20 Less Current Maturities of Long-Term Debt — 250 Total Long-Term Debt, Net $ 2,135 $ 1,814 (1) The 2012 Senior Notes are callable prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, the notes are callable at par plus accrued interest. (2) The 2012 Pima A bonds become callable at par on or after June 1, 2022. The 2013 Pima A bonds become callable at par on or after March 1, 2023. (3) The 2012 Apache A bonds become callable at par on or after March 1, 2022. (4) As of December 31, 2021, all of TEP's debt is unsecured. Debt Issuances and Redemptions In August 2021, TEP redeemed at par $250 million aggregate principal amount of 5.15% senior unsecured notes, prior to maturity. 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 notes 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 September 2020, TEP extinguished its obligations on two series of fixed rate tax-exempt bonds with aggregate principal amounts of: (i) $80 million, which matured on October 1, 2020; and (ii) $100 million redeemed at par on October 1, 2020, the first par call date. In August 2020, TEP issued and sold $300 million aggregate principal amount of 1.50% senior unsecured notes due August 2030. The debt is callable prior to May 1, 2030, with a make-whole premium plus accrued interest. After May 1, 2030, the debt becomes callable at par plus accrued interest. An amount equal to the net proceeds was allocated to the total costs of Oso Grande. In April 2020, TEP issued and sold $350 million aggregate principal amount of 4.00% senior unsecured notes due June 2050. The debt is callable prior to December 15, 2049, with a make-whole premium plus accrued interest. After December 15, 2049, the debt becomes callable at par plus accrued interest. TEP used the net proceeds from the sale: (i) to repay amounts outstanding under its credit agreement; (ii) to repay and terminate $225 million in term loans; and (iii) for general corporate purposes. Maturities Long-term debt matures on the following dates: (in millions) Long-Term Debt (1) 2022 $ — 2023 150 2024 — 2025 300 2026 — Thereafter 1,709 Total $ 2,159 (1) Total long-term debt excludes $16 million of related unamortized debt issuance costs and $8 million of unamortized original issue discount. CREDIT AGREEMENT In October 2021, TEP entered into an unsecured credit agreement that provides for revolving credit commitments with swingline and LOC sublimits, due in October 2026, the termination date (2021 Credit Agreement). The final maturity date is subject to two one Amounts borrowed under the 2021 Credit Agreement are used for working capital and other general corporate purposes and are recorded in Borrowings Under Credit Agreement on the Consolidated Balance Sheets. Interest rates and fees are based on a pricing grid tied to TEP's credit rating. LOCs are issued from time to time to support energy procurement, hedging transactions, and other business activities. The credit agreement provides for transitions to alternative benchmark rates. Terms are as follows: Sub-Limit Swingline (1) Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed (2) Available Pricing (3) ($ in millions) December 31, 2021 2021 Agreement $ 250 $ 15 $ 50 $ 25 $ 225 2.53 % LIBOR + 1.000% or ABR + 0.00% (1) ABR pricing would apply to swingline loans. (2) Includes a $10 million LOC at a rate of 1.00% per annum issued in October 2021 to replace LOCs originally issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the BTA. (3) TEP's pricing may be adjusted based on performance measured using two key performance indicators: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage. Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed (1) Available Pricing ($ in millions) December 31, 2020 2015 Agreement $ 250 $ 50 $ 12 $ 238 — % LIBOR + 1.000% or ABR + 0.00% (1) Included $12 million in LOCs at a rate of 1.00% per annum issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the BTA. As of February 10, 2022, there was $220 million available under the 2021 Credit Agreement.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
LEASES	LEASES TEP’s leases are included on the balance sheet as follows: December 31, (in millions) Lease Type 2021 2020 Lease Assets Regulatory and Other Assets, Other Operating $ 7 $ 8 Lease Liabilities Current Liabilities, Other Operating 1 1 Regulatory and Other Liabilities, Other Operating 6 7 OPERATING LEASES TEP leases office facilities, land, rail cars, and communication tower space with remaining terms of one to 20 years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 10 years . Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. LEASE COST The following table presents the components of TEP’s lease costs: Years Ended December 31, (in millions) 2021 2020 2019 Finance Amortization of Leased Assets (1)(2) $ — $ 10 $ 13 Interest on Lease Liabilities (3) — 2 13 Operating 1 1 1 Variable (4) 4 2 16 Short Term 2 1 1 Total Lease Cost $ 7 $ 16 $ 44 (1) Finance lease amortization is recorded in Depreciation on the Consolidated Statements of Income. In 2020, TEP deferred $2 million of amortization related to the Springerville Common Facilities in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. See Note 3 for additional information about TEP's purchase of Springerville Common Facilities. (2) TEP entered into a tolling PPA to purchase and receive capacity, power, and ancillary services from Gila River Unit 2, which was accounted for as a finance lease. In 2019, TEP deferred $6 million of amortization in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on PPFAC recovery of TEP's fixed capacity payment. TEP purchased Gila River Unit 2 in December 2019. (3) In 2020 , TEP deferred $1 million of lease interest expense related to the Springerville Common Facilities in Regulatory and Other Assets —Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. Finance lease interest expense related to Gila River Unit 2 was $12 million in 2019. (4) Variable lease cost is primarily comprised of battery storage with variable payments contingent on performance. In April 2021, a 20-year renewable PPA, accompanied by battery storage, achieved commercial operation. See Note 9 for additional information about TEP's renewable PPAs. MATURITY ANALYSIS OF LEASE LIABILITIES As of December 31, 2021, TEP's future minimum lease payments, excluding payments to lessors for variable costs, follow: (in millions) Operating Leases 2022 $ 1 2023 1 2024 1 2025 1 2026 1 Thereafter 3 Total Lease Payments 8 Less Imputed Interest 1 Total Lease Obligations 7 Less Current Portion 1 Total Non-Current Lease Obligations $ 6 LEASE TERMS AND DISCOUNT RATES The following table presents TEP's lease terms and discount rates related to its leases: December 31, 2021 2020 Weighted-Average Remaining Lease Term (years) Operating Leases 11 11 Weighted-Average Discount Rate Operating Leases 3.9 % 3.9 % LEASE CASH FLOWS The following table presents cash paid for amounts included in the measurement of lease liabilities: Years Ended December 31, (in millions) 2021 2020 2019 Operating Cash Flows used for Finance Leases $ — $ 1 $ 13 Operating Cash Flows used for Operating Leases 1 1 1 Financing Cash Flows used for Finance Leases — 17 11 Investing Cash Flows used for Finance Leases — 68 164 See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. LEASE INCOME TEP leases limited office facilities and utility property to others with remaining terms of two Most leases include one or more options to renew with renewal terms that may extend a lease term for up to three years. TEP's operating lease income was $1 million in each of 2021, 2020, and 2019, included in Other, Net on the Consolidated Statements of Income. TEP's expected operating lease payments to be received as of December 31, 2021, are $1 million or less in each year from 2022 through 2026 and $2 million thereafter.
LEASES	LEASES TEP’s leases are included on the balance sheet as follows: December 31, (in millions) Lease Type 2021 2020 Lease Assets Regulatory and Other Assets, Other Operating $ 7 $ 8 Lease Liabilities Current Liabilities, Other Operating 1 1 Regulatory and Other Liabilities, Other Operating 6 7 OPERATING LEASES TEP leases office facilities, land, rail cars, and communication tower space with remaining terms of one to 20 years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 10 years . Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. LEASE COST The following table presents the components of TEP’s lease costs: Years Ended December 31, (in millions) 2021 2020 2019 Finance Amortization of Leased Assets (1)(2) $ — $ 10 $ 13 Interest on Lease Liabilities (3) — 2 13 Operating 1 1 1 Variable (4) 4 2 16 Short Term 2 1 1 Total Lease Cost $ 7 $ 16 $ 44 (1) Finance lease amortization is recorded in Depreciation on the Consolidated Statements of Income. In 2020, TEP deferred $2 million of amortization related to the Springerville Common Facilities in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. See Note 3 for additional information about TEP's purchase of Springerville Common Facilities. (2) TEP entered into a tolling PPA to purchase and receive capacity, power, and ancillary services from Gila River Unit 2, which was accounted for as a finance lease. In 2019, TEP deferred $6 million of amortization in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on PPFAC recovery of TEP's fixed capacity payment. TEP purchased Gila River Unit 2 in December 2019. (3) In 2020 , TEP deferred $1 million of lease interest expense related to the Springerville Common Facilities in Regulatory and Other Assets —Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. Finance lease interest expense related to Gila River Unit 2 was $12 million in 2019. (4) Variable lease cost is primarily comprised of battery storage with variable payments contingent on performance. In April 2021, a 20-year renewable PPA, accompanied by battery storage, achieved commercial operation. See Note 9 for additional information about TEP's renewable PPAs. MATURITY ANALYSIS OF LEASE LIABILITIES As of December 31, 2021, TEP's future minimum lease payments, excluding payments to lessors for variable costs, follow: (in millions) Operating Leases 2022 $ 1 2023 1 2024 1 2025 1 2026 1 Thereafter 3 Total Lease Payments 8 Less Imputed Interest 1 Total Lease Obligations 7 Less Current Portion 1 Total Non-Current Lease Obligations $ 6 LEASE TERMS AND DISCOUNT RATES The following table presents TEP's lease terms and discount rates related to its leases: December 31, 2021 2020 Weighted-Average Remaining Lease Term (years) Operating Leases 11 11 Weighted-Average Discount Rate Operating Leases 3.9 % 3.9 % LEASE CASH FLOWS The following table presents cash paid for amounts included in the measurement of lease liabilities: Years Ended December 31, (in millions) 2021 2020 2019 Operating Cash Flows used for Finance Leases $ — $ 1 $ 13 Operating Cash Flows used for Operating Leases 1 1 1 Financing Cash Flows used for Finance Leases — 17 11 Investing Cash Flows used for Finance Leases — 68 164 See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. LEASE INCOME TEP leases limited office facilities and utility property to others with remaining terms of two Most leases include one or more options to renew with renewal terms that may extend a lease term for up to three years. TEP's operating lease income was $1 million in each of 2021, 2020, and 2019, included in Other, Net on the Consolidated Statements of Income. TEP's expected operating lease payments to be received as of December 31, 2021, are $1 million or less in each year from 2022 through 2026 and $2 million thereafter.
LEASES	LEASES TEP’s leases are included on the balance sheet as follows: December 31, (in millions) Lease Type 2021 2020 Lease Assets Regulatory and Other Assets, Other Operating $ 7 $ 8 Lease Liabilities Current Liabilities, Other Operating 1 1 Regulatory and Other Liabilities, Other Operating 6 7 OPERATING LEASES TEP leases office facilities, land, rail cars, and communication tower space with remaining terms of one to 20 years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 10 years . Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. LEASE COST The following table presents the components of TEP’s lease costs: Years Ended December 31, (in millions) 2021 2020 2019 Finance Amortization of Leased Assets (1)(2) $ — $ 10 $ 13 Interest on Lease Liabilities (3) — 2 13 Operating 1 1 1 Variable (4) 4 2 16 Short Term 2 1 1 Total Lease Cost $ 7 $ 16 $ 44 (1) Finance lease amortization is recorded in Depreciation on the Consolidated Statements of Income. In 2020, TEP deferred $2 million of amortization related to the Springerville Common Facilities in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. See Note 3 for additional information about TEP's purchase of Springerville Common Facilities. (2) TEP entered into a tolling PPA to purchase and receive capacity, power, and ancillary services from Gila River Unit 2, which was accounted for as a finance lease. In 2019, TEP deferred $6 million of amortization in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on PPFAC recovery of TEP's fixed capacity payment. TEP purchased Gila River Unit 2 in December 2019. (3) In 2020 , TEP deferred $1 million of lease interest expense related to the Springerville Common Facilities in Regulatory and Other Assets —Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. Finance lease interest expense related to Gila River Unit 2 was $12 million in 2019. (4) Variable lease cost is primarily comprised of battery storage with variable payments contingent on performance. In April 2021, a 20-year renewable PPA, accompanied by battery storage, achieved commercial operation. See Note 9 for additional information about TEP's renewable PPAs. MATURITY ANALYSIS OF LEASE LIABILITIES As of December 31, 2021, TEP's future minimum lease payments, excluding payments to lessors for variable costs, follow: (in millions) Operating Leases 2022 $ 1 2023 1 2024 1 2025 1 2026 1 Thereafter 3 Total Lease Payments 8 Less Imputed Interest 1 Total Lease Obligations 7 Less Current Portion 1 Total Non-Current Lease Obligations $ 6 LEASE TERMS AND DISCOUNT RATES The following table presents TEP's lease terms and discount rates related to its leases: December 31, 2021 2020 Weighted-Average Remaining Lease Term (years) Operating Leases 11 11 Weighted-Average Discount Rate Operating Leases 3.9 % 3.9 % LEASE CASH FLOWS The following table presents cash paid for amounts included in the measurement of lease liabilities: Years Ended December 31, (in millions) 2021 2020 2019 Operating Cash Flows used for Finance Leases $ — $ 1 $ 13 Operating Cash Flows used for Operating Leases 1 1 1 Financing Cash Flows used for Finance Leases — 17 11 Investing Cash Flows used for Finance Leases — 68 164 See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. LEASE INCOME TEP leases limited office facilities and utility property to others with remaining terms of two Most leases include one or more options to renew with renewal terms that may extend a lease term for up to three years. TEP's operating lease income was $1 million in each of 2021, 2020, and 2019, included in Other, Net on the Consolidated Statements of Income. TEP's expected operating lease payments to be received as of December 31, 2021, are $1 million or less in each year from 2022 through 2026 and $2 million thereafter.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS As of December 31, 2021, TEP had the following commitments: (in millions) 2022 2023 2024 2025 2026 Thereafter Total Minimum Purchase Commitments Fuel, Including Transportation $ 83 $ 74 $ 36 $ 28 $ 25 $ 144 $ 390 Purchased Power 47 47 — — — — 94 Transmission 31 20 15 13 5 4 88 Purchase Commitments Renewable Power Purchase Agreements 80 80 79 79 79 847 1,244 RES Performance-Based Incentives 7 7 7 5 5 23 54 Total Commitments $ 248 $ 228 $ 137 $ 125 $ 114 $ 1,018 $ 1,870 Costs for Purchased Power, Transmission, 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. PBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms. Minimum Purchase Commitments Fuel, Including Transportation TEP has long-term agreements for the purchase and delivery of coal with various expiration dates between 2022 and 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs. In 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 December 31, 2021. TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2022 and 2040. Purchased Power In 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 2022 and 2023. TEP will pay monthly capacity charges and variable power charges. In 2021, TEP also entered into tolling PPAs with UNS Electric to sell and deliver up to 150 MW of capacity, power, and ancillary services over the same 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. Transmission TEP has long-term firm point-to-point contracts to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2022 and 2030. Purchase Commitments Renewable Power Purchase Agreements TEP enters into long-term renewable PPAs, which require TEP to purchase 100% of certain renewable energy generation facilities' output and RECs associated with the output delivered once commercial operation status is achieved. In 2021, two PPA facilities and the associated battery storage achieved commercial operation. The PPAs expire in April 2041 and December 2051. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2051. RES Performance-Based Incentives TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2022 and 2034. 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 final mine reclamation costs, as a component of fuel costs, to retail customers. 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 $44 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 $40 million as of December 31, 2021 and 2020, was recorded in Other on the 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, 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 on the non-defaulting parties is $250 million at Four Corners. As of December 31, 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).

EMPLOYEE BENEFITS PLANS

EMPLOYEE BENEFITS PLANS	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS PLANS	EMPLOYEE BENEFITS PLANS PENSION BENEFIT PLANS TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under IRS regulations. TEP also maintains a SERP for executive management. OTHER POSTRETIREMENT BENEFITS PLAN TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $3 million in 2021 and $1 million in 2020 and 2019. Other postretirement benefits for unclassified employees are self-funded. REGULATORY RECOVERY TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income (Loss) since SERP expense is not currently recoverable in rates. The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the balance sheet: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2021 2020 2021 2020 Regulatory Assets $ 126 $ 150 $ 2 $ 16 Accrued Employee Expenses (1) (1) (3) (3) Pension and Other Postretirement Benefits (61) (91) (59) (72) Accumulated Other Comprehensive Loss, SERP 13 14 — — Net Amount Recognized $ 77 $ 72 $ (60) $ (59) OBLIGATIONS AND FUNDED STATUS The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2021 and 2020. The table below presents the status of all of TEP’s pension and other postretirement benefit plans. All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2021 2020 2021 2020 Change in Benefit Obligation Beginning of Period $ 606 $ 525 $ 99 $ 79 Actuarial (Gain) Loss (6) 76 (12) 18 Interest Cost 14 16 2 3 Service Cost 20 16 6 4 Benefits Paid (34) (27) (5) (5) End of Period 600 606 90 99 Change in Fair Value of Plan Assets Beginning of Period 514 446 24 21 Actual Return on Plan Assets 43 78 3 3 Benefits Paid (32) (26) (2) (5) Employer Contributions (1) 13 16 3 5 End of Period (2) 538 514 28 24 Funded Status at End of Period $ (62) $ (92) $ (62) $ (75) (1) TEP expects to contribute $11 million to the pension plans and less than $1 million to the VEBA trust in 2022. (2) The increase in pension benefit plan assets was primarily due to positive equity returns. The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2021 2020 2021 2020 Net Loss $ 139 $ 164 $ 4 $ 18 Prior Service Cost (Benefit) — 1 (2) (2) The accumulated benefit obligations aggregated for all pension plans as of December 31, 2021, was $538 million. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2021, compared to all three as of December 31, 2020. This was due to an increase in discount rates and positive equity returns. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2021 2020 Accumulated Benefit Obligation $ 26 $ 545 Fair Value of Plan Assets — 514 The Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2021 2020 2019 2021 2020 2019 Service Cost $ 20 $ 16 $ 13 $ 6 $ 4 $ 4 Non-Service Cost Interest Cost 14 16 18 2 3 3 Expected Return on Plan Assets (34) (30) (26) (2) (2) (2) Amortization of Net (Gain) Loss 9 8 8 1 — — Net Periodic Benefit Cost $ 9 $ 10 $ 13 $ 7 $ 5 $ 5 The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. TEP capitalized 22% of service cost as a cost of construction in 2021 and 2020, and 21% in 2019. The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2021 2020 2019 2021 2020 2019 2021 2020 2019 Current Year Actuarial (Gain) Loss $ (16) $ 23 $ 16 $ — $ 5 $ 4 $ (13) $ 17 $ 1 Amortization of Net Loss (8) (8) (8) (1) (1) (1) (1) — — Prior Service (Credit) Cost — — — — — 1 — — — Total Recognized (Gain) Loss $ (24) $ 15 $ 8 $ (1) $ 4 $ 4 $ (14) $ 17 $ 1 For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25 th percentile to the 75 th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes. The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2021 2020 2021 2020 Discount Rate 3.2% 2.9% 3.0% 2.6% Rate of Compensation Increase 2.8% 2.8% N/A N/A The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2021 2020 2019 2021 2020 2019 Discount Rate, Service Cost 3.3% 3.8% 4.7% 2.9% 3.5% 4.5% Discount Rate, Interest Cost 2.3% 3.1% 4.2% 1.9% 2.9% 4.0% Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A Expected Return on Plan Assets 6.8% 6.8% 7.0% 7.0% 7.0% 7.0% Healthcare cost trend rates are assumed to decrease gradually from Next Year to the year the ultimate rate is reached: December 31, 2021 2020 Next Year (Pre-65) 6.5% 6.1% Next Year (Post-65) 5.5% 7.1% Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5% Year Ultimate Rate is Reached (Pre-65) 2031 2037 Year Ultimate Rate is Reached (Post-65) 2027 2037 PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement Benefits 2021 2020 2021 2020 Asset Category Equity Securities 54 % 47 % 63 % 63 % Fixed Income Securities 40 % 45 % 35 % 35 % Real Estate 5 % 7 % — % — % Other 1 % 1 % 2 % 2 % Total 100 % 100 % 100 % 100 % As of December 31, 2021, the fair value of VEBA trust assets was $28 million, of which $10 million were fixed income investments and $18 million were equities. As of December 31, 2020, the fair value of VEBA trust assets was $24 million, of which $9 million were fixed income investments and $15 million were equities. The VEBA trust assets are primarily Level 2 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust. The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2021 Asset Category Cash Equivalents $ 2 $ — $ — $ 2 Equity Securities: United States Large Cap — 77 — 77 United States Small Cap — 28 — 28 Non-United States — 105 — 105 Global — 83 — 83 Fixed Income — 213 — 213 Real Estate — — 26 26 Private Equity — — 4 4 Total $ 2 $ 506 $ 30 $ 538 (in millions) December 31, 2020 Asset Category Equity Securities: United States Large Cap $ — $ 65 $ — $ 65 United States Small Cap — 25 — 25 Non-United States — 95 — 95 Global — 59 — 59 Fixed Income — 231 — 231 Real Estate — 12 23 35 Private Equity — — 4 4 Total $ — $ 487 $ 27 $ 514 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2019 $ 5 $ 23 $ 28 Actual Return on Plan Assets: Assets Held at Reporting Date — — — Purchases, Sales, and Settlements (1) — (1) Balance as of December 31, 2020 4 23 27 Actual Return on Plan Assets: Assets Held at Reporting Date 2 3 5 Purchases, Sales, and Settlements (2) — (2) Balance as of December 31, 2021 $ 4 $ 26 $ 30 Pension Plan Investments Investment Goals Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. Risk Management TEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes. Relationship between Plan Assets and Benefit Obligations The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation. Target Allocation Percentages The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced: Pension Other Postretirement Benefits December 31, 2021 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 13% 39% United States Small Cap 5% 5% Non-United States Developed —% 7% Non-United States Emerging —% 9% Global Equity 32% —% Global Infrastructure 3% —% Fixed Income 40% 38% Real Estate 6% —% Private Equity 1% —% Total 100% 100% Pension Fund Descriptions For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds. ESTIMATED FUTURE BENEFIT PAYMENTS TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate: (in millions) 2022 2023 2024 2025 2026 2027-2031 Pension Benefits $ 28 $ 29 $ 29 $ 29 $ 30 $ 158 Other Postretirement Benefits 5 5 5 6 5 26 DEFINED CONTRIBUTION PLAN TEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $7 million in 2021 and $6 million in 2020 and 2019.

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
SHARE-BASED COMPENSATION	SHARE-BASED COMPENSATION 2020 FORTIS RESTRICTED STOCK UNIT PLAN The Fortis Board of Directors ratified the 2020 Restricted Stock Unit Plan (2020 Plan) effective January 2020. Under the 2020 Plan, executive officers of Fortis and its subsidiaries may be granted time-based RSUs annually, which may be settled in cash or shares. Each RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. Fortis accounts for forfeitures as they occur. The following table represents RSUs awarded by Fortis for UNS Energy: 2021 2020 RSUs 20,794 15,751 The awards are initially classified as liability awards because: (i) executive officers have the option to elect the cash or share settlement feature; and (ii) this election is contingent on an event within the executive officers' control. The liability awards may be reclassified as equity awards if the executive officers elect the share settlement feature on the modification date. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $2 million and $1 million as of December 31, 2021 and 2020, respectively. TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded no compensation expense in 2021 and $1 million in 2020 based on its share of Fortis' compensation expense. 2015 SHARE UNIT PLAN The Human Resources and Governance Committee of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (2015 Plan) effective January 2015. Under the 2015 Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of PSUs and RSUs annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur. The following table represents PSUs and RSUs awarded by UNS Energy: 2021 2020 2019 PSUs 44,931 35,328 66,978 RSUs (1) 2,401 1,918 33,489 (1) Effective January 2020, executive officer RSU awards are issued through the 2020 Plan. Certain key employees will continue to be awarded RSUs through the 2015 Plan. The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $9 million and $10 million as of December 31, 2021 and 2020, respectively. TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2021, $3 million in 2020, and $4 million in 2019 based on its share of UNS Energy's compensation expense.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Years Ended December 31, (in millions) 2021 2020 2019 Interest Paid, Net of Amounts Capitalized $ 76 $ 76 $ 80 Income Tax Refunds (1) — (14) (14) (1) TEP received refunds of AMT credit carryforwards in 2020 and 2019. See Note 14 for additional information regarding AMT. 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: Years Ended December 31, (in millions) 2021 2020 2019 Accrued Capital Expenditures $ 38 $ 26 $ 40 Asset Retirement Obligations Increase (Decrease) (1) 34 (12) 26 Renewable Energy Credits 3 3 3 Operating Leases (2) — 1 8 Finance Leases — — 67 Net Cost of Removal Increase (Decrease) (3) (41) (34) (10) (1) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of expected future cash flows. (2) In 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. (3) 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.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 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) December 31, 2021 Assets Restricted Cash (1) $ 23 $ — $ 23 Energy Derivative Contracts, Regulatory Recovery (2) — 30 30 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 23 34 57 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (20) (20) Total Liabilities — (20) (20) Total Assets (Liabilities), Net $ 23 $ 14 $ 37 (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 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 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) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (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: Years Ended December 31, (in millions) 2021 2020 2019 Unrealized Net Gain (Loss) (1) $ 62 $ 21 $ (45) (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 Consolidated Statements of Income: Years Ended December 31, (in millions) 2021 2020 2019 Operating Revenues $ 7 $ 5 $ 6 Derivative Volumes As of December 31, 2021, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts: December 31, 2021 2020 Power Contracts GWh 2,617 4,143 Gas Contracts BBtu 112,316 111,585 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 $26 million as of December 31, 2021, compared with $60 million as of December 31, 2020. As of December 31, 2021, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on December 31, 2021, TEP would have been required to post $26 million of collateral of which $21 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: Net Carrying Value Fair Value Fair Value Hierarchy December 31, (in millions) 2021 2020 2021 2020 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,135 $ 2,064 $ 2,357 $ 2,363

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% to pre-tax income due to the following: Years Ended December 31, (in millions) 2021 2020 2019 Federal Income Tax Expense at Statutory Rate $ 49 $ 49 $ 46 State Income Tax Expense, Net of Federal Deduction 9 9 9 Federal/State Tax Credits (1) (10) (3) (6) Allowance for Equity Funds Used During Construction (3) (7) (3) Excess Deferred Income Taxes (14) (7) (9) Impact of AMT Sequestration — — (2) Other 1 — (1) Total Income Tax Expense $ 32 $ 41 $ 34 (1) In 2021, TEP realized PTC benefits of $7 million related to Oso Grande being placed in service in May 2021. Income Tax Expense included on the Consolidated Statements of Income consists of the following: Years Ended December 31, (in millions) 2021 2020 2019 Current Income Tax Expense Federal $ (2) $ (2) $ (8) State — 1 — Total Current Income Tax Expense (2) (1) (8) Deferred Income Tax Expense Federal 27 37 41 Federal Investment Tax Credits (1) (1) (4) State 8 6 5 Total Deferred Income Tax Expense 34 42 42 Total Income Tax Expense $ 32 $ 41 $ 34 In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $14 million, $7 million, and $9 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2021, 2020, and 2019, respectively. As part of the 2020 Rate Order, TEP received approval of a TEAM that allows income tax changes that materially affect TEP’s authorized revenue requirement to be shared with customers including changes in EDIT amortization. Effective January 1, 2021, TEP shares any changes in its EDIT amortization through the usage-based adjustor. See Note 2 for additional information regarding the 2020 Rate Order. Under the TCJA, existing AMT credit carryforwards could be refunded or used to offset U.S. federal income tax liabilities through our 2021 tax year. Along with other significant provisions, the CARES Act accelerated the recovery of remaining AMT credits by allowing corporations to immediately claim refunds of all unused carryforward balances. In 2020, the remaining AMT credit carryforward balance of $14 million was refunded to the Company. The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2021 2020 Gross Deferred Income Tax Assets Customer Advances and Contributions in Aid of Construction $ 20 $ 19 Other Postretirement Benefits 15 15 Investment Tax Credit Carryforward 23 19 Income Taxes Payable Through Future Rates 67 74 Other 93 76 Total Gross Deferred Income Tax Assets 218 203 Gross Deferred Income Tax Liabilities Plant, Net (682) (639) PPFAC (23) (6) Plant Abandonments (8) (11) Pensions (18) (17) Income Taxes Recoverable Through Future Rates (4) (7) Other (32) (16) Total Gross Deferred Income Tax Liabilities (767) (696) Deferred Income Taxes, Net $ (549) $ (493) TEP recorded no valuation allowance against all other tax credit and net operating loss carryforward deferred income tax assets as of December 31, 2021 and 2020. Management believes TEP will produce sufficient taxable income in the future to realize credit and loss carryforwards before they expire. As of December 31, 2021, TEP had the following carryforward amounts: ($ in millions) Amount Expiring Year State Net Operating Loss $ 1 2026 State Credits 9 2023 - 29 Investment Tax Credits 22 2034 - 41 Other Federal Credits 8 2034 - 41 UNCERTAIN TAX POSITIONS A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2021 2020 Beginning of Period $ 19 $ 18 Additions Based on Tax Positions Taken in the Current Year — 1 Reductions Based on Positions Taken in Prior Years (18) — End of Period $ 1 $ 19 Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2021 and 2020. TEP recorded no interest expense in 2021 and 2020 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2021 and 2020. TEP has been audited by the IRS through tax year 2010. TEP's 2011 to 2020 tax years are open for audit by federal and state tax agencies. TEP had previously filed an application with the IRS for a change in accounting method on uncertain tax positions. On February 2, 2021, TEP received approval of this application from the IRS which resulted in a $18 million decrease in uncertain tax position obligations on a prospective basis. TAX SHARING AGREEMENT Under the terms of the tax sharing agreement with UNS Energy, TEP made net payments of $7 million in 2021 and received net refunds of $10 million in 2020 and $14 million in 2019 related to Federal income tax returns.

NATURE OF OPERATIONS AND SUMM_2

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Accounting for Regulated Operations	BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Accounting for Regulated Operations TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates charged to retail customers or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers.
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 the primary beneficiary of the VIEs on a quarterly basis.
New Accounting Standards Issued and Not Yet Adopted	NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the FASB 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.
Use of Accounting Estimates	USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheet at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statement during the periods presented. Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates.
Asset Retirement Obligations	Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset or liability account based on the ACC's approval of these costs in its depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities.
Contingencies	Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these legal proceedings and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made.
Cash and Cash Equivalents	CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents.
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 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.
Allowance for Credit Losses	ALLOWANCE FOR CREDIT LOSSESTEP records an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical credit loss patterns, sales, current conditions, and reasonable and supportable forecasts. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible
Inventory	INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory.
Utility Plant	UTILITY PLANT Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement.
AFUDC and Capitalized Interest	AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income.
Depreciation	Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis, excluding software intangible plant, at depreciation rates based on the economic lives of the assets, including estimates for salvage value and removal costs. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation, distribution, and general plant assets. Transmission assets are subject to the jurisdiction of the FERC.
Computer Software and Cloud Computing Costs	Computer Software and Cloud Computing Costs Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over three
Evaluation of Assets for Impairment	EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time.
Deferred Financing Costs	DEFERRED FINANCING COSTS Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to credit facility arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt.
Leases	LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.
Operating Revenues	OPERATING REVENUES TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the
Purchased Power and Fuel Adjustment Clause	PURCHASED POWER AND FUEL ADJUSTMENT CLAUSETEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities, and cost under-recoveries are deferred as regulatory assets.
Renewable Energy and Energy Efficiency Programs and Renewable Energy Credits	RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file annual RES implementation plans for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through a RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the LFCR mechanism. 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 of February 10, 2022, the ACC has not set annual target retail kWh savings requirements for future years. The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism. Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Operating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power or the REC purchase price equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power or contract price for power is recoverable through the PPFAC mechanism.
Taxes Other Than Income Taxes	TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement. Payroll Tax In response to the COVID-19 pandemic, the CARES Act was signed into law on March 27, 2020. As permitted by the CARES Act, TEP deferred payment of the employer's portion of social security taxes. In 2020, TEP recorded total deferred deposits of $7 million in Accrued Taxes Other than Income Taxes and Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. TEP paid $3 million in December 2021 and expects to pay the remaining deferred deposits to the IRS in 2022.
Income Taxes	INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income. TEP accounts for federal energy credits generated prior to 2013 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. TEP had an aggregate liability balance of $5 million and $6 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $1 million and $2 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS.
Pension and Other Post Retirement Benefits	PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement plan. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.
Fair Value	FAIR VALUEAs defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Derivative Instruments	DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; and (ii) reduce exposure to energy commodity price volatility. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities on the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity on the income statement.

NATURE OF OPERATIONS AND SUMM_3

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restrictions on cash and 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: Years Ended December 31, (in millions) 2021 2020 2019 Cash and Cash Equivalents $ 10 $ 61 $ 10 Restricted Cash included in: Investments and Other Property 20 19 16 Current Assets—Other 3 2 2 Total Cash, Cash Equivalents, and Restricted Cash $ 33 $ 82 $ 28
AFUDC rates	The average AFUDC rates on regulated construction expenditures are included in the table below: 2021 2020 2019 Average AFUDC Rates 6.88 % 6.63 % 7.86 %
Summary of average annual depreciation rates for all utility plants	Below are the summarized average annual depreciation rates for all utility plant: 2021 2020 2019 Average Annual Depreciation Rates 3.30 % 3.15 % 3.08 %
Schedule of renewable energy credit	The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Beginning of Period $ 66 $ 63 Purchased 49 48 Used for Compliance (46) (45) End of Period $ 69 $ 66

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Schedule of Purchased Power and Fuel Adjustment Rates	The table below summarizes the PPFAC regulatory asset (liability) balance: Years Ended December 31, (in millions) 2021 2020 Beginning of Period $ 23 $ 36 Deferred Fuel and Purchased Power Costs (1) 343 283 PPFAC and Base Power Recoveries (2) (275) (296) End of Period $ 91 $ 23 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2021 and 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2021 and June 1, 2020.
Schedule of Regulatory Assets and Liabilities	Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2021 2020 Regulatory Assets Pension and Other Postretirement Benefits (Note 10) Various $ 128 $ 166 Under Recovered Purchased Energy Costs 2 91 23 Early Generation Retirement Costs Various 38 43 Lost Fixed Cost Recovery 1 37 59 Property Tax Deferrals (1) 1 27 26 Income Taxes Recoverable through Future Rates (2) Various 17 27 Final Mine Reclamation and Retiree Healthcare Costs (3) 7 17 20 Derivatives (Note 13) 8 8 55 Springerville Unit 1 Leasehold Improvements (4) 2 4 7 Tax Expense Adjustor Mechanism 1 3 — Other Regulatory Assets Various 14 16 Total Regulatory Assets 384 442 Less Current Portion 1 116 124 Total Non-Current Regulatory Assets $ 268 $ 318 Regulatory Liabilities Income Taxes Payable through Future Rates (2) Various $ 268 $ 298 Net Cost of Removal (5) Various 73 125 Renewable Energy Standard Various 66 63 Derivatives (Note 13) 8 19 4 Transmission Revenue Subject to Refund—FERC 1 15 15 Demand Side Management 1 12 6 Transmission Cost Adjustor 1 9 — Tax Expense Adjustor Mechanism 1 — 29 Other Regulatory Liabilities Various 1 1 Total Regulatory Liabilities 463 541 Less Current Portion 1 111 151 Total Non-Current Regulatory Liabilities $ 352 $ 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) Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 14 for additional information regarding income taxes. (3) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. (4) Represents investments TEP made, which were previously recorded in Plant in Service on the 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

UTILITY PLANT AND JOINTLY-OWN_2

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Public utility PPE	The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (3) Average Remaining Life in Years (3) December 31, ($ in millions) 2021 2020 Plant in Service Generation Plant 3.11% 18 $ 3,753 $ 3,279 Distribution Plant 1.93% 33 2,024 1,906 Transmission Plant 1.69% 35 1,210 1,090 General Plant 6.01% 7 540 503 Intangible Plant, Software Costs, and Other (1) Various Various 268 291 Plant Held for Future Use — — 3 4 Total Plant in Service (2) $ 7,798 $ 7,073 (1) Primarily represents computer software, which is amortized over three (2) Includes plant acquisition adjustments of $(206) million and $(202) million as of December 31, 2021 and 2020, respectively. (3) Based on the 2018 depreciation study available for the major classes of Plant in Service, effective January 1, 2021, as approved as part of the 2020 Rate Order. Transmission Plant depreciation rates are based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 2019 FERC Rate Case.
Schedule of jointly owned utility plants	As of December 31, 2021, TEP was a participant in the following jointly-owned generation facilities and transmission systems: ($ in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Unit 1 50.0% $ 285 $ 1 $ (269) $ 17 Four Corners Units 4 and 5 7.0% 188 4 (81) 111 Luna 33.3% 59 1 (3) 57 Gila River Unit 3 75.0% 206 — (65) 141 Gila River Common Facilities 43.8% 75 1 (26) 50 Springerville Coal Handling Facilities 83.0% 209 — (95) 114 Springerville Common Facilities 86.0% 399 — (207) 192 Transmission Facilities Various 462 20 (229) 253 Total $ 1,883 $ 27 $ (975) $ 935
Schedule of asset retirement obligations	The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Beginning of Period $ 96 $ 107 Liabilities Incurred (1) 14 — Liabilities Settled (2) (2) (5) Regulatory Deferral/Accretion Expense 4 4 Revisions to the Present Value of Estimated Cash Flows (3) 27 (10) End of Period $ 139 $ 96 (1) Asset retirement obligation for Oso Grande, placed in service in May 2021. (2) Primarily related to the retirement of Navajo. (3) Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of San Juan and changes in ownership of Springerville Common Facilities.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of revenue	The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service: Years Ended December 31, (in millions) 2021 2020 2019 Retail $ 1,088 $ 1,039 $ 972 Wholesale 278 190 247 Other Services 114 95 124 Revenues from Contracts with Customers 1,480 1,324 1,343 Alternative Revenues 12 48 35 Other 101 53 40 Total Operating Revenues $ 1,593 $ 1,425 $ 1,418

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Schedule of the components of accounts receivable, net	The following table presents the components of Accounts Receivable on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Retail $ 78 $ 90 Retail, Unbilled 44 41 Retail, Allowance for Credit Losses (10) (13) Wholesale (1) 47 33 Due from Affiliates (Note 6) 17 9 Other 17 13 Accounts Receivable $ 193 $ 173 (1) Includes $16 million and $7 million as of December 31, 2021 and 2020, respectively, of receivables related to revenue from derivative instruments.
Schedule of accounts receivable, 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 Consolidated Balance Sheets: Years Ended December 31, (in millions) 2021 2020 Beginning of Period $ (13) $ (6) Credit Loss Expense — (10) Write-offs 3 3 End of Period $ (10) $ (13)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Table)	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Schedule of related party transactions	The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets: December 31, (in millions) 2021 2020 Receivables from Related Parties UNS Electric $ 8 $ 6 UNS Energy 7 2 UNS Gas 2 1 Total Due from Related Parties $ 17 $ 9 Payables to Related Parties UNS Energy $ 1 $ 1 UNS Gas 1 — SES — 4 Total Due to Related Parties $ 2 $ 5 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2021 2020 2019 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 11 $ 9 $ 7 Wholesale Revenues, UNS Electric (1)(2) 25 1 1 Control Area Services, UNS Electric (3) 6 4 4 Common Costs, UNS Energy Affiliates (4) 21 19 19 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) 1 — — Supplemental Workforce, SES (5) — 14 15 Corporate Services, UNS Energy (6) 7 5 6 Corporate Services, UNS Energy Affiliates (7) 3 4 4 Capacity Charges, UNS Gas (8) — — 1 Corporate Services, Fortis Affiliates (9) — 1 — (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT. (2) In the second quarter of 2021, TEP began charging UNS Electric for capacity, power, and ancillary services under a tolling PPA. See Note 9 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. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $6 million in 2021, 2020, and 2019. (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. (8) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities. (9) Fortis charges TEP for its share of payroll tax, insurance, and other costs paid by Fortis for affiliated employees.

DEBT AND CREDIT AGREEMENTS (Tab

DEBT AND CREDIT AGREEMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of long-term debt instruments	The following table presents the components of long-term debt, which includes Long-Term Debt, Net and Current Maturities of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2021 2020 Notes 2011 Senior Notes 5.15% 2021 $ — $ 250 2012 Senior Notes (1) 3.85% 2023 150 150 2014 Senior Notes 5.00% 2044 150 150 2015 Senior Notes 3.05% 2025 300 300 2018 Senior Notes 4.85% 2048 300 300 2020 Senior Notes 4.00% 2050 350 350 2020 Senior Notes 1.50% 2030 300 300 2021 Senior Notes 3.25% 2051 325 — Tax-Exempt Local Furnishings Bonds (2) 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 Tax-Exempt Pollution Control Bonds 2012 Apache A (3) 4.50% 2030 177 177 Total Long-Term Debt (4) 2,159 2,084 Less Unamortized Discount and Debt Issuance Costs 24 20 Less Current Maturities of Long-Term Debt — 250 Total Long-Term Debt, Net $ 2,135 $ 1,814 (1) The 2012 Senior Notes are callable prior to December 15, 2022, with a make-whole premium plus accrued interest. After December 15, 2022, the notes are callable at par plus accrued interest. (2) The 2012 Pima A bonds become callable at par on or after June 1, 2022. The 2013 Pima A bonds become callable at par on or after March 1, 2023. (3) The 2012 Apache A bonds become callable at par on or after March 1, 2022. (4) As of December 31, 2021, all of TEP's debt is unsecured.
Schedule of maturities of long-term debt	Long-term debt matures on the following dates: (in millions) Long-Term Debt (1) 2022 $ — 2023 150 2024 — 2025 300 2026 — Thereafter 1,709 Total $ 2,159 (1) Total long-term debt excludes $16 million of related unamortized debt issuance costs and $8 million of unamortized original issue discount.
Schedule of line of credit facilities	Terms are as follows: Sub-Limit Swingline (1) Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed (2) Available Pricing (3) ($ in millions) December 31, 2021 2021 Agreement $ 250 $ 15 $ 50 $ 25 $ 225 2.53 % LIBOR + 1.000% or ABR + 0.00% (1) ABR pricing would apply to swingline loans. (2) Includes a $10 million LOC at a rate of 1.00% per annum issued in October 2021 to replace LOCs originally issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the BTA. (3) TEP's pricing may be adjusted based on performance measured using two key performance indicators: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage. Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed (1) Available Pricing ($ in millions) December 31, 2020 2015 Agreement $ 250 $ 50 $ 12 $ 238 — % LIBOR + 1.000% or ABR + 0.00% (1) Included $12 million in LOCs at a rate of 1.00% per annum issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the BTA.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lease assets and lease liabilities	TEP’s leases are included on the balance sheet as follows: December 31, (in millions) Lease Type 2021 2020 Lease Assets Regulatory and Other Assets, Other Operating $ 7 $ 8 Lease Liabilities Current Liabilities, Other Operating 1 1 Regulatory and Other Liabilities, Other Operating 6 7
Components of lease cost	The following table presents the components of TEP’s lease costs: Years Ended December 31, (in millions) 2021 2020 2019 Finance Amortization of Leased Assets (1)(2) $ — $ 10 $ 13 Interest on Lease Liabilities (3) — 2 13 Operating 1 1 1 Variable (4) 4 2 16 Short Term 2 1 1 Total Lease Cost $ 7 $ 16 $ 44 (1) Finance lease amortization is recorded in Depreciation on the Consolidated Statements of Income. In 2020, TEP deferred $2 million of amortization related to the Springerville Common Facilities in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. See Note 3 for additional information about TEP's purchase of Springerville Common Facilities. (2) TEP entered into a tolling PPA to purchase and receive capacity, power, and ancillary services from Gila River Unit 2, which was accounted for as a finance lease. In 2019, TEP deferred $6 million of amortization in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets based on PPFAC recovery of TEP's fixed capacity payment. TEP purchased Gila River Unit 2 in December 2019. (3) In 2020 , TEP deferred $1 million of lease interest expense related to the Springerville Common Facilities in Regulatory and Other Assets —Regulatory Assets on the Consolidated Balance Sheets based on recovery over the expected life of the asset. Finance lease interest expense related to Gila River Unit 2 was $12 million in 2019. (4) Variable lease cost is primarily comprised of battery storage with variable payments contingent on performance. In April 2021, a 20-year renewable PPA, accompanied by battery storage, achieved commercial operation. See Note 9 for additional information about TEP's renewable PPAs. The following table presents cash paid for amounts included in the measurement of lease liabilities: Years Ended December 31, (in millions) 2021 2020 2019 Operating Cash Flows used for Finance Leases $ — $ 1 $ 13 Operating Cash Flows used for Operating Leases 1 1 1 Financing Cash Flows used for Finance Leases — 17 11 Investing Cash Flows used for Finance Leases — 68 164
Future minimum lease payments for operating leases	As of December 31, 2021, TEP's future minimum lease payments, excluding payments to lessors for variable costs, follow: (in millions) Operating Leases 2022 $ 1 2023 1 2024 1 2025 1 2026 1 Thereafter 3 Total Lease Payments 8 Less Imputed Interest 1 Total Lease Obligations 7 Less Current Portion 1 Total Non-Current Lease Obligations $ 6
Lease terms and discount rates	The following table presents TEP's lease terms and discount rates related to its leases: December 31, 2021 2020 Weighted-Average Remaining Lease Term (years) Operating Leases 11 11 Weighted-Average Discount Rate Operating Leases 3.9 % 3.9 %

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments	As of December 31, 2021, TEP had the following commitments: (in millions) 2022 2023 2024 2025 2026 Thereafter Total Minimum Purchase Commitments Fuel, Including Transportation $ 83 $ 74 $ 36 $ 28 $ 25 $ 144 $ 390 Purchased Power 47 47 — — — — 94 Transmission 31 20 15 13 5 4 88 Purchase Commitments Renewable Power Purchase Agreements 80 80 79 79 79 847 1,244 RES Performance-Based Incentives 7 7 7 5 5 23 54 Total Commitments $ 248 $ 228 $ 137 $ 125 $ 114 $ 1,018 $ 1,870

EMPLOYEE BENEFITS PLANS (Tables

EMPLOYEE BENEFITS PLANS (Tables)	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
Schedule of pension and other postretirement benefit amounts	The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the balance sheet: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2021 2020 2021 2020 Regulatory Assets $ 126 $ 150 $ 2 $ 16 Accrued Employee Expenses (1) (1) (3) (3) Pension and Other Postretirement Benefits (61) (91) (59) (72) Accumulated Other Comprehensive Loss, SERP 13 14 — — Net Amount Recognized $ 77 $ 72 $ (60) $ (59)
Schedule of changes in funded status	All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2021 2020 2021 2020 Change in Benefit Obligation Beginning of Period $ 606 $ 525 $ 99 $ 79 Actuarial (Gain) Loss (6) 76 (12) 18 Interest Cost 14 16 2 3 Service Cost 20 16 6 4 Benefits Paid (34) (27) (5) (5) End of Period 600 606 90 99 Change in Fair Value of Plan Assets Beginning of Period 514 446 24 21 Actual Return on Plan Assets 43 78 3 3 Benefits Paid (32) (26) (2) (5) Employer Contributions (1) 13 16 3 5 End of Period (2) 538 514 28 24 Funded Status at End of Period $ (62) $ (92) $ (62) $ (75) (1) TEP expects to contribute $11 million to the pension plans and less than $1 million to the VEBA trust in 2022. (2) The increase in pension benefit plan assets was primarily due to positive equity returns.
Schedule of net periodic benefit cost not yet recognized	The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2021 2020 2021 2020 Net Loss $ 139 $ 164 $ 4 $ 18 Prior Service Cost (Benefit) — 1 (2) (2)
Schedule of information for the pension plans with accumulated benefit obligations in excess of pension plan	The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2021 2020 Accumulated Benefit Obligation $ 26 $ 545 Fair Value of Plan Assets — 514
Components of net periodic benefit plan cost	Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2021 2020 2019 2021 2020 2019 Service Cost $ 20 $ 16 $ 13 $ 6 $ 4 $ 4 Non-Service Cost Interest Cost 14 16 18 2 3 3 Expected Return on Plan Assets (34) (30) (26) (2) (2) (2) Amortization of Net (Gain) Loss 9 8 8 1 — — Net Periodic Benefit Cost $ 9 $ 10 $ 13 $ 7 $ 5 $ 5
Schedule of the changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI	The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2021 2020 2019 2021 2020 2019 2021 2020 2019 Current Year Actuarial (Gain) Loss $ (16) $ 23 $ 16 $ — $ 5 $ 4 $ (13) $ 17 $ 1 Amortization of Net Loss (8) (8) (8) (1) (1) (1) (1) — — Prior Service (Credit) Cost — — — — — 1 — — — Total Recognized (Gain) Loss $ (24) $ 15 $ 8 $ (1) $ 4 $ 4 $ (14) $ 17 $ 1
Schedule of weighted average assumptions used to determine benefit obligations	The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2021 2020 2021 2020 Discount Rate 3.2% 2.9% 3.0% 2.6% Rate of Compensation Increase 2.8% 2.8% N/A N/A
Schedule of weighted average assumptions used to determine net periodic benefit costs	The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2021 2020 2019 2021 2020 2019 Discount Rate, Service Cost 3.3% 3.8% 4.7% 2.9% 3.5% 4.5% Discount Rate, Interest Cost 2.3% 3.1% 4.2% 1.9% 2.9% 4.0% Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A Expected Return on Plan Assets 6.8% 6.8% 7.0% 7.0% 7.0% 7.0%
Schedule of healthcare cost trend rates	Healthcare cost trend rates are assumed to decrease gradually from Next Year to the year the ultimate rate is reached: December 31, 2021 2020 Next Year (Pre-65) 6.5% 6.1% Next Year (Post-65) 5.5% 7.1% Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5% Year Ultimate Rate is Reached (Pre-65) 2031 2037 Year Ultimate Rate is Reached (Post-65) 2027 2037
Schedule of asset allocations, by asset category, on the measurement date	Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement Benefits 2021 2020 2021 2020 Asset Category Equity Securities 54 % 47 % 63 % 63 % Fixed Income Securities 40 % 45 % 35 % 35 % Real Estate 5 % 7 % — % — % Other 1 % 1 % 2 % 2 % Total 100 % 100 % 100 % 100 %
Schedule of fair value measurements of pension plan assets by level	The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2021 Asset Category Cash Equivalents $ 2 $ — $ — $ 2 Equity Securities: United States Large Cap — 77 — 77 United States Small Cap — 28 — 28 Non-United States — 105 — 105 Global — 83 — 83 Fixed Income — 213 — 213 Real Estate — — 26 26 Private Equity — — 4 4 Total $ 2 $ 506 $ 30 $ 538 (in millions) December 31, 2020 Asset Category Equity Securities: United States Large Cap $ — $ 65 $ — $ 65 United States Small Cap — 25 — 25 Non-United States — 95 — 95 Global — 59 — 59 Fixed Income — 231 — 231 Real Estate — 12 23 35 Private Equity — — 4 4 Total $ — $ 487 $ 27 $ 514 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models.
Schedule of reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy	The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2019 $ 5 $ 23 $ 28 Actual Return on Plan Assets: Assets Held at Reporting Date — — — Purchases, Sales, and Settlements (1) — (1) Balance as of December 31, 2020 4 23 27 Actual Return on Plan Assets: Assets Held at Reporting Date 2 3 5 Purchases, Sales, and Settlements (2) — (2) Balance as of December 31, 2021 $ 4 $ 26 $ 30
Schedule of target allocation percentages for the major asset categories of the plan	The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced: Pension Other Postretirement Benefits December 31, 2021 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 13% 39% United States Small Cap 5% 5% Non-United States Developed —% 7% Non-United States Emerging —% 9% Global Equity 32% —% Global Infrastructure 3% —% Fixed Income 40% 38% Real Estate 6% —% Private Equity 1% —% Total 100% 100%
Schedule of expected benefit payments	TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate: (in millions) 2022 2023 2024 2025 2026 2027-2031 Pension Benefits $ 28 $ 29 $ 29 $ 29 $ 30 $ 158 Other Postretirement Benefits 5 5 5 6 5 26

SHARE-BASED COMPENSATION (Table

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Schedule of awards	The following table represents RSUs awarded by Fortis for UNS Energy: 2021 2020 RSUs 20,794 15,751 The following table represents PSUs and RSUs awarded by UNS Energy: 2021 2020 2019 PSUs 44,931 35,328 66,978 RSUs (1) 2,401 1,918 33,489

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	CASH TRANSACTIONS Years Ended December 31, (in millions) 2021 2020 2019 Interest Paid, Net of Amounts Capitalized $ 76 $ 76 $ 80 Income Tax Refunds (1) — (14) (14) (1) TEP received refunds of AMT credit carryforwards in 2020 and 2019. See Note 14 for additional information regarding AMT. 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: Years Ended December 31, (in millions) 2021 2020 2019 Accrued Capital Expenditures $ 38 $ 26 $ 40 Asset Retirement Obligations Increase (Decrease) (1) 34 (12) 26 Renewable Energy Credits 3 3 3 Operating Leases (2) — 1 8 Finance Leases — — 67 Net Cost of Removal Increase (Decrease) (3) (41) (34) (10) (1) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of expected future cash flows. (2) In 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. (3) 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.

FAIR VALUE MEASUREMENTS AND D_2

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
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) December 31, 2021 Assets Restricted Cash (1) $ 23 $ — $ 23 Energy Derivative Contracts, Regulatory Recovery (2) — 30 30 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 23 34 57 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (20) (20) Total Liabilities — (20) (20) Total Assets (Liabilities), Net $ 23 $ 14 $ 37 (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 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 Consolidated Balance Sheets.
Potential offset of assets by counterparty netting and cash collateral	The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (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	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) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (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: Years Ended December 31, (in millions) 2021 2020 2019 Unrealized Net Gain (Loss) (1) $ 62 $ 21 $ (45) (1) Increase in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices of natural gas. Years Ended December 31, (in millions) 2021 2020 2019 Operating Revenues $ 7 $ 5 $ 6
Derivative volumes	The following table presents volumes associated with the energy contracts: December 31, 2021 2020 Power Contracts GWh 2,617 4,143 Gas Contracts BBtu 112,316 111,585
Schedule 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: Net Carrying Value Fair Value Fair Value Hierarchy December 31, (in millions) 2021 2020 2021 2020 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,135 $ 2,064 $ 2,357 $ 2,363

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate	Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% to pre-tax income due to the following: Years Ended December 31, (in millions) 2021 2020 2019 Federal Income Tax Expense at Statutory Rate $ 49 $ 49 $ 46 State Income Tax Expense, Net of Federal Deduction 9 9 9 Federal/State Tax Credits (1) (10) (3) (6) Allowance for Equity Funds Used During Construction (3) (7) (3) Excess Deferred Income Taxes (14) (7) (9) Impact of AMT Sequestration — — (2) Other 1 — (1) Total Income Tax Expense $ 32 $ 41 $ 34 (1) In 2021, TEP realized PTC benefits of $7 million related to Oso Grande being placed in service in May 2021.
Schedule of income tax reconciliation	Income Tax Expense included on the Consolidated Statements of Income consists of the following: Years Ended December 31, (in millions) 2021 2020 2019 Current Income Tax Expense Federal $ (2) $ (2) $ (8) State — 1 — Total Current Income Tax Expense (2) (1) (8) Deferred Income Tax Expense Federal 27 37 41 Federal Investment Tax Credits (1) (1) (4) State 8 6 5 Total Deferred Income Tax Expense 34 42 42 Total Income Tax Expense $ 32 $ 41 $ 34
Schedule of components of deferred income tax assets and liabilities	The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2021 2020 Gross Deferred Income Tax Assets Customer Advances and Contributions in Aid of Construction $ 20 $ 19 Other Postretirement Benefits 15 15 Investment Tax Credit Carryforward 23 19 Income Taxes Payable Through Future Rates 67 74 Other 93 76 Total Gross Deferred Income Tax Assets 218 203 Gross Deferred Income Tax Liabilities Plant, Net (682) (639) PPFAC (23) (6) Plant Abandonments (8) (11) Pensions (18) (17) Income Taxes Recoverable Through Future Rates (4) (7) Other (32) (16) Total Gross Deferred Income Tax Liabilities (767) (696) Deferred Income Taxes, Net $ (549) $ (493)
TEP had the following carryforward amounts	As of December 31, 2021, TEP had the following carryforward amounts: ($ in millions) Amount Expiring Year State Net Operating Loss $ 1 2026 State Credits 9 2023 - 29 Investment Tax Credits 22 2034 - 41 Other Federal Credits 8 2034 - 41
Summary of reconciliation of the beginning and ending balances of unrecognized tax benefits	A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2021 2020 Beginning of Period $ 19 $ 18 Additions Based on Tax Positions Taken in the Current Year — 1 Reductions Based on Positions Taken in Prior Years (18) — End of Period $ 1 $ 19

NATURE OF OPERATIONS AND SUMM_4

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Details) customer in Thousands	12 Months Ended
	Dec. 31, 2021mi²customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of retail customers | customer	438
Area in which subsidiary generates transmits and distributes electricity to retail electric customers (sq miles) | mi²	1,155
Minimum
Regulatory Assets [Line Items]
Contracts, payment terms	10 days
Maximum
Regulatory Assets [Line Items]
Contracts, payment terms	20 days
Cloud Computing | Minimum
Regulatory Assets [Line Items]
Amortization period	3 years
Cloud Computing | Maximum
Regulatory Assets [Line Items]
Amortization period	5 years

NATURE OF OPERATIONS AND SUMM_5

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Restricted Cash) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and Cash Equivalents	$ 9,970	$ 60,960	$ 10,000
Total Cash, Cash Equivalents, and Restricted Cash	33,489	82,003	28,472	$ 152,747
Investments and Other Property
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted Cash	20,000	19,000	16,000
Current Assets—Other
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted Cash	$ 3,000	$ 2,000	$ 2,000

NATURE OF OPERATIONS AND SUMM_6

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average AFUDC Rates	6.88%	6.63%	7.86%

NATURE OF OPERATIONS AND SUMM_7

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Average Annual Depreciation Rates	3.30%	3.15%	3.08%

NATURE OF OPERATIONS AND SUMM_8

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy and Energy Efficiency Programs) (Details) - Renewable Energy Standard	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Renewable energy target percentage by 2025 (in percentage)		11.00%
Forecast
Public Utilities, General Disclosures [Line Items]
Renewable energy target percentage by 2025 (in percentage)	15.00%
Distributed generation requirement target percentage (in percentage)	30.00%

NATURE OF OPERATIONS AND SUMM_9

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy Credits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Renewable Energy Credits [Roll Forward]
Beginning of Period	$ 66	$ 63
Purchased	49	48
Used for Compliance	(46)	(45)
End of Period	$ 69	$ 66

NATURE OF OPERATIONS AND SUM_10

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Taxes) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 463	$ 541
Federal energy credits | Prior to 2013
Regulatory Liabilities [Line Items]
Regulatory liabilities	5	6
Federal energy credits | Since 2013
Regulatory Liabilities [Line Items]
Regulatory liabilities	1	2
Accrued Taxes Other than Income Taxes and Other Liabilities
Other Than Income Taxes Accruals [Line Items]
Deferred deposits	$ 3	$ 7

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%
Capital structure for rate making purposes, common equity (percentage)	53.00%
Capital structure for rate making purposes, long-term debt (percentage)	47.00%

REGULATORY MATTERS (2019 FERC R

REGULATORY MATTERS (2019 FERC Rate Case) (Details) - USD ($) $ in Thousands	Aug. 01, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Wholesale revenue		$ 1,480,000	$ 1,324,000	$ 1,343,000
Regulatory liability		$ 111,356	151,189
Federal Energy Regulatory Commission
Public Utilities, General Disclosures [Line Items]
Percent of transmission costs allocated to retail customers		25.00%
Percent of transmission costs allocated between wholesale and retail customers		75.00%
Abandonment costs		$ 4,000
Abandonment costs, amortization period		10 years
Decrease in alternative revenue		$ 3,000
Federal Energy Regulatory Commission | Transmission Service
Public Utilities, General Disclosures [Line Items]
Wholesale revenue		$ 12,000	4,000	$ 3,000
Federal Energy Regulatory Commission | Transmission Services Rate
Public Utilities, General Disclosures [Line Items]
Approved return on equity (percentage)	10.40%
Requested return on equity (percentage)		9.79%
Federal Energy Regulatory Commission | Transmission Services Rate | Revenue Subject to Refund
Public Utilities, General Disclosures [Line Items]
Regulatory liability		$ 15,000	$ 15,000

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions	Feb. 01, 2022	Sep. 30, 2021	Jun. 30, 2021	Dec. 31, 2025	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Regulatory Liabilities [Roll Forward]
Environmental compliance adjustor, as a percentage of total retail revenue					0.50%
Purchased Power and Fuel Adjustment Clause
Regulatory Liabilities [Roll Forward]
Beginning of Period					$ 23	$ 36
Deferred Fuel and Purchased Power Costs					343	283
PPFAC and Base Power Recoveries					(275)	(296)
End of Period					91	$ 23	$ 36
Tax Expense Adjustor Mechanism
Regulatory Liabilities [Roll Forward]
Customer Refunds					$ 29
Purchased Power and Fuel Adjustment Clause
Public Utilities, General Disclosures [Line Items]
Months approved rate in effect unless modified					12 months
Renewable Energy Standard
Regulatory Liabilities [Roll Forward]
Renewable energy target percentage					11.00%
Approved spending budget		$ 66
Renewable energy actual percentage					26.00%
Renewable Energy Standard | Forecast
Regulatory Liabilities [Roll Forward]
Renewable energy target percentage				15.00%
Distributed generation requirement percent of target percentage (percentage)				30.00%
Energy Efficiency Standards
Regulatory Liabilities [Roll Forward]
Percentage of cumulative annual retail kilowatt savings, actual					23.00%
Approved recovery of spending budget							$ 23
Requested recovery of spending budget			$ 23
Lost Fixed Cost Recovery
Regulatory Liabilities [Roll Forward]
Cap on increase in lost fixed cost recovery rate (percentage)					2.00%
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Period of recovery of uncollected true-up balance, scenario 1	18 months
Period of recovery of uncollected true-up balance, scenario 2	24 months

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Remaining recovery period (years)	1 year
Total Regulatory Assets	$ 384,000	$ 442,000
Less Current Portion	116,442	123,588
Regulatory Assets	267,669	318,474
Pension and Other Postretirement Benefits
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 128,000	166,000
Under Recovered Purchased Energy Costs
Regulatory Assets [Line Items]
Remaining recovery period (years)	2 years
Total Regulatory Assets	$ 91,000	23,000
Early Generation Retirement Costs
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 38,000	43,000
Lost Fixed Cost Recovery
Regulatory Assets [Line Items]
Remaining recovery period (years)	1 year
Total Regulatory Assets	$ 37,000	59,000
Property Tax Deferrals
Regulatory Assets [Line Items]
Remaining recovery period (years)	1 year
Total Regulatory Assets	$ 27,000	26,000
Remaining recovery period (in years)	6 months
Income Taxes Recoverable through Future Rates
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 17,000	27,000
Income Taxes Recoverable through Future Rates | Minimum
Regulatory Assets [Line Items]
Amortization period	5 years
Income Taxes Recoverable through Future Rates | Maximum
Regulatory Assets [Line Items]
Amortization period	10 years
Final Mine Reclamation and Retiree Healthcare Costs
Regulatory Assets [Line Items]
Remaining recovery period (years)	7 years
Total Regulatory Assets	$ 17,000	20,000
Derivatives
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 8,000	55,000
Derivatives | Derivatives
Regulatory Assets [Line Items]
Remaining recovery period (years)	8 years
Springerville Unit 1 Leasehold Improvements
Regulatory Assets [Line Items]
Remaining recovery period (years)	2 years
Total Regulatory Assets	$ 4,000	7,000
Useful life (in years)	10 years
Tax Expense Adjustor Mechanism
Regulatory Assets [Line Items]
Remaining recovery period (years)	1 year
Total Regulatory Assets	$ 3,000	0
Other Regulatory Assets
Regulatory Assets [Line Items]
Total Regulatory Assets	$ 14,000	$ 16,000

REGULATORY MATTERS (Regulator_2

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 463,000	$ 541,000
Less Current Portion	111,356	151,189
Total Non-Current Regulatory Liabilities	$ 352,226	390,164
Remaining recovery period (years)	1 year
Income Taxes Payable through Future Rates
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 268,000	298,000
Net Cost of Removal
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	73,000	125,000
Renewable Energy Standard
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	66,000	63,000
Derivatives
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 19,000	4,000
Derivatives | Derivatives
Regulatory Liabilities [Line Items]
Remaining recovery period (years)	8 years
Transmission Revenue Subject to Refund—FERC
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 15,000	15,000
Remaining recovery period (years)	1 year
Demand Side Management
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 12,000	6,000
Remaining recovery period (years)	1 year
Transmission Cost Adjustor
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 9,000	0
Remaining recovery period (years)	1 year
Tax Expense Adjustor Mechanism
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 0	29,000
Remaining recovery period (years)	1 year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Total Regulatory Liabilities	$ 1,000	$ 1,000

UTILITY PLANT AND JOINTLY-OWN_3

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Utility Plant in Service by Major Class) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)MWhgenerating_units	Dec. 31, 2019USD ($)	May 31, 2021MWh
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 7,797,935	$ 7,073,292
Plant acquisition adjustments		(206,000)	(202,000)
Amount reclassified	$ 33,000
Computer software, accumulated amortization		169,000	199,000
Amortization of computer software costs		$ 33,000	$ 29,000	$ 26,000
Future estimated amortization costs for intangible assets
Average Annual Depreciation Rates		3.30%	3.15%	3.08%
Springerville Common Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of interest purchased			32.20%
RICE Units
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service			$ 187,000
Number of units in service | generating_units			10
Generating capacity (MW) | MWh			188
Oso Grande
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 444,000
Generating capacity placed in service, in MWs | MWh					250
Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Renewable nominal generation capacity, including PPAs (MWs) | MWh					700
Smaller Application Software | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Amortization period		3 years
Smaller Application Software | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Amortization period		5 years
Large Enterprise Software
Public Utility, Property, Plant and Equipment [Line Items]
Amortization period		10 years
Generation Plant
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 3,753,000	$ 3,279,000
Future estimated amortization costs for intangible assets
Average Annual Depreciation Rates		3.11%
Average Remaining Life in Years		18 years
Distribution Plant
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 2,024,000	1,906,000
Future estimated amortization costs for intangible assets
Average Annual Depreciation Rates		1.93%
Average Remaining Life in Years		33 years
Transmission Plant
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 1,210,000	1,090,000
Future estimated amortization costs for intangible assets
Average Annual Depreciation Rates		1.69%
Average Remaining Life in Years		35 years
General Plant
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 540,000	503,000
Future estimated amortization costs for intangible assets
Average Annual Depreciation Rates		6.01%
Average Remaining Life in Years		7 years
Intangible Plant, Software Costs and Other
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 268,000	291,000
Plant acquisition adjustments		(4,000)	0
Future estimated amortization costs for intangible assets
2022		26,000
2023		19,000
2024		12,000
2025		7,000
2026		$ 4,000
Average Remaining Life in Years		3 years
Plant Held for Future Use
Public Utility, Property, Plant and Equipment [Line Items]
Plant in Service		$ 3,000	$ 4,000

UTILITY PLANT AND JOINTLY-OWN_4

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Narrative) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2020USD ($)MWhgenerating_units	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)MWhgenerating_units	May 31, 2021MWh
Public Utility, Property, Plant and Equipment [Line Items]
Plant in service	$ 7,073,292	$ 7,797,935	$ 7,073,292
Springerville Common Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of interest purchased			32.20%
Purchased interest	$ 68,000
Springerville Common Facilities | Tri-State
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of interest purchased	14.00%
Purchased interest	$ 30,000
Springerville Common Facilities | Tri-State | Option to Buy or Continue to Make Payments
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of interest purchased		14.00%
Purchased interest		$ 30,000
Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Renewable nominal generation capacity, including PPAs (MWs) | MWh				700
Oso Grande
Public Utility, Property, Plant and Equipment [Line Items]
Generating capacity placed in service, in MWs | MWh				250
Plant in service		$ 444,000
RICE Units
Public Utility, Property, Plant and Equipment [Line Items]
Plant in service	$ 187,000		$ 187,000
Number of units in service | generating_units	10		10
Generating capacity (MW) | MWh	188		188

UTILITY PLANT AND JOINTLY-OWN_5

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Jointly-Owned Facilities) (Details) $ in Millions	Dec. 31, 2021USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Net Book Value	$ 935
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	1,883
Construction Work in Progress	27
Accumulated Depreciation	$ (975)
San Juan Unit 1
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	50.00%
Net Book Value	$ 17
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	285
Construction Work in Progress	1
Accumulated Depreciation	$ (269)
Four Corners Units 4 and 5
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	7.00%
Net Book Value	$ 111
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	188
Construction Work in Progress	4
Accumulated Depreciation	$ (81)
Luna
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	33.30%
Net Book Value	$ 57
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	59
Construction Work in Progress	1
Accumulated Depreciation	$ (3)
Gila River Unit 3
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	75.00%
Net Book Value	$ 141
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	206
Construction Work in Progress	0
Accumulated Depreciation	$ (65)
Gila River Common Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	43.80%
Net Book Value	$ 50
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	75
Construction Work in Progress	1
Accumulated Depreciation	$ (26)
Springerville Coal Handling Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	83.00%
Net Book Value	$ 114
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	209
Construction Work in Progress	0
Accumulated Depreciation	$ (95)
Springerville Common Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Percentage (in percentage)	86.00%
Net Book Value	$ 192
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	399
Construction Work in Progress	0
Accumulated Depreciation	(207)
Transmission Facilities
Public Utility, Property, Plant and Equipment [Line Items]
Net Book Value	253
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	462
Construction Work in Progress	20
Accumulated Depreciation	$ (229)

UTILITY PLANT AND JOINTLY-OWN_6

UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of Period	$ 96	$ 107
Liabilities Incurred	14	0
Liabilities Settled	(2)	(5)
Regulatory Deferral/Accretion Expense	4	4
Revisions to the Present Value of Estimated Cash Flows	27	(10)
End of Period	$ 139	$ 96

REVENUE (Details)

REVENUE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 1,480,000	$ 1,324,000	$ 1,343,000
Alternative Revenues	12,000	48,000	35,000
Other	101,000	53,000	40,000
Total Operating Revenues	1,592,586	1,424,741	1,418,338
Retail
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	1,088,000	1,039,000	972,000
Wholesale
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	278,000	190,000	247,000
Other Services
Disaggregation of Revenue [Line Items]
Revenues from Contracts with Customers	$ 114,000	$ 95,000	$ 124,000
Lost Fixed Cost Recovery Mechanism
Disaggregation of Revenue [Line Items]
Cap on increase in lost fixed cost recovery rate (percentage)	2.00%

ACCOUNTS RECEIVABLE (Details)

ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable
Retail, Allowance for Credit Losses	$ (10,044)	$ (13,260)
Accounts Receivable	192,579	173,412
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning of Period	(13,260)	(6,000)
Credit Loss Expense	0	(10,000)
Write-offs	3,000	3,000
End of Period	(10,044)	(13,260)
Retail
Accounts Receivable
Accounts receivable, gross	78,000	90,000
Retail, Allowance for Credit Losses	(10,000)	(13,000)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning of Period	(13,000)
End of Period	(10,000)	(13,000)
Retail | Retail, Unbilled
Accounts Receivable
Accounts receivable, gross	44,000	41,000
Wholesale
Accounts Receivable
Accounts receivable, gross	47,000	33,000
Wholesale | Derivatives
Accounts Receivable
Accounts receivable, gross	16,000	7,000
Trade Accounts | Due from Affiliates
Accounts Receivable
Accounts receivable, gross	17,000	9,000
Other
Accounts Receivable
Accounts receivable, gross	$ 17,000	$ 13,000

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)facility	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties	$ 17,000	$ 9,000
Payables to Related Parties	2,000	5,000
Operating Revenues	1,592,586	1,424,741	$ 1,418,338
Supplemental Workforce, SES	605,606	515,030	505,796
Transmission Revenues, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Transmission and Wholesale Revenue	11,000	9,000	7,000
Wholesale Revenues, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Transmission and Wholesale Revenue	25,000	1,000	1,000
Control Area Services, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Control Area Services and Corporate Services	6,000	4,000	4,000
Common Costs, UNS Energy Affiliates
Related Party Transaction, Due from (to) Related Parties [Abstract]
Common Costs, UNS Energy Affiliates	21,000	19,000	19,000
Supplemental Workforce, SES
Related Party Transaction, Due from (to) Related Parties [Abstract]
Supplemental Workforce, SES	0	14,000	15,000
Corporate Services, UNS Energy
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services	$ 7,000	5,000	6,000
Intercompany allocation parent to subsidiary (in percentage)	85.00%
Management fee	$ 6,000	6,000	6,000
Corporate Services, UNS Energy Affiliates
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services	3,000	4,000	4,000
Capacity Charges, UNS Gas
Related Party Transaction, Due from (to) Related Parties [Abstract]
Capacity Charges, UNS Gas	$ 0	0	1,000
Number of generation facilities | facility	1
Corporate Services, Fortis Affiliates
Related Party Transaction, Due from (to) Related Parties [Abstract]
Corporate Services	$ 0	1,000	0
Wholesale Revenues, UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Operating Revenues	1,000	0	$ 0
UNS Electric
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties	8,000	6,000
UNS Energy
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties	7,000	2,000
Payables to Related Parties	1,000	1,000
UNS Gas
Related Party Transaction, Due from (to) Related Parties [Abstract]
Receivables from Related Parties	2,000	1,000
Payables to Related Parties	1,000	0
SES
Related Party Transaction, Due from (to) Related Parties [Abstract]
Payables to Related Parties	$ 0	$ 4,000

DEBT AND CREDIT AGREEMENTS (Lon

DEBT AND CREDIT AGREEMENTS (Long-term Debt) (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Aug. 31, 2021	May 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term debt	$ 2,159,000			$ 2,084,000
Less Unamortized Discount and Debt Issuance Costs	24,000			20,000
Current Maturities of Long-Term Debt	0			250,000
Total Long-Term Debt, Net	$ 2,134,534			1,814,059
2011 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	5.15%	5.15%
Long-term debt	$ 0			250,000
2012 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	3.85%
Long-term debt	$ 150,000			150,000
2014 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	5.00%
Long-term debt	$ 150,000			150,000
2015 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	3.05%
Long-term debt	$ 300,000			300,000
2018 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.85%
Long-term debt	$ 300,000			300,000
2020 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.00%
Long-term debt	$ 350,000			350,000
2020 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	1.50%
Long-term debt	$ 300,000			300,000
2021 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	3.25%		3.25%
Long-term debt	$ 325,000			0
2012 Pima A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.50%
Long-term debt	$ 16,000			16,000
2013 Pima A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.00%
Long-term debt	$ 91,000			91,000
2012 Apache A | Unsecured Debt
Debt Instrument [Line Items]
Interest Rate	4.50%
Long-term debt	$ 177,000			$ 177,000

DEBT AND CREDIT AGREEMENTS (Iss

DEBT AND CREDIT AGREEMENTS (Issuances and Redemptions) (Details) - USD ($)	1 Months Ended
	Aug. 31, 2021	May 31, 2021	Sep. 30, 2020	Apr. 30, 2020	Dec. 31, 2021	Aug. 31, 2020
Line of Credit | 2019 Credit Agreement
Debt Instrument [Line Items]
Redemption of debt				$ 225,000,000
Debt extinguishment				225,000,000
2021 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest rate		3.25%			3.25%
Debt instrument, face amount		$ 325,000,000
Proceeds from issuance of debt		$ 325,000,000
Fixed Rate Tax-exempt Bonds Maturing in October 2020
Debt Instrument [Line Items]
Redemption of debt			$ 80,000,000
Debt extinguishment			80,000,000
Fixed rate tax-exempt bonds callable for redemption at par on or after October 2020
Debt Instrument [Line Items]
Redemption of debt			100,000,000
Debt extinguishment			$ 100,000,000
2020 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest rate					1.50%
Debt instrument, face amount						$ 300,000,000
2020 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Interest rate					4.00%
Debt instrument, face amount				$ 350,000,000
2011 Senior Notes | Unsecured Debt
Debt Instrument [Line Items]
Redemption of debt	$ 250,000,000
Interest rate	5.15%				5.15%
Debt extinguishment	$ 250,000,000

DEBT AND CREDIT AGREEMENTS (Mat

DEBT AND CREDIT AGREEMENTS (Maturities of Long-term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Long-Term Debt Maturities
2022	$ 0
2023	150
2024	0
2025	300
2026	0
Thereafter	1,709
Total Long-Term Debt	2,159	$ 2,084
Unamortized debt issuance expense	16
Debt discount	$ 8

DEBT AND CREDIT AGREEMENTS (Cre

DEBT AND CREDIT AGREEMENTS (Credit Agreements) (Details)	1 Months Ended	12 Months Ended
	Oct. 31, 2021USD ($)extension_option	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Feb. 10, 2022USD ($)	Jan. 31, 2020USD ($)
2021 Agreement | Sub-Limit LOC
Short-term Debt [Line Items]
Number of extensions | extension_option	2
Extension period	1 year
2021 Agreement | Line of Credit
Short-term Debt [Line Items]
Available		$ 225,000,000
Borrowed		25,000,000
2021 Agreement | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Available				$ 220,000,000
2021 Agreement | Line of Credit | Revolver
Short-term Debt [Line Items]
Line of credit facility borrowing capacity		$ 250,000,000
Weighted Average Interest Rate (in percentage)		2.53%
2021 Agreement | Line of Credit | Revolver | LIBOR
Short-term Debt [Line Items]
Basis spread on variable rate (in percentage)		1.00%
2021 Agreement | Line of Credit | Revolver | Base Rate
Short-term Debt [Line Items]
Basis spread on variable rate (in percentage)		0.00%
2021 Agreement | Line of Credit | Sub-Limit LOC
Short-term Debt [Line Items]
Line of credit facility borrowing capacity		$ 50,000,000
Borrowed	$ 10,000,000
Weighted Average Interest Rate (in percentage)	1.00%
2021 Agreement | Line of Credit | Sub-Limit Swingline
Short-term Debt [Line Items]
Line of credit facility borrowing capacity		$ 15,000,000
2015 Agreement | Line of Credit
Short-term Debt [Line Items]
Available			$ 238,000,000
Borrowed			12,000,000		$ 12,000,000
2015 Agreement | Line of Credit | Revolver
Short-term Debt [Line Items]
Line of credit facility borrowing capacity			$ 250,000,000
Weighted Average Interest Rate (in percentage)			0.00%
2015 Agreement | Line of Credit | Revolver | LIBOR
Short-term Debt [Line Items]
Basis spread on variable rate (in percentage)			1.00%
2015 Agreement | Line of Credit | Revolver | Base Rate
Short-term Debt [Line Items]
Basis spread on variable rate (in percentage)			0.00%
2015 Agreement | Line of Credit | Sub-Limit LOC
Short-term Debt [Line Items]
Line of credit facility borrowing capacity			$ 50,000,000
Weighted Average Interest Rate (in percentage)					1.00%

LEASES (Assets and Liabilities)

LEASES (Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Lease Assets
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other	Other
Regulatory and Other Assets, Other	$ 7	$ 8
Lease Liabilities
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other	Other
Current Liabilities, Other	$ 1	$ 1
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other	Other
Regulatory and Other Liabilities, Other	$ 6	$ 7

LEASES (Narrative) (Details)

LEASES (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)option	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Renewal term	10 years
Operating lease cost	$ 1	$ 1	$ 1
Number of renewal options | option	1
Operating lease income	$ 1	$ 1	$ 1
Lessor, Operating Lease, Payments, Fiscal Year Maturity
2022	1
2023	1
2024	1
2025	1
2026	1
Thereafter	$ 2
Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Renewal term	3 years
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Minimum | Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Remaining lease term	2 years
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	20 years
Maximum | Office Facility and Utility Property
Lessee, Lease, Description [Line Items]
Remaining lease term	21 years

LEASES (Lease Cost) (Details)

LEASES (Lease Cost) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finance
Amortization of Leased Assets		$ 0	$ 10	$ 13
Interest on Lease Liabilities		0	2	13
Operating		1	1	1
Variable		4	2	16
Short Term		2	1	1
Total Lease Cost		$ 7	16	44
Battery Storage
Finance
PPA, renewable term	20 years
Springerville Common Facilities
Finance
Amortization of Leased Assets			2
Deferred interest expense			$ 1
Gila River Unit 2
Finance
Amortization of Leased Assets				6
Interest on Lease Liabilities				$ 12

LEASES (Lease Liability) (Detai

LEASES (Lease Liability) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
2022	$ 1
2022	1
2023	1
2024	1
2025	1
Thereafter	3
Total Lease Payments	8
Less Imputed Interest	$ 1
Operating Lease, Liability, Statement of Financial Position [Extensible List]	Other Liabilities
Total Lease Obligations	$ 7
Less Current Portion	1	$ 1
Total Non-Current Lease Obligations	$ 6	$ 7

LEASES (Term and Rate) (Details

LEASES (Term and Rate) (Details)	Dec. 31, 2021	Dec. 31, 2020
Weighted-Average Remaining Lease Term (years)
Weighted-Average Remaining Lease Term (years), Operating Leases	11 years	11 years
Weighted-Average Discount Rate
Weighted-Average Discount Rate, Operating Leases	3.90%	3.90%

LEASES (Cash Flows) (Details)

LEASES (Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Cash Flows used for Finance Leases	$ 0	$ 1,000	$ 13,000
Operating Cash Flows used for Operating Leases	1,000	1,000	1,000
Financing Cash Flows used for Finance Leases	0	17,087	10,890
Investing Cash Flows used for Finance Leases	$ 0	$ 68,000	$ 164,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)MW	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jul. 31, 2021MW
Purchase Obligation, Fiscal Year Maturity [Abstract]
2022	$ 248,000
2023	228,000
2024	137,000
2025	125,000
2026	114,000
Thereafter	1,018,000
Total	1,870,000
Capital expenditures	$ 499,405	$ 839,958	$ 607,593
UNS Electric
Purchase Obligation, Fiscal Year Maturity [Abstract]
Power delivery agreement, in MW | MW				150
Monthly capacity charge as percent of company's charge				50.00%
Capacity, Power, and Ancillary Services | Maximum
Purchase Obligation, Fiscal Year Maturity [Abstract]
Power purchase agreement, in MW | MW	300
Fuel, Including Transportation
Purchase Obligation, Fiscal Year Maturity [Abstract]
2022	$ 83,000
2023	74,000
2024	36,000
2025	28,000
2026	25,000
Thereafter	144,000
Total	390,000
Purchased Power
Purchase Obligation, Fiscal Year Maturity [Abstract]
2022	47,000
2023	47,000
2024	0
2025	0
2026	0
Thereafter	0
Total	94,000
Transmission
Purchase Obligation, Fiscal Year Maturity [Abstract]
2022	31,000
2023	20,000
2024	15,000
2025	13,000
2026	5,000
Thereafter	4,000
Total	88,000
Renewable Power Purchase Agreements
Purchase Obligation, Fiscal Year Maturity [Abstract]
2022	80,000
2023	80,000
2024	79,000
2025	79,000
2026	79,000
Thereafter	847,000
Total	$ 1,244,000
Percentage of purchase power obligations (in percentage)	100.00%
RES Performance-Based Incentives
Purchase Obligation, Fiscal Year Maturity [Abstract]
2022	$ 7,000
2023	7,000
2024	7,000
2025	5,000
2026	5,000
Thereafter	23,000
Total	$ 54,000

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - San Juan and Four Corners - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Commitments And Contingencies [Line Items]
Reclamation costs	$ 44
Other Liabilities
Commitments And Contingencies [Line Items]
Reclamation costs accrued	$ 40	$ 40

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee	Dec. 31, 2021USD ($)
Guarantor Obligations [Line Items]
Current carrying value	$ 0
Navajo, San Juan, Luna
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	0
Four Corner
Guarantor Obligations [Line Items]
Maximum exposure, undiscounted	$ 250,000,000

EMPLOYEE BENEFITS PLANS (Additi

EMPLOYEE BENEFITS PLANS (Additional Information) (Details)	12 Months Ended
	Dec. 31, 2021USD ($)plan	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Number of defined benefit pension plans | plan	3
Number of qualified defined benefit pension plans | plan	2
Percentage of service cost that was capitalized (in percentage)	22.00%	22.00%	21.00%
Investment return model best-estimate range (in years)	20 years
Matching 401(k) contributions made	$ 7,000,000	$ 6,000,000	$ 6,000,000
Level 3
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	30,000,000	27,000,000	28,000,000
Other Postretirement Benefits
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employer Contribution to VEBA Trust	3,000,000	1,000,000	1,000,000
Fair value measurements of plan assets	28,000,000	24,000,000	21,000,000
Other Postretirement Benefits | Level 1 and Level 2
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	28,000,000	24,000,000
Other Postretirement Benefits | Level 3
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	0
Pension Benefits
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Accumulated benefit obligation	538,000,000
Fair value measurements of plan assets	538,000,000	514,000,000	$ 446,000,000
Pension Benefits | Level 3
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	30,000,000	27,000,000
Transfers	$ 0
Minimum
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used (in percentage)	25.00%
Maximum
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Percentile of investment return model range used (in percentage)	75.00%
Fixed Income Securities | Other Postretirement Benefits | Level 1 and Level 2
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 10,000,000	9,000,000
Equities | Other Postretirement Benefits | Level 1 and Level 2
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Fair value measurements of plan assets	$ 18,000,000	$ 15,000,000

EMPLOYEE BENEFITS PLANS (Pensio

EMPLOYEE BENEFITS PLANS (Pension and Other Postretirement Benefit Amounts included in Consolidated Balance Sheet ) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	$ 384	$ 442
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	126	150
Accrued Employee Expenses	(1)	(1)
Pension and Other Postretirement Benefits	(61)	(91)
Accumulated Other Comprehensive Loss, SERP	13	14
Net Amount Recognized	77	72
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Regulatory Assets	2	16
Accrued Employee Expenses	(3)	(3)
Pension and Other Postretirement Benefits	(59)	(72)
Accumulated Other Comprehensive Loss, SERP	0	0
Net Amount Recognized	$ (60)	$ (59)

EMPLOYEE BENEFITS PLANS (Change

EMPLOYEE BENEFITS PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Change in Benefit Obligation
Beginning of Period	$ 606	$ 525
Actuarial (Gain) Loss	(6)	76
Interest Cost	14	16	$ 18
Service Cost	20	16	13
Benefits Paid	(34)	(27)
End of Period	600	606	525
Change in Fair Value of Plan Assets
Beginning of Period	514	446
Actual Return on Plan Assets	43	78
Benefits Paid	(32)	(26)
Employer Contributions	13	16
End of Period	538	514	446
Funded Status at End of Period	(62)	(92)
Expected future contribution	11
Other Postretirement Benefits
Change in Benefit Obligation
Beginning of Period	99	79
Actuarial (Gain) Loss	(12)	18
Interest Cost	2	3	3
Service Cost	6	4	4
Benefits Paid	(5)	(5)
End of Period	90	99	79
Change in Fair Value of Plan Assets
Beginning of Period	24	21
Actual Return on Plan Assets	3	3
Benefits Paid	(2)	(5)
Employer Contributions	3	5
End of Period	28	24	$ 21
Funded Status at End of Period	(62)	$ (75)
Expected future contribution	$ 1

EMPLOYEE BENEFITS PLANS (Compon

EMPLOYEE BENEFITS PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	$ 139	$ 164
Prior Service Cost (Benefit)	0	1
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Net Loss	4	18
Prior Service Cost (Benefit)	$ (2)	$ (2)

EMPLOYEE BENEFITS PLANS (Inform

EMPLOYEE BENEFITS PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Details) - Pension Benefits - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]
Accumulated Benefit Obligation	$ 26	$ 545
Fair Value of Plan Assets	$ 0	$ 514

EMPLOYEE BENEFITS PLANS (Comp_2

EMPLOYEE BENEFITS PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 20	$ 16	$ 13
Non-Service Cost
Interest Cost	14	16	18
Expected Return on Plan Assets	(34)	(30)	(26)
Amortization of Net (Gain) Loss	9	8	8
Net Periodic Benefit Cost	9	10	13
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost	6	4	4
Non-Service Cost
Interest Cost	2	3	3
Expected Return on Plan Assets	(2)	(2)	(2)
Amortization of Net (Gain) Loss	1	0	0
Net Periodic Benefit Cost	$ 7	$ 5	$ 5

EMPLOYEE BENEFITS PLANS (Chan_2

EMPLOYEE BENEFITS PLANS (Changes in Regulatory Assets and Accumulated Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits | Regulatory Asset
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	$ (16)	$ 23	$ 16
Amortization of Net Loss	(8)	(8)	(8)
Prior Service (Credit) Cost	0	0	0
Total Recognized (Gain) Loss	(24)	15	8
Pension Benefits | AOCI
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	0	5	4
Amortization of Net Loss	(1)	(1)	(1)
Prior Service (Credit) Cost	0	0	1
Total Recognized (Gain) Loss	(1)	4	4
Other Postretirement Benefits | Regulatory Asset
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current Year Actuarial (Gain) Loss	(13)	17	1
Amortization of Net Loss	(1)	0	0
Prior Service (Credit) Cost	0	0	0
Total Recognized (Gain) Loss	$ (14)	$ 17	$ 1

EMPLOYEE BENEFITS PLANS (Weight

EMPLOYEE BENEFITS PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Details)	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	3.20%	2.90%
Rate of Compensation Increase (in percentage)	2.80%	2.80%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	3.00%	2.60%

EMPLOYEE BENEFITS PLANS (Weig_2

EMPLOYEE BENEFITS PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Rate of Compensation Increase (in percentage)	2.80%	2.80%	2.80%
Expected Return on Plan Assets (in percentage)	6.80%	6.80%	7.00%
Pension Benefits | Service cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	3.30%	3.80%	4.70%
Pension Benefits | Interest Cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	2.30%	3.10%	4.20%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected Return on Plan Assets (in percentage)	7.00%	7.00%	7.00%
Other Postretirement Benefits | Service cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	2.90%	3.50%	4.50%
Other Postretirement Benefits | Interest Cost
Defined Benefit Plan Disclosure [Line Items]
Discount Rate (in percentage)	1.90%	2.90%	4.00%

EMPLOYEE BENEFITS PLANS (Assume

EMPLOYEE BENEFITS PLANS (Assumed Health Care Cost Trend Rates) (Details)	Dec. 31, 2021	Dec. 31, 2020
Retirement Benefits [Abstract]
Next Year (Pre-65) (in percentage)	6.50%	6.10%
Next Year (Post-65) (in percentage)	5.50%	7.10%
Ultimate Rate Assumed (Pre-65 and Post-65) (in percentage)	4.50%	4.50%

EMPLOYEE BENEFITS PLANS (Percen

EMPLOYEE BENEFITS PLANS (Percentage of Pension Plan Assets By Asset Category) (Details)	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	100.00%	100.00%
Pension Benefits | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	54.00%	47.00%
Pension Benefits | Fixed Income Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	40.00%	45.00%
Pension Benefits | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	5.00%	7.00%
Pension Benefits | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	1.00%	1.00%
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	100.00%	100.00%
Other Postretirement Benefits | Equity Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	63.00%	63.00%
Other Postretirement Benefits | Fixed Income Securities
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	35.00%	35.00%
Other Postretirement Benefits | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	0.00%	0.00%
Other Postretirement Benefits | Other
Pension And Other Employee Benefit Plans [Line Items]
Pension plan assets allocation (in percentage)	2.00%	2.00%

EMPLOYEE BENEFITS PLANS (Fair V

EMPLOYEE BENEFITS PLANS (Fair Value Measurements of Plan Assets By Level) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Level 3
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 30	$ 27	$ 28
Level 3 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	26	23	23
Level 3 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	4	4	5
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	538	514	$ 446
Pension Benefits | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	2
Pension Benefits | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	77	65
Pension Benefits | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	28	25
Pension Benefits | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	105	95
Pension Benefits | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	83	59
Pension Benefits | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	213	231
Pension Benefits | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	26	35
Pension Benefits | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	4	4
Pension Benefits | Level 1
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	2	0
Pension Benefits | Level 1 | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	2
Pension Benefits | Level 1 | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 1 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 2
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	506	487
Pension Benefits | Level 2 | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0
Pension Benefits | Level 2 | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	77	65
Pension Benefits | Level 2 | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	28	25
Pension Benefits | Level 2 | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	105	95
Pension Benefits | Level 2 | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	83	59
Pension Benefits | Level 2 | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	213	231
Pension Benefits | Level 2 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	12
Pension Benefits | Level 2 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	30	27
Pension Benefits | Level 3 | Cash Equivalents
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0
Pension Benefits | Level 3 | United States Large Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | United States Small Cap
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Non-United States
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Global
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Fixed Income
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	0	0
Pension Benefits | Level 3 | Real Estate
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	26	23
Pension Benefits | Level 3 | Private Equity
Pension And Other Employee Benefit Plans [Line Items]
Fair value measurements of plan assets	$ 4	$ 4

EMPLOYEE BENEFITS PLANS (Reconc

EMPLOYEE BENEFITS PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning of Period	$ 27	$ 28
Actual Return on Plan Assets:
Assets Held at Reporting Date	5	0
Purchases, Sales, and Settlements	(2)	(1)
End of Period	30	27
Private Equity
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning of Period	4	5
Actual Return on Plan Assets:
Assets Held at Reporting Date	2	0
Purchases, Sales, and Settlements	(2)	(1)
End of Period	4	4
Real Estate
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Beginning of Period	23	23
Actual Return on Plan Assets:
Assets Held at Reporting Date	3	0
Purchases, Sales, and Settlements	0	0
End of Period	$ 26	$ 23

EMPLOYEE BENEFITS PLANS (Target

EMPLOYEE BENEFITS PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Details)	Dec. 31, 2021
Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	100.00%
Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	100.00%
Cash/Treasury Bills | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Cash/Treasury Bills | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	2.00%
United States Large Cap | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	13.00%
United States Large Cap | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	39.00%
United States Small Cap | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	5.00%
United States Small Cap | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	5.00%
Non-United States Developed | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Non-United States Developed | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	7.00%
Non-United States Emerging | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Non-United States Emerging | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	9.00%
Global Equity | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	32.00%
Global Equity | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Global Infrastructure | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	3.00%
Global Infrastructure | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Fixed Income Securities | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	40.00%
Fixed Income Securities | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	38.00%
Real Estate | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	6.00%
Real Estate | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%
Private Equity | Pension Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	1.00%
Private Equity | Other Postretirement Benefits
Pension And Other Employee Benefit Plans [Line Items]
Target allocation percentage of plan assets (in percentage)	0.00%

EMPLOYEE BENEFITS PLANS (Future

EMPLOYEE BENEFITS PLANS (Future Benefit Payments) (Details) $ in Millions	Dec. 31, 2021USD ($)
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2022	$ 28
2023	29
2024	29
2025	29
2026	30
2027-2031	158
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2022	5
2023	5
2024	5
2025	6
2026	5
2027-2031	$ 26

SHARE-BASED COMPENSATION (Detai

SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
2020 FORTIS RESTRICTED STOCK UNIT PLAN
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, valuation, share equivalent, number (in shares)	1
Allocated share of probable payout	$ 2	$ 1
Allocated share-based compensation expense	$ 0	$ 1
2020 FORTIS RESTRICTED STOCK UNIT PLAN | RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options awarded during the period (in shares)	20,794	15,751
2015 Share Unit Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, valuation, share equivalent, number (in shares)	1
Allocated share of probable payout	$ 9	$ 10
Allocated share-based compensation expense	$ 4	$ 3	$ 4
2015 Share Unit Plan | RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options awarded during the period (in shares)	2,401	1,918	33,489
2015 Share Unit Plan | PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options awarded during the period (in shares)	44,931	35,328	66,978

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION (Cash Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Interest Paid, Net of Amounts Capitalized	$ 76	$ 76	$ 80
Income Tax Refunds	$ 0	$ (14)	$ (14)

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Accrued Capital Expenditures	$ 38	$ 26	$ 40
Asset Retirement Obligations Increase (Decrease)	34	(12)	26
Renewable Energy Credits	3	3	3
Operating Leases	0	1	8
Finance Leases	0	0	67
Net Cost of Removal Increase (Decrease)	$ (41)	$ (34)	$ (10)

FAIR VALUE MEASUREMENTS AND D_3

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Assets
Restricted Cash	$ 23,000,000	$ 21,000,000
Energy Derivative Contract, Regulatory Recovery	30,000,000	14,000,000
Energy Derivative Contract, No Regulatory Recovery	4,000,000	3,000,000
Total Assets	57,000,000	38,000,000
Liabilities
Energy Derivative Contracts, Regulatory Recovery	(20,000,000)	(66,000,000)
Total Liabilities	(20,000,000)	(66,000,000)
Total Assets (Liabilities), Net	37,000,000	(28,000,000)
Level 1
Assets
Restricted Cash	23,000,000	21,000,000
Energy Derivative Contract, Regulatory Recovery	0	0
Energy Derivative Contract, No Regulatory Recovery	0	0
Total Assets	23,000,000	21,000,000
Liabilities
Energy Derivative Contracts, Regulatory Recovery	0	0
Total Liabilities	0	0
Total Assets (Liabilities), Net	23,000,000	21,000,000
Level 2
Assets
Restricted Cash	0	0
Energy Derivative Contract, Regulatory Recovery	30,000,000	14,000,000
Energy Derivative Contract, No Regulatory Recovery	4,000,000	3,000,000
Total Assets	34,000,000	17,000,000
Liabilities
Energy Derivative Contracts, Regulatory Recovery	(20,000,000)	(66,000,000)
Total Liabilities	(20,000,000)	(66,000,000)
Total Assets (Liabilities), Net	14,000,000	$ (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 - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Asset [Abstract]
Derivative Asset, Gross Amount Recognized in the Balance Sheets	$ 34	$ 17
Derivative Asset, Counterparty Netting	14	14
Derivative Asset, Cash Collateral Received/Posted	0	0
Derivative Asset, Net Amount	20	3
Derivative Liability [Abstract]
Derivative Liability, Gross Amount Recognized in the Balance Sheets	(20)	(66)
Derivative Liability, Counterparty Netting	(14)	(14)
Derivative Liability, Cash Collateral Received/Posted	0	(7)
Derivative Liability, Net Amount	$ (6)	$ (45)

FAIR VALUE MEASUREMENTS AND D_5

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Percent of gains shared with ratepayers	10.00%
Operating Revenues	$ 1,592,586	$ 1,424,741	$ 1,418,338
Energy Derivative | Not Designated
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Loss	62,000	21,000	(45,000)
Operating Revenues	$ 7,000	$ 5,000	$ 6,000

FAIR VALUE MEASUREMENTS AND D_6

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Billions	12 Months Ended
	Dec. 31, 2021GWhBTU	Dec. 31, 2020BTUGWh
Power Contracts GWh
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, nonmonetary notional amount | GWh	2,617	4,143
Gas Contracts BBtu
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, nonmonetary notional amount | BTU	112,316	111,585

FAIR VALUE MEASUREMENTS AND D_7

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
FV of derivative instruments in net liability positions with credit risk related features, including normal purchase normal sale	$ 26	$ 60
Collateral posted	0
Additional collateral to post if credit-risk contingent features are triggered	26
Outstanding Net Payable Balances for Settled Positions
Derivative [Line Items]
Additional collateral to post if credit-risk contingent features are triggered	$ 21

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	Dec. 31, 2021	Dec. 31, 2020
Net Carrying Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,135	$ 2,064
Fair Value
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Long-Term Debt, including Current Maturities	$ 2,357	$ 2,363

INCOME TAXES (Reconciliation of

INCOME TAXES (Reconciliation of Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal Income Tax Expense at Statutory Rate	$ 49,000	$ 49,000	$ 46,000
State Income Tax Expense, Net of Federal Deduction	9,000	9,000	9,000
Federal/State Tax Credits	(10,000)	(3,000)	(6,000)
Allowance for Equity Funds Used During Construction	(3,000)	(7,000)	(3,000)
Excess Deferred Income Taxes	(14,000)	(7,000)	(9,000)
Impact of AMT Sequestration	0	0	(2,000)
Other	1,000	0	(1,000)
Total Income Tax Expense	32,476	$ 41,452	$ 34,053
Tax credit benefits	$ 7,000

INCOME TAXES (Income Tax Expens

INCOME TAXES (Income Tax Expense Included in Income Statements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current Income Tax Expense
Federal	$ (2,000)	$ (2,000)	$ (8,000)
State	0	1,000	0
Total Current Income Tax Expense	(2,000)	(1,000)	(8,000)
Deferred Income Tax Expense
Federal	27,000	37,000	41,000
Federal Investment Tax Credits	(1,000)	(1,000)	(4,000)
State	8,000	6,000	5,000
Total Deferred Income Tax Expense	34,000	42,000	42,000
Total Income Tax Expense	$ 32,476	$ 41,452	$ 34,053

INCOME TAXES (Additional Inform

INCOME TAXES (Additional Information) (Details) - USD ($)	Feb. 02, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Loss Carryforwards [Line Items]
Excess deferred income taxes		$ 14,000,000	$ 7,000,000	$ 9,000,000
Valuation allowance		0	0
Unrecognized tax benefits, if recognized, decrease in income tax expense (benefit)		1,000,000	1,000,000
Interest expense related to uncertain tax position		0	0
Interest payable		0	0
Penalties accrued		0	0
Decrease in uncertain tax position obligations	$ 18,000,000	18,000,000	0
Income taxes paid, net		0	(14,000,000)	(14,000,000)
UNS Energy | Federal
Operating Loss Carryforwards [Line Items]
Income taxes paid, net		$ 7,000,000
Proceeds from income tax refunds			10,000,000	$ 14,000,000
Current Assets—Other
Operating Loss Carryforwards [Line Items]
AMT credit			$ 14,000,000

INCOME TAXES (The Significant C

INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Gross Deferred Income Tax Assets
Customer Advances and Contributions in Aid of Construction	$ 20	$ 19
Other Postretirement Benefits	15	15
Investment Tax Credit Carryforward	23	19
Income Taxes Payable Through Future Rates	67	74
Other	93	76
Total Gross Deferred Income Tax Assets	218	203
Gross Deferred Income Tax Liabilities
Plant, Net	(682)	(639)
PPFAC	(23)	(6)
Plant Abandonments	(8)	(11)
Pensions	(18)	(17)
Income Taxes Payable Through Future Rates	(4)	(7)
Other	(32)	(16)
Total Gross Deferred Income Tax Liabilities	(767)	(696)
Deferred Income Taxes, Net	$ (549)	$ (493)

INCOME TAXES (Summary of Tax Ca

INCOME TAXES (Summary of Tax Carryforwards) (Details) $ in Millions	Dec. 31, 2021USD ($)
Income Tax Contingency [Line Items]
Investment Tax Credits	$ 22
State
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	1
Tax Credits	9
Federal
Income Tax Contingency [Line Items]
Other Federal Credits	$ 8

INCOME TAXES (Uncertain Tax Pos

INCOME TAXES (Uncertain Tax Positions) (Details) - USD ($) $ in Millions	Feb. 02, 2021	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning of Period		$ 19	$ 18
Additions Based on Tax Positions Taken in the Current Year		0	1
Reductions Based on Positions Taken in Prior Years	$ (18)	(18)	0
End of Period		$ 1	$ 19