Cover Page
Cover Page - shares | 3 Months Ended | |
Mar. 31, 2023 | May 02, 2023 | |
Cover [Abstract] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Mar. 31, 2023 | |
Document Transition Report | false | |
Entity File Number | 1-5924 | |
Entity Registrant Name | TUCSON ELECTRIC POWER CO | |
Entity Incorporation, State or Country Code | AZ | |
Entity Tax Identification Number | 86-0062700 | |
Entity Address, Address Line One | 88 East Broadway Boulevard | |
Entity Address, City or Town | Tucson | |
Entity Address, State or Province | AZ | |
Entity Address, Postal Zip Code | 85701 | |
City Area Code | 520 | |
Local Phone Number | 571-4000 | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 32,139,434 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2023 | |
Document Fiscal Period Focus | Q1 | |
Entity Central Index Key | 0000100122 | |
Current Fiscal Year End Date | --12-31 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Income Statement [Abstract] | ||
Operating Revenues | $ 435,853 | $ 336,726 |
Operating Expenses | ||
Fuel | 124,070 | 82,964 |
Purchased Power | 36,440 | 30,544 |
Transmission and Other PPFAC Recoverable Costs | 16,599 | 16,835 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | 7,914 | (11,881) |
Total Fuel and Purchased Power | 185,023 | 118,462 |
Operations and Maintenance | 108,059 | 97,233 |
Depreciation | 47,140 | 53,598 |
Amortization | 9,691 | 9,918 |
Taxes Other Than Income Taxes | 17,277 | 16,699 |
Total Operating Expenses | 367,190 | 295,910 |
Operating Income | 68,663 | 40,816 |
Other Income (Expense) | ||
Interest Expense | (23,316) | (21,490) |
Allowance For Borrowed Funds | 1,008 | 610 |
Allowance For Equity Funds | 2,893 | 1,671 |
Unrealized Gains (Losses) on Investments | 1,360 | (2,784) |
Other, Net | 2,091 | 2,986 |
Total Other Income (Expense) | (15,964) | (19,007) |
Income Before Income Tax Expense | 52,699 | 21,809 |
Income Tax Expense | 5,806 | 2,389 |
Net Income | $ 46,893 | $ 19,420 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Cash Flows from Operating Activities | ||
Net Income | $ 46,893 | $ 19,420 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | ||
Depreciation Expense | 47,140 | 53,598 |
Amortization Expense | 9,691 | 9,918 |
Amortization of Debt Issuance Costs | 782 | 722 |
Use of Renewable Energy Credits for Compliance | 11,402 | 11,908 |
Deferred Income Taxes | 4,657 | 1,988 |
Pension and Other Postretirement Benefits Expense | 3,794 | 2,912 |
Pension and Other Postretirement Benefits Funding | (1,186) | (1,924) |
Allowance for Equity Funds Used During Construction | (2,893) | (1,671) |
Changes in Current Assets and Current Liabilities: | ||
Accounts Receivable | 133,058 | 25,842 |
Materials, Supplies, and Fuel Inventory | (10,040) | 1,305 |
Regulatory Assets | 294 | (10,252) |
Other Current Assets | (887) | 743 |
Accounts Payable and Accrued Charges | (104,341) | 6,734 |
Income Taxes Receivable/Payable | (777) | (282) |
Regulatory Liabilities | (2,818) | 593 |
Other, Net | (13,858) | (1,918) |
Net Cash Flows—Operating Activities | 120,911 | 119,636 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (116,683) | (107,734) |
Purchase Intangibles, Renewable Energy Credits | (12,961) | (12,702) |
Contributions in Aid of Construction | 799 | 3,857 |
Net Cash Flows—Investing Activities | (128,845) | (116,579) |
Cash Flows from Financing Activities | ||
Proceeds from Borrowings, Revolving Credit Facility | 0 | 5,000 |
Repayments of Borrowings, Revolving Credit Facility | 0 | (20,000) |
Proceeds from Issuance, Long-Term Debt—Net of Discount | 373,954 | 323,804 |
Repayments of Long-Term Debt | (240,745) | (177,000) |
Payment of Debt Issuance Costs | (3,738) | (2,419) |
Contribution from Parent | 5,900 | 0 |
Other, Net | (560) | 3,415 |
Net Cash Flows—Financing Activities | 134,811 | 132,800 |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 126,877 | 135,857 |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 50,981 | 33,489 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | $ 177,858 | $ 169,346 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2023 | Dec. 31, 2022 |
Utility Plant | ||
Plant in Service | $ 7,872,807 | $ 7,813,680 |
Construction Work in Progress | 338,351 | 256,044 |
Total Utility Plant | 8,211,158 | 8,069,724 |
Accumulated Depreciation and Amortization | (2,647,889) | (2,603,730) |
Total Utility Plant, Net | 5,563,269 | 5,465,994 |
Investments and Other Property | 66,079 | 74,128 |
Current Assets | ||
Cash and Cash Equivalents | 144,378 | 16,237 |
Accounts Receivable (Net of Allowance for Credit Losses of $8,106 and $9,012) | 179,661 | 320,899 |
Fuel Inventory | 36,210 | 28,681 |
Materials and Supplies | 158,161 | 155,650 |
Regulatory Assets | 200,348 | 185,034 |
Derivative Instruments | 20,525 | 27,019 |
Other | 31,436 | 30,547 |
Total Current Assets | 770,719 | 764,067 |
Regulatory and Other Assets | ||
Regulatory Assets | 182,778 | 184,894 |
Derivative Instruments | 60,107 | 77,123 |
Other | 128,360 | 123,575 |
Total Regulatory and Other Assets | 371,245 | 385,592 |
Total Assets | 6,771,312 | 6,689,781 |
Common Stock Equity: | ||
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2023 and December 31, 2022) | 1,702,439 | 1,696,539 |
Capital Stock Expense | (6,357) | (6,357) |
Retained Earnings | 1,015,260 | 968,367 |
Accumulated Other Comprehensive Loss | (2,856) | (2,884) |
Total Common Stock Equity | 2,708,486 | 2,655,665 |
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2023 and December 31, 2022) | 0 | 0 |
Long-Term Debt, Net | 2,394,930 | 2,114,980 |
Total Capitalization | 5,103,416 | 4,770,645 |
Current Liabilities | ||
Current Maturities of Long-Term Debt, Net | 0 | 149,957 |
Accounts Payable | 156,111 | 233,920 |
Accrued Taxes Other Than Income Taxes | 69,039 | 58,914 |
Accrued Employee Expenses | 28,908 | 38,459 |
Accrued Interest | 21,538 | 14,868 |
Regulatory Liabilities | 98,808 | 110,782 |
Customer Deposits | 14,310 | 14,073 |
Derivative Instruments | 20,280 | 12,752 |
Other | 38,881 | 49,163 |
Total Current Liabilities | 447,875 | 682,888 |
Regulatory and Other Liabilities | ||
Deferred Income Taxes, Net | 598,975 | 590,926 |
Regulatory Liabilities | 352,507 | 377,546 |
Pension and Other Postretirement Benefits | 69,703 | 69,048 |
Derivative Instruments | 5,348 | 4,787 |
Other | 193,488 | 193,941 |
Total Regulatory and Other Liabilities | 1,220,021 | 1,236,248 |
Commitments and Contingencies | ||
Total Capitalization and Other Liabilities | $ 6,771,312 | $ 6,689,781 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands | Mar. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Allowance for credit losses | $ 8,106 | $ 9,012 |
Common stock, shares authorized (in shares) | 75,000,000 | 75,000,000 |
Common stock, shares outstanding (in shares) | 32,139,434 | 32,139,434 |
Preferred stock, shares authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred stock, shares outstanding (in shares) | 0 | 0 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited) - USD ($) $ in Thousands | Total | Common Stock | Capital Stock Expense | Retained Earnings | Accumulated Other Comprehensive Loss |
Beginning balance at Dec. 31, 2021 | $ 2,531,209 | $ 1,696,539 | $ (6,357) | $ 850,942 | $ (9,915) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 19,420 | 19,420 | |||
Other Comprehensive Income, Net of Tax | 197 | 197 | |||
Ending balance at Mar. 31, 2022 | 2,550,826 | 1,696,539 | (6,357) | 870,362 | (9,718) |
Beginning balance at Dec. 31, 2022 | 2,655,665 | 1,696,539 | (6,357) | 968,367 | (2,884) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 46,893 | 46,893 | |||
Other Comprehensive Income, Net of Tax | 28 | 28 | |||
Contribution from Parent | 5,900 | 5,900 | |||
Ending balance at Mar. 31, 2023 | $ 2,708,486 | $ 1,702,439 | $ (6,357) | $ 1,015,260 | $ (2,856) |
NATURE OF OPERATIONS AND FINANC
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | 3 Months Ended |
Mar. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 445,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis. BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the United States Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2022 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no impact on TEP's results of operation, financial position, or cash flows. Variable Interest Entities A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is the primary beneficiary of the VIEs on a quarterly basis. As of March 31, 2023, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs were predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. Restricted Cash Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows: Three Months Ended March 31, (in millions) 2023 2022 Cash and Cash Equivalents $ 144 $ 146 Restricted Cash included in: Investments and Other Property 21 19 Current Assets—Other 13 4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 178 $ 169 Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan. Income Tax Expense TEP realized PTC benefits associated with Oso Grande of $4 million and $2 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three months ended March 31, 2023 and 2022, respectively. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) had not yet been adopted and reflected in TEP's financial statements as of March 31, 2023. New authoritative accounting guidance not listed below 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. Reference Rate Reform 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. TEP continues to evaluate the impact of ASC 848. |
REGULATORY MATTERS
REGULATORY MATTERS | 3 Months Ended |
Mar. 31, 2023 | |
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 TEP's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. RATE CASE MATTERS 2022 Rate Case In 2022, TEP filed a general rate case with the ACC based on a test year ended December 31, 2021. TEP requested new rates to be implemented by September 1, 2023. TEP's key 2022 Rate Case proposals, adjusted for rejoinder testimony filed in March 2023, include: • a non-fuel retail revenue increase of $123 million over test year non-fuel retail revenues; • a 7.04% return on original cost rate base of $3.6 billion, which includes a cost of equity of 9.75% and an average cost of debt of 3.82%; and • a new System Reliability Benefit adjustor that is designed to provide more timely recovery of TEP's energy resource investments. In January 2023, the ACC ordered that the just and equitable transition away from fossil-based generation facilities be considered as part of the 2022 Rate Case. TEP cannot predict the timing or outcome of this proceeding. 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. In November 2022, the FERC published 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 set 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. In January 2023, TEP filed a request to collect under-collected balances over 12 months. TEP cannot predict the timing or outcome of this proceeding. The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended March 31, (in millions) 2023 2022 Beginning of Period $ 124 $ 91 Deferred Fuel and Purchased Power Costs (1) 58 65 PPFAC and Base Power Recoveries (2) (64) (54) End of Period $ 118 $ 102 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) The 2022 PPFAC rate adjustment became effective in April 2022. Transmission Cost Adjustor The Transmission Cost Adjustor (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. TEP files new TCA rates with the ACC in December each year based on changes in the OATT formula rate. New TCA rates take effect in January of each year. Renewable Energy Standard The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy sales by 2025, with DG accounting for 30%. The renewable energy requirement in 2023 is 13% of retail electric sales. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES Tariff. 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. In 2022, the ACC approved an extension of the 2021 RES implementation plan through 2023. Energy Efficiency Standards TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. In November 2022, the ACC approved TEP’s 2022 energy efficiency implementation plan, with a budget of $24 million, which is collected through the DSM surcharge. The 2022 plan will remain in effect until another plan is approved. In 2022, the ACC set an annual 1.3% energy efficiency target measured by retail MWh savings over three years. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR mechanism is adjusted in each rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below: ($ in millions) Remaining Recovery Period March 31, 2023 December 31, 2022 Regulatory Assets Under Recovered Purchased Energy Costs 1 $ 118 $ 124 Pension and Other Postretirement Benefits (Note 8) Various 88 90 Early Generation Retirement Costs Various 57 58 Lost Fixed Cost Recovery 1 31 25 Property Tax Deferrals (1) 1 29 29 Derivatives (Note 9) 7 19 3 Final Mine Reclamation and Retiree Healthcare Costs (2) 6 11 11 Income Taxes Recoverable through Future Rates (3) Various 6 6 Unamortized Loss on Reacquired Debt Various 5 5 Other Regulatory Assets Various 19 19 Total Regulatory Assets 383 370 Less Current Portion 1 200 185 Total Non-Current Regulatory Assets $ 183 $ 185 Regulatory Liabilities Income Taxes Payable through Future Rates (3) Various $ 240 $ 244 Renewable Energy Standard Various 73 73 Derivatives (Note 9) 7 60 86 Net Cost of Removal (4) Various 39 43 Demand Side Management 1 15 16 Pension and Other Postretirement Benefits (Note 8) Various 8 8 Deferred Investment Tax Credits Various 7 7 Transmission Cost Adjustor 1 7 9 Other Regulatory Liabilities Various 3 3 Total Regulatory Liabilities 452 489 Less Current Portion 1 99 111 Total Non-Current Regulatory Liabilities $ 353 $ 378 (1) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. (2) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022. (3) Amortized over five years, 10 years, or the lives of the assets. (4) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Under Recovered Purchased Energy Costs, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to |
REVENUE
REVENUE | 3 Months Ended |
Mar. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE | REVENUE DISAGGREGATION OF REVENUES TEP earns most of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended March 31, (in millions) 2023 2022 Retail $ 233 $ 218 Wholesale (1) 126 56 Other Services 31 24 Revenues from Contracts with Customers 390 298 Alternative Revenues 13 11 Other 33 28 Total Operating Revenues $ 436 $ 337 (1) In 2022, the FERC issued the 2022 Final FERC Rate Order approving TEP's proposed OATT revisions. Prior to July 2022, wholesale revenues excluded an estimate of revenues probable of refund. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 3 Months Ended |
Mar. 31, 2023 | |
Receivables [Abstract] | |
ACCOUNTS RECEIVABLE | ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2023 December 31, 2022 Retail $ 65 $ 87 Retail, Unbilled 34 46 Retail, Allowance for Credit Losses (8) (9) Wholesale (1) 51 132 Due from Affiliates (Note 5) 12 26 Other 26 39 Accounts Receivable $ 180 $ 321 (1) Includes $15 million as of March 31, 2023, and $52 million as of December 31, 2022, of receivables related to revenue from derivative instruments. ALLOWANCE FOR CREDIT LOSSES TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended March 31, (in millions) 2023 2022 Beginning of Period $ (9) $ (10) Credit Loss Expense (1) — Write-offs 2 1 End of Period $ (8) $ (9) |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 3 Months Ended |
Mar. 31, 2023 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services. The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2023 December 31, 2022 Receivables from Related Parties UNS Electric $ 8 $ 22 UNS Energy 2 2 UNS Gas 2 2 Total Due from Related Parties $ 12 $ 26 Payables to Related Parties UNS Electric $ 5 $ 5 UNS Energy 3 1 UNS Gas 1 1 Total Due to Related Parties $ 9 $ 7 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended March 31, (in millions) 2023 2022 Goods and Services Provided by TEP to Affiliates Wholesale Revenues, UNS Electric (1) $ 7 $ 1 Common Costs, UNS Energy Affiliates (2) 6 5 Transmission Revenues, UNS Electric (1) 2 2 Control Area Services, UNS Electric (3) — 1 Goods and Services Provided by Affiliates to TEP Corporate Services, UNS Energy (4) $ 3 $ 3 Purchased Power, UNS Electric (1) 1 — Capacity Charges, UNS Gas (5) 1 — (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable OATT. (2) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (3) TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement. (4) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million in each of the three months ended March 31, 2023 and 2022. (5) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities. |
DEBT AND CREDIT AGREEMENT
DEBT AND CREDIT AGREEMENT | 3 Months Ended |
Mar. 31, 2023 | |
Debt Disclosure [Abstract] | |
DEBT AND CREDIT AGREEMENTS | DEBT AND CREDIT AGREEMENT There have been no significant changes to TEP's debt or credit agreement from those reported in its 2022 Annual Report on Form 10-K, except as noted below. DEBT Issuance and Redemptions In February 2023, TEP issued and sold $375 million aggregate principal amount of 5.50% senior unsecured notes due April 2053. TEP may redeem the notes prior to October 15, 2052, with a make-whole premium plus accrued interest. On or after October 15, 2052, TEP may redeem the notes at par plus accrued interest . TEP used the net proceeds to redeem and repay debt and for general corporate purposes. In March 2023, TEP repaid at maturity $150 million aggregate principal amount of 3.85% senior unsecured notes. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended |
Mar. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES COMMITMENTS There have been no significant changes to TEP's long-term commitments from those reported in its 2022 Annual Report on Form 10-K, except as noted below. Fuel, Including Transportation TEP has firm natural gas transportation agreements with capacity sufficient to meet its load requirements. In the first quarter of 2023, TEP amended and extended an agreement for gas transportation to Sundt through 2048. TEP's minimum purchase commitment is $5 million in each of 2023 through 2027 and $92 million thereafter. CONTINGENCIES Legal Matters TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. Mine Reclamation at Generation Facilities Not Operated by TEP TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation costs are subject to various assumptions, such as: (i) estimations of reclamation costs; (ii) timing of when final reclamation will occur; and (iii) the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining term of the respective coal supply agreement. TEP’s PPFAC allows the pass-through of final mine reclamation costs to retail customers as a component of fuel costs. Therefore, TEP defers these expenses until recovered from customers by recording a regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are funded. After expiration of the related coal supply agreement, TEP 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 $7 million u pon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the coal supply agreement in June 2022. As of March 31, 2023, TEP’s remaining final mine reclamation liability at San Juan was $30 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 occur by 2039. See Note 1 for additional information on restricted cash. TEP's aggregate liability balance related to San Juan and Four Corners final mine reclamation totaled $36 million and $37 million as of March 31, 2023, and December 31, 2022, respectively, and was recorded in Other on the Condensed Consolidated Balance Sheets. Performance Guarantees TEP has joint generation participation agreements with participants at Four Corners and Luna Generating Station (Luna), which expire in 2041 and 2046, respectively. The participants at Four Corners and Luna, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. There is no maximum potential amount of future payments TEP could be required to make under the Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of March 31, 2023, there have been no such payment defaults under either of the participation agreements. The Navajo Generating Station (Navajo) and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, the non-defaulting participants would seek financial recovery directly from the defaulting party. Environmental Matters TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 3 Months Ended |
Mar. 31, 2023 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, (in millions) 2023 2022 2023 2022 Service Cost $ 3 $ 5 $ 1 $ 1 Non-Service Cost (1) Interest Cost 5 4 1 — Expected Return on Plan Assets (7) (9) — — Amortization of Net Loss 1 2 — — Net Periodic Benefit Cost $ 2 $ 2 $ 2 $ 1 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. |
FAIR VALUE MEASUREMENTS AND DER
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 3 Months Ended |
Mar. 31, 2023 | |
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) March 31, 2023 Assets Restricted Cash (1) $ 27 $ — $ 27 Energy Derivative Contracts, Regulatory Recovery (2) — 65 65 Energy Derivative Contracts, No Regulatory Recovery (2) — 16 16 Total Assets 27 81 108 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (26) (26) Total Liabilities — (26) (26) Total Assets (Liabilities), Net $ 27 $ 55 $ 82 (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 (1) Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) March 31, 2023 Derivative Assets Energy Derivative Contracts $ 81 $ 15 $ — $ 66 Derivative Liabilities Energy Derivative Contracts (26) (15) — (11) (in millions) December 31, 2022 Derivative Assets Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76 Derivative Liabilities Energy Derivative Contracts (18) (14) — (4) DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly. Energy Derivative Contracts, Regulatory Recovery TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended March 31, (in millions) 2023 2022 Unrealized Net Gain (Loss) (1) $ (42) $ 89 (1) For the three months ended March 31, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas. For the three months ended March 31, 2022, unrealized net gain on regulatory recoverable derivative contracts was primarily due to increases in forward market prices of natural gas. Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended March 31, (in millions) 2023 2022 Operating Revenues $ 13 $ 8 Derivative Volumes As of March 31, 2023, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts: March 31, 2023 December 31, 2022 Power Contracts GWh 4,239 1,979 Gas Contracts BBtu 100,943 96,755 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 $27 million as of March 31, 2023, compared with $86 million as of December 31, 2022. As of March 31, 2023, TEP had no cash posted as collateral to provide credit enhancement. If the credit risk contingent features were triggered on March 31, 2023, TEP would have been required to post $27 million of collateral. As of March 31, 2023, TEP had $16 million in outstanding net payable balances for settled positions. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) March 31, 2023 December 31, 2022 March 31, 2023 December 31, 2022 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,395 $ 2,265 $ 2,124 $ 1,901 |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 3 Months Ended |
Mar. 31, 2023 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: Three Months Ended March 31, (in millions) 2023 2022 Accrued Capital Expenditures $ 47 $ 29 Renewable Energy Credits 6 6 Asset Retirement Obligation/Cost Increase (Decrease) (1) (1) (14) Net Cost of Removal Increase (Decrease) (2) (3) (1) (1) In 2022, primarily represents a reduction in the net value of asset retirement cost of San Juan for depreciation, which does not impact earnings. |
NATURE OF OPERATIONS AND FINA_2
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies) | 3 Months Ended |
Mar. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the United States Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of TEP and subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission systems with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2022 Annual Report on Form 10-K. |
Variable Interest Entities | Variable Interest Entities A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is the primary beneficiary of the VIEs on a quarterly basis. As of March 31, 2023, the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs were predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. |
Restricted Cash | Restricted CashRestricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. Restricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan. |
New Accounting Standards Issued and Not Yet Adopted | NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) had not yet been adopted and reflected in TEP's financial statements as of March 31, 2023. New authoritative accounting guidance not listed below 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. Reference Rate Reform 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. TEP continues to evaluate the impact of ASC 848. |
Derivative Instruments | DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of TEP's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and real power line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and TEP's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly. |
NATURE OF OPERATIONS AND FINA_3
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Cash, Cash Equivalents | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows: Three Months Ended March 31, (in millions) 2023 2022 Cash and Cash Equivalents $ 144 $ 146 Restricted Cash included in: Investments and Other Property 21 19 Current Assets—Other 13 4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 178 $ 169 |
Schedule of Restricted Cash | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows: Three Months Ended March 31, (in millions) 2023 2022 Cash and Cash Equivalents $ 144 $ 146 Restricted Cash included in: Investments and Other Property 21 19 Current Assets—Other 13 4 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 178 $ 169 |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Regulated Operations [Abstract] | |
Schedule of Purchased Power and Fuel Adjustment Rates | The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended March 31, (in millions) 2023 2022 Beginning of Period $ 124 $ 91 Deferred Fuel and Purchased Power Costs (1) 58 65 PPFAC and Base Power Recoveries (2) (64) (54) End of Period $ 118 $ 102 (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) The 2022 PPFAC rate adjustment became effective in April 2022. |
Schedule of Regulatory Assets and Liabilities | Regulatory assets and liabilities recorded on the Condensed Consolidated Balance Sheets are summarized in the table below: ($ in millions) Remaining Recovery Period March 31, 2023 December 31, 2022 Regulatory Assets Under Recovered Purchased Energy Costs 1 $ 118 $ 124 Pension and Other Postretirement Benefits (Note 8) Various 88 90 Early Generation Retirement Costs Various 57 58 Lost Fixed Cost Recovery 1 31 25 Property Tax Deferrals (1) 1 29 29 Derivatives (Note 9) 7 19 3 Final Mine Reclamation and Retiree Healthcare Costs (2) 6 11 11 Income Taxes Recoverable through Future Rates (3) Various 6 6 Unamortized Loss on Reacquired Debt Various 5 5 Other Regulatory Assets Various 19 19 Total Regulatory Assets 383 370 Less Current Portion 1 200 185 Total Non-Current Regulatory Assets $ 183 $ 185 Regulatory Liabilities Income Taxes Payable through Future Rates (3) Various $ 240 $ 244 Renewable Energy Standard Various 73 73 Derivatives (Note 9) 7 60 86 Net Cost of Removal (4) Various 39 43 Demand Side Management 1 15 16 Pension and Other Postretirement Benefits (Note 8) Various 8 8 Deferred Investment Tax Credits Various 7 7 Transmission Cost Adjustor 1 7 9 Other Regulatory Liabilities Various 3 3 Total Regulatory Liabilities 452 489 Less Current Portion 1 99 111 Total Non-Current Regulatory Liabilities $ 353 $ 378 (1) Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. (2) Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully recover these costs on a pay-as-you-go basis through the PPFAC mechanism. Final mine reclamation costs are expected to be funded by TEP through 2028. San Juan Unit 1 was retired in June 2022. (3) Amortized over five years, 10 years, or the lives of the assets. (4) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended. |
REVENUE (Tables)
REVENUE (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended March 31, (in millions) 2023 2022 Retail $ 233 $ 218 Wholesale (1) 126 56 Other Services 31 24 Revenues from Contracts with Customers 390 298 Alternative Revenues 13 11 Other 33 28 Total Operating Revenues $ 436 $ 337 (1) In 2022, the FERC issued the 2022 Final FERC Rate Order approving TEP's proposed OATT revisions. Prior to July 2022, wholesale revenues excluded an estimate of revenues probable of refund. |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Receivables [Abstract] | |
Accounts Receivable | The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2023 December 31, 2022 Retail $ 65 $ 87 Retail, Unbilled 34 46 Retail, Allowance for Credit Losses (8) (9) Wholesale (1) 51 132 Due from Affiliates (Note 5) 12 26 Other 26 39 Accounts Receivable $ 180 $ 321 (1) Includes $15 million as of March 31, 2023, and $52 million as of December 31, 2022, of receivables related to revenue from derivative instruments. |
Schedule of Allowance for Credit Loss | The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended March 31, (in millions) 2023 2022 Beginning of Period $ (9) $ (10) Credit Loss Expense (1) — Write-offs 2 1 End of Period $ (8) $ (9) |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Balances and Transactions | The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2023 December 31, 2022 Receivables from Related Parties UNS Electric $ 8 $ 22 UNS Energy 2 2 UNS Gas 2 2 Total Due from Related Parties $ 12 $ 26 Payables to Related Parties UNS Electric $ 5 $ 5 UNS Energy 3 1 UNS Gas 1 1 Total Due to Related Parties $ 9 $ 7 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended March 31, (in millions) 2023 2022 Goods and Services Provided by TEP to Affiliates Wholesale Revenues, UNS Electric (1) $ 7 $ 1 Common Costs, UNS Energy Affiliates (2) 6 5 Transmission Revenues, UNS Electric (1) 2 2 Control Area Services, UNS Electric (3) — 1 Goods and Services Provided by Affiliates to TEP Corporate Services, UNS Energy (4) $ 3 $ 3 Purchased Power, UNS Electric (1) 1 — Capacity Charges, UNS Gas (5) 1 — (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable OATT. (2) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (3) TEP charges UNS Electric for control area services under a FERC-filed Control Area Services Agreement. (4) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry-accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million in each of the three months ended March 31, 2023 and 2022. (5) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities. |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Retirement Benefits [Abstract] | |
Components of Net Periodic Benefit Cost | Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, (in millions) 2023 2022 2023 2022 Service Cost $ 3 $ 5 $ 1 $ 1 Non-Service Cost (1) Interest Cost 5 4 1 — Expected Return on Plan Assets (7) (9) — — Amortization of Net Loss 1 2 — — Net Periodic Benefit Cost $ 2 $ 2 $ 2 $ 1 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. |
FAIR VALUE MEASUREMENTS AND D_2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Financial Instruments Measured at Fair Value on Recurring Basis | The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Total (in millions) March 31, 2023 Assets Restricted Cash (1) $ 27 $ — $ 27 Energy Derivative Contracts, Regulatory Recovery (2) — 65 65 Energy Derivative Contracts, No Regulatory Recovery (2) — 16 16 Total Assets 27 81 108 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (26) (26) Total Liabilities — (26) (26) Total Assets (Liabilities), Net $ 27 $ 55 $ 82 (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 (1) Restricted Cash represents amounts held in money market funds, which approximates fair market value. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. |
Potential Offset of Assets by Counterparty Netting and Cash Collateral | The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) March 31, 2023 Derivative Assets Energy Derivative Contracts $ 81 $ 15 $ — $ 66 Derivative Liabilities Energy Derivative Contracts (26) (15) — (11) (in millions) December 31, 2022 Derivative Assets Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76 Derivative Liabilities Energy Derivative Contracts (18) (14) — (4) |
Potential Offset of Liabilities by Counterparty Netting and Cash Collateral | The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) March 31, 2023 Derivative Assets Energy Derivative Contracts $ 81 $ 15 $ — $ 66 Derivative Liabilities Energy Derivative Contracts (26) (15) — (11) (in millions) December 31, 2022 Derivative Assets Energy Derivative Contracts $ 104 $ 14 $ 14 $ 76 Derivative Liabilities Energy Derivative Contracts (18) (14) — (4) |
Financial Impact of Energy Contracts | The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended March 31, (in millions) 2023 2022 Unrealized Net Gain (Loss) (1) $ (42) $ 89 (1) For the three months ended March 31, 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in forward market prices of natural gas. For the three months ended March 31, 2022, unrealized net gain on regulatory recoverable derivative contracts was primarily due to increases in forward market prices of natural gas. Three Months Ended March 31, (in millions) 2023 2022 Operating Revenues $ 13 $ 8 |
Derivative Volumes | The following table presents volumes associated with the energy contracts: March 31, 2023 December 31, 2022 Power Contracts GWh 4,239 1,979 Gas Contracts BBtu 100,943 96,755 |
Face Value and Estimated Fair Value of Long-Term Debt | The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) March 31, 2023 December 31, 2022 March 31, 2023 December 31, 2022 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 2,395 $ 2,265 $ 2,124 $ 1,901 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2023 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: Three Months Ended March 31, (in millions) 2023 2022 Accrued Capital Expenditures $ 47 $ 29 Renewable Energy Credits 6 6 Asset Retirement Obligation/Cost Increase (Decrease) (1) (1) (14) Net Cost of Removal Increase (Decrease) (2) (3) (1) (1) In 2022, primarily represents a reduction in the net value of asset retirement cost of San Juan for depreciation, which does not impact earnings. |
NATURE OF OPERATIONS AND FINA_4
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Narrative) (Details) customer in Thousands, $ in Millions | 3 Months Ended | |
Mar. 31, 2023 USD ($) mi² customer | Mar. 31, 2022 USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Number of retail customers | customer | 445 | |
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi² | 1,155 | |
PTC benefits | $ | $ 4 | $ 2 |
NATURE OF OPERATIONS AND FINA_5
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands | Mar. 31, 2023 | Dec. 31, 2022 | Mar. 31, 2022 | Dec. 31, 2021 |
Cash and Cash Equivalents [Line Items] | ||||
Cash and Cash Equivalents | $ 144,378 | $ 16,237 | $ 146,000 | |
Cash, Cash Equivalents, and Restricted Cash, End of Period | 177,858 | $ 50,981 | 169,346 | $ 33,489 |
Investments and Other Property | ||||
Cash and Cash Equivalents [Line Items] | ||||
Restricted cash | 21,000 | 19,000 | ||
Current Assets—Other | ||||
Cash and Cash Equivalents [Line Items] | ||||
Restricted cash | $ 13,000 | $ 4,000 |
REGULATORY MATTERS (2022 Rate C
REGULATORY MATTERS (2022 Rate Case) (Details) - Arizona Corporation Commission $ in Millions | 1 Months Ended |
Mar. 31, 2023 USD ($) | |
Public Utilities, General Disclosures [Line Items] | |
Original cost rate base (percentage) | 7.04% |
Original cost rate base | $ 3,600 |
Original cost of equity (percentage) | 9.75% |
Average original cost of debt (percentage) | 3.82% |
Non-fuel Retail Revenues | |
Public Utilities, General Disclosures [Line Items] | |
Base rate increase (decrease) | $ 123 |
REGULATORY MATTERS (Cost Recove
REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
Jan. 31, 2023 | Nov. 30, 2022 | Apr. 30, 2022 | Mar. 31, 2023 | Mar. 31, 2022 | Dec. 31, 2025 | Dec. 31, 2021 | Dec. 31, 2022 | |
Purchased Power and Fuel Adjustment Clause | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Months approved rate in effect unless modified | 12 months | |||||||
Period of recovery of uncollected true-up balance, approved | 18 months | |||||||
Forward-looking component of PPFAC rate, approved | $ 0 | |||||||
Regulatory Assets [Roll Forward] | ||||||||
Beginning of Period | $ 124,000,000 | $ 102,000,000 | $ 124,000,000 | $ 91,000,000 | ||||
Deferred fuel and purchased power costs | 58,000,000 | 65,000,000 | ||||||
PPFAC and base power recoveries | (64,000,000) | (54,000,000) | ||||||
End of Period | $ 118,000,000 | $ 102,000,000 | $ 91,000,000 | |||||
Purchased Power and Fuel Adjustment Clause | Minimum | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Under-collected balances, duration | 12 months | |||||||
Renewable Energy Standard | ||||||||
Regulatory Assets [Roll Forward] | ||||||||
Renewable Energy Required Percentage | 13% | |||||||
Approved spending budget for the years of 2021 and 2022 | $ 66,000,000 | |||||||
Renewable Energy Standard | Scenario, Forecast | ||||||||
Regulatory Assets [Roll Forward] | ||||||||
Renewable energy target percentage | 15% | |||||||
Distributed generation requirement percent of target percentage (percentage) | 30% | |||||||
Energy Efficiency Standards | ||||||||
Regulatory Assets [Roll Forward] | ||||||||
Approved recovery of spending budget | $ 24,000,000 | |||||||
Annual energy efficiency target, percentage | 1.30% | |||||||
Lost Fixed Cost Recovery | ||||||||
Regulatory Assets [Roll Forward] | ||||||||
Cap on increase in lost fixed cost recovery rate (percentage) | 2% |
REGULATORY MATTERS (Regulatory
REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2023 | Dec. 31, 2022 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 383,000 | $ 370,000 |
Less Current Portion | 200,348 | 185,034 |
Total Non-Current Regulatory Assets | $ 182,778 | 184,894 |
Under Recovered Purchased Energy Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 118,000 | 124,000 |
Pension and Other Postretirement Benefits | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | 88,000 | 90,000 |
Early Generation Retirement Costs | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 57,000 | 58,000 |
Lost Fixed Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 31,000 | 25,000 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 29,000 | 29,000 |
Derivatives | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 7 years | |
Total Regulatory Assets | $ 19,000 | 3,000 |
Final Mine Reclamation and Retiree Healthcare Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 6 years | |
Total Regulatory Assets | $ 11,000 | 11,000 |
Income Taxes Recoverable through Future Rates | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | 6,000 | 6,000 |
Unamortized Loss on Reacquired Debt | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | 5,000 | 5,000 |
Other Regulatory Assets | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 19,000 | $ 19,000 |
REGULATORY MATTERS (Regulator_2
REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2023 | Dec. 31, 2022 | |
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 452,000 | $ 489,000 |
Less Current Portion | 98,808 | 110,782 |
Total Non-Current Regulatory Liabilities | 352,507 | 377,546 |
Income Taxes Payable through Future Rates | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 240,000 | 244,000 |
Renewable Energy Standard | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 73,000 | 73,000 |
Derivatives | ||
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 7 years | |
Total Regulatory Liabilities | $ 60,000 | 86,000 |
Net Cost of Removal | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 39,000 | 43,000 |
Demand Side Management | ||
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 15,000 | 16,000 |
Pension and Other Postretirement Benefits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 8,000 | 8,000 |
Deferred Investment Tax Credits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 7,000 | 7,000 |
Transmission Cost Adjustor | ||
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 7,000 | 9,000 |
Other Regulatory Liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 3,000 | $ 3,000 |
REGULATORY MATTERS (Regulator_3
REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details) - Income Taxes Recoverable (Payable) through Future Rates | 3 Months Ended |
Mar. 31, 2023 | |
Minimum | |
Regulatory Assets [Line Items] | |
Amortization period | 5 years |
Maximum | |
Regulatory Assets [Line Items] | |
Amortization period | 10 years |
REVENUE (Details)
REVENUE (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Disaggregation of Revenue [Line Items] | ||
Revenues from Contracts with Customers | $ 390,000 | $ 298,000 |
Alternative Revenues | 13,000 | 11,000 |
Other | 33,000 | 28,000 |
Total Operating Revenues | 435,853 | 336,726 |
Retail | ||
Disaggregation of Revenue [Line Items] | ||
Revenues from Contracts with Customers | 233,000 | 218,000 |
Wholesale | ||
Disaggregation of Revenue [Line Items] | ||
Revenues from Contracts with Customers | 126,000 | 56,000 |
Other Services | ||
Disaggregation of Revenue [Line Items] | ||
Revenues from Contracts with Customers | $ 31,000 | $ 24,000 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2023 | Mar. 31, 2022 | Dec. 31, 2022 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Retail, Allowance for Credit Losses | $ (8,106) | $ (9,000) | $ (9,012) |
Accounts Receivable | 179,661 | 320,899 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Beginning of Period | (9,012) | (10,000) | |
Credit Loss Expense | (1,000) | 0 | |
Write-offs | 2,000 | 1,000 | |
End of Period | (8,106) | $ (9,000) | |
Due from Affiliates | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts receivable, gross | 12,000 | 26,000 | |
Wholesale | Derivatives | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts receivable, gross | 15,000 | 52,000 | |
Trade Accounts Receivable | Retail | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Retail, Allowance for Credit Losses | (8,000) | (9,000) | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Beginning of Period | (9,000) | ||
End of Period | (8,000) | ||
Trade Accounts Receivable | Wholesale | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts receivable, gross | 51,000 | 132,000 | |
Other | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts receivable, gross | 26,000 | 39,000 | |
Retail | Trade Accounts Receivable | Retail | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts receivable, gross | 65,000 | 87,000 | |
Retail, Unbilled | Trade Accounts Receivable | Retail | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts receivable, gross | $ 34,000 | $ 46,000 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2023 | Mar. 31, 2022 | Dec. 31, 2022 | |
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Total Due from Related Parties | $ 12 | $ 26 | |
Total Due to Related Parties | 9 | 7 | |
Wholesale Revenues, UNS Electric | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Revenue from related party | 7 | $ 1 | |
Common Costs, UNS Energy Affiliates | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Common costs | 6 | 5 | |
Transmission Revenues, UNS Electric | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Revenue from related party | 2 | 2 | |
Control Area Services, UNS Electric | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Control area services | 0 | 1 | |
Corporate Services, UNS Energy | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Corporate services | $ 3 | 3 | |
Massachusetts formula - TEP's allocation (percentage) | 85% | ||
Management fee | $ 2 | 2 | |
Purchased Power, UNS Electric | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Wholesale purchases | 1 | 0 | |
UNS Gas to TEP | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Capacity charges | 1 | $ 0 | |
UNS Electric | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Total Due from Related Parties | 8 | 22 | |
Total Due to Related Parties | 5 | 5 | |
UNS Energy | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Total Due from Related Parties | 2 | 2 | |
Total Due to Related Parties | 3 | 1 | |
UNS Gas | |||
Related Party Transaction, Due to/from Related Party [Abstract] | |||
Total Due from Related Parties | 2 | 2 | |
Total Due to Related Parties | $ 1 | $ 1 |
DEBT AND CREDIT AGREEMENT (Deta
DEBT AND CREDIT AGREEMENT (Details) - Unsecured Debt - USD ($) | 1 Months Ended | |
Mar. 31, 2023 | Feb. 28, 2023 | |
5.50% Senior Unsecured Notes due April 2053 | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 375,000,000 | |
Proceeds from issuance of debt | $ 375,000,000 | |
Interest rate | 5.50% | |
3.85% Percent Senior Unsecured Notes Due 2023 | ||
Debt Instrument [Line Items] | ||
Interest rate | 3.85% | |
Debt extinguishment | $ 150,000,000 | |
4% Tax Exempt Bonds | ||
Debt Instrument [Line Items] | ||
Interest rate | 4% | |
Debt extinguishment | $ 91,000,000 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Fuel, Including Transportation) (Details) $ in Millions | Mar. 31, 2023 USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Minimum purchase commitment 2023 | $ 5 |
Minimum purchase commitment 2024 | 5 |
Minimum purchase commitment 2025 | 5 |
Minimum purchase commitment 2026 | 5 |
Minimum purchase commitment 2027 | 5 |
Minimum purchase commitment thereafter | $ 92 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Mine Reclamation) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2023 | Mar. 31, 2023 | Dec. 31, 2022 | |
San Juan and Four Corners | Other Liabilities | |||
Jointly Owned Utility Plant Interests [Line Items] | |||
Reclamation costs accrued | $ 36 | $ 36 | $ 37 |
Four Corners | |||
Jointly Owned Utility Plant Interests [Line Items] | |||
Reclamation anticipated costs | $ 7 | ||
San Juan | |||
Jointly Owned Utility Plant Interests [Line Items] | |||
Reclamation anticipated costs | $ 30 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee | Mar. 31, 2023 USD ($) |
Guarantor Obligations [Line Items] | |
Current carrying value | $ 0 |
Luna | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | 0 |
Four Corners | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | $ 250,000,000 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Pension Benefits | ||
Components of Net Periodic Benefit Plan Cost | ||
Service Cost | $ 3 | $ 5 |
Non-Service Cost | ||
Interest Cost | 5 | 4 |
Expected Return on Plan Assets | (7) | (9) |
Amortization of Net Loss | 1 | 2 |
Net Periodic Benefit Cost | 2 | 2 |
Other Postretirement Benefits | ||
Components of Net Periodic Benefit Plan Cost | ||
Service Cost | 1 | 1 |
Non-Service Cost | ||
Interest Cost | 1 | 0 |
Expected Return on Plan Assets | 0 | 0 |
Amortization of Net Loss | 0 | 0 |
Net Periodic Benefit Cost | $ 2 | $ 1 |
FAIR VALUE MEASUREMENTS AND D_3
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Recurring - USD ($) | Mar. 31, 2023 | Dec. 31, 2022 |
Assets | ||
Restricted cash | $ 27,000,000 | $ 35,000,000 |
Energy derivative contract assets - regulatory recovery | 65,000,000 | 100,000,000 |
Energy derivative contract assets - no regulatory recovery | 16,000,000 | 4,000,000 |
Total Assets | 108,000,000 | 139,000,000 |
Liabilities | ||
Energy derivative contract liabilities - regulatory recovery | (26,000,000) | (18,000,000) |
Total Liabilities | (26,000,000) | (18,000,000) |
Total Assets (Liabilities), Net | 82,000,000 | 121,000,000 |
Level 1 | ||
Assets | ||
Restricted cash | 27,000,000 | 35,000,000 |
Energy derivative contract assets - regulatory recovery | 0 | 0 |
Energy derivative contract assets - no regulatory recovery | 0 | 0 |
Total Assets | 27,000,000 | 35,000,000 |
Liabilities | ||
Energy derivative contract liabilities - regulatory recovery | 0 | 0 |
Total Liabilities | 0 | 0 |
Total Assets (Liabilities), Net | 27,000,000 | 35,000,000 |
Level 2 | ||
Assets | ||
Restricted cash | 0 | 0 |
Energy derivative contract assets - regulatory recovery | 65,000,000 | 100,000,000 |
Energy derivative contract assets - no regulatory recovery | 16,000,000 | 4,000,000 |
Total Assets | 81,000,000 | 104,000,000 |
Liabilities | ||
Energy derivative contract liabilities - regulatory recovery | (26,000,000) | (18,000,000) |
Total Liabilities | (26,000,000) | (18,000,000) |
Total Assets (Liabilities), Net | 55,000,000 | $ 86,000,000 |
Level 3 | ||
Liabilities | ||
Total Assets (Liabilities), Net | $ 0 |
FAIR VALUE MEASUREMENTS AND D_4
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative Contracts - USD ($) $ in Millions | Mar. 31, 2023 | Dec. 31, 2022 |
Derivative Assets | ||
Gross Amount Recognized in the Balance Sheets | $ 81 | $ 104 |
Counterparty Netting of Energy Contracts | 15 | 14 |
Cash collateral received/posted | 0 | 14 |
Net Amount | 66 | 76 |
Derivative Liabilities | ||
Gross Amount Recognized in the Balance Sheets | (26) | (18) |
Counterparty Netting of Energy Contracts | (15) | (14) |
Cash collateral received/posted | 0 | 0 |
Net Amount | $ (11) | $ (4) |
FAIR VALUE MEASUREMENTS AND D_5
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Percent of long-term trading contract gains shared with customers (percentage) | 10% | |
Operating Revenues | $ 435,853 | $ 336,726 |
Energy Derivative Contracts | Not Designated as Hedging Instrument | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized net gain (loss) | (42,000) | 89,000 |
Operating Revenues | $ 13,000 | $ 8,000 |
FAIR VALUE MEASUREMENTS AND D_6
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BTU in Billions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2023 GWh BTU | Dec. 31, 2022 BTU GWh | |
Power Contracts GWh | ||
Derivative Volume [Line Items] | ||
Derivative, energy measure | GWh | 4,239 | 1,979 |
Gas Contracts BBtu | ||
Derivative Volume [Line Items] | ||
Derivative, energy measure | BTU | 100,943 | 96,755 |
FAIR VALUE MEASUREMENTS AND D_7
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) | Mar. 31, 2023 | Dec. 31, 2022 |
Derivative [Line Items] | ||
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale | $ 27,000,000 | $ 86,000,000 |
Collateral posted | 0 | |
Additional collateral required to post if credit-risk contingent features are triggered | 27,000,000 | |
Amount relating to outstanding net payable balances for settled positions | ||
Derivative [Line Items] | ||
Assets needed for immediate settlement, aggregate fair value | $ 16,000,000 |
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 | Mar. 31, 2023 | Dec. 31, 2022 |
Net Carrying Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 2,395 | $ 2,265 |
Fair Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 2,124 | $ 1,901 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2023 | Mar. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | ||
Accrued Capital Expenditures | $ 47 | $ 29 |
Renewable Energy Credits | 6 | 6 |
Asset Retirement Obligation/Cost Increase (Decrease) | (1) | (14) |
Net Cost of Removal Increase (Decrease) | $ (3) | $ (1) |