Cover Page
Cover Page - shares | 6 Months Ended | |
Jun. 30, 2020 | Jul. 29, 2020 | |
Cover [Abstract] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Jun. 30, 2020 | |
Document Transition Report | false | |
Entity File Number | 1-5924 | |
Entity Registrant Name | TUCSON ELECTRIC POWER CO | |
Entity Incorporation, State or Country Code | AZ | |
Entity Tax Identification Number | 86-0062700 | |
Entity Address, Address Line One | 88 East Broadway Boulevard | |
Entity Address, City or Town | Tucson | |
Entity Address, State or Province | AZ | |
Entity Address, Postal Zip Code | 85701 | |
City Area Code | 520 | |
Local Phone Number | 571-4000 | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 32,139,434 | |
Entity Central Index Key | 0000100122 | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2020 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Income Statement [Abstract] | ||||
Operating Revenues | $ 339,705 | $ 326,091 | $ 618,261 | $ 659,094 |
Operating Expenses | ||||
Fuel | 62,697 | 75,441 | 125,996 | 164,859 |
Purchased Power | 28,833 | 27,345 | 47,151 | 60,195 |
Transmission and Other PPFAC Recoverable Costs | 12,005 | 12,094 | 22,600 | 24,019 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | 6,378 | (10,918) | 5,196 | (4,713) |
Total Fuel and Purchased Power | 109,913 | 103,962 | 200,943 | 244,360 |
Operations and Maintenance | 84,032 | 92,045 | 171,487 | 178,633 |
Depreciation | 47,123 | 41,427 | 93,622 | 82,744 |
Amortization | 7,042 | 7,397 | 13,998 | 15,014 |
Taxes Other Than Income Taxes | 14,643 | 14,120 | 29,552 | 28,321 |
Total Operating Expenses | 262,753 | 258,951 | 509,602 | 549,072 |
Operating Income | 76,952 | 67,140 | 108,659 | 110,022 |
Other Income (Expense) | ||||
Interest Expense | (22,572) | (22,144) | (43,053) | (44,275) |
Allowance For Borrowed Funds | 2,013 | 1,303 | 4,895 | 2,577 |
Allowance For Equity Funds | 7,189 | 3,398 | 10,223 | 6,721 |
Unrealized Gains (Losses) on Investments | 3,276 | 934 | (3,151) | 4,014 |
Other, Net | 1,339 | (92) | 2,192 | 116 |
Total Other Income (Expense) | (8,755) | (16,601) | (28,894) | (30,847) |
Income Before Income Tax Expense | 68,197 | 50,539 | 79,765 | 79,175 |
Income Tax Expense | 10,707 | 8,476 | 14,357 | 10,917 |
Net Income | $ 57,490 | $ 42,063 | $ 65,408 | $ 68,258 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Statement of Comprehensive Income [Abstract] | ||||
Net Income | $ 57,490 | $ 42,063 | $ 65,408 | $ 68,258 |
Net Changes in Fair Value of Cash Flow Hedges: | ||||
Net of Income Tax Expense | 0 | 24 | 0 | 52 |
Supplemental Executive Retirement Plan Adjustments: | ||||
Net of Income Tax Expense | 135 | 66 | 270 | 132 |
Total Other Comprehensive Income, Net of Tax | 135 | 90 | 270 | 184 |
Total Comprehensive Income | $ 57,625 | $ 42,153 | $ 65,678 | $ 68,442 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Statement of Comprehensive Income [Abstract] | ||||
Tax Expense Related to Change in Fair Value of Cash Flow Hedges | $ 0 | $ 8 | $ 0 | $ 17 |
Tax Expense Related to Supplemental Executive Retirement Plan Adjustments | $ 45 | $ 22 | $ 90 | $ 44 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2020 | Jun. 30, 2019 | |
Cash Flows from Operating Activities | ||
Net Income | $ 65,408 | $ 68,258 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | ||
Depreciation Expense | 93,622 | 82,744 |
Amortization Expense | 13,998 | 15,014 |
Amortization of Debt Issuance Costs | 1,280 | 1,153 |
Use of Renewable Energy Credits for Compliance | 21,664 | 18,624 |
Deferred Income Taxes | 19,866 | 14,244 |
Pension and Other Postretirement Benefits Expense | 7,442 | 8,881 |
Pension and Other Postretirement Benefits Funding | (4,955) | (6,431) |
Allowance for Equity Funds Used During Construction | (10,223) | (6,721) |
Regulatory Deferral, ACC Refund Order | 8,817 | 3,156 |
Changes in Current Assets and Current Liabilities: | ||
Accounts Receivable | (11,386) | 5,910 |
Materials, Supplies, and Fuel Inventory | 3,847 | (4,689) |
Regulatory Assets | (1,500) | (151) |
Other Current Assets | 2,121 | 1,766 |
Accounts Payable and Accrued Charges | (20,317) | (32,061) |
Income Taxes Receivable, Net | (7,154) | (3,326) |
Regulatory Liabilities | 3,213 | (4,507) |
Other, Net | 2,661 | 969 |
Net Cash Flows—Operating Activities | 188,404 | 162,833 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (473,881) | (199,791) |
Purchase Intangibles, Renewable Energy Credits | (25,746) | (24,793) |
Purchase, Other Investments | 8,556 | 0 |
Contributions in Aid of Construction | 2,329 | 3,932 |
Net Cash Flows—Investing Activities | (505,854) | (220,652) |
Cash Flows from Financing Activities | ||
Proceeds from Borrowings, Revolving Credit Facility | 105,000 | 0 |
Repayments of Borrowings, Revolving Credit Facility | (105,000) | 0 |
Proceeds from Borrowings, Term Loan | 60,000 | 0 |
Repayments of Borrowings, Term Loan | (225,000) | 0 |
Proceeds from Issuance, Long-Term Debt—Net of Discount | 346,983 | 0 |
Payments of Finance Lease Obligations | (11,535) | (10,889) |
Contribution from Parent | 200,000 | 0 |
Other, Net | (2,632) | (166) |
Net Cash Flows—Financing Activities | 367,816 | (11,055) |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 50,366 | (68,874) |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 28,472 | 152,747 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | $ 78,838 | $ 83,873 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2020 | Dec. 31, 2019 |
Utility Plant | ||
Plant in Service | $ 6,902,038 | $ 6,663,912 |
Utility Plant Under Finance Leases | 151,467 | 151,467 |
Construction Work in Progress | 483,450 | 303,488 |
Total Utility Plant | 7,536,955 | 7,118,867 |
Accumulated Depreciation and Amortization | (2,559,434) | (2,506,686) |
Accumulated Amortization of Finance Lease Assets | (82,160) | (77,285) |
Total Utility Plant, Net | 4,895,361 | 4,534,896 |
Investments and Other Property | 67,049 | 62,136 |
Current Assets | ||
Cash and Cash Equivalents | 60,895 | 9,762 |
Accounts Receivable (Net of Allowance for Credit Losses of $6,679 and $5,716) | 166,855 | 154,847 |
Fuel Inventory | 24,672 | 23,731 |
Materials and Supplies | 116,755 | 121,542 |
Regulatory Assets | 123,848 | 138,412 |
Derivative Instruments | 8,771 | 3,596 |
Other | 26,839 | 21,416 |
Total Current Assets | 528,635 | 473,306 |
Regulatory and Other Assets | ||
Regulatory Assets | 322,072 | 326,860 |
Derivative Instruments | 3,872 | 2,763 |
Other | 92,347 | 89,196 |
Total Regulatory and Other Assets | 418,291 | 418,819 |
Total Assets | 5,909,336 | 5,489,157 |
Common Stock Equity: | ||
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2020 and December 31, 2019) | 1,596,539 | 1,396,539 |
Capital Stock Expense | (6,357) | (6,357) |
Retained Earnings | 661,200 | 595,792 |
Accumulated Other Comprehensive Loss | (7,501) | (7,771) |
Total Common Stock Equity | 2,243,881 | 1,978,203 |
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2020 and December 31, 2019) | 0 | 0 |
Finance Lease Obligations | 0 | 67,316 |
Long-Term Debt, Net | 1,865,995 | 1,522,087 |
Total Capitalization | 4,109,876 | 3,567,606 |
Current Liabilities | ||
Current Maturities of Long-Term Debt, Net | 80,383 | 80,330 |
Borrowings Under Credit Agreements, Net | 0 | 165,000 |
Finance Lease Obligations | 72,868 | 17,086 |
Accounts Payable | 108,376 | 136,465 |
Accrued Taxes Other than Income Taxes | 48,220 | 42,741 |
Accrued Employee Expenses | 28,520 | 32,567 |
Accrued Interest | 17,470 | 16,700 |
Regulatory Liabilities | 100,190 | 96,017 |
Customer Deposits | 20,871 | 24,568 |
Derivative Instruments | 14,059 | 27,615 |
Other | 26,420 | 23,678 |
Total Current Liabilities | 517,377 | 662,767 |
Regulatory and Other Liabilities | ||
Deferred Income Taxes, Net | 459,920 | 432,484 |
Regulatory Liabilities | 466,261 | 477,495 |
Pension and Other Postretirement Benefits | 132,086 | 133,452 |
Derivative Instruments | 52,099 | 48,697 |
Other | 171,717 | 166,656 |
Total Regulatory and Other Liabilities | 1,282,083 | 1,258,784 |
Commitments and Contingencies | ||
Total Capitalization and Other Liabilities | $ 5,909,336 | $ 5,489,157 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Thousands | Jun. 30, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Allowance for Credit Losses | $ 6,679 | $ 5,716 |
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_5
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, 2018 | $ 1,819,745 | $ 1,346,539 | $ (6,357) | $ 484,277 | $ (4,714) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 68,258 | 68,258 | |||
Other Comprehensive Income, Net of Tax | 184 | 184 | |||
Ending balance at Jun. 30, 2019 | 1,888,187 | 1,346,539 | (6,357) | 552,535 | (4,530) |
Beginning balance at Mar. 31, 2019 | 1,846,034 | 1,346,539 | (6,357) | 510,472 | (4,620) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 42,063 | 42,063 | |||
Other Comprehensive Income, Net of Tax | 90 | 90 | |||
Ending balance at Jun. 30, 2019 | 1,888,187 | 1,346,539 | (6,357) | 552,535 | (4,530) |
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 | 65,408 | 65,408 | |||
Other Comprehensive Income, Net of Tax | 270 | 270 | |||
Contribution from Parent | 200,000 | 200,000 | |||
Ending balance at Jun. 30, 2020 | 2,243,881 | 1,596,539 | (6,357) | 661,200 | (7,501) |
Beginning balance at Mar. 31, 2020 | 2,136,256 | 1,546,539 | (6,357) | 603,710 | (7,636) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 57,490 | 57,490 | |||
Other Comprehensive Income, Net of Tax | 135 | 135 | |||
Contribution from Parent | 50,000 | 50,000 | |||
Ending balance at Jun. 30, 2020 | $ 2,243,881 | $ 1,596,539 | $ (6,357) | $ 661,200 | $ (7,501) |
NATURE OF OPERATIONS AND FINANC
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | 6 Months Ended |
Jun. 30, 2020 | |
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 432,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis. BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. 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 2019 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. Most notably, TEP bifurcated Other, Net on the Condensed Consolidated Statements of Income as follows: As Filed Amount Reclassified As Reclassified As Filed Amount Reclassified As Reclassified (in thousands) Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Other Income (Expense) Other, Net $ 842 $ (934 ) $ (92 ) $ 4,130 $ (4,014 ) $ 116 Unrealized Gains (Losses) on Investments — 934 934 — 4,014 4,014 Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis. As of June 30, 2020 , the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. Restricted Cash Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: June 30, (in millions) 2020 2019 Cash and Cash Equivalents $ 61 $ 70 Restricted Cash included in: Investments and Other Property 16 13 Current Assets—Other 2 1 Total Cash, Cash Equivalents, and Restricted Cash $ 79 $ 84 Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2020. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. Credit Losses TEP adopted accounting guidance that requires entities to incorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. See Note 4 for additional disclosure about TEP's allowance for credit losses. 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. |
REGULATORY MATTERS
REGULATORY MATTERS | 6 Months Ended |
Jun. 30, 2020 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect TEP's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. 2019 ACC RATE CASE In April 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018. TEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019, include: • a non-fuel retail revenue increase of $99 million , partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $60 million over test year retail revenues; • a 7.49% return on original cost rate base of $2.7 billion , which includes a cost of equity of 10.00% and an average cost of debt of 4.65% ; • a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the purchase of Gila River Unit 2 and the installation of the Sundt RICE Units; • a TEAM that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and • a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC. Hearings before an ALJ were held during the first six months of 2020. Parties to the rate case will file post-hearing briefs in July and August 2020. As a result of work schedule disruptions arising from the COVID-19 pandemic, the timing of when new rates will go into effect is uncertain. TEP cannot predict the outcome of the proceeding. 2019 FERC RATE CASE In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. Provisions of the order include, but are not limited to: • replacing TEP's stated transmission rates with a forward-looking formula rate; • a 10.4% return on equity; and • elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate. The requested forward-looking formula rate is intended to allow for a more timely recovery of transmission related costs. As part of the order, the FERC established hearing and settlement procedures. All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. TEP had reserved $9 million as of June 30, 2020 , and $4 million as of December 31, 2019 , of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP cannot predict the outcome of the proceeding. FEDERAL TAX LEGISLATION Arizona Corporation Commission In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of customer bill credits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018 (ACC Refund Order). The ACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. The table below summarizes the regulatory asset (liability) over or under collected balance related to the ACC Refund Order: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Beginning of Period $ — $ 3 $ — $ 4 ACC Refund (Reduction in Operating Revenues) (9 ) (9 ) (16 ) (16 ) Amount Returned to Customers through Bill Credits 5 6 8 10 Regulatory Deferral 5 1 9 3 End of Period $ 1 $ 1 $ 1 $ 1 Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. TEP filed an informational filing with the ACC to establish a 2020 customer refund of $35 million . The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our rate case. A regulatory liability balance related to the deferred TCJA customer refunds of $17 million as of June 30, 2020 , and $8 million as of December 31, 2019 , was recorded in Regulatory and Other Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is typically adjusted annually on April 1st and goes into effect for the subsequent 12 -month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12 -month period. The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Beginning of Period $ 36 $ (22 ) $ 36 $ (17 ) Deferred Fuel and Purchased Power Costs (1) 67 75 115 128 PPFAC and Base Power Recoveries (2) (75 ) (62 ) (123 ) (120 ) End of Period $ 28 $ (9 ) $ 28 $ (9 ) (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. In March 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2020. Renewable Energy Standard The ACC’s Renewable Energy Standard (RES) requires Arizona-regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2020 is 10% of retail electric sales, which will increase annually until renewable retail sales represent at least 15% by 2025 . DG will account for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. In 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million . The recovery funds: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Energy Efficiency Standards TEP is required to implement cost-effective DSM programs to comply with the ACC’s Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 2020 and 2019 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income. In 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million , which is collected through the DSM surcharge, and approved a waiver of the 2018 EE Standard. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans. In June 2020, TEP filed its 2021 energy efficiency implementation plan with a budget of approximately $23 million . TEP cannot predict the outcome of the proceeding. TEP filed a request with the ACC in April 2020 to refund to customers approximately $8 million of over-collected DSM funds as a result of the COVID-19 pandemic. In May 2020, the ACC approved the request and TEP returned the funds in the form of customer bill credits over the June 2020 billing cycle. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when amounts are verifiable regardless of when the lost retail kWh sales occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues. The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 LFCR Revenues $ 10 $ 6 $ 22 $ 16 REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: ($ in millions) Remaining Recovery Period (years) June 30, 2020 December 31, 2019 Regulatory Assets Pension and Other Postretirement Benefits Various $ 131 $ 135 Early Generation Retirement Costs Various 64 68 Derivatives (Note 9) 10 59 72 Lost Fixed Cost Recovery 2 57 46 Income Taxes Recoverable through Future Rates (1) Various 33 38 Under Recovered Purchased Energy Costs 1 28 36 Property Tax Deferrals (2) 1 25 24 Final Mine Reclamation and Retiree Healthcare Costs (3) 9 22 19 Springerville Unit 1 Leasehold Improvements (4) 3 8 9 Other Regulatory Assets Various 19 18 Total Regulatory Assets 446 465 Less Current Portion 1 124 138 Total Non-Current Regulatory Assets $ 322 $ 327 Regulatory Liabilities Income Taxes Payable through Future Rates (1) Various $ 315 $ 327 Net Cost of Removal (5) Various 156 164 Renewable Energy Standard Various 60 59 Deferred Investment Tax Credits (6) Various 2 3 Other Regulatory Liabilities Various 33 20 Total Regulatory Liabilities 566 573 Less Current Portion 1 100 96 Total Non-Current Regulatory Liabilities $ 466 $ 477 (1) Amortized over the lives of the assets. (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. This asset is fully recovered in rates with a recovery period of approximately six months . (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. The majority of final mine reclamation costs are expected to be funded by TEP through 2028 . (4) Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe and reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year period. (5) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. (6) Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates, TEP does not pay a return on regulatory liabilities. PLANT IN SERVICE Under an air permit approved by the Pima County Department of Environmental Quality, TEP placed in service five natural gas RICE units at Sundt in December 2019 and an additional five units in March 2020. There was $183 million as of June 30, 2020 , and $82 million , as of December 31, 2019 , related to the Sundt RICE Units recorded in Plant in Service on the Condensed Consolidated Balance Sheets. The 10 units have a total nominal generation capacity of 188 MW. |
REVENUE
REVENUE | 6 Months Ended |
Jun. 30, 2020 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE | REVENUE DISAGGREGATION OF REVENUES TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Retail $ 265 $ 236 $ 457 $ 438 Wholesale (1) 30 43 66 127 Other Services 23 30 47 54 Revenues from Contracts with Customers 318 309 570 619 Alternative Revenues 10 6 24 18 Other 12 11 24 22 Total Operating Revenues (2) $ 340 $ 326 $ 618 $ 659 (1) In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the 2019 FERC Rate Case. (2) Calculated on rounded data and may not correspond exactly to TEP's Operating Revenues reported on the Condensed Consolidated Statements of Income. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 6 Months Ended |
Jun. 30, 2020 | |
Receivables [Abstract] | |
ACCOUNTS RECEIVABLE | ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2020 December 31, 2019 Retail $ 76 $ 61 Retail, Unbilled 62 42 Retail, Allowance for Credit Losses (7 ) (6 ) Wholesale (1) 19 31 Due from Affiliates (Note 5) 6 8 Other 11 19 Accounts Receivable $ 167 $ 155 (1) Includes $3 million as of June 30, 2020 , and $5 million as of December 31, 2019 , of receivables related to revenue from derivative instruments. 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 collection patterns, sales, current conditions, and reasonable and supportable forecasts. Based on these factors, TEP has not recorded an allowance for credit losses on non-retail trade receivables as of June 30, 2020 and December 31, 2019 . 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 Six Months Ended (in millions) June 30, 2020 June 30, 2020 Beginning of Period $ (6 ) $ (6 ) Credit Loss Expense (1 ) (2 ) Write-offs — 1 End of Period $ (7 ) $ (7 ) Service Disconnection Moratoriums In 2019, the ACC enacted emergency rules that suspended service disconnections and late fees for electric residential customers who would have otherwise been eligible for service disconnection during the period from June 1 through October 15 (Summer Moratorium). The emergency rules will remain in effect until the ACC permanently adopts new rules regarding electric service disconnections. In addition, in March 2020 TEP voluntarily suspended service disconnections and late fees for all customers who would have otherwise been eligible for service disconnection to help customers affected by the COVID-19 pandemic. As of June 1, 2020, the Summer Moratorium became effective for electric residential customers eligible for service disconnection. As a result of the service disconnection moratoriums, in June 2020 TEP increased its bad debt reserve rate and estimated the total impact on operating expenses to be approximately $2 million through the end of 2020 . The change to the bad debt reserve rate did not have a significant impact on operating expenses in the second quarter of 2020 . TEP will continue monitoring collection activity and adjust the bad debt reserve rate as needed. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 6 Months Ended |
Jun. 30, 2020 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor-related services. The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2020 December 31, 2019 Receivables from Related Parties UNS Electric $ 4 $ 6 UNS Gas 2 2 Total Due from Related Parties $ 6 $ 8 Payables to Related Parties SES $ 2 $ 2 UNS Electric — 1 UNS Energy 1 1 Total Due to Related Parties $ 3 $ 4 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 2 $ 2 $ 4 $ 3 Control Area Services, UNS Electric (2) 1 1 2 2 Common Costs, UNS Energy Affiliates (3) 4 5 9 10 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 3 4 7 7 Corporate Services, UNS Energy (5) 2 2 3 3 Corporate Services, UNS Energy Affiliates (6) 1 1 2 2 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable OATT. (2) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (4) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (5) 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 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and six months ended June 30, 2020 and 2019 , respectively. (6) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. DIVIDENDS PAID TO PARENT On July 23, 2020, TEP declared a $38 million dividend to UNS Energy, which was paid July 27, 2020. |
DEBT AND CREDIT AGREEMENTS
DEBT AND CREDIT AGREEMENTS | 6 Months Ended |
Jun. 30, 2020 | |
Debt Disclosure [Abstract] | |
DEBT AND CREDIT AGREEMENTS | DEBT AND CREDIT AGREEMENTS There have been no significant changes to TEP's debt or credit agreements from those reported in its 2019 Annual Report on Form 10-K, except as noted below. DEBT Issuance In April 2020, TEP issued and sold $350 million aggregate principal amount of 4.00% senior unsecured notes due June 2050. TEP may call the debt prior to December 15, 2049, with a make-whole premium plus accrued interest. After December 15, 2049, TEP may call the debt at par plus accrued interest. TEP used the net proceeds from the sale to repay amounts outstanding under its credit agreements and for general corporate purposes. CREDIT AGREEMENTS 2019 Credit Agreement The following table presents components of TEP's unsecured 2019 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets: Capacity Borrowed (1) Available Weighted Average Interest Rate Pricing (2) (in millions) June 30, 2020 Term Loan $ 225 $ 225 $ — — % LIBOR + 0.550% or ABR + 0.00% In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the outstanding term loans and terminate such agreement. 2015 Credit Agreement The following table presents components of TEP's unsecured 2015 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets: Capacity Sub-Limit LOC Borrowed (1) Available Weighted Average Interest Rate Pricing (2) (in millions) June 30, 2020 Revolver and LOC $ 250 $ 50 $ 12 $ 238 — % LIBOR + 1.000% or ABR + 0.00% (1) Includes $12 million in LOCs issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. (2) Interest rates and fees are based on a pricing grid tied to TEP's credit rating. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 6 Months Ended |
Jun. 30, 2020 | |
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 2019 Annual Report on Form 10-K. CONTINGENCIES Legal Matters TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. Mine Reclamation at Generation Facilities Not Operated by TEP TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, timing of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP prospectively adjusts the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP defers these expenses until recovered from customers by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid. TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of final mine reclamation costs at both mines is $56 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $39 million as of June 30, 2020 , and $36 million as of December 31, 2019 , was recorded in Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs. Performance Guarantees TEP has joint participation agreements with participants at San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of June 30, 2020 , there have been no such payment defaults under any of the participation agreements. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generating station. Relative to the Navajo performance obligations, in the case of a default, 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 Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 6 Months Ended |
Jun. 30, 2020 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, (in millions) 2020 2019 2020 2019 Service Cost $ 4 $ 3 $ 1 $ 1 Non-Service Cost (1) Interest Cost 4 5 1 1 Expected Return on Plan Assets (8 ) (7 ) (1 ) — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 2 $ 3 $ 1 $ 2 Pension Benefits Other Postretirement Benefits Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Service Cost $ 8 $ 6 $ 2 $ 2 Non-Service Cost (1) Interest Cost 8 9 1 1 Expected Return on Plan Assets (15 ) (13 ) (1 ) — Amortization of Net Loss 4 4 — — Net Periodic Benefit Cost $ 5 $ 6 $ 2 $ 3 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. |
FAIR VALUE MEASUREMENTS AND DER
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 6 Months Ended |
Jun. 30, 2020 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. TEP has no financial instruments categorized as Level 3. FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Total (in millions) June 30, 2020 Assets Restricted Cash (1) $ 18 $ — $ 18 Energy Derivative Contracts, Regulatory Recovery (2) — 8 8 Energy Derivative Contracts, No Regulatory Recovery (2) — 5 5 Total Assets 18 13 31 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (66 ) (66 ) Total Liabilities — (66 ) (66 ) Total Assets (Liabilities), Net $ 18 $ (53 ) $ (35 ) (in millions) December 31, 2019 Assets Restricted Cash (1) $ 18 $ — $ 18 Energy Derivative Contracts, Regulatory Recovery (2) — 3 3 Energy Derivative Contracts, No Regulatory Recovery (2) — 3 3 Total Assets 18 6 24 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (76 ) (76 ) Total Liabilities — (76 ) (76 ) Total Assets (Liabilities), Net $ 18 $ (70 ) $ (52 ) (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 purchased power and sales 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) June 30, 2020 Derivative Assets Energy Derivative Contracts $ 13 $ 8 $ — $ 5 Derivative Liabilities Energy Derivative Contracts (66 ) (8 ) — (58 ) (in millions) December 31, 2019 Derivative Assets Energy Derivative Contracts $ 6 $ 4 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (76 ) (4 ) (2 ) (70 ) 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 the Company's retail customers. TEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. TEP primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly. Energy Derivative Contracts, Regulatory Recovery TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Unrealized Net Gain (Loss) $ 6 $ (11 ) $ 15 $ (20 ) Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Operating Revenues $ 4 $ 5 $ 5 $ 5 Derivative Volumes As of June 30, 2020 , TEP had energy contracts that will settle on various expiration dates through 2029 . The following table presents volumes associated with the energy contracts: June 30, 2020 December 31, 2019 Power Contracts GWh 5,474 4,740 Gas Contracts BBtu 110,461 122,779 Level 3 Fair Value Measurements As of June 30, 2020 , TEP did not have any Level 3 asset or liability balances. The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held: Three Months Ended Six Months Ended (in millions) June 30, 2019 Beginning of Period $ (6 ) $ 1 Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments (2 ) (10 ) Operating Revenues 5 5 Settlements (1 ) — End of Period $ (4 ) $ (4 ) Gains (Losses), Assets (Liabilities) Still Held $ 3 $ (4 ) 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 certain 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 counterparties' assessment of TEP's credit strength. In the event that such credit events were to occur, TEP, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts. TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts. The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $79 million as of June 30, 2020 , compared with $100 million as of December 31, 2019 . As of June 30, 2020 , TEP had no collateral posted related to energy procurement or hedging activities. If the credit risk contingent features were triggered on June 30, 2020 , TEP would have been required to post an additional $79 million of collateral of which $15 million relates to outstanding net payable balances for settled positions. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Due to the short-term nature of borrowings under revolving credit facilities approximating fair value, they have been excluded from the table below. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) June 30, 2020 December 31, 2019 June 30, 2020 December 31, 2019 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,946 $ 1,602 $ 2,202 $ 1,755 |
NATURE OF OPERATIONS AND FINA_2
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies) | 6 Months Ended |
Jun. 30, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of presentation | BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. 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 2019 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. |
Variable interest entities | Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis. As of June 30, 2020 , the carrying amounts of assets and liabilities on the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as TEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. |
Restricted cash | Restricted Cash Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. |
New accounting standards | NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2020. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. Credit Losses TEP adopted accounting guidance that requires entities to incorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. See Note 4 for additional disclosure about TEP's allowance for credit losses. 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. |
NATURE OF OPERATIONS AND FINA_3
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of amounts reclassified | Certain amounts from prior periods have been reclassified to conform to the current period presentation. Most notably, TEP bifurcated Other, Net on the Condensed Consolidated Statements of Income as follows: As Filed Amount Reclassified As Reclassified As Filed Amount Reclassified As Reclassified (in thousands) Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Other Income (Expense) Other, Net $ 842 $ (934 ) $ (92 ) $ 4,130 $ (4,014 ) $ 116 Unrealized Gains (Losses) on Investments — 934 934 — 4,014 4,014 |
Schedule of cash, cash equivalents | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: June 30, (in millions) 2020 2019 Cash and Cash Equivalents $ 61 $ 70 Restricted Cash included in: Investments and Other Property 16 13 Current Assets—Other 2 1 Total Cash, Cash Equivalents, and Restricted Cash $ 79 $ 84 |
Schedule of restricted cash | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: June 30, (in millions) 2020 2019 Cash and Cash Equivalents $ 61 $ 70 Restricted Cash included in: Investments and Other Property 16 13 Current Assets—Other 2 1 Total Cash, Cash Equivalents, and Restricted Cash $ 79 $ 84 |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | The table below summarizes the regulatory asset (liability) over or under collected balance related to the ACC Refund Order: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Beginning of Period $ — $ 3 $ — $ 4 ACC Refund (Reduction in Operating Revenues) (9 ) (9 ) (16 ) (16 ) Amount Returned to Customers through Bill Credits 5 6 8 10 Regulatory Deferral 5 1 9 3 End of Period $ 1 $ 1 $ 1 $ 1 |
Schedule of Purchased Power and Fuel Adjustment Rates | The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Beginning of Period $ 36 $ (22 ) $ 36 $ (17 ) Deferred Fuel and Purchased Power Costs (1) 67 75 115 128 PPFAC and Base Power Recoveries (2) (75 ) (62 ) (123 ) (120 ) End of Period $ 28 $ (9 ) $ 28 $ (9 ) (1) Includes costs eligible for recovery through the PPFAC and base power rates. (2) In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. In March 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, which went into effect on June 1, 2020. |
Schedule of Regulated Operating Revenue | The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 LFCR Revenues $ 10 $ 6 $ 22 $ 16 |
Schedule of Regulatory Assets and Liabilities | Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: ($ in millions) Remaining Recovery Period (years) June 30, 2020 December 31, 2019 Regulatory Assets Pension and Other Postretirement Benefits Various $ 131 $ 135 Early Generation Retirement Costs Various 64 68 Derivatives (Note 9) 10 59 72 Lost Fixed Cost Recovery 2 57 46 Income Taxes Recoverable through Future Rates (1) Various 33 38 Under Recovered Purchased Energy Costs 1 28 36 Property Tax Deferrals (2) 1 25 24 Final Mine Reclamation and Retiree Healthcare Costs (3) 9 22 19 Springerville Unit 1 Leasehold Improvements (4) 3 8 9 Other Regulatory Assets Various 19 18 Total Regulatory Assets 446 465 Less Current Portion 1 124 138 Total Non-Current Regulatory Assets $ 322 $ 327 Regulatory Liabilities Income Taxes Payable through Future Rates (1) Various $ 315 $ 327 Net Cost of Removal (5) Various 156 164 Renewable Energy Standard Various 60 59 Deferred Investment Tax Credits (6) Various 2 3 Other Regulatory Liabilities Various 33 20 Total Regulatory Liabilities 566 573 Less Current Portion 1 100 96 Total Non-Current Regulatory Liabilities $ 466 $ 477 (1) Amortized over the lives of the assets. (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. This asset is fully recovered in rates with a recovery period of approximately six months . (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. The majority of final mine reclamation costs are expected to be funded by TEP through 2028 . (4) Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe and reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year period. (5) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. (6) Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. |
REVENUE (Tables)
REVENUE (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Retail $ 265 $ 236 $ 457 $ 438 Wholesale (1) 30 43 66 127 Other Services 23 30 47 54 Revenues from Contracts with Customers 318 309 570 619 Alternative Revenues 10 6 24 18 Other 12 11 24 22 Total Operating Revenues (2) $ 340 $ 326 $ 618 $ 659 (1) In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the 2019 FERC Rate Case. (2) Calculated on rounded data and may not correspond exactly to TEP's Operating Revenues reported on the Condensed Consolidated Statements of Income. |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Receivables [Abstract] | |
Accounts Receivable | The following table presents the components of Accounts Receivable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2020 December 31, 2019 Retail $ 76 $ 61 Retail, Unbilled 62 42 Retail, Allowance for Credit Losses (7 ) (6 ) Wholesale (1) 19 31 Due from Affiliates (Note 5) 6 8 Other 11 19 Accounts Receivable $ 167 $ 155 (1) Includes $3 million as of June 30, 2020 , and $5 million as of December 31, 2019 , of receivables related to revenue from derivative instruments. |
Schedule of Allowance for Credit Losses | The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets: Three Months Ended Six Months Ended (in millions) June 30, 2020 June 30, 2020 Beginning of Period $ (6 ) $ (6 ) Credit Loss Expense (1 ) (2 ) Write-offs — 1 End of Period $ (7 ) $ (7 ) |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Balances and Transactions | The following table presents the components of related party balances included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2020 December 31, 2019 Receivables from Related Parties UNS Electric $ 4 $ 6 UNS Gas 2 2 Total Due from Related Parties $ 6 $ 8 Payables to Related Parties SES $ 2 $ 2 UNS Electric — 1 UNS Energy 1 1 Total Due to Related Parties $ 3 $ 4 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 2 $ 2 $ 4 $ 3 Control Area Services, UNS Electric (2) 1 1 2 2 Common Costs, UNS Energy Affiliates (3) 4 5 9 10 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 3 4 7 7 Corporate Services, UNS Energy (5) 2 2 3 3 Corporate Services, UNS Energy Affiliates (6) 1 1 2 2 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable OATT. (2) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (4) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (5) 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 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and six months ended June 30, 2020 and 2019 , respectively. (6) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. |
DEBT AND CREDIT AGREEMENTS (Tab
DEBT AND CREDIT AGREEMENTS (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Debt Disclosure [Abstract] | |
Schedule of line of credit facilities | The following table presents components of TEP's unsecured 2015 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets: Capacity Sub-Limit LOC Borrowed (1) Available Weighted Average Interest Rate Pricing (2) (in millions) June 30, 2020 Revolver and LOC $ 250 $ 50 $ 12 $ 238 — % LIBOR + 1.000% or ABR + 0.00% (1) Includes $12 million in LOCs issued in January 2020 pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. (2) Interest rates and fees are based on a pricing grid tied to TEP's credit rating. The following table presents components of TEP's unsecured 2019 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets: Capacity Borrowed (1) Available Weighted Average Interest Rate Pricing (2) (in millions) June 30, 2020 Term Loan $ 225 $ 225 $ — — % LIBOR + 0.550% or ABR + 0.00% |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Retirement Benefits [Abstract] | |
Components of Net Periodic Benefit Cost | Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, (in millions) 2020 2019 2020 2019 Service Cost $ 4 $ 3 $ 1 $ 1 Non-Service Cost (1) Interest Cost 4 5 1 1 Expected Return on Plan Assets (8 ) (7 ) (1 ) — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 2 $ 3 $ 1 $ 2 Pension Benefits Other Postretirement Benefits Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Service Cost $ 8 $ 6 $ 2 $ 2 Non-Service Cost (1) Interest Cost 8 9 1 1 Expected Return on Plan Assets (15 ) (13 ) (1 ) — Amortization of Net Loss 4 4 — — Net Periodic Benefit Cost $ 5 $ 6 $ 2 $ 3 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. |
FAIR VALUE MEASUREMENTS AND D_2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
Fair Value Disclosures [Abstract] | |
Financial Instruments Measured at Fair Value on Recurring Basis | The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Total (in millions) June 30, 2020 Assets Restricted Cash (1) $ 18 $ — $ 18 Energy Derivative Contracts, Regulatory Recovery (2) — 8 8 Energy Derivative Contracts, No Regulatory Recovery (2) — 5 5 Total Assets 18 13 31 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (66 ) (66 ) Total Liabilities — (66 ) (66 ) Total Assets (Liabilities), Net $ 18 $ (53 ) $ (35 ) (in millions) December 31, 2019 Assets Restricted Cash (1) $ 18 $ — $ 18 Energy Derivative Contracts, Regulatory Recovery (2) — 3 3 Energy Derivative Contracts, No Regulatory Recovery (2) — 3 3 Total Assets 18 6 24 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (76 ) (76 ) Total Liabilities — (76 ) (76 ) Total Assets (Liabilities), Net $ 18 $ (70 ) $ (52 ) (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 purchased power and sales contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. |
Potential Offset of Assets by Counterparty Netting and Cash Collateral | TEP presents derivatives on a gross basis on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) June 30, 2020 Derivative Assets Energy Derivative Contracts $ 13 $ 8 $ — $ 5 Derivative Liabilities Energy Derivative Contracts (66 ) (8 ) — (58 ) (in millions) December 31, 2019 Derivative Assets Energy Derivative Contracts $ 6 $ 4 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (76 ) (4 ) (2 ) (70 ) |
Potential Offset of Liabilities by Counterparty Netting and Cash Collateral | TEP presents derivatives on a gross basis on the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral: Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) June 30, 2020 Derivative Assets Energy Derivative Contracts $ 13 $ 8 $ — $ 5 Derivative Liabilities Energy Derivative Contracts (66 ) (8 ) — (58 ) (in millions) December 31, 2019 Derivative Assets Energy Derivative Contracts $ 6 $ 4 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (76 ) (4 ) (2 ) (70 ) |
Financial Impact of Energy Contracts | The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Unrealized Net Gain (Loss) $ 6 $ (11 ) $ 15 $ (20 ) Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Operating Revenues $ 4 $ 5 $ 5 $ 5 |
Derivative Volumes | The following table presents volumes associated with the energy contracts: June 30, 2020 December 31, 2019 Power Contracts GWh 5,474 4,740 Gas Contracts BBtu 110,461 122,779 |
Level 3 Fair Value Reconciliation of Changes | The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held: Three Months Ended Six Months Ended (in millions) June 30, 2019 Beginning of Period $ (6 ) $ 1 Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments (2 ) (10 ) Operating Revenues 5 5 Settlements (1 ) — End of Period $ (4 ) $ (4 ) Gains (Losses), Assets (Liabilities) Still Held $ 3 $ (4 ) |
Face Value and Estimated Fair Value of Long-Term Debt | The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Net Carrying Value Fair Value (in millions) June 30, 2020 December 31, 2019 June 30, 2020 December 31, 2019 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,946 $ 1,602 $ 2,202 $ 1,755 |
NATURE OF OPERATIONS AND FINA_4
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands | 6 Months Ended |
Jun. 30, 2020mi²customer | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of retail customers | customer | 432 |
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi² | 1,155 |
NATURE OF OPERATIONS AND FINA_5
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Amounts Reclassified) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Other Income (Expense) | ||||
Other, Net | $ 1,339 | $ (92) | $ 2,192 | $ 116 |
Unrealized Gains (Losses) on Investments | $ 3,276 | 934 | $ (3,151) | 4,014 |
As Filed | ||||
Other Income (Expense) | ||||
Other, Net | 842 | 4,130 | ||
Unrealized Gains (Losses) on Investments | 0 | 0 | ||
Amount Reclassified | ||||
Other Income (Expense) | ||||
Other, Net | (934) | (4,014) | ||
Unrealized Gains (Losses) on Investments | $ 934 | $ 4,014 |
NATURE OF OPERATIONS AND FINA_6
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands | Jun. 30, 2020 | Dec. 31, 2019 | Jun. 30, 2019 | Dec. 31, 2018 |
Cash and Cash Equivalents [Line Items] | ||||
Cash and Cash Equivalents | $ 60,895 | $ 9,762 | $ 70,000 | |
Total Cash, Cash Equivalents, and Restricted Cash | 78,838 | $ 28,472 | 83,873 | $ 152,747 |
Investments and Other Property | ||||
Cash and Cash Equivalents [Line Items] | ||||
Restricted Cash | 16,000 | 13,000 | ||
Current Assets—Other | ||||
Cash and Cash Equivalents [Line Items] | ||||
Restricted Cash | $ 2,000 | $ 1,000 |
REGULATORY MATTERS (2019 ACC Ra
REGULATORY MATTERS (2019 ACC Rate Case) (Details) - Arizona Corporation Commission $ in Millions | 1 Months Ended |
Apr. 30, 2019USD ($) | |
Non-fuel Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ 99 |
Original cost rate base (percentage) | 7.49% |
Original cost rate base | $ 2,700 |
Original cost of equity (percentage) | 10.00% |
Average original cost of debt (percentage) | 4.65% |
Fuel Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ (39) |
Revenue Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ 60 |
REGULATORY MATTERS (2019 FERC R
REGULATORY MATTERS (2019 FERC Rate Case) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Jun. 30, 2020 | |
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | $ 96,017 | $ 100,190 |
FERC | Transmission Services Rate | ||
Public Utilities, General Disclosures [Line Items] | ||
Return on equity (percentage) | 10.40% | |
FERC | Transmission Services Rate | Revenue Subject to Refund | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Liabilities | $ 4,000 | $ 9,000 |
REGULATORY MATTERS (Federal Tax
REGULATORY MATTERS (Federal Tax Legislation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | |
Regulatory Assets [Roll Forward] | ||||||
Regulatory Deferral | $ 8,817 | $ 3,156 | ||||
Arizona Corporation Commission | ||||||
Regulatory Assets [Roll Forward] | ||||||
Customers bill as percent of returned savings | 50.00% | 50.00% | ||||
Deferred TCJA Customer Refunds, Liability | $ 17,000 | $ 17,000 | $ 8,000 | |||
Arizona Corporation Commission | Scenario, Forecast | ||||||
Regulatory Assets [Roll Forward] | ||||||
Change in tax rate, refund to customers, net of amortization | $ 35,000 | |||||
Arizona Corporation Commission | Revenue Refund | ||||||
Regulatory Assets [Roll Forward] | ||||||
Beginning of Period | 0 | $ 3,000 | 0 | 4,000 | $ 0 | |
ACC Approved Refund (Reduction in Operating Revenues) | (9,000) | (9,000) | (16,000) | (16,000) | ||
Amount Returned to Customers Through Bill Credits | 5,000 | 6,000 | 8,000 | 10,000 | ||
Regulatory Deferral | 5,000 | 1,000 | 9,000 | 3,000 | ||
End of Period | $ 1,000 | $ 1,000 | $ 1,000 | $ 1,000 |
REGULATORY MATTERS (Cost Recove
REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Jun. 30, 2020 | Apr. 30, 2020 | Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | Dec. 31, 2025 | Dec. 31, 2019 | |
Over Recovered Purchased Energy Costs | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Months approved rate in effect unless modified | 12 months | |||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Beginning of Period | $ 36 | $ 36 | $ (22) | $ 36 | $ (17) | $ (17) | ||
Deferred Fuel and Purchased Power Costs | 67 | 75 | 115 | 128 | ||||
PPFAC Refunds (Recoveries) | (75) | (62) | (123) | (120) | ||||
End of Period | $ 28 | 28 | (9) | $ 28 | (9) | 36 | ||
Renewable Energy Standard | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Renewable energy target percentage | 10.00% | |||||||
Approved spending budget | 55 | |||||||
Demand Side Management | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Recovery revenue | $ 2 | 2 | ||||||
Energy Efficiency Standards | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Approved recovery of spending budget | $ 23 | |||||||
Recovery of spending budget, requested amount | $ 23 | |||||||
Refunded to customers, approved amount | $ 8 | |||||||
Lost Fixed Cost Recovery | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Recovery revenue | $ 10 | $ 6 | $ 22 | $ 16 | ||||
Cap on increase in lost fixed cost recovery rate (percentage) | 2.00% | |||||||
Scenario, Forecast | Renewable Energy Standard | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Renewable energy target percentage | 15.00% | |||||||
Distributed generation requirement percent of target percentage (percentage) | 30.00% |
REGULATORY MATTERS (Regulatory
REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2020 | Dec. 31, 2019 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 446,000 | $ 465,000 |
Less Current Portion | 123,848 | 138,412 |
Total Non-Current Regulatory Assets | 322,072 | 326,860 |
Pension and Other Postretirement Benefits | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | 131,000 | 135,000 |
Early Generation Retirement Costs | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 64,000 | 68,000 |
Derivatives (Note 9) | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 10 years | |
Total Regulatory Assets | $ 59,000 | 72,000 |
Lost Fixed Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 2 years | |
Total Regulatory Assets | $ 57,000 | 46,000 |
Income Taxes Recoverable through Future Rates | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 33,000 | 38,000 |
Under Recovered Purchased Energy Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 28,000 | 36,000 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 25,000 | 24,000 |
Final Mine Reclamation and Retiree Healthcare Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 9 years | |
Total Regulatory Assets | $ 22,000 | 19,000 |
Springerville Unit 1 Leasehold Improvements | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 3 years | |
Total Regulatory Assets | $ 8,000 | 9,000 |
Other Regulatory Assets | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 19,000 | $ 18,000 |
REGULATORY MATTERS (Regulator_2
REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2020 | Dec. 31, 2019 | |
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 566,000 | $ 573,000 |
Less Current Portion | 100,190 | 96,017 |
Total Non-Current Regulatory Liabilities | 466,261 | 477,495 |
Income Taxes Payable through Future Rates | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 315,000 | 327,000 |
Net Cost of Removal | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 156,000 | 164,000 |
Renewable Energy Standard | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 60,000 | 59,000 |
Deferred Investment Tax Credits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 2,000 | 3,000 |
Other Regulatory Liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 33,000 | $ 20,000 |
REGULATORY MATTERS (Regulator_3
REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details) | 6 Months Ended |
Jun. 30, 2020 | |
Property Tax Deferrals | |
Regulatory Assets [Line Items] | |
Regulatory Assets, Remaining Recovery Period | 6 months |
Springerville Unit 1 Leasehold Improvements | |
Regulatory Assets [Line Items] | |
Useful life (in years) | 10 years |
REGULATORY MATTERS (Plant in Se
REGULATORY MATTERS (Plant in Service) (Details) - RICE Units $ in Millions | Jun. 30, 2020USD ($)MWhrice | Mar. 31, 2020rice | Dec. 31, 2019USD ($)rice |
Public Utilities, General Disclosures [Line Items] | |||
Number of units in service | 5 | 5 | |
Plant in service | $ | $ 183 | $ 82 | |
Total number of units | 10 | ||
Generating capacity purchased, in MW | MWh | 188 |
REVENUE (Details)
REVENUE (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | $ 318,000 | $ 309,000 | $ 570,000 | $ 619,000 |
Alternative Revenues | 10,000 | 6,000 | 24,000 | 18,000 |
Other | 12,000 | 11,000 | 24,000 | 22,000 |
Total Operating Revenues | 339,705 | 326,091 | 618,261 | 659,094 |
Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | 265,000 | 236,000 | 457,000 | 438,000 |
Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | 30,000 | 43,000 | 66,000 | 127,000 |
Other Services | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | $ 23,000 | $ 30,000 | $ 47,000 | $ 54,000 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 7 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2020 | Dec. 31, 2020 | Jun. 30, 2020 | Dec. 31, 2019 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Accounts receivable, gross | $ 76,000 | $ 61,000 | |||
Allowance for Credit Losses | $ (6,000) | $ (6,679) | (6,679) | (5,716) | |
Accounts Receivable, Net | 166,855 | 154,847 | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||||
Beginning of Period | (6,000) | (5,716) | |||
Credit Loss Expense | (1,000) | (2,000) | |||
Write-offs | 0 | 1,000 | |||
End of Period | $ (6,679) | $ (6,679) | |||
Scenario, Forecast | |||||
Service Disconnection Moratoriums [Abstract] | |||||
Estimated impact on operating expense | $ 2,000 | ||||
Unbilled | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Accounts receivable, gross | 62,000 | 42,000 | |||
Trade Accounts | Due from Affiliates | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Accounts receivable, gross | 6,000 | 8,000 | |||
Other | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Accounts receivable, gross | 11,000 | 19,000 | |||
Wholesale | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Accounts receivable, gross | 19,000 | 31,000 | |||
Wholesale | Derivatives | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Accounts receivable, gross | $ 3,000 | $ 5,000 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions | Jul. 27, 2020 | Jul. 23, 2020 | Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | Dec. 31, 2019 |
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due from related parties | $ 6 | $ 6 | $ 8 | ||||
Due to related parties | 3 | 3 | 4 | ||||
Transmission Revenues, UNS Electric | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Revenue from related party | 2 | $ 2 | 4 | $ 3 | |||
Control Area Services, UNS Electric | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Control area services | 1 | 1 | 2 | 2 | |||
Common Costs, UNS Energy Affiliates | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Common costs | 4 | 5 | 9 | 10 | |||
Supplemental Workforce, SES | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Supplemental workforce | 3 | 4 | 7 | 7 | |||
Corporate Services, UNS Energy | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Corporate services | 2 | 2 | $ 3 | 3 | |||
Massachusetts Formula - TEP's allocation (percentage) | 83.00% | ||||||
Management fee | 1 | 1 | $ 3 | 3 | |||
Corporate Services, UNS Energy Affiliates | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Corporate services | 1 | $ 1 | 2 | $ 2 | |||
SES | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due to related parties | 2 | 2 | 2 | ||||
UNS Electric | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due from related parties | 4 | 4 | 6 | ||||
Due to related parties | 0 | 0 | 1 | ||||
UNS Energy | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due to related parties | 1 | 1 | 1 | ||||
UNS Energy | Subsequent Event | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Dividends declared | $ 38 | ||||||
Payments of dividends | $ 38 | ||||||
UNS Gas | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due from related parties | $ 2 | $ 2 | $ 2 |
DEBT AND CREDIT AGREEMENTS (Det
DEBT AND CREDIT AGREEMENTS (Details) - USD ($) | 6 Months Ended | ||
Jun. 30, 2020 | Apr. 30, 2020 | Jan. 31, 2020 | |
Unsecured Debt | 4.00% Unsecured Senior Notes | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 350,000,000 | ||
Interest Rate | 4.00% | ||
Line of Credit | Term Loan | |||
Debt Instrument [Line Items] | |||
Line of credit facility borrowing capacity | $ 225,000,000 | ||
Borrowed | 225,000,000 | ||
Available | $ 0 | ||
Weighted Average Interest Rate (in percentage) | 0.00% | ||
Line of Credit | Term Loan | LIBOR | |||
Debt Instrument [Line Items] | |||
Basis of variable spread (in percentage) | 0.55% | ||
Line of Credit | Term Loan | Base Rate | |||
Debt Instrument [Line Items] | |||
Basis of variable spread (in percentage) | 0.00% | ||
Line of Credit | Revolver | |||
Debt Instrument [Line Items] | |||
Line of credit facility borrowing capacity | $ 250,000,000 | ||
Borrowed | 12,000,000 | ||
Available | $ 238,000,000 | ||
Weighted Average Interest Rate (in percentage) | 0.00% | ||
Line of Credit | Revolver | LIBOR | |||
Debt Instrument [Line Items] | |||
Basis of variable spread (in percentage) | 1.00% | ||
Line of Credit | Revolver | Base Rate | |||
Debt Instrument [Line Items] | |||
Basis of variable spread (in percentage) | 0.00% | ||
Line of Credit | Sub-Limit LOC | |||
Debt Instrument [Line Items] | |||
Line of credit facility borrowing capacity | $ 50,000,000 | ||
Borrowed | $ 12,000,000 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - San Juan and Four Corners - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2020 | Dec. 31, 2019 | |
Commitments And Contingencies [Line Items] | ||
Reclamation costs | $ 56 | |
Other Liabilities | ||
Commitments And Contingencies [Line Items] | ||
Reclamation costs accrued | $ 39 | $ 36 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Performance guarantees) (Details) - Performance Guarantee | Jun. 30, 2020USD ($) |
Guarantor Obligations [Line Items] | |
Current carrying value | $ 0 |
Navajo, San Juan, Luna | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | 0 |
Four Corner | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | $ 250,000,000 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Pension Benefits | ||||
Components of Net Periodic Benefit Plan Cost | ||||
Service Cost | $ 4 | $ 3 | $ 8 | $ 6 |
Non-Service Cost | ||||
Interest Cost | 4 | 5 | 8 | 9 |
Expected Return on Plan Assets | (8) | (7) | (15) | (13) |
Amortization of Net Loss | 2 | 2 | 4 | 4 |
Net Periodic Benefit Cost | 2 | 3 | 5 | 6 |
Other Postretirement Benefits | ||||
Components of Net Periodic Benefit Plan Cost | ||||
Service Cost | 1 | 1 | 2 | 2 |
Non-Service Cost | ||||
Interest Cost | 1 | 1 | 1 | 1 |
Expected Return on Plan Assets | (1) | 0 | (1) | 0 |
Amortization of Net Loss | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | $ 1 | $ 2 | $ 2 | $ 3 |
FAIR VALUE MEASUREMENTS AND D_3
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Recurring - USD ($) | Jun. 30, 2020 | Dec. 31, 2019 |
Assets | ||
Restricted Cash | $ 18,000,000 | $ 18,000,000 |
Energy Derivative Contract Assets - Regulatory Recovery | 8,000,000 | 3,000,000 |
Energy Derivative Contract Assets - No Regulatory Recovery | 5,000,000 | 3,000,000 |
Total Assets | 31,000,000 | 24,000,000 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (66,000,000) | (76,000,000) |
Total Liabilities | (66,000,000) | (76,000,000) |
Total Assets (Liabilities), Net | (35,000,000) | (52,000,000) |
Level 1 | ||
Assets | ||
Restricted Cash | 18,000,000 | 18,000,000 |
Energy Derivative Contract Assets - Regulatory Recovery | 0 | 0 |
Energy Derivative Contract Assets - No Regulatory Recovery | 0 | 0 |
Total Assets | 18,000,000 | 18,000,000 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | 0 | 0 |
Total Liabilities | 0 | 0 |
Total Assets (Liabilities), Net | 18,000,000 | 18,000,000 |
Level 2 | ||
Assets | ||
Restricted Cash | 0 | 0 |
Energy Derivative Contract Assets - Regulatory Recovery | 8,000,000 | 3,000,000 |
Energy Derivative Contract Assets - No Regulatory Recovery | 5,000,000 | 3,000,000 |
Total Assets | 13,000,000 | 6,000,000 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (66,000,000) | (76,000,000) |
Total Liabilities | (66,000,000) | (76,000,000) |
Total Assets (Liabilities), Net | (53,000,000) | $ (70,000,000) |
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 | Jun. 30, 2020 | Dec. 31, 2019 |
Derivative Assets | ||
Gross Amount Recognized in the Balance Sheets | $ 13 | $ 6 |
Counterparty Netting of Energy Contracts | 8 | 4 |
Cash Collateral Received/Posted | 0 | 0 |
Net Amount | 5 | 2 |
Derivative Liabilities | ||
Gross Amount Recognized in the Balance Sheets | (66) | (76) |
Counterparty Netting of Energy Contracts | (8) | (4) |
Cash Collateral Received/Posted | 0 | (2) |
Net Amount | $ (58) | $ (70) |
FAIR VALUE MEASUREMENTS AND D_5
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2020 | Jun. 30, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Percent of long-term trading contract gains shared with customers (percentage) | 10.00% | |||
Operating Revenues | $ 339,705 | $ 326,091 | $ 618,261 | $ 659,094 |
Energy Derivative Contracts | Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Net Gain (Loss) | 6,000 | (11,000) | 15,000 | (20,000) |
Operating Revenues | $ 4,000 | $ 5,000 | $ 5,000 | $ 5,000 |
FAIR VALUE MEASUREMENTS AND D_6
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) BBtu in Billions | Jun. 30, 2020GWhBBtu | Dec. 31, 2019GWhBBtu |
Power Contracts GWh | ||
Derivative Volume [Line Items] | ||
Derivatives volumes | GWh | 5,474 | 4,740 |
Gas Contracts BBtu | ||
Derivative Volume [Line Items] | ||
Derivatives volumes | BBtu | 110,461 | 122,779 |
FAIR VALUE MEASUREMENTS AND D_7
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended |
Jun. 30, 2019 | Jun. 30, 2019 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||
Beginning of Period | $ (6) | $ 1 |
Gains (Losses) Recorded | ||
Regulatory Assets or Liabilities, Derivative Instruments | (2) | (10) |
Operating Revenues | 5 | 5 |
Settlements | (1) | 0 |
End of Period | (4) | (4) |
Gains (Losses), Assets (Liabilities) Still Held | $ 3 | $ (4) |
FAIR VALUE MEASUREMENTS AND D_8
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) | Jun. 30, 2020 | Dec. 31, 2019 |
Derivative [Line Items] | ||
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale | $ 79,000,000 | $ 100,000,000 |
Collateral posted | 0 | |
Additional collateral required to post if credit-risk contingent features are triggered | 79,000,000 | |
Amount relating to outstanding net payable balances for settled positions | ||
Derivative [Line Items] | ||
Additional collateral required to post if credit-risk contingent features are triggered | $ 15,000,000 |
FAIR VALUE MEASUREMENTS AND D_9
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions | Jun. 30, 2020 | Dec. 31, 2019 |
Net Carrying Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 1,946 | $ 1,602 |
Fair Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 2,202 | $ 1,755 |