Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Feb. 09, 2023 | Jun. 30, 2022 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2022 | ||
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 | Yes | ||
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 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Entity Central Index Key | 0000100122 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Name | Deloitte & Touche LLP |
Auditor Location | Tempe, Arizona |
Auditor Firm ID | 34 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Statement [Abstract] | |||
Operating Revenues | $ 1,808,082 | $ 1,592,586 | $ 1,424,741 |
Operating Expenses | |||
Fuel | 504,757 | 399,914 | 302,637 |
Purchased Power | 209,790 | 204,264 | 146,968 |
Transmission and Other PPFAC Recoverable Costs | 84,323 | 65,583 | 52,860 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | (27,643) | (64,155) | 12,565 |
Total Fuel and Purchased Power | 771,227 | 605,606 | 515,030 |
Operations and Maintenance | 405,438 | 397,095 | 351,584 |
Depreciation | 211,008 | 201,524 | 189,051 |
Amortization | 40,045 | 43,995 | 28,754 |
Taxes Other Than Income Taxes | 63,706 | 62,010 | 58,222 |
Total Operating Expenses | 1,491,424 | 1,310,230 | 1,142,641 |
Operating Income | 316,658 | 282,356 | 282,100 |
Other Income (Expense) | |||
Interest Expense | (85,217) | (86,865) | (88,214) |
Allowance For Borrowed Funds | 2,756 | 6,624 | 9,480 |
Allowance For Equity Funds | 8,170 | 17,885 | 22,847 |
Unrealized Gains (Losses) on Investments | (7,094) | 3,898 | 1,741 |
Other, Net | 14,414 | 9,823 | 4,903 |
Total Other Income (Expense) | (66,971) | (48,635) | (49,243) |
Income Before Income Tax Expense | 249,687 | 233,721 | 232,857 |
Income Tax Expense | 32,262 | 32,476 | 41,452 |
Net Income | $ 217,425 | $ 201,245 | $ 191,405 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash Flows from Operating Activities | |||
Net Income | $ 217,425 | $ 201,245 | $ 191,405 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation Expense | 211,008 | 201,524 | 189,051 |
Amortization Expense | 40,045 | 43,995 | 28,754 |
Amortization of Debt Issuance Costs | 3,000 | 2,829 | 2,721 |
Use of Renewable Energy Credits for Compliance | 44,762 | 45,815 | 44,517 |
Deferred Income Taxes | 32,825 | 37,217 | 39,408 |
Pension and Other Postretirement Benefits Expense | 12,207 | 15,342 | 14,883 |
Pension and Other Postretirement Benefits Funding | (17,818) | (20,806) | (21,018) |
Allowance for Equity Funds Used During Construction | (8,170) | (17,885) | (22,847) |
Regulatory Deferral, ACC Refund Order | 0 | 0 | (7,705) |
Changes in Current Assets and Current Liabilities: | |||
Accounts Receivable | (120,780) | (18,738) | (19,019) |
Materials, Supplies, and Fuel Inventory | (12,953) | (18,445) | (3,460) |
Regulatory Assets | (76,900) | (59,542) | 5,339 |
Other Current Assets | (2,205) | 4,670 | (8,311) |
Accounts Payable and Accrued Charges | 132,796 | 14,979 | (20,885) |
Income Taxes Receivable/Payable | 0 | (3,271) | 10,245 |
Regulatory Liabilities | (2,615) | (9,599) | 41,287 |
Other, Net | 56,783 | 8,724 | 1,689 |
Net Cash Flows—Operating Activities | 509,410 | 428,054 | 466,054 |
Cash Flows from Investing Activities | |||
Capital Expenditures | (457,517) | (499,405) | (839,958) |
Proceeds from Sale, Springerville Common Facilities | 0 | 0 | 29,569 |
Purchase Intangibles, Renewable Energy Credits | (63,738) | (55,297) | (53,509) |
Other Investments | 2,517 | 0 | (8,500) |
Contributions in Aid of Construction | 8,131 | 5,678 | 4,615 |
Net Cash Flows—Investing Activities | (510,607) | (549,024) | (867,783) |
Cash Flows from Financing Activities | |||
Proceeds from Borrowings, Revolving Credit Facility | 5,000 | 50,000 | 105,000 |
Repayments of Borrowings, Revolving Credit Facility | (20,000) | (35,000) | (105,000) |
Proceeds from Borrowings, Term Loan | 0 | 0 | 60,000 |
Repayments of Borrowings, Term Loan | 0 | 0 | (225,000) |
Proceeds from Issuance, Long-Term Debt—Net of Discount | 323,804 | 322,231 | 645,768 |
Repayments of Long-Term Debt | (193,465) | (250,000) | (180,410) |
Dividends Paid to Parent | (100,000) | (62,500) | (75,000) |
Payments of Finance Lease Obligations | 0 | 0 | (17,087) |
Payment of Debt Issuance Costs | (3,012) | (4,382) | (6,327) |
Contributions from Parent | 0 | 50,000 | 250,000 |
Other, Net | 6,362 | 2,107 | 3,316 |
Net Cash Flows—Financing Activities | 18,689 | 72,456 | 455,260 |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 17,492 | (48,514) | 53,531 |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 33,489 | 82,003 | 28,472 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | $ 50,981 | $ 33,489 | $ 82,003 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Utility Plant | ||
Plant in Service | $ 7,813,680 | $ 7,797,935 |
Construction Work in Progress | 256,044 | 320,931 |
Total Utility Plant | 8,069,724 | 8,118,866 |
Accumulated Depreciation and Amortization | (2,603,730) | (2,786,839) |
Total Utility Plant, Net | 5,465,994 | 5,332,027 |
Investments and Other Property | 74,128 | 81,958 |
Current Assets | ||
Cash and Cash Equivalents | 16,237 | 9,970 |
Accounts Receivable (Net of Allowance for Credit Losses of $9,012 and $10,044) | 320,899 | 192,579 |
Fuel Inventory | 28,681 | 26,971 |
Materials and Supplies | 155,650 | 141,677 |
Regulatory Assets | 185,034 | 116,442 |
Derivative Instruments | 27,019 | 19,406 |
Other | 30,547 | 24,229 |
Total Current Assets | 764,067 | 531,274 |
Regulatory and Other Assets | ||
Regulatory Assets | 184,894 | 267,669 |
Derivative Instruments | 77,123 | 14,392 |
Other | 123,575 | 94,420 |
Total Regulatory and Other Assets | 385,592 | 376,481 |
Total Assets | 6,689,781 | 6,321,740 |
Common Stock Equity: | ||
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2022 and 2021) | 1,696,539 | 1,696,539 |
Capital Stock Expense | (6,357) | (6,357) |
Retained Earnings | 968,367 | 850,942 |
Accumulated Other Comprehensive Loss | (2,884) | (9,915) |
Total Common Stock Equity | 2,655,665 | 2,531,209 |
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2022 and 2021) | 0 | 0 |
Long-Term Debt, Net | 2,114,980 | 2,134,534 |
Total Capitalization | 4,770,645 | 4,665,743 |
Current Liabilities | ||
Current Maturities of Long-Term Debt, Net | 149,957 | 0 |
Borrowings Under Credit Agreement | 0 | 15,000 |
Accounts Payable | 233,920 | 139,329 |
Accrued Taxes Other than Income Taxes | 58,914 | 53,534 |
Accrued Employee Expenses | 38,459 | 36,217 |
Accrued Interest | 14,868 | 16,265 |
Regulatory Liabilities | 110,782 | 111,356 |
Customer Deposits | 14,073 | 12,791 |
Derivative Instruments | 12,752 | 15,854 |
Other | 49,163 | 25,358 |
Total Current Liabilities | 682,888 | 425,704 |
Regulatory and Other Liabilities | ||
Deferred Income Taxes, Net | 590,926 | 548,750 |
Regulatory Liabilities | 377,546 | 352,226 |
Pension and Other Postretirement Benefits | 69,048 | 120,020 |
Derivative Instruments | 4,787 | 3,848 |
Other | 193,941 | 205,449 |
Total Regulatory and Other Liabilities | 1,236,248 | 1,230,293 |
Commitments and Contingencies | ||
Total Capitalization and Other Liabilities | $ 6,689,781 | $ 6,321,740 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Accounts receivable, allowance for credit loss, current | $ 9,012 | $ 10,044 |
Common stock, shares authorized (in shares) | 75,000,000 | 75,000,000 |
Common stock, shares outstanding (in shares) | 32,139,434 | 32,139,434 |
Preferred stock, shares authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred stock, shares outstanding (in shares) | 0 | 0 |
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, 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) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 217,425 | 217,425 | |||
Other Comprehensive Income(Loss), Net of Tax | 7,031 | 7,031 | |||
Dividends Declared to Parent | (100,000) | (100,000) | |||
Ending balances at Dec. 31, 2022 | $ 2,655,665 | $ 1,696,539 | $ (6,357) | $ 968,367 | $ (2,884) |
NATURE OF OPERATIONS AND SUMMAR
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
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 443,000 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 facilities and transmission systems with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows. 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 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, 2022, 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. In 2020, the FASB issued Accounting Standards Update (ASU) 2020-04 establishing Accounting Standards Codification (ASC) Topic 848, Reference Rate Reform, and in 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (collectively, ASC 848). ASC 848 contains practical expedients for reference rate reform related activities that impact debt, leases, derivatives and other contracts. The guidance in ASC 848 is optional and may be elected over time as reference rate reform activities occur. In 2022, the FASB issued ASU 2022-06, Deferral of the Sunset Date of Topic 848 (ASU 2022-06), to defer the sunset date of ASC 848 to December 31, 2024. ASU 2022-06 is effective immediately for all companies. TEP continues to evaluate the impact of ASC 848. 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 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) 2022 2021 2020 Cash and Cash Equivalents $ 16 $ 10 $ 61 Restricted Cash included in: Investments and Other Property 22 20 19 Current Assets—Other 13 3 2 Total Cash, Cash Equivalents, and Restricted Cash $ 51 $ 33 $ 82 Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan. 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 receivables are written-off in the period in which the receivable is deemed uncollectible. 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 facilities and transmission and distribution systems. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction. The cost of repairs and maintenance, including planned generation facility overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. 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: (i) the original cost; (ii) plus removal costs; (iii) 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 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: 2022 2021 2020 Average AFUDC Rates 6.74 % 6.88 % 6.63 % 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. The ACC approves depreciation rates for all generation facilities, distribution systems, and general plant assets. Transmission system assets are subject to the jurisdiction of the FERC. Below are the summarized average annual depreciation rates for all utility plant: 2022 2021 2020 Average Annual Depreciation Rates 3.24 % 3.30 % 3.15 % 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 filing 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. 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. 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. 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. TEP has operating leases for office facilities, land, rail cars, and communication tower space that are included on the balance sheet as follows: December 31, (in millions) 2022 2021 Lease Assets Regulatory and Other Assets, Other $ 6 $ 7 Lease Liabilities Current Liabilities, Other 1 1 Regulatory and Other Liabilities, Other 5 6 As of December 31, 2022, TEP's future minimum operating lease payments, excluding payments to lessors for variable costs, are $1 million or less in each year from 2023 through 2027 and $3 million thereafter. 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. 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 sales by 2025, with DG accounting for 30%. 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. The associated lost revenues attributable to meeting the EE Standards 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. 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) 2022 2021 Beginning of Period $ 69 $ 66 Purchased 58 49 Used for Compliance (45) (46) End of Period $ 82 $ 69 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. 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 an asset for a defined benefit plan's overfunded status or a liability for a plan's underfunded status in the balance sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement 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 not yet recognized in the income statement 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. 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. 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. 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. 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. Federal ITCs are deferred and amortized as a reduction to income tax expense over the life of the underlying asset. All other federal and state income tax credits, including PTCs, are treated as a reduction to income tax expense in the year the credit arises. |
REGULATORY MATTERS
REGULATORY MATTERS | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation facilities and transmission systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. RATE CASE MATTERS 2022 Rate Case In June 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021. TEP's key 2022 Rate Case proposals are described below: • a $136 million net increase in retail revenues comprised of the following components: ◦ a non-fuel retail revenue increase of $159 million over test year non-fuel retail revenues; ◦ a $66 million increase in fuel-related retail revenues, offset by a $71 million reduction in PPFAC revenues; and ◦ changes in certain adjustor mechanisms, including DSM, ECA, and RES, which result in an $18 million reduction in revenues. • a 7.31% return on original cost rate base of $3.6 billion, which includes a cost of equity of 10.25% and an average cost of debt of 3.82%; and • a new RTM adjustor that is designed to provide more timely recovery of TEP's clean energy investments and replace the ECA. TEP requested new rates to be implemented by September 1, 2023. TEP cannot predict the timing or outcome of this proceeding. 2020 ACC Phase 2 Proceedings In 2020, the ACC issued a rate order for new rates and established a second phase of TEP’s rate case to address the impact on certain communities due to the closures of fossil-based generation facilities (Phase 2). In 2021, the ACC staff opened a generic docket related to this matter, and in January 2022, the ACC issued an order delaying Phase 2 until after the completion of the generic docket. In January 2023, the ACC closed Phase 2 and ordered that just and equitable transition issues be considered as part of the 2022 Rate Case. 2022 Final FERC Rate Order In 2019, TEP filed a proposal with the FERC requesting a forward-looking formula rate intended to allow for timely recovery of transmission-related costs. The FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. As part of the 2022 Final FERC Rate Order, the FERC established hearing and settlement procedures. In December 2021, the settlement agreement was filed with the FERC. In March 2022, the FERC approved the settlement agreement. Provisions of the settlement agreement include, but are not limited to: • replacing TEP's stated transmission rates with a single forward-looking formula rate; • a 9.79% return on equity; and • elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor. Increased rates charged under the 2022 Final FERC Rate Order were subject to refund and deferred as a regulatory liability. In 2022, TEP returned all amounts in excess of the rates approved in the settlement agreement previously deferred as a regulatory liability. TEP had no wholesale revenues reserved in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2022, and $15 million reserved as of December 31, 2021, related to the 2022 Final FERC Rate Order. OTHER FERC MATTERS In January 2021, the FERC notified TEP that it was commencing an audit with the intent 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 covered the period of January 1, 2018, to December 31, 2021. On November 4, 2022, the FERC published without prejudice the final audit report with its findings and recommendations. TEP accepted the findings therein and submitted compliance items related to the audit in January 2023. TEP does not expect a material financial impact from the results of the audit. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for timely recovery of certain costs through recovery mechanisms. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that allows for reconciliation of differences between actual costs and those recovered in the preceding period. In April 2022, the ACC approved a rate adjustment for the PPFAC that sets the true-up component of the PPFAC rate to recover the existing uncollected true-up balance over 18 months. The ACC also set the forward-looking component of the PPFAC rate to zero, which has resulted in under-collection of PPFAC costs. The table below summarizes the PPFAC regulatory asset (liability) balance: Years Ended December 31, (in millions) 2022 2021 Beginning of Period $ 91 $ 23 Deferred Fuel and Purchased Power Costs (1) 348 343 PPFAC and Base Power Recoveries (2) (315) (275) End of Period $ 124 $ 91 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request beginning in June 2021. The 2022 PPFAC rate adjustment became effective on April 29, 2022. Environmental Compliance Adjustor The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided they are not already recovered in base rates or recovered through another commission-approved mechanism. Costs eligible for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. The difference between costs recovered through rates and actual ECA eligible costs is deferred . TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. The 2022 Rate Case includes a proposal to transition away from the current ECA surcharge and to recover the costs in base rates. Tax Expense Adjustor Mechanism The TEAM allows for the timely recovery of future significant income tax changes and provides the Company the ability to pass through as a kWh surcharge: (i) the change in EDIT compared to the test year; and (ii) the income tax effects of tax legislation that materially impacts TEP's authorized revenue requirement. Transmission Cost Adjustor The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's OATT rate. The Company files a notice with the ACC in December each year presenting a revised tariff that reflects the changes in the formula OATT rate which goes into effect in the first billing cycle in January of each year. In February 2022, the ACC approved TEP's motion to modify the TCA plan of administration to reflect the terms of the 2022 Final FERC Rate Order settlement agreement. Renewable Energy Standard The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2022 was 12% of retail electric sales. In 2022, the percentage of TEP's retail kWh sales attributable to the RES was approximately 24%. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES surcharge. In 2021, the ACC approved TEP's 2021 RES implementation plan for the years 2021 and 2022 with a budget of $66 million. The approved amounts fund: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Additionally, the ACC directed TEP to collaborate with the ACC to develop and file a proposal to phase out the RES tariff. In June 2022, TEP filed a request with the ACC for approval of an extension of the 2021 RES implementation plan through the completion of the 2022 Rate Case. The rate case includes a proposal to transition away from the current RES surcharge and to recover the costs in base rates. Energy Efficiency Standards TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. As of December 31, 2022, TEP's cumulative annual energy savings were approximately 24%. In November 2022, the ACC approved TEP’s 2022 energy efficiency implementation plan, with a budget of $24 million, which is collected through the DSM surcharge. The 2022 plan will remain in effect until another plan is approved. The 2022 Rate Case includes a proposal to transition away from the current DSM surcharge and to recover the costs in base rates. In 2022, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings over three years. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2022 2021 Regulatory Assets Under Recovered Purchased Energy Costs 2 $ 124 $ 91 Pension and Other Postretirement Benefits (Note 9) Various 90 128 Early Generation Retirement Costs (1) Various 58 38 Property Tax Deferrals (2) 1 29 27 Lost Fixed Cost Recovery 1 25 37 Final Mine Reclamation and Retiree Healthcare Costs (3) 6 11 17 Income Taxes Recoverable through Future Rates (4) Various 6 17 Unamortized Loss on Reacquired Debt Various 5 5 Derivatives (Note 12) 7 3 8 Tax Expense Adjustor Mechanism 1 3 3 Springerville Unit 1 Leasehold Improvements (5) 1 2 4 Other Regulatory Assets Various 14 9 Total Regulatory Assets 370 384 Less Current Portion 1 185 116 Total Non-Current Regulatory Assets $ 185 $ 268 Regulatory Liabilities Income Taxes Payable through Future Rates (4) Various $ 244 $ 268 Derivatives (Note 12) 7 86 19 Renewable Energy Standard Various 73 66 Net Cost of Removal (6) Various 43 73 Demand Side Management 1 16 12 Transmission Cost Adjustor 1 9 9 Pension and Other Postretirement Benefits (Note 9) Various 8 — Deferred Investment Tax Credits Various 7 1 Transmission Revenue Subject to Refund - FERC 1 1 15 Other Regulatory Liabilities Various 2 — Total Regulatory Liabilities 489 463 Less Current Portion 1 111 111 Total Non-Current Regulatory Liabilities $ 378 $ 352 (1) Increase in Early Generation Retirement Costs is primarily due to the retirement of San Juan Unit 1 in June 2022. (2) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. (3) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022. (4) Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 13 for additional information regarding income taxes. (5) 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. (6) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. The decrease in Net Cost of Removal is primarily due to the retirement of San Juan Unit 1 in June 2022. Regulatory Assets and Liabilities Except for Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, Springerville Unit 1 Leasehold Improvements, and Under Recovered Purchased Energy Costs, 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, 2022 | |
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 (4) Average Remaining Life in Years (4) December 31, ($ in millions) 2022 2021 Plant in Service Generation Plant (1) 3.11% 17 $ 3,491 $ 3,753 Distribution Plant 1.93% 32 2,149 2,024 Transmission Plant 1.69% 34 1,295 1,210 General Plant 6.01% 6 653 540 Intangible Plant, Software Costs, and Other (2) Various Various 224 268 Plant Held for Future Use — — 2 3 Total Plant in Service (3) $ 7,814 $ 7,798 (1) In June 2022, San Juan Unit 1 was retired by PNM, the operator of San Juan. Contemporaneously, TEP's obligations ceased with respect to: (i) costs incurred for San Juan Unit 1 and the related common facilities stemming from continued operations at San Juan; and (ii) purchases under the coal supply agreement between PNM and San Juan Coal Company. (2) Primarily represents computer software, which is amortized over three (3) Includes plant acquisition adjustments of $(206) million as of December 31, 2022 and 2021. (4) 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 2022 Final FERC Rate Order. Accumulated Depreciation and Amortization Amortization of Intangible Plant Intangible Plant primarily consists of computer software. Accumulated amortization of computer software costs was $110 million and $169 million as of December 31, 2022 and 2021, respectively. Amortization of computer software costs totaled $30 million in 2022, $33 million in 2021, and $29 million in 2020. Future estimated amortization costs for existing computer software are $26 million in 2023, $18 million in 2024, $14 million in 2025, $10 million in 2026, and $4 million in 2027. Intangible Plant includes $(4) million in acquisition discounts not subject to amortization as of December 31, 2022 and 2021. JOINTLY-OWNED FACILITIES As of December 31, 2022, TEP was a participant in the following jointly-owned generation facilities and transmission systems: ($ in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value Four Corners Units 4 and 5 7.0% $ 191 $ 5 $ (88) $ 108 Luna 33.3% 57 — 1 58 Gila River Unit 3 75.0% 204 2 (63) 143 Gila River Common Facilities 43.8% 75 — (28) 47 Springerville Coal Handling Facilities 83.0% 207 — (98) 109 Springerville Common Facilities 86.0% 404 1 (218) 187 Transmission Facilities Various 551 16 (234) 333 Total $ 1,689 $ 24 $ (728) $ 985 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) 2022 2021 Beginning of Period $ 139 $ 96 Liabilities Incurred (1) 1 14 Liabilities Settled (2) (8) (2) Regulatory Deferral/Accretion Expense 5 4 Revisions to the Present Value of Estimated Cash Flows (3) (16) 27 End of Period $ 121 $ 139 (1) In 2021, TEP incurred an ARO for Oso Grande. In 2022, TEP incurred an ARO for new photovoltaic generation placed in service. (2) Primarily related to the retirement of Navajo. (3) Primarily related to revised decommissioning estimates for San Juan. |
REVENUE
REVENUE | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE | REVENUETEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration. 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) 2022 2021 2020 Retail $ 1,140 $ 1,088 $ 1,039 Wholesale (1) 456 278 190 Other Services 104 114 95 Revenues from Contracts with Customers 1,700 1,480 1,324 Alternative Revenues 28 12 48 Other 80 101 53 Total Operating Revenues $ 1,808 $ 1,593 $ 1,425 (1) Change primarily due to an increase in forward market prices. 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 spring and summer months then decrease during fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances. See Note 5 for components of Accounts Receivable on the Consolidated Balance Sheets. In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. 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. See Note 2 for more information regarding the 2022 Final FERC Rate Order. Other Services Revenues Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, reimbursement of various operating expenses for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities by the lessee of Springerville Unit 3, and miscellaneous service-related revenues. 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 TCA and ECA mechanisms, LFCR, DSM performance incentive, and OATT balancing activity 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, asset management agreement service fees, late and returned payment finance charges and common cost allocations to affiliates. See Note 6 for information regarding revenue from related parties and Note 12 for information regarding derivative instruments. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 12 Months Ended |
Dec. 31, 2022 | |
Receivables [Abstract] | |
ACCOUNTS RECEIVABLE | ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Consolidated Balance Sheets: December 31, (in millions) 2022 2021 Retail $ 87 $ 78 Retail, Unbilled 46 44 Retail, Allowance for Credit Losses (9) (10) Wholesale (1) 132 47 Due from Affiliates (Note 6) 26 17 Other 39 17 Accounts Receivable $ 321 $ 193 (1) Includes $52 million and $16 million as of December 31, 2022 and 2021, 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) 2022 2021 Beginning of Period $ (10) $ (13) Credit Loss Expense (1) (5) — Write-offs (2) 6 3 End of Period $ (9) $ (10) (1) Credit loss expense increased due to a disconnection moratorium. (2) Write-offs increased due to the expiration of a payment plan offered during the COVID-19 pandemic. Customer Payment Assistance In 2022, TEP received funds for customer payment assistance from the Arizona Department of Economic Security (DES) to provide emergency payment assistance to renters. Customer payment assistance is dependent on qualifying customers applying. TEP received $15 million DES payment assistance funds in the year ended December 31, 2022. Funds received directly reduced Accounts Receivable on the Consolidated Balance Sheets. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONSTEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services. 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) 2022 2021 Receivables from Related Parties UNS Electric $ 22 $ 8 UNS Energy 2 7 UNS Gas 2 2 Total Due from Related Parties $ 26 $ 17 Payables to Related Parties UNS Electric $ 5 $ — UNS Gas 1 1 UNS Energy 1 1 Total Due to Related Parties $ 7 $ 2 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2022 2021 2020 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 5 $ 11 $ 9 Wholesale Revenues, UNS Electric (1)(2) 50 25 1 Control Area Services, UNS Electric (3) 3 6 4 Common Costs, UNS Energy Affiliates (4) 22 21 19 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) 2 1 — Supplemental Workforce, SES (5) — — 14 Corporate Services, UNS Energy (6) 8 7 5 Corporate Services, UNS Energy Affiliates (7) 1 3 4 Capacity Charges, UNS Gas 1 — — Corporate Services, Fortis Affiliates (8) — — 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 8 for additional information related to the tolling PPA. In May 2022, TEP began charging UNS Electric for power purchased in the EIM on behalf of UNS Electric. (3) TEP charges UNS Electric for control area services under a FERC-filed 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 $7 million in 2022, and $6 million in each of 2021 and 2020. (7) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. (8) Fortis charges TEP for its share of payroll tax, insurance, and other costs paid by Fortis for affiliated employees. |
DEBT AND CREDIT AGREEMENT
DEBT AND CREDIT AGREEMENT | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
DEBT AND CREDIT AGREEMENT | DEBT AND CREDIT AGREEMENT DEBT Long-term debt matures more than one year from the date of debt issuance. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2022 2021 Notes 2012 Senior Notes (1) 3.85% 2023 $ 150 $ 150 2015 Senior Notes 3.05% 2025 300 300 2020 Senior Notes 1.50% 2030 300 300 2022 Senior Notes 3.25% 2032 325 — 2014 Senior Notes 5.00% 2044 150 150 2018 Senior Notes 4.85% 2048 300 300 2020 Senior Notes 4.00% 2050 350 350 2021 Senior Notes 3.25% 2051 325 325 Tax-Exempt Local Furnishings Bonds 2013 Pima A (2) 4.00% 2029 91 91 2012 Pima A 4.50% 2030 — 16 Tax-Exempt Pollution Control Bonds 2012 Apache A 4.50% 2030 — 177 Total Long-Term Debt (3) 2,291 2,159 Less Unamortized Discount and Debt Issuance Costs 26 24 Less Current Maturities of Long-Term Debt 150 — Total Long-Term Debt, Net $ 2,115 $ 2,135 (1) After December 15, 2022, the 2012 Senior Notes became callable at par plus accrued interest. The notes mature on March 15, 2023. (2) The 2013 Pima A bonds become callable at par on or after March 1, 2023. (3) As of December 31, 2022, all of TEP's debt is unsecured. Debt Issuances and Redemptions In June 2022, TEP redeemed at par prior to maturity $16 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum. In March 2022, TEP redeemed at par prior to maturity $177 million aggregate principal amount of fixed rate tax-exempt bonds bearing interest at a rate of 4.50% per annum. In February 2022, TEP issued and sold $325 million aggregate principal amount of 3.25% senior unsecured notes due May 2032. TEP may redeem the notes prior to February 15, 2032, with a make-whole premium plus accrued interest. On or after February 15, 2032, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to redeem debt in March 2022 and June 2022 and for general corporate purposes. In August 2021, TEP redeemed at par prior to maturity $250 million aggregate principal amount of 5.15% senior unsecured notes. 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. Maturities Long-term debt matures on the following dates: (in millions) Long-Term Debt (1) 2023 $ 150 2024 — 2025 300 2026 — 2027 — Thereafter 1,841 Total $ 2,291 (1) Total long-term debt excludes $17 million of related unamortized debt issuance costs and $9 million of unamortized original issue discount. CREDIT AGREEMENT In October 2021, TEP entered into an unsecured credit agreement that provides for revolving credit commitments with swingline and LOC sublimits, due in October 2026, the termination date (2021 Credit Agreement). The final maturity date is subject to two one-year extensions if certain conditions are satisfied. Amounts borrowed are recorded in Borrowings Under Credit Agreement on the Consolidated Balance Sheets. • Amounts borrowed under the 2021 Credit Agreement are used for working capital and other general corporate purposes. • Interest rates and fees are based on a pricing grid tied to TEP's credit rating. • LOCs are issued from time to time to support energy procurement, hedging transactions, and other business activities. The credit agreement provides for transitions to alternative benchmark rates. Terms are as follows: Sub-Limit Swingline (1) Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed (2) Available Pricing (3)(4) ($ in millions) December 31, 2022 2021 Agreement $ 250 $ 15 $ 50 $ 5 $ 245 — % LIBOR + 1.025% or ABR + 0.025% ($ 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) The borrowed amounts include a $5 million LOC at a rate of 1.025% per annum as of December 31, 2022, and a $10 million LOC at a rate of 1.00% per annum as of December 31, 2021. This LOC was issued in October 2021 to replace an LOC originally issued in January 2020 pursuant to TEP taking ownership of Oso Grande. The LOC expires October 2023. (3) TEP's pricing may be adjusted based on performance measured using two sustainability targets: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage. (4) TEP plans to amend the 2021 Credit Agreement to provide for the transition to SOFR-based borrowings before the end of the second quarter of 2023 |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES COMMITMENTS As of December 31, 2022, TEP had the following commitments: (in millions) 2023 2024 2025 2026 2027 Thereafter Total Minimum Purchase Commitments Fuel, Including Transportation $ 107 $ 57 $ 48 $ 45 $ 44 $ 176 $ 477 Purchased Power 78 16 — — — — 94 Transmission 28 23 21 4 1 3 80 Purchase Commitments Renewable Power Purchase Agreements 80 80 79 79 79 768 1,165 RES Performance-Based Incentives 7 7 5 4 4 19 46 Total Commitments $ 300 $ 183 $ 153 $ 132 $ 128 $ 966 $ 1,862 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 2023 and 2031. In 2022, TEP amended and extended its existing coal sales agreement for the supply of coal for Springerville Unit 1 through 2027 and Unit 2 through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs. TEP entered into natural gas commodity purchase agreements that expire through 2023. Certain of these contracts are at a fixed price per MMBtu and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2022. TEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. In 2022, TEP extended an agreement for gas transportation to Luna through 2032. These agreements expire in various years between 2023 and 2040. TEP has related party agreements for natural gas supply with UNS Electric through 2023. UNS Electric will pay TEP monthly charges equal to 50% of TEP's related monthly natural gas cost. Natural gas is supplied as needed to meet UNS Electric’s load requirements. TEP's commitment does not reflect any reduction for the subsequent sale of natural gas. See Note 6 for more information on related party transactions. Purchased Power TEP has contracts for purchased power to: (i) meet system load and energy requirements; (ii) replace generation from company-owned units under maintenance and during outages; and (iii) meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the third quarter of 2024. Certain of these contracts are at a fixed price per MW and others are indexed to market prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2022. TEP has a tolling PPA to purchase and receive up to 300 MW of capacity, power, and ancillary services from June 15 through October 15, 2023. TEP will pay monthly capacity charges and variable power charges. TEP also has a tolling PPA with UNS Electric to sell and deliver up to 150 MW of capacity, power, and ancillary services over the same period. UNS Electric will pay TEP 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. See Note 6 for more information on related party transactions. 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 2023 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. 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 2023 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 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 term of the respective coal supply agreement. TEP’s PPFAC allows the Company to pass through to retail customers final mine reclamation costs, as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability. TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP's share of final mine reclamation costs at Four Corners is $8 million upon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the coal supply agreement on June 30, 2022. As of December 31, 2022, TEP's remaining final mine reclamation liability at San Juan was $32 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the completion of final mine reclamation activities currently projected to be 2039. For additional information see Note 1, Restricted Cash, and Note 3, Plant in Service. TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation totaled $37 million and $40 million as of December 31, 2022 and 2021, respectively, and was recorded in Other on the Consolidated Balance Sheets. Performance Guarantees TEP has joint generation participation agreements with participants at Four Corners and Luna, which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. There is no maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of December 31, 2022, there have been no such payment defaults under either of the participation agreements. The Navajo and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, the non-defaulting participants would seek financial recovery directly from the defaulting party. Environmental Matters TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects. Broadway-Pantano Site The WQARF imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. These landfills were in operation from 1959 to 1972 and 1953 to 1962, respectively. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized. |
EMPLOYEE BENEFITS PLANS
EMPLOYEE BENEFITS PLANS | 12 Months Ended |
Dec. 31, 2022 | |
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 $2 million in 2022, $3 million in 2021, and $1 million in 2020. 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) 2022 2021 2022 2021 Regulatory Assets $ 90 $ 126 $ — $ 2 Regulatory Liabilities — — (8) — Regulatory and Other Assets—Other 8 — — — Accrued Employee Expenses (1) (1) (2) (3) Pension and Other Postretirement Benefits (20) (61) (49) (59) Accumulated Other Comprehensive Loss 4 13 — — Net Amount Recognized $ 81 $ 77 $ (59) $ (60) 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, 2022 and 2021. The table below presents the status of all TEP pension and other postretirement benefit plans. Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2022 2021 2022 2021 Change in Benefit Obligation Beginning of Period $ 600 $ 606 $ 90 $ 99 Actuarial Gain (176) (6) (17) (12) Interest Cost 16 14 2 2 Service Cost 21 20 5 6 Benefits Paid (35) (34) (6) (5) Plan Amendments (1) 1 — — — Settlements (2) (16) — — — End of Period (3) 411 600 74 90 Change in Fair Value of Plan Assets Beginning of Period 538 514 28 24 Actual Return on Plan Assets (101) 43 (4) 3 Benefits Paid (34) (32) (3) (2) Employer Contributions (4) 11 13 2 3 Settlements (2) (16) — — — End of Period (5) 398 538 23 28 Funded Status at End of Period $ (13) $ (62) $ (51) $ (62) (1) Employees promoted to officer become eligible for SERP benefits based in part on their service prior to officer promotion. These prior service costs are accounted for in this table as a plan amendment. (2) Represents the aggregate lump-sum benefit payments for plans that exceeded the threshold of service plus interest costs. The change is due to an increase in retiring employees opting to receive their benefits as a lump-sum as a result of a rise in interest rates. (3) The decrease in pension and other postretirement benefit obligations was primarily due to an increase in the discount rate. (4) TEP expects to contribute $7 million to the pension plans and less than $1 million to the VEBA trust in 2023. (5) The decrease in pension and other postretirement benefit plan assets was primarily due to negative equity and fixed income returns. One pension plan had a projected benefit obligation in excess of plan assets as of December 31, 2022, compared to all three as of December 31, 2021. This was due to an increase in discount rates only partially offset by negative equity and fixed income returns. For plans with projected benefit obligations in excess of plan assets, total projected benefit obligations and plan assets were $21 million and none, respectively, as of December 31, 2022, and $600 million and $538 million, respectively, as of December 31, 2021. The other postretirement benefits plan had an accumulated postretirement benefit obligation in excess of the fair value of plan assets as of December 31, 2022 and 2021. The accumulated benefit obligation aggregated for all pension plans was $373 million and $538 million as of December 31, 2022 and 2021, respectively. One pension plan had an accumulated benefit obligation in excess of plan assets as of December 31, 2022 and 2021. The following table includes information for the pension plan with an accumulated benefit obligation in excess of pension plan assets: December 31, (in millions) 2022 2021 Accumulated Benefit Obligation $ 19 $ 26 Fair Value of Plan Assets — — The following table provides the components of TEP’s regulatory assets, regulatory liabilities, and AOCL that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2022 2021 2022 2021 Net Loss (Gain) $ 93 $ 139 $ (7) $ 4 Prior Service Cost (Benefit) 1 — (1) (2) 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) 2022 2021 2020 2022 2021 2020 Service Cost $ 21 $ 20 $ 16 $ 5 $ 6 $ 4 Non-Service Cost Interest Cost 16 14 16 2 2 3 Expected Return on Plan Assets (37) (34) (30) (1) (2) (2) Prior Service Benefit Amortization — — — (1) — — Amortization of Net Loss 7 9 8 — 1 — Effect of Settlement 3 — — — — — Net Periodic Benefit Cost $ 10 $ 9 $ 10 $ 5 $ 7 $ 5 The non-service components of net periodic benefit cost are primarily included in Other, Net on the Consolidated Statements of Income. In 2022, $3 million of the effect of settlement was deferred as a regulatory asset and recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets. TEP capitalized 21% of service cost as a cost of construction in 2022, and 22% in each of 2021 and 2020. The changes in plan assets and benefit obligations recognized as regulatory assets, regulatory liabilities, or in AOCL were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCL Regulatory Asset/Liability (in millions) 2022 2021 2020 2022 2021 2020 2022 2021 2020 Current Year Actuarial (Gain) Loss $ (27) $ (16) $ 23 $ (9) $ — $ 5 $ (11) $ (13) $ 17 Prior Service Benefit Amortization — — — — — — 1 — — Amortization of Net Loss (6) (8) (8) (1) (1) (1) — (1) — Prior Service Cost — — — 1 — — — — — Effect of Settlement (3) — — — — — — — — Total Recognized (Gain) Loss $ (36) $ (24) $ 15 $ (9) $ (1) $ 4 $ (10) $ (14) $ 17 For all pension plans, TEP amortizes prior service costs and benefits on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. 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 regarding 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 2022 2021 2022 2021 Discount Rate 5.7% 3.2% 5.6% 3.0% Rate of Compensation Increase 2.9% 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 2022 2021 2020 2022 2021 2020 Discount Rate, Service Cost 3.4% 3.3% 3.8% 3.2% 2.9% 3.5% Discount Rate, Interest Cost 2.7% 2.3% 3.1% 2.5% 1.9% 2.9% Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A Expected Return on Plan Assets 7.0% 6.8% 6.8% 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, 2022 2021 Next Year (Pre-65) 7.0% 6.5% Next Year (Post-65) 6.0% 5.5% Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5% Year Ultimate Rate is Reached (Pre-65) 2032 2031 Year Ultimate Rate is Reached (Post-65) 2028 2027 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 2022 2021 2022 2021 Asset Category Equity Securities 53 % 54 % 61 % 63 % Fixed Income Securities 39 % 40 % 38 % 35 % Real Estate 7 % 5 % — % — % Other 1 % 1 % 1 % 2 % Total 100 % 100 % 100 % 100 % As of December 31, 2022, the fair value of VEBA trust assets was $23 million, of which $9 million were fixed income investments and $14 million were equities. 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. 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, 2022 Asset Category Equity Securities: United States Large Cap — 61 — 61 United States Small Cap — 23 — 23 Non-United States — 66 — 66 Global — 61 — 61 Fixed Income — 154 — 154 Real Estate — — 30 30 Private Equity — — 3 3 Total $ — $ 365 $ 33 $ 398 (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 • 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 comparable 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, 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 Actual Return on Plan Assets: Assets Held at Reporting Date — 4 4 Purchases, Sales, and Settlements (1) — (1) Balance as of December 31, 2022 $ 3 $ 30 $ 33 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 considering the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes. 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, 2022 Cash/Treasury Bills —% 1% Equity Securities: United States Large Cap 16% 25% United States Mid Cap —% 8% United States Small Cap 6% 4% Non-United States Developed —% 15% Non-United States Emerging —% 8% Global Equity 28% —% Global Infrastructure 3% —% Fixed Income 40% 39% 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-party 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) 2023 2024 2025 2026 2027 2028-2032 Pension Benefits $ 25 $ 26 $ 26 $ 27 $ 27 $ 149 Other Postretirement Benefits 6 6 6 6 5 28 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 each of 2022 and 2021, and $6 million in 2020. |
SHARE-BASED COMPENSATION
SHARE-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2022 | |
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: 2022 2021 RSUs 17,996 20,794 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 as of December 31, 2022 and 2021. 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 2022 or 2021 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: 2022 2021 2020 PSUs 40,793 44,931 35,328 RSUs (1) 2,409 2,401 1,918 (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 $4 million and $9 million as of December 31, 2022 and 2021, 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 $2 million in 2022, $4 million in 2021, and $3 million in 2020 based on its share of UNS Energy's compensation expense. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Years Ended December 31, (in millions) 2022 2021 2020 Interest Paid, Net of Amounts Capitalized $ 80 $ 76 $ 76 Income Tax Refunds (1) — — (14) (1) TEP received refunds of AMT credit carryforwards in 2020 and 2019. See Note 13 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) 2022 2021 2020 Accrued Capital Expenditures $ 26 $ 38 $ 26 Renewable Energy Credits 3 3 3 Operating Leases — — 1 Asset Retirement Obligations Increase (Decrease) (1) (30) 34 (12) Net Cost of Removal Increase (Decrease) (2) (49) (41) (34) (1) In 2021, primarily represents a new obligation related to Oso Grande. In 2022, primarily represents the retirement of the San Juan asset retirement cost asset. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2021, TEP transferred a portion of the Net Cost of Removal recorded in Regulatory Liabilities to Accumulated Depreciation and Amortization on the Consolidated Balance Sheets to reflect the impact of revised depreciation rates. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset. |
FAIR VALUE MEASUREMENTS AND DER
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTSTEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3. FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Total (in millions) December 31, 2022 Assets Restricted Cash (1) $ 35 $ — $ 35 Energy Derivative Contracts, Regulatory Recovery (2) — 100 100 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 35 104 139 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (18) (18) Total Liabilities — (18) (18) Total Assets (Liabilities), Net $ 35 $ 86 $ 121 (in millions) December 31, 2021 Assets Restricted Cash (1) $ 23 $ — $ 23 Energy Derivative Contracts, Regulatory Recovery (2) — 30 30 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 23 34 57 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (20) (20) Total Liabilities — (20) (20) Total Assets (Liabilities), Net $ 23 $ 14 $ 37 (1) 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 (1) (in millions) December 31, 2022 Derivative Assets Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76 Derivative Liabilities Energy Derivative Contracts (18) (14) — (4) (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (1) TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Consolidated Balance Sheets. As of February 9, 2023, TEP held $9 million of cash received as collateral to provide credit enhancement. DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and 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) 2022 2021 2020 Unrealized Net Gain (1) $ 72 $ 62 $ 21 (1) The change in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices. 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) 2022 2021 2020 Operating Revenues $ 11 $ 7 $ 5 Derivative Volumes As of December 31, 2022, 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, 2022 2021 Power Contracts GWh 1,979 2,617 Gas Contracts BBtu 96,755 112,316 CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value. TEP has contractual agreements for energy procurement and hedging activities that contain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, TEP, or its counterparties, could have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts. TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to 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 $86 million as of December 31, 2022, compared with $26 million as of December 31, 2021. As of December 31, 2022, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on December 31, 2022, TEP would have been required to post $86 million of collateral. As of December 31, 2022, TEP had $73 million in outstanding net payable balances for settled positions. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Net Carrying Value Fair Value Fair Value Hierarchy December 31, (in millions) 2022 2021 2022 2021 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,265 $ 2,135 $ 1,901 $ 2,357 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 2020 Federal Income Tax Expense at Statutory Rate $ 52 $ 49 $ 49 State Income Tax Expense, Net of Federal Deduction 10 9 9 Federal/State Tax Credits (1) (22) (10) (3) Allowance for Equity Funds Used During Construction (1) (3) (7) Excess Deferred Income Taxes (10) (14) (7) Other 3 1 — Total Income Tax Expense $ 32 $ 32 $ 41 (1) TEP realized PTC benefits of $19 million and $7 million in 2022 and 2021, respectively, 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) 2022 2021 2020 Current Income Tax Expense Federal $ (1) $ (2) $ (2) State — — 1 Total Current Income Tax Expense (1) (2) (1) Deferred Income Tax Expense Federal 26 27 37 Federal Investment Tax Credits (1) (1) (1) State 8 8 6 Total Deferred Income Tax Expense 33 34 42 Total Income Tax Expense $ 32 $ 32 $ 41 In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $10 million, $14 million, and $7 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2022, 2021, and 2020, respectively. TEP's TEAM 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. The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2022 2021 Gross Deferred Income Tax Assets Customer Advances and Contributions in Aid of Construction $ 22 $ 20 Federal General Business Credits (1) 61 32 Income Taxes Payable Through Future Rates 60 67 Other 103 99 Total Gross Deferred Income Tax Assets 246 218 Gross Deferred Income Tax Liabilities Plant, Net (735) (682) PPFAC (31) (23) Plant Abandonments (14) (8) Pensions (20) (18) Income Taxes Recoverable Through Future Rates (1) (4) Other (36) (32) Total Gross Deferred Income Tax Liabilities (837) (767) Deferred Income Taxes, Net $ (591) $ (549) (1) Includes ITC and PTC carryovers. TEP recorded no valuation allowance against tax credit and net operating loss carryforward deferred income tax assets as of December 31, 2022 and 2021. Management believes TEP will produce sufficient taxable income in the future to realize credit and loss carryforwards before they expire. As of December 31, 2022, TEP had the following carryforward amounts: ($ in millions) Amount Expiring Year Federal Net Operating Loss $ 2 None State Net Operating Loss 3 2026 - 27 State Credits 10 2023 - 29 Federal Investment Tax Credits 33 2034 - 42 Federal Production Tax Credits 26 2041 - 42 Other Federal Credits 2 2034 - 42 TEP recorded no interest expense in 2022 and 2021 related to uncertain tax positions. In addition, TEP had no interest payable, and no penalties accrued as of December 31, 2022 and 2021. TEP has been audited by the IRS through tax year 2010. TEP's 2014 to 2021 tax years are open for audit by federal and state tax agencies. Included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets are current income taxes receivable and payable that are due from and to affiliates, respectively. TEP’s net intercompany income taxes were a receivable of $1 million and $6 million as of December 31, 2022 and 2021, respectively. |
NATURE OF OPERATIONS AND SUMM_2
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
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 facilities and transmission systems with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. Certain amounts from prior periods have been reclassified to conform to the current year presentation. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows. 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 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. In 2020, the FASB issued Accounting Standards Update (ASU) 2020-04 establishing Accounting Standards Codification (ASC) Topic 848, Reference Rate Reform, and in 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (collectively, ASC 848). ASC 848 contains practical expedients for reference rate reform related activities that impact debt, leases, derivatives and other contracts. The guidance in ASC 848 is optional and may be elected over time as reference rate reform activities occur. In 2022, the FASB issued ASU 2022-06, Deferral of the Sunset Date of Topic 848 (ASU 2022-06), to defer the sunset date of ASC 848 to December 31, 2024. ASU 2022-06 is effective immediately for all companies. TEP continues to evaluate the impact of ASC 848. |
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 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 primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan. |
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 receivables 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 facilities and transmission and distribution systems. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction. The cost of repairs and maintenance, including planned generation facility overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. 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: (i) the original cost; (ii) plus removal costs; (iii) 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 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. The ACC approves depreciation rates for all generation facilities, distribution systems, and general plant assets. Transmission system 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 filing 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. |
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 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. No component of the transaction price is allocated to unsatisfied performance obligations. |
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. |
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 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 sales by 2025, with DG accounting for 30%. 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. The associated lost revenues attributable to meeting the EE Standards 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. |
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 an asset for a defined benefit plan's overfunded status or a liability for a plan's underfunded status in the balance sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation for the pension plans or accumulated postretirement obligation for the other postretirement 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 not yet recognized in the income statement 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. DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and 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. |
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. |
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. Federal ITCs are deferred and amortized as a reduction to income tax expense over the life of the underlying asset. All other federal and state income tax credits, including PTCs, are treated as a reduction to income tax expense in the year the credit arises. |
Revenues | 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 spring and summer months then decrease during fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances. See Note 5 for components of Accounts Receivable on the Consolidated Balance Sheets. In December 2020, the ACC issued a rate order for new rates that took effect January 1, 2021. 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. See Note 2 for more information regarding the 2022 Final FERC Rate Order. Other Services Revenues Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, reimbursement of various operating expenses for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities by the lessee of Springerville Unit 3, and miscellaneous service-related revenues. 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 TCA and ECA mechanisms, LFCR, DSM performance incentive, and OATT balancing activity 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, asset management agreement service fees, late and returned payment finance charges and common cost allocations to affiliates. See Note 6 for information regarding revenue from related parties and Note 12 for information regarding derivative instruments. |
NATURE OF OPERATIONS AND SUMM_3
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 2020 Cash and Cash Equivalents $ 16 $ 10 $ 61 Restricted Cash included in: Investments and Other Property 22 20 19 Current Assets—Other 13 3 2 Total Cash, Cash Equivalents, and Restricted Cash $ 51 $ 33 $ 82 |
AFUDC Rates | The average AFUDC rates on regulated construction expenditures are included in the table below: 2022 2021 2020 Average AFUDC Rates 6.74 % 6.88 % 6.63 % |
Summary Of Average Annual Depreciation Rates For All Utility Plants | Below are the summarized average annual depreciation rates for all utility plant: 2022 2021 2020 Average Annual Depreciation Rates 3.24 % 3.30 % 3.15 % |
Schedule Of Lease Assets And Liabilities | TEP has operating leases for office facilities, land, rail cars, and communication tower space that are included on the balance sheet as follows: December 31, (in millions) 2022 2021 Lease Assets Regulatory and Other Assets, Other $ 6 $ 7 Lease Liabilities Current Liabilities, Other 1 1 Regulatory and Other Liabilities, Other 5 6 |
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) 2022 2021 Beginning of Period $ 69 $ 66 Purchased 58 49 Used for Compliance (45) (46) End of Period $ 82 $ 69 |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 Beginning of Period $ 91 $ 23 Deferred Fuel and Purchased Power Costs (1) 348 343 PPFAC and Base Power Recoveries (2) (315) (275) End of Period $ 124 $ 91 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2021, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request beginning in June 2021. The 2022 PPFAC rate adjustment became effective on April 29, 2022. |
Schedule of Regulatory Assets and Liabilities | Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2022 2021 Regulatory Assets Under Recovered Purchased Energy Costs 2 $ 124 $ 91 Pension and Other Postretirement Benefits (Note 9) Various 90 128 Early Generation Retirement Costs (1) Various 58 38 Property Tax Deferrals (2) 1 29 27 Lost Fixed Cost Recovery 1 25 37 Final Mine Reclamation and Retiree Healthcare Costs (3) 6 11 17 Income Taxes Recoverable through Future Rates (4) Various 6 17 Unamortized Loss on Reacquired Debt Various 5 5 Derivatives (Note 12) 7 3 8 Tax Expense Adjustor Mechanism 1 3 3 Springerville Unit 1 Leasehold Improvements (5) 1 2 4 Other Regulatory Assets Various 14 9 Total Regulatory Assets 370 384 Less Current Portion 1 185 116 Total Non-Current Regulatory Assets $ 185 $ 268 Regulatory Liabilities Income Taxes Payable through Future Rates (4) Various $ 244 $ 268 Derivatives (Note 12) 7 86 19 Renewable Energy Standard Various 73 66 Net Cost of Removal (6) Various 43 73 Demand Side Management 1 16 12 Transmission Cost Adjustor 1 9 9 Pension and Other Postretirement Benefits (Note 9) Various 8 — Deferred Investment Tax Credits Various 7 1 Transmission Revenue Subject to Refund - FERC 1 1 15 Other Regulatory Liabilities Various 2 — Total Regulatory Liabilities 489 463 Less Current Portion 1 111 111 Total Non-Current Regulatory Liabilities $ 378 $ 352 (1) Increase in Early Generation Retirement Costs is primarily due to the retirement of San Juan Unit 1 in June 2022. (2) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. (3) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022. (4) Amortized over five years, 10 years, or the lives of the assets. See Note 1 and Note 13 for additional information regarding income taxes. (5) 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. (6) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. The decrease in Net Cost of Removal is primarily due to the retirement of San Juan Unit 1 in June 2022. |
UTILITY PLANT AND JOINTLY-OWN_2
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Public Utility PPE | The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (4) Average Remaining Life in Years (4) December 31, ($ in millions) 2022 2021 Plant in Service Generation Plant (1) 3.11% 17 $ 3,491 $ 3,753 Distribution Plant 1.93% 32 2,149 2,024 Transmission Plant 1.69% 34 1,295 1,210 General Plant 6.01% 6 653 540 Intangible Plant, Software Costs, and Other (2) Various Various 224 268 Plant Held for Future Use — — 2 3 Total Plant in Service (3) $ 7,814 $ 7,798 (1) In June 2022, San Juan Unit 1 was retired by PNM, the operator of San Juan. Contemporaneously, TEP's obligations ceased with respect to: (i) costs incurred for San Juan Unit 1 and the related common facilities stemming from continued operations at San Juan; and (ii) purchases under the coal supply agreement between PNM and San Juan Coal Company. (2) Primarily represents computer software, which is amortized over three (3) Includes plant acquisition adjustments of $(206) million as of December 31, 2022 and 2021. (4) Based on the 2018 depreciation study available for the major classes of Plant in Service, effective January 1, 2021, as approved as part of the 2020 Rate Order. Transmission Plant depreciation rates are based on the 2018 depreciation study, effective August 1, 2019, as approved as part of the 2022 Final FERC Rate Order. |
Schedule Of Jointly Owned Utility Plants | As of December 31, 2022, TEP was a participant in the following jointly-owned generation facilities and transmission systems: ($ in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value Four Corners Units 4 and 5 7.0% $ 191 $ 5 $ (88) $ 108 Luna 33.3% 57 — 1 58 Gila River Unit 3 75.0% 204 2 (63) 143 Gila River Common Facilities 43.8% 75 — (28) 47 Springerville Coal Handling Facilities 83.0% 207 — (98) 109 Springerville Common Facilities 86.0% 404 1 (218) 187 Transmission Facilities Various 551 16 (234) 333 Total $ 1,689 $ 24 $ (728) $ 985 |
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) 2022 2021 Beginning of Period $ 139 $ 96 Liabilities Incurred (1) 1 14 Liabilities Settled (2) (8) (2) Regulatory Deferral/Accretion Expense 5 4 Revisions to the Present Value of Estimated Cash Flows (3) (16) 27 End of Period $ 121 $ 139 (1) In 2021, TEP incurred an ARO for Oso Grande. In 2022, TEP incurred an ARO for new photovoltaic generation placed in service. (2) Primarily related to the retirement of Navajo. (3) Primarily related to revised decommissioning estimates for San Juan. |
REVENUE (Tables)
REVENUE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 2020 Retail $ 1,140 $ 1,088 $ 1,039 Wholesale (1) 456 278 190 Other Services 104 114 95 Revenues from Contracts with Customers 1,700 1,480 1,324 Alternative Revenues 28 12 48 Other 80 101 53 Total Operating Revenues $ 1,808 $ 1,593 $ 1,425 (1) Change primarily due to an increase in forward market prices. |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 Retail $ 87 $ 78 Retail, Unbilled 46 44 Retail, Allowance for Credit Losses (9) (10) Wholesale (1) 132 47 Due from Affiliates (Note 6) 26 17 Other 39 17 Accounts Receivable $ 321 $ 193 (1) Includes $52 million and $16 million as of December 31, 2022 and 2021, 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) 2022 2021 Beginning of Period $ (10) $ (13) Credit Loss Expense (1) (5) — Write-offs (2) 6 3 End of Period $ (9) $ (10) (1) Credit loss expense increased due to a disconnection moratorium. (2) Write-offs increased due to the expiration of a payment plan offered during the COVID-19 pandemic. |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Table) | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 Receivables from Related Parties UNS Electric $ 22 $ 8 UNS Energy 2 7 UNS Gas 2 2 Total Due from Related Parties $ 26 $ 17 Payables to Related Parties UNS Electric $ 5 $ — UNS Gas 1 1 UNS Energy 1 1 Total Due to Related Parties $ 7 $ 2 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2022 2021 2020 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 5 $ 11 $ 9 Wholesale Revenues, UNS Electric (1)(2) 50 25 1 Control Area Services, UNS Electric (3) 3 6 4 Common Costs, UNS Energy Affiliates (4) 22 21 19 Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) 2 1 — Supplemental Workforce, SES (5) — — 14 Corporate Services, UNS Energy (6) 8 7 5 Corporate Services, UNS Energy Affiliates (7) 1 3 4 Capacity Charges, UNS Gas 1 — — Corporate Services, Fortis Affiliates (8) — — 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 8 for additional information related to the tolling PPA. In May 2022, TEP began charging UNS Electric for power purchased in the EIM on behalf of UNS Electric. (3) TEP charges UNS Electric for control area services under a FERC-filed 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 $7 million in 2022, and $6 million in each of 2021 and 2020. (7) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. (8) Fortis charges TEP for its share of payroll tax, insurance, and other costs paid by Fortis for affiliated employees. |
DEBT AND CREDIT AGREEMENT (Tabl
DEBT AND CREDIT AGREEMENT (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule Of Long-Term Debt Instruments | The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2022 2021 Notes 2012 Senior Notes (1) 3.85% 2023 $ 150 $ 150 2015 Senior Notes 3.05% 2025 300 300 2020 Senior Notes 1.50% 2030 300 300 2022 Senior Notes 3.25% 2032 325 — 2014 Senior Notes 5.00% 2044 150 150 2018 Senior Notes 4.85% 2048 300 300 2020 Senior Notes 4.00% 2050 350 350 2021 Senior Notes 3.25% 2051 325 325 Tax-Exempt Local Furnishings Bonds 2013 Pima A (2) 4.00% 2029 91 91 2012 Pima A 4.50% 2030 — 16 Tax-Exempt Pollution Control Bonds 2012 Apache A 4.50% 2030 — 177 Total Long-Term Debt (3) 2,291 2,159 Less Unamortized Discount and Debt Issuance Costs 26 24 Less Current Maturities of Long-Term Debt 150 — Total Long-Term Debt, Net $ 2,115 $ 2,135 (1) After December 15, 2022, the 2012 Senior Notes became callable at par plus accrued interest. The notes mature on March 15, 2023. (2) The 2013 Pima A bonds become callable at par on or after March 1, 2023. (3) As of December 31, 2022, 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) 2023 $ 150 2024 — 2025 300 2026 — 2027 — Thereafter 1,841 Total $ 2,291 (1) Total long-term debt excludes $17 million of related unamortized debt issuance costs and $9 million of unamortized original issue discount. |
Schedule Of Line Of Credit Facilities | Terms are as follows: Sub-Limit Swingline (1) Sub-Limit LOC Weighted Average Interest Rate Capacity Borrowed (2) Available Pricing (3)(4) ($ in millions) December 31, 2022 2021 Agreement $ 250 $ 15 $ 50 $ 5 $ 245 — % LIBOR + 1.025% or ABR + 0.025% ($ 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) The borrowed amounts include a $5 million LOC at a rate of 1.025% per annum as of December 31, 2022, and a $10 million LOC at a rate of 1.00% per annum as of December 31, 2021. This LOC was issued in October 2021 to replace an LOC originally issued in January 2020 pursuant to TEP taking ownership of Oso Grande. The LOC expires October 2023. (3) TEP's pricing may be adjusted based on performance measured using two sustainability targets: (i) the three-year average Occupational Safety and Health Administration total recordable incident rate, excluding solely COVID-19 pandemic-related incidents; and (ii) capacity targets for owned plus firm purchased power agreement renewable generation, including energy storage. (4) TEP plans to amend the 2021 Credit Agreement to provide for the transition to SOFR-based borrowings before the end of the second quarter of 2023 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments | As of December 31, 2022, TEP had the following commitments: (in millions) 2023 2024 2025 2026 2027 Thereafter Total Minimum Purchase Commitments Fuel, Including Transportation $ 107 $ 57 $ 48 $ 45 $ 44 $ 176 $ 477 Purchased Power 78 16 — — — — 94 Transmission 28 23 21 4 1 3 80 Purchase Commitments Renewable Power Purchase Agreements 80 80 79 79 79 768 1,165 RES Performance-Based Incentives 7 7 5 4 4 19 46 Total Commitments $ 300 $ 183 $ 153 $ 132 $ 128 $ 966 $ 1,862 |
EMPLOYEE BENEFITS PLANS (Tables
EMPLOYEE BENEFITS PLANS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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) 2022 2021 2022 2021 Regulatory Assets $ 90 $ 126 $ — $ 2 Regulatory Liabilities — — (8) — Regulatory and Other Assets—Other 8 — — — Accrued Employee Expenses (1) (1) (2) (3) Pension and Other Postretirement Benefits (20) (61) (49) (59) Accumulated Other Comprehensive Loss 4 13 — — Net Amount Recognized $ 81 $ 77 $ (59) $ (60) |
Schedule Of Changes In Funded Status | The table below presents the status of all TEP pension and other postretirement benefit plans. Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2022 2021 2022 2021 Change in Benefit Obligation Beginning of Period $ 600 $ 606 $ 90 $ 99 Actuarial Gain (176) (6) (17) (12) Interest Cost 16 14 2 2 Service Cost 21 20 5 6 Benefits Paid (35) (34) (6) (5) Plan Amendments (1) 1 — — — Settlements (2) (16) — — — End of Period (3) 411 600 74 90 Change in Fair Value of Plan Assets Beginning of Period 538 514 28 24 Actual Return on Plan Assets (101) 43 (4) 3 Benefits Paid (34) (32) (3) (2) Employer Contributions (4) 11 13 2 3 Settlements (2) (16) — — — End of Period (5) 398 538 23 28 Funded Status at End of Period $ (13) $ (62) $ (51) $ (62) (1) Employees promoted to officer become eligible for SERP benefits based in part on their service prior to officer promotion. These prior service costs are accounted for in this table as a plan amendment. (2) Represents the aggregate lump-sum benefit payments for plans that exceeded the threshold of service plus interest costs. The change is due to an increase in retiring employees opting to receive their benefits as a lump-sum as a result of a rise in interest rates. (3) The decrease in pension and other postretirement benefit obligations was primarily due to an increase in the discount rate. (4) TEP expects to contribute $7 million to the pension plans and less than $1 million to the VEBA trust in 2023. |
Schedule Of Information For The Pension Plans With Accumulated Benefit Obligations In Excess Of Pension Plan | The following table includes information for the pension plan with an accumulated benefit obligation in excess of pension plan assets: December 31, (in millions) 2022 2021 Accumulated Benefit Obligation $ 19 $ 26 Fair Value of Plan Assets — — |
Schedule Of Net Periodic Benefit Cost Not Yet Recognized | The following table provides the components of TEP’s regulatory assets, regulatory liabilities, and AOCL that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2022 2021 2022 2021 Net Loss (Gain) $ 93 $ 139 $ (7) $ 4 Prior Service Cost (Benefit) 1 — (1) (2) |
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) 2022 2021 2020 2022 2021 2020 Service Cost $ 21 $ 20 $ 16 $ 5 $ 6 $ 4 Non-Service Cost Interest Cost 16 14 16 2 2 3 Expected Return on Plan Assets (37) (34) (30) (1) (2) (2) Prior Service Benefit Amortization — — — (1) — — Amortization of Net Loss 7 9 8 — 1 — Effect of Settlement 3 — — — — — Net Periodic Benefit Cost $ 10 $ 9 $ 10 $ 5 $ 7 $ 5 |
Schedule Of The Changes In Plan Assets And Benefit Obligations Recognized As Regulatory Assets Or In AOCL | The changes in plan assets and benefit obligations recognized as regulatory assets, regulatory liabilities, or in AOCL were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCL Regulatory Asset/Liability (in millions) 2022 2021 2020 2022 2021 2020 2022 2021 2020 Current Year Actuarial (Gain) Loss $ (27) $ (16) $ 23 $ (9) $ — $ 5 $ (11) $ (13) $ 17 Prior Service Benefit Amortization — — — — — — 1 — — Amortization of Net Loss (6) (8) (8) (1) (1) (1) — (1) — Prior Service Cost — — — 1 — — — — — Effect of Settlement (3) — — — — — — — — Total Recognized (Gain) Loss $ (36) $ (24) $ 15 $ (9) $ (1) $ 4 $ (10) $ (14) $ 17 |
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 2022 2021 2022 2021 Discount Rate 5.7% 3.2% 5.6% 3.0% Rate of Compensation Increase 2.9% 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 2022 2021 2020 2022 2021 2020 Discount Rate, Service Cost 3.4% 3.3% 3.8% 3.2% 2.9% 3.5% Discount Rate, Interest Cost 2.7% 2.3% 3.1% 2.5% 1.9% 2.9% Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A Expected Return on Plan Assets 7.0% 6.8% 6.8% 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, 2022 2021 Next Year (Pre-65) 7.0% 6.5% Next Year (Post-65) 6.0% 5.5% Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5% Year Ultimate Rate is Reached (Pre-65) 2032 2031 Year Ultimate Rate is Reached (Post-65) 2028 2027 |
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 2022 2021 2022 2021 Asset Category Equity Securities 53 % 54 % 61 % 63 % Fixed Income Securities 39 % 40 % 38 % 35 % Real Estate 7 % 5 % — % — % Other 1 % 1 % 1 % 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, 2022 Asset Category Equity Securities: United States Large Cap — 61 — 61 United States Small Cap — 23 — 23 Non-United States — 66 — 66 Global — 61 — 61 Fixed Income — 154 — 154 Real Estate — — 30 30 Private Equity — — 3 3 Total $ — $ 365 $ 33 $ 398 (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 • 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 comparable 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, 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 Actual Return on Plan Assets: Assets Held at Reporting Date — 4 4 Purchases, Sales, and Settlements (1) — (1) Balance as of December 31, 2022 $ 3 $ 30 $ 33 |
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, 2022 Cash/Treasury Bills —% 1% Equity Securities: United States Large Cap 16% 25% United States Mid Cap —% 8% United States Small Cap 6% 4% Non-United States Developed —% 15% Non-United States Emerging —% 8% Global Equity 28% —% Global Infrastructure 3% —% Fixed Income 40% 39% 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) 2023 2024 2025 2026 2027 2028-2032 Pension Benefits $ 25 $ 26 $ 26 $ 27 $ 27 $ 149 Other Postretirement Benefits 6 6 6 6 5 28 |
SHARE-BASED COMPENSATION (Table
SHARE-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Share-Based Payment Arrangement [Abstract] | |
Schedule Of Awards | The following table represents RSUs awarded by Fortis for UNS Energy: 2022 2021 RSUs 17,996 20,794 The following table represents PSUs and RSUs awarded by UNS Energy: 2022 2021 2020 PSUs 40,793 44,931 35,328 RSUs (1) 2,409 2,401 1,918 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash And Non-Cash Transactions | CASH TRANSACTIONS Years Ended December 31, (in millions) 2022 2021 2020 Interest Paid, Net of Amounts Capitalized $ 80 $ 76 $ 76 Income Tax Refunds (1) — — (14) (1) TEP received refunds of AMT credit carryforwards in 2020 and 2019. See Note 13 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) 2022 2021 2020 Accrued Capital Expenditures $ 26 $ 38 $ 26 Renewable Energy Credits 3 3 3 Operating Leases — — 1 Asset Retirement Obligations Increase (Decrease) (1) (30) 34 (12) Net Cost of Removal Increase (Decrease) (2) (49) (41) (34) (1) In 2021, primarily represents a new obligation related to Oso Grande. In 2022, primarily represents the retirement of the San Juan asset retirement cost asset. (2) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In 2021, TEP transferred a portion of the Net Cost of Removal recorded in Regulatory Liabilities to Accumulated Depreciation and Amortization on the Consolidated Balance Sheets to reflect the impact of revised depreciation rates. In 2022, TEP reclassified a portion of the Net Cost of Removal related to San Juan to the unrecovered book value of the retiring asset. |
FAIR VALUE MEASUREMENTS AND D_2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
Schedule Of 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, 2022 Assets Restricted Cash (1) $ 35 $ — $ 35 Energy Derivative Contracts, Regulatory Recovery (2) — 100 100 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 35 104 139 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (18) (18) Total Liabilities — (18) (18) Total Assets (Liabilities), Net $ 35 $ 86 $ 121 (in millions) December 31, 2021 Assets Restricted Cash (1) $ 23 $ — $ 23 Energy Derivative Contracts, Regulatory Recovery (2) — 30 30 Energy Derivative Contracts, No Regulatory Recovery (2) — 4 4 Total Assets 23 34 57 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (20) (20) Total Liabilities — (20) (20) Total Assets (Liabilities), Net $ 23 $ 14 $ 37 (1) 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. |
Schedule Potential Offset Of Assets By Counterparty Netting And Cash Collateral | The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (1) (in millions) December 31, 2022 Derivative Assets Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76 Derivative Liabilities Energy Derivative Contracts (18) (14) — (4) (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (1) TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Consolidated Balance Sheets. As of February 9, 2023, TEP held $9 million of cash received as collateral to provide credit enhancement. |
Schedule Of Potential Offset Of Liabilities By Counterparty Netting And Cash Collateral | The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (1) (in millions) December 31, 2022 Derivative Assets Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76 Derivative Liabilities Energy Derivative Contracts (18) (14) — (4) (in millions) December 31, 2021 Derivative Assets Energy Derivative Contracts $ 34 $ 14 $ — $ 20 Derivative Liabilities Energy Derivative Contracts (20) (14) — (6) (1) TEP records cash collateral received related to energy derivative contracts in Current Liabilities—Other on the Consolidated Balance Sheets. As of February 9, 2023, TEP held $9 million of cash received as collateral to provide credit enhancement. |
Schedule Of 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) 2022 2021 2020 Unrealized Net Gain (1) $ 72 $ 62 $ 21 (1) The change in unrealized net gain on regulatory recoverable derivative contracts is primarily due to increases in forward market prices. Years Ended December 31, (in millions) 2022 2021 2020 Operating Revenues $ 11 $ 7 $ 5 |
Schedule Of Derivative Volumes | The following table presents volumes associated with the energy contracts: December 31, 2022 2021 Power Contracts GWh 1,979 2,617 Gas Contracts BBtu 96,755 112,316 |
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) 2022 2021 2022 2021 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,265 $ 2,135 $ 1,901 $ 2,357 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Schedule Of 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) 2022 2021 2020 Federal Income Tax Expense at Statutory Rate $ 52 $ 49 $ 49 State Income Tax Expense, Net of Federal Deduction 10 9 9 Federal/State Tax Credits (1) (22) (10) (3) Allowance for Equity Funds Used During Construction (1) (3) (7) Excess Deferred Income Taxes (10) (14) (7) Other 3 1 — Total Income Tax Expense $ 32 $ 32 $ 41 (1) TEP realized PTC benefits of $19 million and $7 million in 2022 and 2021, respectively, 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) 2022 2021 2020 Current Income Tax Expense Federal $ (1) $ (2) $ (2) State — — 1 Total Current Income Tax Expense (1) (2) (1) Deferred Income Tax Expense Federal 26 27 37 Federal Investment Tax Credits (1) (1) (1) State 8 8 6 Total Deferred Income Tax Expense 33 34 42 Total Income Tax Expense $ 32 $ 32 $ 41 |
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) 2022 2021 Gross Deferred Income Tax Assets Customer Advances and Contributions in Aid of Construction $ 22 $ 20 Federal General Business Credits (1) 61 32 Income Taxes Payable Through Future Rates 60 67 Other 103 99 Total Gross Deferred Income Tax Assets 246 218 Gross Deferred Income Tax Liabilities Plant, Net (735) (682) PPFAC (31) (23) Plant Abandonments (14) (8) Pensions (20) (18) Income Taxes Recoverable Through Future Rates (1) (4) Other (36) (32) Total Gross Deferred Income Tax Liabilities (837) (767) Deferred Income Taxes, Net $ (591) $ (549) (1) Includes ITC and PTC carryovers. |
Schedule Of TEP Had The Following Carryforward Amounts | As of December 31, 2022, TEP had the following carryforward amounts: ($ in millions) Amount Expiring Year Federal Net Operating Loss $ 2 None State Net Operating Loss 3 2026 - 27 State Credits 10 2023 - 29 Federal Investment Tax Credits 33 2034 - 42 Federal Production Tax Credits 26 2041 - 42 Other Federal Credits 2 2034 - 42 |
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, 2022 mi² customer | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of retail customers | customer | 443 |
Area in which subsidiary generates transmits and distributes electricity to retail electric customers (sq miles) | mi² | 1,155 |
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 (Operating Revenues) (Details) | 12 Months Ended |
Dec. 31, 2022 | |
Minimum | |
Revenue from External Customer [Line Items] | |
Contracts, payment terms | 10 days |
Maximum | |
Revenue from External Customer [Line Items] | |
Contracts, payment terms | 20 days |
NATURE OF OPERATIONS AND SUMM_6
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Restricted Cash) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Cash and Cash Equivalents | $ 16,237 | $ 9,970 | $ 61,000 | |
Total Cash, Cash Equivalents, and Restricted Cash | 50,981 | 33,489 | 82,003 | $ 28,472 |
Investments and Other Property | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | 22,000 | 20,000 | 19,000 | |
Current Assets—Other | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted cash | $ 13,000 | $ 3,000 | $ 2,000 |
NATURE OF OPERATIONS AND SUMM_7
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Average AFUDC Rates | 6.74% | 6.88% | 6.63% |
NATURE OF OPERATIONS AND SUMM_8
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Average Annual Depreciation Rates | 3.24% | 3.30% | 3.15% |
NATURE OF OPERATIONS AND SUMM_9
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule Of Lease Assets And Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Regulatory and Other Assets, Other | $ 6 | $ 7 |
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 | $ 5 | $ 6 |
Operating Leases | ||
2023 | 1 | |
2024 | 1 | |
2025 | 1 | |
2026 | 1 | |
2027 | 1 | |
Thereafter | $ 3 |
NATURE OF OPERATIONS AND SUM_10
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, 2022 | |
Public Utilities, General Disclosures [Line Items] | ||
Renewable energy target percentage by 2025 (in percentage) | 12% | |
Forecast | ||
Public Utilities, General Disclosures [Line Items] | ||
Renewable energy target percentage by 2025 (in percentage) | 15% | |
Distributed generation requirement target percentage (in percentage) | 30% |
NATURE OF OPERATIONS AND SUM_11
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy Credits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Renewable Energy Credits [Roll Forward] | ||
Beginning of Period | $ 69 | $ 66 |
Purchased | 58 | 49 |
Used for Compliance | (45) | (46) |
End of Period | $ 82 | $ 69 |
REGULATORY MATTERS (2022 Rate C
REGULATORY MATTERS (2022 Rate Case) (Details) - Arizona Corporation Commission $ in Millions | 1 Months Ended |
Jun. 30, 2022 USD ($) | |
Public Utilities, General Disclosures [Line Items] | |
Original cost rate base (percentage) | 7.31% |
Original cost rate base | $ 3,600 |
Original cost of equity (percentage) | 10.25% |
Average original cost of debt (percentage) | 3.82% |
Retail Revenues | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ 136 |
Non-fuel Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | 159 |
Fuel Related Retail Revenues | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | 66 |
P P F A C Revenues | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | (71) |
Revenues Collected from Customers | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ (18) |
REGULATORY MATTERS (2022 Final
REGULATORY MATTERS (2022 Final FERC Rate Order) (Details) - USD ($) | 1 Months Ended | ||
Mar. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Public Utilities, General Disclosures [Line Items] | |||
Regulatory liability | $ 110,782,000 | $ 111,356,000 | |
Federal Energy Regulatory Commission | Transmission Services Rate | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved 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 | $ 0 | $ 15,000,000 |
REGULATORY MATTERS (Cost Recove
REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |||
Nov. 30, 2022 | Apr. 30, 2022 | Dec. 31, 2025 | Dec. 31, 2022 | Dec. 31, 2021 | |
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 | $ 91,000,000 | $ 23,000,000 | |||
Deferred fuel and purchased power costs | 348,000,000 | 343,000,000 | |||
PPFAC and base power recoveries | (315,000,000) | (275,000,000) | |||
End of Period | $ 124,000,000 | 91,000,000 | |||
Purchased Power and Fuel Adjustment Clause | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Months approved rate in effect unless modified | 12 months | ||||
Period of recovery of uncollected true up balance approved | 18 months | ||||
Forward looking component of PPFAC rate approved | $ 0 | ||||
Renewable Energy Standard | |||||
Regulatory Liabilities [Roll Forward] | |||||
Renewable energy target percentage | 12% | ||||
Renewable energy actual percentage | 24% | ||||
Approved spending budget | $ 66,000,000 | ||||
Renewable Energy Standard | Forecast | |||||
Regulatory Liabilities [Roll Forward] | |||||
Renewable energy target percentage | 15% | ||||
Distributed generation requirement target percentage (in percentage) | 30% | ||||
Energy Efficiency Standards | |||||
Regulatory Liabilities [Roll Forward] | |||||
Percentage of cumulative annual retail kilowatt savings, actual (percentage) | 24% | ||||
Approved recovery of spending budget | $ 24,000,000 | ||||
Annual energy efficiency target, percentage | 1.30% | ||||
Lost Fixed Cost Recovery | |||||
Regulatory Liabilities [Roll Forward] | |||||
Cap on increase in lost fixed cost recovery rate (percentage) | 2% |
REGULATORY MATTERS (Regulatory
REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Assets | $ 370,000 | $ 384,000 |
Less Current Portion | 185,034 | 116,442 |
Total Non-Current Regulatory Assets | $ 184,894 | 267,669 |
Under Recovered Purchased Energy Costs | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 2 years | |
Total Regulatory Assets | $ 124,000 | 91,000 |
Pension and Other Postretirement Benefits | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | 90,000 | 128,000 |
Early Generation Retirement Costs | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 58,000 | 38,000 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Assets | $ 29,000 | 27,000 |
Lost Fixed Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Assets | $ 25,000 | 37,000 |
Final Mine Reclamation and Retiree Healthcare Costs | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 6 years | |
Total Regulatory Assets | $ 11,000 | 17,000 |
Income Taxes Recoverable through Future Rates | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 6,000 | 17,000 |
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 | |
Unamortized Loss on Reacquired Debt | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 5,000 | 5,000 |
Derivatives | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 7 years | |
Total Regulatory Assets | $ 3,000 | 8,000 |
Tax Expense Adjustor Mechanism | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Assets | $ 3,000 | 3,000 |
Springerville Unit 1 Leasehold Improvements | ||
Regulatory Assets [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Assets | $ 2,000 | 4,000 |
Useful life (in years) | 10 years | |
Other Regulatory Assets | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 14,000 | $ 9,000 |
REGULATORY MATTERS (Regulator_2
REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory Liabilities [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Liabilities | $ 489,000 | $ 463,000 |
Less Current Portion | 110,782 | 111,356 |
Total Non-Current Regulatory Liabilities | 377,546 | 352,226 |
Income Taxes Payable through Future Rates | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 244,000 | 268,000 |
Derivatives | ||
Regulatory Liabilities [Line Items] | ||
Remaining recovery period (years) | 7 years | |
Total Regulatory Liabilities | $ 86,000 | 19,000 |
Renewable Energy Standard | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 73,000 | 66,000 |
Net Cost of Removal | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 43,000 | 73,000 |
Demand Side Management | ||
Regulatory Liabilities [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Liabilities | $ 16,000 | 12,000 |
Transmission Cost Adjustor | ||
Regulatory Liabilities [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Liabilities | $ 9,000 | 9,000 |
Pension and Other Postretirement Benefits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 8,000 | 0 |
Deferred Investment Tax Credits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 7,000 | 1,000 |
Transmission Revenue Subject to Refund - FERC | ||
Regulatory Liabilities [Line Items] | ||
Remaining recovery period (years) | 1 year | |
Total Regulatory Liabilities | $ 1,000 | 15,000 |
Other Regulatory Liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 2,000 | $ 0 |
UTILITY PLANT AND JOINTLY-OWN_3
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Utility Plant in Service by Major Class) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 3.24% | 3.30% | 3.15% |
Total plant in service | $ 7,813,680 | $ 7,797,935 | |
Plant acquisition adjustments | $ (206,000) | (206,000) | |
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] | |||
Annual depreciation rate | 3.11% | ||
Average remaining life in years | 17 years | ||
Total plant in service | $ 3,491,000 | 3,753,000 | |
Distribution Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 1.93% | ||
Average remaining life in years | 32 years | ||
Total plant in service | $ 2,149,000 | 2,024,000 | |
Transmission Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 1.69% | ||
Average remaining life in years | 34 years | ||
Total plant in service | $ 1,295,000 | 1,210,000 | |
General Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 6.01% | ||
Average remaining life in years | 6 years | ||
Total plant in service | $ 653,000 | 540,000 | |
Intangible Plant, Software Costs and Other | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Average remaining life in years | 3 years | ||
Total plant in service | $ 224,000 | 268,000 | |
Plant acquisition adjustments | (4,000) | (4,000) | |
Plant Held for Future Use | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Total plant in service | $ 2,000 | $ 3,000 |
UTILITY PLANT AND JOINTLY-OWN_4
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Computer software, accumulated amortization | $ 110 | $ 169 | |
Amortization of computer software costs | 30 | 33 | $ 29 |
Plant acquisition adjustments | (206) | (206) | |
Intangible Plant, Software Costs and Other | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Plant acquisition adjustments | (4) | $ (4) | |
Future estimated amortization costs for intangible assets | |||
2023 | 26 | ||
2024 | 18 | ||
2025 | 14 | ||
2026 | 10 | ||
2027 | $ 4 |
UTILITY PLANT AND JOINTLY-OWN_5
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Jointly-Owned Facilities) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Public Utility, Property, Plant and Equipment [Line Items] | |
Plant in Service | $ 1,689 |
Construction Work in Progress | 24 |
Accumulated Depreciation | (728) |
Net Book Value | $ 985 |
Four Corners Units 4 and 5 | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 7% |
Plant in Service | $ 191 |
Construction Work in Progress | 5 |
Accumulated Depreciation | (88) |
Net Book Value | $ 108 |
Luna | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 33.30% |
Plant in Service | $ 57 |
Construction Work in Progress | 0 |
Accumulated Depreciation | 1 |
Net Book Value | $ 58 |
Gila River Unit 3 | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 75% |
Plant in Service | $ 204 |
Construction Work in Progress | 2 |
Accumulated Depreciation | (63) |
Net Book Value | $ 143 |
Gila River Common Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 43.80% |
Plant in Service | $ 75 |
Construction Work in Progress | 0 |
Accumulated Depreciation | (28) |
Net Book Value | $ 47 |
Springerville Coal Handling Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 83% |
Plant in Service | $ 207 |
Construction Work in Progress | 0 |
Accumulated Depreciation | (98) |
Net Book Value | $ 109 |
Springerville Common Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 86% |
Plant in Service | $ 404 |
Construction Work in Progress | 1 |
Accumulated Depreciation | (218) |
Net Book Value | 187 |
Transmission Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Plant in Service | 551 |
Construction Work in Progress | 16 |
Accumulated Depreciation | (234) |
Net Book Value | $ 333 |
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, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning of Period | $ 139 | $ 96 |
Liabilities incurred | 1 | 14 |
Liabilities settled | (8) | (2) |
Regulatory Deferral/Accretion Expense | 5 | 4 |
Revisions to the present value of estimated cash flows | (16) | 27 |
End of Period | $ 121 | $ 139 |
REVENUE (Details)
REVENUE (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Revenue [Line Items] | |||
Revenues from Contracts with Customers | $ 1,700,000 | $ 1,480,000 | $ 1,324,000 |
Alternative Revenues | 28,000 | 12,000 | 48,000 |
Other | 80,000 | 101,000 | 53,000 |
Total Operating Revenues | 1,808,082 | 1,592,586 | 1,424,741 |
Retail | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from Contracts with Customers | 1,140,000 | 1,088,000 | 1,039,000 |
Wholesale | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from Contracts with Customers | 456,000 | 278,000 | 190,000 |
Other Services | |||
Disaggregation of Revenue [Line Items] | |||
Revenues from Contracts with Customers | $ 104,000 | $ 114,000 | $ 95,000 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Accounts Receivable | ||
Retail, allowance for credit losses | $ (9,012) | $ (10,044) |
Accounts Receivable | 320,899 | 192,579 |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Beginning of Period | (10,044) | (13,000) |
Credit Loss Expense (1) | (5,000) | 0 |
Write-offs (2) | 6,000 | 3,000 |
End of Period | (9,012) | (10,044) |
Department of economic security payment assistance funds | 15,000 | |
Due from Affiliates | ||
Accounts Receivable | ||
Accounts receivable, gross | 26,000 | 17,000 |
Other | ||
Accounts Receivable | ||
Accounts receivable, gross | 39,000 | 17,000 |
Retail | Trade Accounts | ||
Accounts Receivable | ||
Retail, allowance for credit losses | (9,000) | (10,000) |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | ||
Beginning of Period | (10,000) | |
End of Period | (9,000) | (10,000) |
Wholesale | Derivatives | ||
Accounts Receivable | ||
Accounts receivable, gross | 52,000 | 16,000 |
Wholesale | Trade Accounts | ||
Accounts Receivable | ||
Accounts receivable, gross | 132,000 | 47,000 |
Billed Revenues | Retail | Trade Accounts | ||
Accounts Receivable | ||
Accounts receivable, gross | 87,000 | 78,000 |
Retail, Unbilled | Retail | Trade Accounts | ||
Accounts Receivable | ||
Accounts receivable, gross | $ 46,000 | $ 44,000 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | $ 26 | $ 17 | |
Payables to Related Parties | 7 | 2 | |
Transmission Revenues, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Transmission and wholesale revenue | 5 | 11 | $ 9 |
Wholesale Revenues, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Transmission and wholesale revenue | 50 | 25 | 1 |
Control Area Services, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Control area services and corporate services | 3 | 6 | 4 |
Common Costs, UNS Energy Affiliates | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Common costs, UNS energy affiliates | 22 | 21 | 19 |
Wholesale Revenues, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Revenue expenses | 2 | 1 | 0 |
Supplemental Workforce, SES | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Supplemental workforce, SES | 0 | 0 | 14 |
Corporate Services, UNS Energy | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Corporate services | $ 8 | 7 | 5 |
Intercompany allocation parent to subsidiary (in percentage) | 85% | ||
Management fee | $ 7 | 6 | 6 |
Corporate Services, UNS Energy Affiliates | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Corporate services | 1 | 3 | 4 |
Capacity Charges, UNS Gas | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Capacity charges, UNS gas | 1 | 0 | 0 |
Corporate Services, Fortis Affiliates | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Corporate services | 0 | 0 | $ 1 |
UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | 22 | 8 | |
Payables to Related Parties | 5 | 0 | |
UNS Energy | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | 2 | 7 | |
Payables to Related Parties | 1 | 1 | |
UNS Gas | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | 2 | 2 | |
Payables to Related Parties | $ 1 | $ 1 |
DEBT AND CREDIT AGREEMENT (Long
DEBT AND CREDIT AGREEMENT (Long-term Debt) (Detail) - USD ($) $ in Thousands | Dec. 31, 2022 | Feb. 28, 2022 | Dec. 31, 2021 | May 31, 2021 |
Debt Instrument [Line Items] | ||||
Long-term debt | $ 2,291,000 | $ 2,159,000 | ||
Less Unamortized Discount and Debt Issuance Costs | 26,000 | 24,000 | ||
Less Current Maturities of Long-Term Debt | 150,000 | 0 | ||
Total Long-Term Debt, Net | $ 2,114,980 | 2,134,534 | ||
2012 Senior Notes | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 3.85% | |||
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 | ||
2020 Senior Notes | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 1.50% | |||
Long-term debt | $ 300,000 | 300,000 | ||
2022 Senior Notes | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 3.25% | 3.25% | ||
Long-term debt | $ 325,000 | $ 325,000 | 0 | |
2014 Senior Notes | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 5% | |||
Long-term debt | $ 150,000 | 150,000 | ||
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% | |||
Long-term debt | $ 350,000 | 350,000 | ||
2021 Senior Notes | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 3.25% | 3.25% | ||
Long-term debt | $ 325,000 | 325,000 | $ 325,000 | |
2013 Pima A | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 4% | |||
Long-term debt | $ 91,000 | 91,000 | ||
2012 Pima A | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 4.50% | |||
Long-term debt | $ 0 | 16,000 | ||
2012 Apache A | Unsecured Debt | ||||
Debt Instrument [Line Items] | ||||
Interest Rate | 4.50% | |||
Long-term debt | $ 0 | $ 177,000 |
DEBT AND CREDIT AGREEMENT (Issu
DEBT AND CREDIT AGREEMENT (Issuances and Redemptions) (Details) - USD ($) $ in Millions | 1 Months Ended | ||||||
Jun. 30, 2022 | Mar. 31, 2022 | Aug. 31, 2021 | Dec. 31, 2022 | Feb. 28, 2022 | Dec. 31, 2021 | May 31, 2021 | |
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 2,291 | $ 2,159 | |||||
A45 Tax Exempt Bonds | Unsecured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Redemption of debt | $ 16 | $ 177 | |||||
2011 Senior Notes | Unsecured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Redemption of debt | $ 250 | ||||||
Interest rate | 5.15% | ||||||
2021 Senior Notes | Unsecured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 3.25% | 3.25% | |||||
Long-term debt | $ 325 | 325 | $ 325 | ||||
2022 Senior Notes | Unsecured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 3.25% | 3.25% | |||||
Long-term debt | $ 325 | $ 325 | $ 0 |
DEBT AND CREDIT AGREEMENT (Matu
DEBT AND CREDIT AGREEMENT (Maturities of Long-term Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Long-Term Debt Maturities | ||
2023 | $ 150 | |
2024 | 0 | |
2025 | 300 | |
2026 | 0 | |
2027 | 0 | |
Thereafter | 1,841 | |
Total | 2,291 | $ 2,159 |
Unamortized debt issuance expense | 17 | |
Debt discount | $ 9 |
DEBT AND CREDIT AGREEMENT (Cred
DEBT AND CREDIT AGREEMENT (Credit Agreements) (Details) - 2021 Agreement | 1 Months Ended | 12 Months Ended | |
Oct. 31, 2021 extension_option | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Sub-Limit LOC | |||
Short-term Debt [Line Items] | |||
Number of extensions | extension_option | 2 | ||
Extension period | 1 year | ||
Line of Credit | |||
Short-term Debt [Line Items] | |||
Borrowed | $ 5,000,000 | $ 25,000,000 | |
Available | 245,000,000 | 225,000,000 | |
Line of Credit | Revolver | |||
Short-term Debt [Line Items] | |||
Line of credit facility borrowing capacity | $ 250,000,000 | $ 250,000,000 | |
Weighted average interest rate (in percentage) | 0% | 2.53% | |
Line of Credit | Revolver | LIBOR | |||
Short-term Debt [Line Items] | |||
Basis spread on variable rate (in percentage) | 1.025% | 1% | |
Line of Credit | Revolver | Base Rate | |||
Short-term Debt [Line Items] | |||
Basis spread on variable rate (in percentage) | 0.025% | 0% | |
Line of Credit | Sub-Limit Swingline | |||
Short-term Debt [Line Items] | |||
Line of credit facility borrowing capacity | $ 15,000,000 | $ 15,000,000 | |
Line of Credit | Sub-Limit LOC | |||
Short-term Debt [Line Items] | |||
Line of credit facility borrowing capacity | 50,000,000 | 50,000,000 | |
Borrowed | $ 5,000,000 | $ 10,000,000 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Millions | Dec. 31, 2022 USD ($) MW |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
2023 | $ 300 |
2024 | 183 |
2025 | 153 |
2026 | 132 |
2027 | 128 |
Thereafter | 966 |
Total | $ 1,862 |
Maximum | Capacity, Power, and Ancillary Services | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
Power purchase agreement, in MW | MW | 300 |
UNS Electric | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
Power delivery agreement, in MW | MW | 150 |
UNS Electric | Natural Gas Service | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
Monthly service fee as percent of total charge (as percent) | 50% |
UNS Electric | Capacity Charges and Variable Power Charges | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
Monthly service fee as percent of total charge (as percent) | 50% |
Fuel, Including Transportation | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
2023 | $ 107 |
2024 | 57 |
2025 | 48 |
2026 | 45 |
2027 | 44 |
Thereafter | 176 |
Total | 477 |
Purchased Power | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
2023 | 78 |
2024 | 16 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
Thereafter | 0 |
Total | 94 |
Transmission | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
2023 | 28 |
2024 | 23 |
2025 | 21 |
2026 | 4 |
2027 | 1 |
Thereafter | 3 |
Total | 80 |
Renewable Power Purchase Agreements | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
2023 | 80 |
2024 | 80 |
2025 | 79 |
2026 | 79 |
2027 | 79 |
Thereafter | 768 |
Total | $ 1,165 |
Percentage of purchase power obligations (in percentage) | 100% |
RES Performance-Based Incentives | |
Purchase Obligation, Fiscal Year Maturity [Abstract] | |
2023 | $ 7 |
2024 | 7 |
2025 | 5 |
2026 | 4 |
2027 | 4 |
Thereafter | 19 |
Total | $ 46 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Four Corners | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs | $ 8 | ||
San Juan | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs | $ 32 | ||
San Juan and Four Corners | Other Liabilities | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs accrued | $ 37 | $ 37 | $ 40 |
COMMITMENTS AND CONTINGENCIES_4
COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee | Dec. 31, 2022 USD ($) |
Guarantor Obligations [Line Items] | |
Current carrying value | $ 0 |
Luna | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | 0 |
Four Corners | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | $ 250,000,000 |
EMPLOYEE BENEFITS PLANS (Additi
EMPLOYEE BENEFITS PLANS (Additional Information) (Details) | 12 Months Ended | ||
Dec. 31, 2022 USD ($) plan | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
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 | ||
Projected benefit obligation | $ 0 | $ 538,000,000 | |
Fair value of plan assets | $ 21,000,000 | $ 600,000,000 | |
Percentage of service cost that was capitalized (in percentage) | 21% | 22% | 22% |
Investment return model best-estimate range (in years) | 20 years | ||
Matching 401(k) contributions made | $ 7,000,000 | $ 7,000,000 | $ 6,000,000 |
Regulatory Asset | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Effect of Settlement | 3,000,000 | ||
Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 33,000,000 | 30,000,000 | 27,000,000 |
Other Postretirement Benefits | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Employer contribution to VEBA trust | 2,000,000 | 3,000,000 | 1,000,000 |
Effect of Settlement | 0 | 0 | 0 |
Fair value measurements of plan assets | 23,000,000 | 28,000,000 | 24,000,000 |
Other Postretirement Benefits | Level 1 and Level 2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 23,000,000 | 28,000,000 | |
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 | 373,000,000 | 538,000,000 | |
Effect of Settlement | (3,000,000) | 0 | 0 |
Fair value measurements of plan assets | 398,000,000 | 538,000,000 | $ 514,000,000 |
Pension Benefits | Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 33,000,000 | 30,000,000 | |
Transfers | $ 0 | ||
Minimum | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Percentile of investment return model range used (in percentage) | 25% | ||
Maximum | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Percentile of investment return model range used (in percentage) | 75% | ||
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 | $ 9,000,000 | 10,000,000 | |
Equities | Other Postretirement Benefits | Level 1 and Level 2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | $ 14,000,000 | $ 18,000,000 |
EMPLOYEE BENEFITS PLANS (Pensio
EMPLOYEE BENEFITS PLANS (Pension and Other Postretirement Benefit Amounts included in Consolidated Balance Sheet ) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | $ 370 | $ 384 |
Regulatory Liabilities | (489) | (463) |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | 90 | 126 |
Regulatory Liabilities | 0 | 0 |
Regulatory and Other Assets—Other | 8 | 0 |
Accrued Employee Expenses | (1) | (1) |
Pension and Other Postretirement Benefits | (20) | (61) |
Accumulated Other Comprehensive Loss | 4 | 13 |
Net Amount Recognized | 81 | 77 |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | 0 | 2 |
Regulatory Liabilities | (8) | 0 |
Regulatory and Other Assets—Other | 0 | 0 |
Accrued Employee Expenses | (2) | (3) |
Pension and Other Postretirement Benefits | (49) | (59) |
Accumulated Other Comprehensive Loss | 0 | 0 |
Net Amount Recognized | $ (59) | $ (60) |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | |||
Change in Benefit Obligation | |||
Beginning of Period | $ 600 | $ 606 | |
Actuarial Gain | (176) | (6) | |
Interest Cost | 16 | 14 | $ 16 |
Service Cost | 21 | 20 | 16 |
Benefits Paid | (35) | (34) | |
Plan amendments | 1 | 0 | |
Settlements | (16) | 0 | |
End of Period | 411 | 600 | 606 |
Change in Fair Value of Plan Assets | |||
Beginning of Period | 538 | 514 | |
Actual Return on Plan Assets | (101) | 43 | |
Benefits Paid | (34) | (32) | |
Employer contributions | 11 | 13 | |
Settlements | (16) | 0 | |
End of Period | 398 | 538 | 514 |
Funded Status at End of Period | (13) | (62) | |
Expected future contribution | 7 | ||
Other Postretirement Benefits | |||
Change in Benefit Obligation | |||
Beginning of Period | 90 | 99 | |
Actuarial Gain | (17) | (12) | |
Interest Cost | 2 | 2 | 3 |
Service Cost | 5 | 6 | 4 |
Benefits Paid | (6) | (5) | |
Plan amendments | 0 | 0 | |
Settlements | 0 | 0 | |
End of Period | 74 | 90 | 99 |
Change in Fair Value of Plan Assets | |||
Beginning of Period | 28 | 24 | |
Actual Return on Plan Assets | (4) | 3 | |
Benefits Paid | (3) | (2) | |
Employer contributions | 2 | 3 | |
Settlements | 0 | 0 | |
End of Period | 23 | 28 | $ 24 |
Funded Status at End of Period | (51) | $ (62) | |
Expected future contribution | $ 1 |
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, 2022 | Dec. 31, 2021 |
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items] | ||
Accumulated Benefit Obligation | $ 19 | $ 26 |
Fair Value of Plan Assets | $ 0 | $ 0 |
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, 2022 | Dec. 31, 2021 | |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net Loss (Gain) | $ 93 | $ 139 |
Prior Service Cost (Benefit) | 1 | 0 |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net Loss (Gain) | (7) | 4 |
Prior Service Cost (Benefit) | $ (1) | $ (2) |
EMPLOYEE BENEFITS PLANS (Comp_2
EMPLOYEE BENEFITS PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | $ 21 | $ 20 | $ 16 |
Non-Service Cost | |||
Interest Cost | 16 | 14 | 16 |
Expected Return on Plan Assets | (37) | (34) | (30) |
Prior Service Benefit Amortization | 0 | 0 | 0 |
Amortization of Net Loss | 7 | 9 | 8 |
Effect of Settlement | 3 | 0 | 0 |
Net Periodic Benefit Cost | 10 | 9 | 10 |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 5 | 6 | 4 |
Non-Service Cost | |||
Interest Cost | 2 | 2 | 3 |
Expected Return on Plan Assets | (1) | (2) | (2) |
Prior Service Benefit Amortization | (1) | 0 | 0 |
Amortization of Net Loss | 0 | 1 | 0 |
Effect of Settlement | 0 | 0 | 0 |
Net Periodic Benefit Cost | $ 5 | $ 7 | $ 5 |
EMPLOYEE BENEFITS PLANS (Chan_2
EMPLOYEE BENEFITS PLANS (Changes in Regulatory Assets and Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | Regulatory Asset | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | $ (27) | $ (16) | $ 23 |
Prior Service Benefit Amortization | 0 | 0 | 0 |
Amortization of Net Loss | (6) | (8) | (8) |
Prior Service Cost | 0 | 0 | 0 |
Effect of Settlement | (3) | 0 | 0 |
Total Recognized (Gain) Loss | (36) | (24) | 15 |
Pension Benefits | AOCL | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | (9) | 0 | 5 |
Prior Service Benefit Amortization | 0 | 0 | 0 |
Amortization of Net Loss | (1) | (1) | (1) |
Prior Service Cost | 1 | 0 | 0 |
Effect of Settlement | 0 | 0 | 0 |
Total Recognized (Gain) Loss | (9) | (1) | 4 |
Other Postretirement Benefits | Regulatory Asset/Liability | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | (11) | (13) | 17 |
Prior Service Benefit Amortization | 1 | 0 | 0 |
Amortization of Net Loss | 0 | (1) | 0 |
Prior Service Cost | 0 | 0 | 0 |
Effect of Settlement | 0 | 0 | 0 |
Total Recognized (Gain) Loss | $ (10) | $ (14) | $ 17 |
EMPLOYEE BENEFITS PLANS (Weight
EMPLOYEE BENEFITS PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Details) | Dec. 31, 2022 | Dec. 31, 2021 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate (in percentage) | 5.70% | 3.20% |
Rate of compensation increase (in percentage) | 2.90% | 2.80% |
Other Postretirement Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate (in percentage) | 5.60% | 3% |
EMPLOYEE BENEFITS PLANS (Weig_2
EMPLOYEE BENEFITS PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Rate of Compensation Increase | 2.80% | 2.80% | 2.80% |
Expected Return on Plan Assets | 7% | 6.80% | 6.80% |
Pension Benefits | Service cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate (in percentage) | 3.40% | 3.30% | 3.80% |
Pension Benefits | Interest Cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate (in percentage) | 2.70% | 2.30% | 3.10% |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected Return on Plan Assets | 7% | 7% | 7% |
Other Postretirement Benefits | Service cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate (in percentage) | 3.20% | 2.90% | 3.50% |
Other Postretirement Benefits | Interest Cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate (in percentage) | 2.50% | 1.90% | 2.90% |
EMPLOYEE BENEFITS PLANS (Assume
EMPLOYEE BENEFITS PLANS (Assumed Health Care Cost Trend Rates) (Details) | Dec. 31, 2022 | Dec. 31, 2021 |
Retirement Benefits [Abstract] | ||
Next year (pre-65) (in percentage) | 7% | 6.50% |
Next year (post-65) (in percentage) | 6% | 5.50% |
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, 2022 | Dec. 31, 2021 |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 100% | 100% |
Pension Benefits | Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 53% | 54% |
Pension Benefits | Fixed Income Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 39% | 40% |
Pension Benefits | Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 7% | 5% |
Pension Benefits | Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 1% | 1% |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 100% | 100% |
Other Postretirement Benefits | Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 61% | 63% |
Other Postretirement Benefits | Fixed Income Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 38% | 35% |
Other Postretirement Benefits | Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 0% | 0% |
Other Postretirement Benefits | Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 1% | 2% |
EMPLOYEE BENEFITS PLANS (Fair V
EMPLOYEE BENEFITS PLANS (Fair Value Measurements of Plan Assets By Level) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Level 3 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $ 33 | $ 30 | $ 27 |
Level 3 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 30 | 26 | 23 |
Level 3 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 3 | 4 | 4 |
Pension Benefits | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 398 | 538 | $ 514 |
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 | 61 | 77 | |
Pension Benefits | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 23 | 28 | |
Pension Benefits | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 66 | 105 | |
Pension Benefits | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 61 | 83 | |
Pension Benefits | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 154 | 213 | |
Pension Benefits | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 30 | 26 | |
Pension Benefits | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 3 | 4 | |
Pension Benefits | Level 1 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 2 | |
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 | 365 | 506 | |
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 | 61 | 77 | |
Pension Benefits | Level 2 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 23 | 28 | |
Pension Benefits | Level 2 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 66 | 105 | |
Pension Benefits | Level 2 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 61 | 83 | |
Pension Benefits | Level 2 | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 154 | 213 | |
Pension Benefits | Level 2 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
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 | 33 | 30 | |
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 | 30 | 26 | |
Pension Benefits | Level 3 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $ 3 | $ 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, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Beginning of Period | $ 30 | $ 27 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 4 | 5 |
Purchases, Sales, and Settlements | (1) | (2) |
End of Period | 33 | 30 |
Private Equity | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Beginning of Period | 4 | 4 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 0 | 2 |
Purchases, Sales, and Settlements | (1) | (2) |
End of Period | 3 | 4 |
Real Estate | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Beginning of Period | 26 | 23 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 4 | 3 |
Purchases, Sales, and Settlements | 0 | 0 |
End of Period | $ 30 | $ 26 |
EMPLOYEE BENEFITS PLANS (Target
EMPLOYEE BENEFITS PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Details) | Dec. 31, 2022 |
Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 100% |
Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 100% |
Cash/Treasury Bills | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
Cash/Treasury Bills | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 1% |
United States Large Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 16% |
United States Large Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 25% |
United States Mid Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
United States Mid Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 8% |
United States Small Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 6% |
United States Small Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 4% |
Non-United States Developed | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
Non-United States Developed | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 15% |
Non-United States Emerging | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
Non-United States Emerging | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 8% |
Global Equity | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 28% |
Global Equity | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
Global Infrastructure | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 3% |
Global Infrastructure | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
Fixed Income | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 40% |
Fixed Income | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 39% |
Real Estate | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 6% |
Real Estate | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
Private Equity | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 1% |
Private Equity | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0% |
EMPLOYEE BENEFITS PLANS (Future
EMPLOYEE BENEFITS PLANS (Future Benefit Payments) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Pension Benefits | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2023 | $ 25 |
2024 | 26 |
2025 | 26 |
2026 | 27 |
2027 | 27 |
2028-2032 | 149 |
Other Postretirement Benefits | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2023 | 6 |
2024 | 6 |
2025 | 6 |
2026 | 6 |
2027 | 5 |
2028-2032 | $ 28 |
SHARE-BASED COMPENSATION (Detai
SHARE-BASED COMPENSATION (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
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 | $ 2,000,000 | $ 2,000,000 | |
Allocated share-based compensation expense | $ 0 | $ 0 | |
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) | 17,996 | 20,794 | |
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 | $ 4,000,000 | $ 9,000,000 | |
Allocated share-based compensation expense | $ 2,000,000 | $ 4,000,000 | $ 3,000,000 |
2015 Share Unit Plan | RSUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options awarded during the period (in shares) | 2,409 | 2,401 | 1,918 |
2015 Share Unit Plan | PSUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options awarded during the period (in shares) | 40,793 | 44,931 | 35,328 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Cash Transactions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental Cash Flow Information [Abstract] | |||
Interest Paid, Net of Amounts Capitalized | $ 80 | $ 76 | $ 76 |
Income Tax Refunds | $ 0 | $ 0 | $ (14) |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental Cash Flow Information [Abstract] | |||
Accrued Capital Expenditures | $ 26 | $ 38 | $ 26 |
Renewable Energy Credits | 3 | 3 | 3 |
Operating Leases | 0 | 0 | 1 |
Asset Retirement Obligations Increase (Decrease) | (30) | 34 | (12) |
Net Cost of Removal Increase (Decrease) | $ (49) | $ (41) | $ (34) |
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, 2022 | Dec. 31, 2021 |
Assets | ||
Restricted cash | $ 35,000,000 | $ 23,000,000 |
Energy derivative contract, regulatory recovery | 100,000,000 | 30,000,000 |
Energy derivative contract, no regulatory recovery | 4,000,000 | 4,000,000 |
Total Assets | 139,000,000 | 57,000,000 |
Liabilities | ||
Energy derivative contracts, regulatory recovery | (18,000,000) | (20,000,000) |
Total Liabilities | (18,000,000) | (20,000,000) |
Total Assets (Liabilities), Net | 121,000,000 | 37,000,000 |
Level 1 | ||
Assets | ||
Restricted cash | 35,000,000 | 23,000,000 |
Energy derivative contract, regulatory recovery | 0 | 0 |
Energy derivative contract, no regulatory recovery | 0 | 0 |
Total Assets | 35,000,000 | 23,000,000 |
Liabilities | ||
Energy derivative contracts, regulatory recovery | 0 | 0 |
Total Liabilities | 0 | 0 |
Total Assets (Liabilities), Net | 35,000,000 | 23,000,000 |
Level 2 | ||
Assets | ||
Restricted cash | 0 | 0 |
Energy derivative contract, regulatory recovery | 100,000,000 | 30,000,000 |
Energy derivative contract, no regulatory recovery | 4,000,000 | 4,000,000 |
Total Assets | 104,000,000 | 34,000,000 |
Liabilities | ||
Energy derivative contracts, regulatory recovery | (18,000,000) | (20,000,000) |
Total Liabilities | (18,000,000) | (20,000,000) |
Total Assets (Liabilities), Net | 86,000,000 | $ 14,000,000 |
Level 3 | ||
Liabilities | ||
Total Assets (Liabilities), Net | $ 0 |
FAIR VALUE MEASUREMENTS AND D_4
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative - USD ($) $ in Millions | Feb. 09, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative Assets | |||
Derivative asset, gross amount recognized in the balance sheets | $ 104 | $ 34 | |
Derivative asset, counterparty netting | 14 | 14 | |
Derivative asset, cash collateral received/posted | 14 | 0 | |
Derivative asset, net amount | 76 | 20 | |
Derivative Liabilities | |||
Derivative liability, gross amount recognized in the balance sheets | (18) | (20) | |
Derivative liability, counterparty netting | (14) | (14) | |
Derivative liability, cash collateral received/posted | 0 | 0 | |
Derivative liability, net amount | $ (4) | $ (6) | |
Subsequent Event | |||
Derivative Assets | |||
Derivative asset, cash collateral received/posted | $ 9 |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Percent of gains shared with ratepayers | 10% | ||
Operating Revenues | $ 1,808,082 | $ 1,592,586 | $ 1,424,741 |
Energy Derivative | Not Designated | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized net gain | 72,000 | 62,000 | 21,000 |
Operating Revenues | $ 11,000 | $ 7,000 | $ 5,000 |
FAIR VALUE MEASUREMENTS AND D_6
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Billions | 12 Months Ended | |
Dec. 31, 2022 GWh BTU | Dec. 31, 2021 BTU GWh | |
Power Contracts GWh | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, nonmonetary notional amount | GWh | 1,979 | 2,617 |
Gas Contracts BBtu | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, nonmonetary notional amount | BTU | 96,755 | 112,316 |
FAIR VALUE MEASUREMENTS AND D_7
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative [Line Items] | ||
FV of derivative instruments in net liability positions with credit risk related features, including normal purchase normal sale | $ 86,000,000 | $ 26,000,000 |
Collateral posted | 0 | |
Additional collateral to post if credit-risk contingent features are triggered | 86,000,000 | |
Outstanding Net Payable Balances for Settled Positions | ||
Derivative [Line Items] | ||
Assets Needed for Immediate Settlement, Aggregate Fair Value | $ 73,000,000 |
FAIR VALUE MEASUREMENTS AND D_8
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Net Carrying Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 2,265 | $ 2,135 |
Fair Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 1,901 | $ 2,357 |
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Federal Income Tax Expense at Statutory Rate | $ 52,000 | $ 49,000 | $ 49,000 |
State Income Tax Expense, Net of Federal Deduction | 10,000 | 9,000 | 9,000 |
Federal/state tax credits | (22,000) | (10,000) | (3,000) |
Allowance for Equity Funds Used During Construction | (1,000) | (3,000) | (7,000) |
Excess Deferred Income Taxes | (10,000) | (14,000) | (7,000) |
Other | 3,000 | 1,000 | 0 |
Total Income Tax Expense | 32,262 | 32,476 | $ 41,452 |
Tax credit benefits | $ 19,000 | $ 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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Current Income Tax Expense | |||
Federal | $ (1,000) | $ (2,000) | $ (2,000) |
State | 0 | 0 | 1,000 |
Total Current Income Tax Expense | (1,000) | (2,000) | (1,000) |
Deferred Income Tax Expense | |||
Federal | 26,000 | 27,000 | 37,000 |
Federal Investment Tax Credits | (1,000) | (1,000) | (1,000) |
State | 8,000 | 8,000 | 6,000 |
Total Deferred Income Tax Expense | 33,000 | 34,000 | 42,000 |
Total Income Tax Expense | $ 32,262 | $ 32,476 | $ 41,452 |
INCOME TAXES (Additional Inform
INCOME TAXES (Additional Information) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Excess deferred income taxes | $ 10,000,000 | $ 14,000,000 | $ 7,000,000 |
Valuation allowance | 0 | 0 | |
Interest expense related to uncertain tax position | 0 | 0 | |
Interest payable | 0 | 0 | |
Penalties accrued | 0 | 0 | |
Intercompany | |||
Subsidiary or Equity Method Investee [Line Items] | |||
Income taxes receivable | $ 1,000,000 | $ 6,000,000 |
INCOME TAXES (The Significant C
INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Gross Deferred Income Tax Assets | ||
Customer Advances and Contributions in Aid of Construction | $ 22 | $ 20 |
Federal General Business Credits (1) | 61 | 32 |
Income Taxes Payable Through Future Rates | 60 | 67 |
Other | 103 | 99 |
Total Gross Deferred Income Tax Assets | 246 | 218 |
Gross Deferred Income Tax Liabilities | ||
Plant, Net | (735) | (682) |
PPFAC | (31) | (23) |
Plant Abandonments | (14) | (8) |
Pensions | (20) | (18) |
Income Taxes Recoverable Through Future Rates | (1) | (4) |
Other | (36) | (32) |
Total Gross Deferred Income Tax Liabilities | (837) | (767) |
Deferred Income Taxes, Net | $ (591) | $ (549) |
INCOME TAXES (Summary of Tax Ca
INCOME TAXES (Summary of Tax Carryforwards) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Federal | |
Income Tax Contingency [Line Items] | |
Net operating loss | $ 2 |
Federal Investment Tax Credits | 33 |
Federal Production Tax Credits | 26 |
Other Federal Credits | 2 |
State | |
Income Tax Contingency [Line Items] | |
Net operating loss | 3 |
Credits | $ 10 |