Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 12, 2020 | Jun. 30, 2019 | |
Cover page. | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 1-5924 | ||
Entity Registrant Name | TUCSON ELECTRIC POWER CO | ||
Entity Incorporation, State or Country Code | AZ | ||
Entity Tax Identification Number | 86-0062700 | ||
Entity Address, Address Line One | 88 East Broadway Boulevard | ||
Entity Address, City or Town | Tucson | ||
Entity Address, State or Province | AZ | ||
Entity Address, Postal Zip Code | 85701 | ||
City Area Code | 520 | ||
Local Phone Number | 571-4000 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 32,139,434 | ||
Documents Incorporated by Reference | None | ||
Entity Central Index Key | 0000100122 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Public Float | $ 0 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement [Abstract] | |||
Operating Revenues | $ 1,418,338 | $ 1,432,618 | $ 1,340,935 |
Operating Expenses | |||
Fuel | 358,394 | 351,749 | 285,551 |
Purchased Power | 137,977 | 134,914 | 136,425 |
Transmission and Other PPFAC Recoverable Costs | 52,261 | 46,595 | 36,239 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | (42,836) | 9,885 | (32,660) |
Total Fuel and Purchased Power | 505,796 | 543,143 | 425,555 |
Operations and Maintenance | 377,563 | 361,963 | 360,302 |
Depreciation | 169,042 | 158,310 | 152,874 |
Amortization | 27,706 | 26,052 | 22,255 |
Taxes Other Than Income Taxes | 55,642 | 55,006 | 53,623 |
Total Operating Expenses | 1,135,749 | 1,144,474 | 1,014,609 |
Operating Income | 282,589 | 288,144 | 326,326 |
Other Income (Expense) | |||
Interest Expense | (88,511) | (67,620) | (65,290) |
Allowance For Borrowed Funds | 5,744 | 3,151 | 2,078 |
Allowance For Equity Funds | 15,222 | 8,117 | 5,322 |
Other, Net | 5,524 | (487) | 8,995 |
Total Other Income (Expense) | (62,021) | (56,839) | (48,895) |
Income Before Income Tax Expense | 220,568 | 231,305 | 277,431 |
Income Tax Expense | 34,053 | 42,982 | 100,763 |
Net Income | $ 186,515 | $ 188,323 | $ 176,668 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income | $ 186,515 | $ 188,323 | $ 176,668 |
Net Changes in Fair Value of Cash Flow Hedges: | |||
Net of Income Tax (Expense) Benefit of $(44), $(121), and $(305) | 133 | 364 | 485 |
Supplemental Executive Retirement Plan Adjustments: | |||
Net of Income Tax (Expense) Benefit of $1,059, $(747), and $637 | (3,190) | 2,026 | (2,156) |
Total Other Comprehensive Income (Loss), Net of Tax | (3,057) | 2,390 | (1,671) |
Total Comprehensive Income | $ 183,458 | $ 190,713 | $ 174,997 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Comprehensive Income [Abstract] | |||
Net changes in fair value of cash flow hedges, tax | $ (44) | $ (121) | $ (305) |
Supplemental executive retirement plan adjustments, tax | $ 1,059 | $ (747) | $ 637 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Flows from Operating Activities | |||
Net Income | $ 186,515 | $ 188,323 | $ 176,668 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation Expense | 169,042 | 158,310 | 152,874 |
Amortization Expense | 27,706 | 26,052 | 22,255 |
Amortization of Debt Issuance Costs | 2,326 | 2,339 | 2,349 |
Use of Renewable Energy Credits for Compliance | 37,141 | 32,350 | 25,453 |
Deferred Income Taxes | 41,614 | 56,066 | 100,762 |
Pension and Other Postretirement Benefits Expense | 17,762 | 15,303 | 16,039 |
Pension and Other Postretirement Benefits Funding | (16,749) | (26,673) | (14,430) |
Allowance for Equity Funds Used During Construction | (15,222) | (8,117) | (5,322) |
FERC Transmission Refund Payable | 0 | 0 | (4,878) |
Regulatory Deferral, ACC Refund Order | 7,705 | (1,562) | 0 |
Changes in Current Assets and Current Liabilities: | |||
Accounts Receivable | 9,238 | (26,729) | (13,219) |
Materials, Supplies, and Fuel Inventory | (16,236) | (2,357) | 175 |
Regulatory Assets | (20,934) | (4,080) | (3,942) |
Other Current Assets | (475) | (1,746) | (751) |
Accounts Payable and Accrued Charges | (27,776) | 33,536 | 9,790 |
Income Taxes Receivable | 6,072 | (13,004) | 0 |
Regulatory Liabilities | (1,626) | 14,028 | (20,227) |
Other, Net | 8,140 | 15,187 | 4,728 |
Net Cash Flows—Operating Activities | 414,243 | 457,226 | 448,324 |
Cash Flows from Investing Activities | |||
Capital Expenditures | (607,593) | (392,522) | (345,617) |
Purchase Intangibles, Renewable Energy Credits | (51,699) | (51,327) | (51,179) |
Contributions in Aid of Construction | 6,607 | 10,817 | 4,983 |
Note Receivable | (1,000) | 0 | 0 |
Net Cash Flows—Investing Activities | (653,685) | (433,032) | (391,813) |
Cash Flows from Financing Activities | |||
Proceeds from Borrowings, Revolving Credit Facility | 0 | 171,000 | 70,000 |
Repayments of Borrowings, Revolving Credit Facility | 0 | (206,000) | (35,000) |
Proceeds from Borrowings, Term Loan | 165,000 | 0 | 0 |
Proceeds from Issuance, Long-Term Debt—Net of Discount | 0 | 298,869 | 0 |
Repayments of Long-Term Debt | (14,700) | (136,700) | 0 |
Dividends Paid to Parent | (75,000) | (85,000) | (70,000) |
Payments of Finance Lease Obligations | (10,890) | ||
Payments of Finance Lease Obligations | (10,930) | (15,571) | |
Payment of Debt Issuance Costs | (757) | (3,265) | (245) |
Contribution from Parent | 50,000 | 50,000 | 0 |
Other, Net | 1,514 | 1,078 | 481 |
Net Cash Flows—Financing Activities | 115,167 | 79,052 | (50,335) |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (124,275) | 103,246 | 6,176 |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 152,747 | 49,501 | 43,325 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | $ 28,472 | $ 152,747 | $ 49,501 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Utility Plant | ||
Plant in Service | $ 6,663,912 | $ 6,020,469 |
Utility Plant Under Finance Leases | 151,467 | 248,635 |
Construction Work in Progress | 303,488 | 258,965 |
Total Utility Plant | 7,118,867 | 6,528,069 |
Accumulated Depreciation and Amortization | (2,506,686) | (2,293,783) |
Accumulated Amortization of Finance Lease Assets | (77,285) | (73,646) |
Total Utility Plant, Net | 4,534,896 | 4,160,640 |
Investments and Other Property | 62,136 | 50,952 |
Current Assets | ||
Cash and Cash Equivalents | 9,762 | 138,114 |
Accounts Receivable, Net | 154,847 | 172,367 |
Fuel Inventory | 23,731 | 22,783 |
Materials and Supplies | 121,542 | 107,990 |
Regulatory Assets | 138,412 | 106,725 |
Derivative Instruments | 3,596 | 3,929 |
Other | 21,416 | 25,571 |
Total Current Assets | 473,306 | 577,479 |
Regulatory and Other Assets | ||
Regulatory Assets | 326,860 | 293,078 |
Derivative Instruments | 2,763 | 8,402 |
Other | 89,196 | 68,656 |
Total Regulatory and Other Assets | 418,819 | 370,136 |
Total Assets | 5,489,157 | 5,159,207 |
Common Stock Equity: | ||
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2019 and 2018) | 1,396,539 | 1,346,539 |
Capital Stock Expense | (6,357) | (6,357) |
Retained Earnings | 595,792 | 484,277 |
Accumulated Other Comprehensive Loss | (7,771) | (4,714) |
Total Common Stock Equity | 1,978,203 | 1,819,745 |
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2019 and 2018) | 0 | 0 |
Finance Lease Obligations | 67,316 | |
Finance Lease Obligations | 19,773 | |
Long-Term Debt, Net | 1,522,087 | 1,615,252 |
Total Capitalization | 3,567,606 | 3,454,770 |
Current Liabilities | ||
Current Maturities of Long-Term Debt | 80,330 | 0 |
Borrowings Under Credit Agreements | 165,000 | 0 |
Finance Lease Obligations | 17,086 | |
Finance Lease Obligations | 172,510 | |
Accounts Payable | 136,465 | 133,012 |
Accrued Taxes Other than Income Taxes | 42,741 | 41,686 |
Accrued Employee Expenses | 32,567 | 34,339 |
Accrued Interest | 16,700 | 17,927 |
Regulatory Liabilities | 96,017 | 95,094 |
Customer Deposits | 24,568 | 27,650 |
Derivative Instruments | 27,615 | 18,137 |
Other | 23,678 | 21,555 |
Total Current Liabilities | 662,767 | 561,910 |
Regulatory and Other Liabilities | ||
Deferred Income Taxes, Net | 432,484 | 369,705 |
Regulatory Liabilities | 477,495 | 512,425 |
Pension and Other Postretirement Benefits | 133,452 | 117,472 |
Derivative Instruments | 48,697 | 19,361 |
Other | 166,656 | 123,564 |
Total Regulatory and Other Liabilities | 1,258,784 | 1,142,527 |
Commitments and Contingencies | ||
Total Capitalization and Other Liabilities | $ 5,489,157 | $ 5,159,207 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Common Stock, Shares Authorized (in shares) | 75,000,000 | 75,000,000 |
Common Stock, Shares Outstanding (in shares) | 32,139,434 | 32,139,434 |
Preferred Stock, Shares Authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY - USD ($) $ in Thousands | Total | Common Stock | Capital Stock Expense | Retained Earnings | Accumulated Other Comprehensive Loss |
Beginning Balance at Dec. 31, 2016 | $ 1,559,035 | $ 1,296,539 | $ (6,357) | $ 273,408 | $ (4,555) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 176,668 | 176,668 | |||
Other Comprehensive (Loss) Income, Net of Tax | (1,671) | (1,671) | |||
Dividends Declared to Parent | (70,000) | (70,000) | |||
Ending Balances at Dec. 31, 2017 | 1,664,032 | 1,296,539 | (6,357) | 380,076 | (6,226) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 188,323 | 188,323 | |||
Other Comprehensive (Loss) Income, Net of Tax | 2,390 | 2,390 | |||
Dividends Declared to Parent | (85,000) | (85,000) | |||
Contribution from Parent | 50,000 | 50,000 | |||
Adoption of ASU, Cumulative Effect Adjustment | 0 | 878 | (878) | ||
Ending Balances at Dec. 31, 2018 | 1,819,745 | 1,346,539 | (6,357) | 484,277 | (4,714) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 186,515 | 186,515 | |||
Other Comprehensive (Loss) Income, Net of Tax | (3,057) | (3,057) | |||
Dividends Declared to Parent | (75,000) | (75,000) | |||
Contribution from Parent | 50,000 | 50,000 | |||
Ending Balances at Dec. 31, 2019 | $ 1,978,203 | $ 1,396,539 | $ (6,357) | $ 595,792 | $ (7,771) |
NATURE OF OPERATIONS AND SUMMAR
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 429,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis. BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Accounting for Regulated Operations TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers. Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a 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 December 31, 2019 , the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019 . 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. Leases TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 8 for additional disclosure about TEP’s leasing arrangements. Internal-Use Software TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheet at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statement during the periods presented. Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates. Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset or liability account based on the ACC approval of these costs in its depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities. Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. RESTRICTED CASH Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to the cash flow statement: Years Ended December 31, (in millions) 2019 2018 2017 Cash and Cash Equivalents $ 10 $ 138 $ 38 Restricted Cash included in: Investments and Other Property 16 14 11 Current Assets—Other 2 1 1 Total Cash, Cash Equivalents, and Restricted Cash $ 28 $ 153 $ 50 Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. ALLOWANCE FOR DOUBTFUL ACCOUNTS TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2019 2018 2017 Beginning of Period $ 5 $ 5 $ 5 Additions Charged to Cost and Expense 4 3 3 Write-offs (3 ) (3 ) (3 ) End of Period $ 6 $ 5 $ 5 INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory. UTILITY PLANT Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement. AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income. The average AFUDC rates on regulated construction expenditures are included in the table below: 2019 2018 2017 Average AFUDC Rates 7.86 % 7.12 % 7.31 % Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant: 2019 2018 2017 Average Annual Depreciation Rates 3.08 % 3.13 % 2.97 % Computer Software and Cloud Computing Costs Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense in the income statement. EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time. DEFERRED FINANCING COSTS Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to credit facility arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt. LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet. OPERATING REVENUES TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date delinquent and charges the customer a late payment fee. No component of the transaction price is allocated to unsatisfied performance obligations. TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP estimates variable consideration at the most likely amount to which the Company expects to be entitled and recognizes a refund liability until TEP is certain that the Company will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods. See Note 4 for the disaggregation of TEP's Operating Revenues. PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters. RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the LFCR mechanism. TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs . The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020 . The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism. Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Operating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism. When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. See Note 2 for additional information regarding regulatory matters. The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Beginning of Period $ 55 $ 42 Purchased 45 45 Used for Compliance (37 ) (32 ) End of Period $ 63 $ 55 TEP expenses the cost of internally developed RECs, including PBI activity that is not included in the table above and recoverable through the RES surcharge. TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement. INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities in the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income. TEP accounts for federal energy credits generated prior to 2013 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. TEP had an aggregate liability balance of $6 million and $7 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2019 and 2018 , respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million and $6 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018 , respectively. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS. PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 10 for additional information regarding the employee benefit plans. FAIR VALUE As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 13 for additional information regarding fair value. DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; (ii) reduce exposure to energy commodity price volatility; and (iii) hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities in the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity in the income statement. For derivatives designated as hedging contracts, TEP formally assesses, at inception, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy. For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 13 for additional information regarding derivative instruments. |
REGULATORY MATTERS
REGULATORY MATTERS | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices. The FERC regulates rates and services for electric transmission and wholesale power sales in interstate commerce. 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 RICE units at Sundt; • 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 in January and February 2020. The hearing will resume in April 2020. TEP requested new rates to be implemented by May 1, 2020. TEP cannot predict the timing or 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. 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 more timely recovery of transmission related costs. As part of the order, the FERC established hearing and settlement procedures, and all revisions to the OATT in the FERC order are subject to refund. As of December 31, 2019 , TEP had reserved $4 million of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Consolidated Balance Sheets as a result of the FERC proceedings. TEP cannot predict the outcome of the proceeding. Abandoned Plant Costs Also in May 2019, TEP filed with the FERC a request to recover through its OATT abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. On September 19, 2019, the FERC issued an order allowing TEP to recover 50% of its costs in its formula rate and established hearing and settlement procedures. TEP plans to incorporate the abandoned plant costs into its formula rate effective January 1, 2020, subject to refund. On September 26, 2019, the FERC issued an order consolidating the 2019 FERC Rate Case and Abandoned Plant Costs proceedings. In 2012, TEP wrote-off a portion of the deferred costs related to the Nogales transmission line. As of December 31, 2019 , there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Consolidated Balance Sheets. 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 issued the 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. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. TEP filed an information 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 next rate case. The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order: Years Ended December 31, (in millions) 2019 2018 Beginning of Period $ 4 $ — ACC Approved Refund (Reduction in Operating Revenues) (34 ) (33 ) Amount Returned to Customers Through Bill Credits 22 37 Regulatory Deferral 8 — End of Period $ — $ 4 See Note 14 for additional information regarding the TCJA. Federal Energy Regulatory Commission In 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the order and the FERC approved TEP's proposal of an overall transmission rate reduction of approximately 5.3% , reflecting the lower federal tax rate, to be effective March 21, 2018. As a result, TEP recognized a reduction in Operating Revenues on the Consolidated Statements of Income of $1 million in 2018 . Also in 2018, the FERC issued a NOPR regarding the effect of the TCJA and related EDIT amortization on rates. In November 2019, the FERC issued a final rule on the NOPR which required TEP to address the effect of the TCJA and related EDIT amortization in its next FERC rate case. As required by the final rule, TEP's 2019 FERC Rate Case addressed the effects of the TCJA and related EDIT amortization. See Note 14 for additional information regarding the TCJA. 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 adjusted annually each 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: Years Ended December 31, (in millions) 2019 2018 Beginning of Period $ (17 ) $ (9 ) Deferred Fuel and Purchased Power Costs 31 2 PPFAC Refunds (Recoveries) (1) 22 (10 ) End of Period $ 36 $ (17 ) (1) In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. Environmental Compliance Adjustor The ECA allows for the recovery of capital carrying costs and incremental operations and maintenance costs related to environmental investments, provided that they are not already recovered in base rates or recovered through another commission-approved mechanism. The eligible costs for the ECA are subject to a cap equal to 0.5% of total annual retail revenue. The Company recognized $2 million in 2019 , $3 million in 2018 , and $1 million in 2017 related to the return on company-owned environmental investments included in Operating Revenues on the Consolidated Statements of Income. Renewable Energy Standard The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting 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 September 2019, the ACC approved TEP's 2019 RES implementation plan with a budget amount of $55 million . The recovery funds the following: (i) above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. The Company recognized less than $1 million in 2019 , and $1 million in 2018 and 2017 of revenue as a return on company-owned solar projects. The return on company-owned solar projects is included in Operating Revenues on the Consolidated Statements of Income. TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism and requests recovery of these types of costs through its rate case process. In 2019, the percentage of TEP's retail kWh sales attributable to the RES was approximately 16% , exceeding the overall 2019 RES requirement of 9% . The ACC approved the waiver of the 2019 DG requirement. Energy Efficiency Standards Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of December 31, 2019 , TEP's cumulative annual energy savings was approximately 19% . TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 2019 , 2018 , and 2017 related to performance in Operating Revenues on the Consolidated Statements of Income. In February 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. 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 the amounts are verifiable regardless of when the lost retail kWh sales occur. 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 Consolidated Statements of Income: Years Ended December 31, (in millions) 2019 2018 2017 LFCR Revenues $ 33 $ 26 $ 22 REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2019 2018 Regulatory Assets Pension and Other Postretirement Benefits (Note 10) Various $ 135 $ 126 Derivatives (Note 13) 10 72 27 Early Generation Retirement Costs Various 68 72 Lost Fixed Cost Recovery 2 46 35 Income Taxes Recoverable through Future Rates (1) Various 38 47 Under Recovered Purchased Energy Costs 1 36 — Property Tax Deferrals (2) 1 24 23 Final Mine Reclamation and Retiree Healthcare Costs (3) 19 19 29 Springerville Unit 1 Leasehold Improvements (4) 4 9 11 Other Regulatory Assets Various 18 30 Total Regulatory Assets 465 400 Less Current Portion 1 138 107 Total Non-Current Regulatory Assets $ 327 $ 293 Regulatory Liabilities Income Taxes Payable through Future Rates (1) Various $ 327 $ 354 Net Cost of Removal (5) Various 164 171 Renewable Energy Standard Various 59 52 Deferred Investment Tax Credits (6) Various 3 7 Over Recovered Purchased Energy Costs Various — 17 Other Regulatory Liabilities Various 20 6 Total Regulatory Liabilities 573 607 Less Current Portion 1 96 95 Total Non-Current Regulatory Liabilities $ 477 $ 512 (1) Amortized over the life of the assets. See Note 14 for additional information regarding income taxes. (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, Four Corners, and Navajo. 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 occur through 2038 . (4) Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year period. (5) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation 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. Early Generation Retirement Costs Navajo Generating Station In 2017, the Navajo Nation approved a land lease extension allowing TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the co-owners of Navajo retired the generation station in November 2019, with related decommissioning activities continuing through 2054 . TEP is currently recovering the capital and operating costs in base rates using a useful life of 2030 for Navajo. Due to the early retirement, TEP requested recovery of final retirement costs over a 10 -year period in the 2019 Rate Case. Sundt Generating Station In 2018, the Pima County Department of Environmental Quality approved TEP's air permit application. Under the project outlined in the application, TEP is placing in service 10 RICE units and was required to retire Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 for Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10 -year period in the 2019 Rate Case. See Note 3 for additional information on the RICE units. Regulatory Assets and Liabilities 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. IMPACTS OF REGULATORY ACCOUNTING If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements. |
UTILITY PLANT AND JOINTLY-OWNED
UTILITY PLANT AND JOINTLY-OWNED FACILITIES | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
UTILITY PLANT AND JOINTLY-OWNED FACILITIES | UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (3) Average Remaining Life in Years (3) December 31, ($ in millions) 2019 2018 Plant in Service Generation Plant 3.19% 20 $ 3,065 $ 2,667 Transmission Plant 1.69% 37 1,060 1,010 Distribution Plant 1.56% 31 1,784 1,692 General Plant 5.89% 20 477 409 Intangible Plant, Software Costs, and Other (1) Various Various 271 239 Plant Held for Future Use — — 7 3 Total Plant in Service (2) $ 6,664 $ 6,020 (1) Primarily represents computer software. Unamortized computer software costs were $78 million and $73 million as of December 31, 2019 and 2018 , respectively. Amortized computer software costs were $26 million in 2019 , $24 million in 2018 , and $19 million in 2017 . Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of three years for large enterprise software. (2) Includes plant acquisition adjustments of $(211) million and $(134) million as of December 31, 2019 and 2018 , respectively. (3) Based on the 2015 depreciation study available for the major classes of Plant in Service, effective March 1, 2017, as approved by the ACC as part of the 2017 TEP Rate Order. TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 2019 FERC Rate Case. Gila River Unit 2 In 2017, TEP entered into a 20 -year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which included a three -year option to purchase the unit. The Tolling PPA was accounted for as a finance lease. See Note 8 for additional information regarding TEP's leases. In December 2019, TEP completed its purchase of Gila River Unit 2 for $165 million . The purchase increased Plant in Service and Material and Supplies and decreased Utility Plant Under Finance Leases on the Consolidated Balance Sheets as of December 31, 2019 . RICE Units Under the air permit approved by the Pima County Department of Environmental Quality, TEP placed in service five natural gas RICE units in December 2019. As a result, Plant in Service on the Consolidated Balance Sheets increased by $82 million . An additional five units are scheduled to be placed in service in the first quarter of 2020. The 10 units have a planned total nominal generation capacity of 188 MW. JOINTLY-OWNED FACILITIES As of December 31, 2019 , TEP was a participant in the following jointly-owned generation facilities and transmission systems: (in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Unit 1 50.0% $ 289 $ 1 $ (193 ) $ 97 Four Corners Units 4 and 5 7.0% 175 5 (77 ) 103 Luna 33.3% 57 — (1 ) 56 Gila River Unit 3 75.0% 200 2 (61 ) 141 Gila River Common Facilities 43.8% 71 — (23 ) 48 Springerville Coal Handling Facilities 83.0% 208 — (90 ) 118 Transmission Facilities Various 545 5 (295 ) 255 Total $ 1,545 $ 13 $ (740 ) $ 818 As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation. ASSET RETIREMENT OBLIGATIONS The liability accrual of AROs is primarily related to generation and PV assets and is included in Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Beginning of Period $ 72 $ 46 Liabilities Incurred — 10 Liabilities Settled (1) (2 ) — Regulatory Deferral/Accretion Expense 2 3 Revisions to the Present Value of Estimated Cash Flows (2) 35 13 End of Period $ 107 $ 72 (1) Primarily related to the retirement of Navajo. (2) Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of certain generation facilities. |
REVENUE
REVENUE | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE | REVENUE TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP has certain contracts with variable transaction pricing that require it to estimate the expected consideration. DISAGGREGATION OF REVENUES The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service: Years Ended December 31, (in millions) 2019 2018 2017 Retail $ 972 $ 1,022 $ 1,017 Wholesale 247 238 152 Other Services 124 100 103 Revenues from Contracts with Customers 1,343 1,360 1,272 Alternative Revenues 35 28 24 Other 40 45 45 Total Operating Revenues $ 1,418 $ 1,433 $ 1,341 Retail Revenues TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Unbilled revenues primarily increase during the spring and summer months and decrease during the fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances in the balance sheet. See Note 5 for components of Accounts Receivable, Net on the Consolidated Balance Sheets. Wholesale Revenues TEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company identifies one or more performance obligations. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand (for capacity) or the reading of meters (for power). For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Operating Revenues on the Consolidated Statements of Income. In May 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing proposed replacing TEP's stated transmission rates with a forward-looking formula rate. Effective August 2019, the FERC authorized TEP to bill the proposed rate revisions, subject to refund. 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 FERC rate case. Other Services Revenues Other Services Revenues primarily include fees earned as operator of Springerville Units 3 and 4, miscellaneous service-related revenues, and reimbursement of various operating expenses for the use of the Springerville Common Facilities by Springerville Units 3 and 4 and the Springerville Coal Handling Facilities by Springerville Unit 3. When TEP recognizes revenue for reimbursement of Springerville Common Facilities and Springerville Coal Handling Facilities' operating expenses, the associated expenses are recorded in their respective line items in the income statement based on the nature of services provided. Alternative Revenues Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. 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. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of applicable retail revenues of 2% . In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding these cost recovery mechanisms. Other Revenues Other Revenues include gains and losses on derivative contracts, late and returned payment finance charges, and lease income. See Note 13 for information regarding derivative instruments and Note 8 for information regarding lease income. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 12 Months Ended |
Dec. 31, 2019 | |
Receivables [Abstract] | |
ACCOUNTS RECEIVABLE | ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Customer (1) $ 92 $ 99 Customer, Unbilled 42 45 Due from Affiliates (Note 6) 8 8 Other 19 25 Allowance for Doubtful Accounts (6 ) (5 ) Accounts Receivable, Net $ 155 $ 172 (1) Includes $5 million and $8 million as of December 31, 2019 and 2018 , respectively, of receivables related to revenue from derivative instruments. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and the 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, Net and Accounts Payable on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Receivables from Related Parties UNS Electric $ 6 $ 7 UNS Gas 2 1 Total Due from Related Parties $ 8 $ 8 Payables to Related Parties SES $ 2 $ 2 UNS Electric 1 1 UNS Gas — 1 UNS Energy 1 1 Total Due to Related Parties $ 4 $ 5 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2019 2018 2017 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 7 $ 6 $ 7 Wholesale Revenues, UNS Electric (1) 1 1 — Control Area Services, UNS Electric (2) 4 3 3 Common Costs, UNS Energy Affiliates (3) 19 18 16 Corporate Services, Fortis Affiliates (4) — — 2 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (5) 15 15 15 Corporate Services, UNS Energy (6) 6 6 5 Corporate Services, UNS Energy Affiliates (7) 4 7 5 Capacity Charges, UNS Gas (8) 1 1 — (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT. (2) 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) TEP provides non-tariffed goods and services to Fortis affiliate companies at the higher of fully burdened cost or fair market value. (5) 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. (6) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 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 $6 million in 2019 , $5 million in 2018 , and $6 million in 2017 . (7) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. (8) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities. CONTRIBUTIONS FROM PARENT In January 2020 , an equity contribution of $125 million was received by TEP from UNS Energy. |
DEBT AND CREDIT AGREEMENTS
DEBT AND CREDIT AGREEMENTS | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
DEBT AND CREDIT AGREEMENTS | DEBT AND CREDIT AGREEMENTS DEBT Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2019 2018 Notes 2011 Notes 5.15% 2021 $ 250 $ 250 2012 Notes 3.85% 2023 150 150 2014 Notes 5.00% 2044 150 150 2015 Notes 3.05% 2025 300 300 2018 Notes 4.85% 2048 300 300 Tax-Exempt Local Furnishings Bonds (1) 2010 Pima A 5.25% 2040 100 100 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 Tax-Exempt Pollution Control Bonds (2) 2009 Pima A 4.95% 2020 80 80 2009 Coconino A 5.13% 2032 — 15 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt (3) 1,614 1,629 Less Unamortized Discount and Debt Issuance Costs 12 14 Less Current Maturities of Long-Term Debt 80 — Total Long-Term Debt, Net $ 1,522 $ 1,615 (1) The 2010 Pima A bonds can be redeemed at par on or after October 2020. TEP has the option to redeem the remaining bonds at par on dates ranging from first quarter of 2022 to first quarter of 2023 . (2) The 2009 Pima A bonds mature in October 2020. The 2012 Apache A bonds may be redeemed at par in the first quarter of 2022 . (3) As of December 31, 2019 , all of TEP's debt is unsecured. Issuances and Redemptions Fixed Rate Debt In November 2019, TEP redeemed at par a series of fixed rate tax-exempt bonds with an aggregate principal amount of $15 million prior to the maturity of the bonds. In November 2018, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to June 1, 2048 , with a make-whole premium plus accrued interest. On or after June 1, 2048 , TEP may redeem the notes at par plus accrued interest. Variable Rate Debt In December 2018, TEP redeemed at par a series of variable rate tax-exempt bonds with an aggregate principal amount of $37 million prior to the maturity of the bonds. The bonds were backed by an LOC issued pursuant to the 2010 Reimbursement Agreement which expired in February 2019. In connection with the redemption of the related bonds, the $37 million LOC and the associated 2010 Reimbursement Agreement were terminated. In November 2018, TEP redeemed at par a series of variable rate tax-exempt bonds with an aggregate principal amount of $100 million prior to the maturity of the bonds. The bonds were subject to mandatory tender for purchase in November 2018. Maturities Long-term debt matures on the following dates: (in millions) Long-Term Debt (1) 2020 $ 80 2021 250 2022 — 2023 150 2024 — Thereafter 1,134 Total $ 1,614 (1) Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount. CREDIT AGREEMENTS Amounts borrowed under credit agreements are recorded in Borrowings Under Credit Agreements on the Consolidated Balance Sheets. 2019 Credit Agreement In December 2019, TEP entered into an unsecured credit agreement with a maturity date of December 2020 that provides for term loans. Terms are as follows: Weighted Average Interest Rate Capacity Borrowed (1) Available Pricing (in millions) December 31, 2019 Term Loan $ 225 $ 165 $ 60 4.75 % LIBOR + 0.550% or ABR + 0.00% (1) All amounts borrowed will be due and payable by December 2020. The 2019 Credit Agreement is intended to supplement TEP's liquidity during a period of increased capital spending and to provide funds: (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. Amounts paid or repaid may not be reborrowed. As of February 12, 2020 , no amount was available as the term loan had been fully drawn. See Note 3 and Note 9 for additional information on the purchase of Gila River Unit 2 and Oso Grande, respectively. 2015 Credit Agreement In October 2015, TEP entered into an unsecured credit agreement with a maturity date of October 2022 that provides for revolving credit commitments and LOC facilities. Terms are as follows: Capacity Sub-Limit LOC Borrowed Available Weighted Average Interest Rate Pricing (1) (in millions) December 31, 2019 Revolver and LOC $ 250 $ 50 $ — $ 250 — % LIBOR + 1.000% or ABR + 0.00% (in millions) December 31, 2018 Revolver and LOC $ 250 $ 50 $ — $ 250 — % LIBOR + 1.000% or ABR + 0.00% (1) Interest rates and fees are based on a pricing grid tied to TEP's credit rating. Amounts borrowed under the 2015 Credit Agreement will be used for working capital and other general corporate purposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and other business activities. In January 2020 , TEP delivered $12 million in LOCs pursuant to TEP taking ownership of Oso Grande under the build-transfer agreement. As of February 12, 2020 , there was $173 million |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
LEASES | LEASES TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years . Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. TEP’s leases are included in the balance sheet as follows: (in millions) Lease Type December 31, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 151 Accumulated Amortization of Finance Lease Assets Finance (77 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations Finance 17 Finance Lease Obligations Finance 67 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 6 Springerville Common Facilities Leases TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019 , TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million . The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities. Gila River Unit 2 In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20 -year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA included a three -year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed. The following table presents the components of TEP’s lease cost: Year Ended (in millions) December 31, 2019 Finance Amortization of Leased Assets (1) $ 13 Interest on Lease Liabilities (2) 13 Operating 1 Variable 16 Short Term 1 Total Lease Cost $ 44 (1) TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment. (2) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019 . TEP purchased Gila River Unit 2 in December 2019. TEP has a 20 -year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020. As of December 31, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases Operating Leases Total 2020 $ 18 $ 1 $ 19 2021 68 1 69 2022 — 1 1 2023 — 1 1 2024 — 1 1 Thereafter — 4 4 Total Lease Payments 86 9 95 Less Imputed Interest 2 2 4 Total Lease Obligations 84 7 91 Less Current Portion 17 1 18 Total Non-Current Lease Obligations $ 67 $ 6 $ 73 The following table presents TEP's lease terms and discount rate related to its leases: December 31, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 2.2 % Operating Leases 4.1 % The following table presents TEP's cash flow information related to its leases: Year Ended (in millions) December 31, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 13 Operating Cash Flows used for Operating Leases 1 Financing Cash Flows used for Finance Leases 11 Investing Cash Flows used for Finance Leases 164 See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years . Operating lease income for the year ended December 31, 2019 , was $1 million . TEP's expected operating lease payments to be received as of December 31, 2019 , are $1 million in each of 2020 through 2024 and thereafter. DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 TEP's operating lease cost was $1 million for the year ended December 31, 2018 . See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. |
LEASES | LEASES TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years . Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. TEP’s leases are included in the balance sheet as follows: (in millions) Lease Type December 31, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 151 Accumulated Amortization of Finance Lease Assets Finance (77 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations Finance 17 Finance Lease Obligations Finance 67 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 6 Springerville Common Facilities Leases TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019 , TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million . The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities. Gila River Unit 2 In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20 -year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA included a three -year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed. The following table presents the components of TEP’s lease cost: Year Ended (in millions) December 31, 2019 Finance Amortization of Leased Assets (1) $ 13 Interest on Lease Liabilities (2) 13 Operating 1 Variable 16 Short Term 1 Total Lease Cost $ 44 (1) TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment. (2) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019 . TEP purchased Gila River Unit 2 in December 2019. TEP has a 20 -year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020. As of December 31, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases Operating Leases Total 2020 $ 18 $ 1 $ 19 2021 68 1 69 2022 — 1 1 2023 — 1 1 2024 — 1 1 Thereafter — 4 4 Total Lease Payments 86 9 95 Less Imputed Interest 2 2 4 Total Lease Obligations 84 7 91 Less Current Portion 17 1 18 Total Non-Current Lease Obligations $ 67 $ 6 $ 73 The following table presents TEP's lease terms and discount rate related to its leases: December 31, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 2.2 % Operating Leases 4.1 % The following table presents TEP's cash flow information related to its leases: Year Ended (in millions) December 31, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 13 Operating Cash Flows used for Operating Leases 1 Financing Cash Flows used for Finance Leases 11 Investing Cash Flows used for Finance Leases 164 See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years . Operating lease income for the year ended December 31, 2019 , was $1 million . TEP's expected operating lease payments to be received as of December 31, 2019 , are $1 million in each of 2020 through 2024 and thereafter. DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 TEP's operating lease cost was $1 million for the year ended December 31, 2018 . See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. |
LEASES | LEASES TEP leases an interest in Springerville Common Facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years . Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. TEP’s leases are included in the balance sheet as follows: (in millions) Lease Type December 31, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 151 Accumulated Amortization of Finance Lease Assets Finance (77 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations Finance 17 Finance Lease Obligations Finance 67 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 6 Springerville Common Facilities Leases TEP finances a portion of the Springerville Common Facilities with finance leases. In December 2019 , TEP elected to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $68 million . The lease assets are amortized over the estimated life of the underlying plant because ownership of the plant transfers at the end of the lease term. In addition, TEP has agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions should TEP complete the purchase of the Springerville Common Facilities: (i) SRP will be obligated to buy a 14% undivided interest in the facilities; and (ii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities. Gila River Unit 2 In May 2018, TEP recorded an increase to finance lease assets and obligations related to a 20 -year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA included a three -year option to purchase the unit. TEP exercised its option and subsequently purchased Gila River Unit 2 in December 2019 at which time the lease asset and obligation were removed. The following table presents the components of TEP’s lease cost: Year Ended (in millions) December 31, 2019 Finance Amortization of Leased Assets (1) $ 13 Interest on Lease Liabilities (2) 13 Operating 1 Variable 16 Short Term 1 Total Lease Cost $ 44 (1) TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment. (2) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019 . TEP purchased Gila River Unit 2 in December 2019. TEP has a 20 -year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020. As of December 31, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases Operating Leases Total 2020 $ 18 $ 1 $ 19 2021 68 1 69 2022 — 1 1 2023 — 1 1 2024 — 1 1 Thereafter — 4 4 Total Lease Payments 86 9 95 Less Imputed Interest 2 2 4 Total Lease Obligations 84 7 91 Less Current Portion 17 1 18 Total Non-Current Lease Obligations $ 67 $ 6 $ 73 The following table presents TEP's lease terms and discount rate related to its leases: December 31, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 2.2 % Operating Leases 4.1 % The following table presents TEP's cash flow information related to its leases: Year Ended (in millions) December 31, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 13 Operating Cash Flows used for Operating Leases 1 Financing Cash Flows used for Finance Leases 11 Investing Cash Flows used for Finance Leases 164 See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. In addition, TEP leases limited office facilities and utility property to others with remaining terms of four to thirteen years . Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to three years . Operating lease income for the year ended December 31, 2019 , was $1 million . TEP's expected operating lease payments to be received as of December 31, 2019 , are $1 million in each of 2020 through 2024 and thereafter. DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 TEP's operating lease cost was $1 million for the year ended December 31, 2018 . See Note 12 for non-cash transactions that resulted in recognition of right-of-use assets in exchange for lease liabilities. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES COMMITMENTS Unconditional Purchase Obligations As of December 31, 2019 , TEP had the following unconditional minimum purchase obligations: (in millions) 2020 2021 2022 2023 2024 Thereafter Total Fuel, Including Transportation $ 94 $ 61 $ 40 $ 33 $ 33 $ 194 $ 455 Purchased Power 8 — — — — — 8 Transmission 21 16 14 3 3 6 63 Renewable Power Purchase Agreements 63 63 63 63 62 543 857 RES Performance-Based Incentives 8 7 7 7 7 33 69 Land Easements and Rights-of-Way (1) 1 2 1 1 3 79 87 Total Purchase Commitments $ 195 $ 149 $ 125 $ 107 $ 108 $ 855 $ 1,539 (1) Land easements and rights-of-way have varying terms and provisions and reflect expiration dates through 2054 . Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBI costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms. Fuel, Including Transportation TEP has long-term agreements for the purchase and delivery of coal with various expiration dates between 2020 and 2031 . Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs. TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2022 and 2040 . Purchased Power TEP has contracts with utilities and other energy suppliers for purchased power to: (i) meet system load and energy requirements; (ii) replace generation from company-owned units under maintenance and during outages; and (iii) meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the second quarter of 2020 . Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2019 . Transmission TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2020 and 2030 . Renewable Power Purchase Agreements TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2036 . RES Performance-Based Incentives TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2020 and 2034 . Build-Transfer Agreement In March 2019, TEP entered into a build-transfer agreement to develop a 250 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico (Oso Grande) with estimated costs of approximately $384 million . In January 2020 , TEP took ownership of Oso Grande. Construction commenced in the third quarter of 2019 and is expected to be completed for operation by December 2020. TEP made payments under the build-transfer agreement of $47 million in 2019 and $226 million in January 2020 . 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. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP and are disclosed below. Claims Related to San Juan Generating Station WildEarth Guardians In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to SJCC) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, including: (i) failure to provide requisite public notice and participation; and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSMRE so the OSMRE may prepare a new Environmental Impact Statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 2019. The order provides that: (i) the OSMRE’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 2019, then the approved mine plan will immediately be vacated, absent further court order. On April 30, 2019, the OSMRE issued a final Record of Decision (ROD) on the Final EIS released March 15, 2019. The Final EIS contemplates continued mining at the San Juan Mine in annual quantities similar to those currently being provided through 2033. The Assistant Secretary for Land and Minerals Management approved the mining plan outlined in the ROD in August 2019. TEP is not a party in this matter but does own 50% of Unit 1 at San Juan. San Juan is scheduled for early retirement in 2022. TEP does not anticipate any significant impact on the cost of coal at San Juan related to this matter. 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 when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust 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 rate payers 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 out. San Juan and Four Corners 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 mine reclamation costs at both mines is $57 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 $36 million and $31 million as of December 31, 2019 and 2018 , respectively, was recorded in Other on the Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs. Navajo In December 2019, TEP entered into an agreement with the owner and operator of the Kayenta Mine and the third-party owners of Navajo for the settlement and release of asserted claims associated with the early retirement of Navajo. During 2019, TEP paid $17 million related to the retirement of Navajo which includes $8 million paid for final mine reclamation costs as a result of the settlement. As of December 31, 2019 , TEP had no liability balance related to Navajo final mine reclamation. A liability balance related to Navajo final mine reclamation of $5 million as of December 31, 2018 , was recorded in Current Liabilities—Other on the Consolidated Balance Sheets. Performance Guarantees TEP has joint participation agreements with participants at Navajo, 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 December 31, 2019 , there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expired in 2019, but certain performance obligations continue through the decommissioning of the generating station. The San Juan participation agreement expires in 2022, Four Corners in 2041, and Luna in 2046. 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 ratepayers. 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 parcel adjacent to these landfills. On November 8, 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 | 12 Months Ended |
Dec. 31, 2019 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS PENSION BENEFIT PLANS TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under IRS regulations. TEP also maintains a SERP for executive management. OTHER POSTRETIREMENT BENEFITS PLAN TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $1 million in 2019 and $3 million in 2018 and 2017 to the VEBA. Other postretirement benefits for unclassified employees are self-funded. REGULATORY RECOVERY TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset or liability, as such amounts are probable of future recovery or refund in rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income (Loss) since SERP expense is not currently recoverable in rates. The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2019 2018 2019 2018 Regulatory Assets $ 135 $ 126 $ — $ — Regulatory Liabilities — — (1 ) (3 ) Accrued Employee Expenses (2 ) (1 ) (2 ) (3 ) Pension and Other Postretirement Benefits (77 ) (63 ) (56 ) (54 ) Accumulated Other Comprehensive Loss, SERP 10 6 — — Net Amount Recognized $ 66 $ 68 $ (59 ) $ (60 ) OBLIGATIONS AND FUNDED STATUS The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2019 and 2018 . The table below presents the status of all of TEP’s pension and other postretirement benefit plans. All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2019 2018 2019 2018 Change in Benefit Obligation Beginning of Period $ 440 $ 475 $ 74 $ 82 Actuarial (Gain) Loss 76 (42 ) 4 (8 ) Interest Cost 18 16 3 2 Service Cost 13 15 4 5 Benefits Paid (23 ) (23 ) (6 ) (5 ) Plan Amendments 1 (1 ) — (2 ) End of Period 525 440 79 74 Change in Fair Value of Plan Assets Beginning of Period 376 403 17 17 Actual Return on Plan Assets 81 (25 ) 4 (1 ) Benefits Paid (22 ) (23 ) (6 ) (5 ) Employer Contributions (1) 11 21 6 6 End of Period 446 376 21 17 Funded Status at End of Period $ (79 ) $ (64 ) $ (58 ) $ (57 ) (1) TEP expects to contribute $11 million to the pension plans and $1 million to the VEBA trust in 2020 . The $85 million increase in the pension benefit obligation was driven by a significant decrease in discount rates as a result of a decrease in interest rates. The $70 million increase in the pension plan assets was due to positive equity returns and fixed income returns as a result of a decline in interest rates. The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2019 2018 2019 2018 Net (Gain) Loss $ 145 $ 133 $ 1 $ (1 ) Prior Service Cost (Benefit) — — (2 ) (2 ) The accumulated benefit obligation aggregated for all pension plans was $476 million and $402 million as of December 31, 2019 and 2018 , respectively. All of the pension plans had accumulated benefit obligations in excess of plan assets as of both December 31, 2019 and 2018 . The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2019 2018 Accumulated Benefit Obligation $ 476 $ 230 Fair Value of Plan Assets 446 202 The Company measures service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2019 2018 2017 2019 2018 2017 Service Cost $ 13 $ 15 $ 13 $ 4 $ 5 $ 4 Non-Service Cost Interest Cost 18 16 15 3 2 2 Expected Return on Plan Assets (26 ) (28 ) (25 ) (2 ) (1 ) (1 ) Amortization of Net (Gain) Loss 8 7 8 — — — Net Periodic Benefit Cost $ 13 $ 10 $ 11 $ 5 $ 6 $ 5 The non-service components of net periodic benefit cost are included in Other, Net on the Consolidated Statements of Income. In 2019 and 2018 , TEP capitalized 21% and 19% of service cost, respectively, as a cost of construction. The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2019 2018 2017 2019 2018 2017 2019 2018 2017 Current Year Actuarial (Gain) Loss $ 16 $ 12 $ 5 $ 4 $ (1 ) $ 3 $ 1 $ (6 ) $ (1 ) Amortization of Net Loss (8 ) (7 ) (7 ) (1 ) — — — — — Prior Service Credit (Cost) — — — 1 (1 ) — — (2 ) — Total Recognized (Gain) Loss $ 8 $ 5 $ (2 ) $ 4 $ (2 ) $ 3 $ 1 $ (8 ) $ (1 ) For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25 th percentile to the 75 th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes. The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2019 2018 2019 2018 Discount Rate 3.6% 4.5% 3.3% 4.3% Rate of Compensation Increase 2.8% 2.8% N/A N/A The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2019 2018 2017 2019 2018 2017 Discount Rate, Service Cost 4.7% 3.8% 4.4% 4.5% 3.8% 4.3% Discount Rate, Interest Cost 4.2% 3.4% 3.7% 4.0% 3.2% 3.3% Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A Expected Return on Plan Assets 7.0% 7.0% 7.0% 7.0% 7.0% 7.0% Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached: December 31, 2019 2018 Next Year (Pre-65) 6.3% 6.5% Next Year (Post-65) 7.5% 7.8% Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5% Year Ultimate Rate is Reached (Pre-65) 2037 2037 Year Ultimate Rate is Reached (Post-65) 2037 2037 PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement Benefits 2019 2018 2019 2018 Asset Category Equity Securities 46 % 45 % 65 % 60 % Fixed Income Securities 45 % 45 % 33 % 38 % Real Estate 8 % 8 % — % — % Other 1 % 2 % 2 % 2 % Total 100 % 100 % 100 % 100 % As of December 31, 2019 , the fair value of VEBA trust assets was $21 million , of which $7 million were fixed income investments and $14 million were equities. As of December 31, 2018 , the fair value of VEBA trust assets was $17 million , of which $7 million were fixed income investments and $10 million were equities. The VEBA trust assets are primarily Level 2 assets within the fair value hierarchy described below. There are no Level 3 assets in the VEBA trust. The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2019 Asset Category Cash Equivalents $ 2 $ — $ — $ 2 Equity Securities: United States Large Cap — 55 — 55 United States Small Cap — 21 — 21 Non-United States — 80 — 80 Global — 51 — 51 Fixed Income — 199 — 199 Real Estate — 10 23 33 Private Equity — — 5 5 Total $ 2 $ 416 $ 28 $ 446 December 31, 2018 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 45 — 45 United States Small Cap — 17 — 17 Non-United States — 67 — 67 Global — 42 — 42 Fixed Income — 167 — 167 Real Estate — 9 22 31 Private Equity — — 6 6 Total $ 1 $ 347 $ 28 $ 376 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2017 $ 6 $ 21 $ 27 Actual Return on Plan Assets: Assets Held at Reporting Date 2 1 3 Purchases, Sales, and Settlements (2 ) — (2 ) Balance as of December 31, 2018 6 22 28 Actual Return on Plan Assets: Assets Held at Reporting Date 1 1 2 Purchases, Sales, and Settlements (2 ) — (2 ) Balance as of December 31, 2019 $ 5 $ 23 $ 28 Pension Plan Investments Investment Goals Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. Risk Management TEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes. Relationship between Plan Assets and Benefit Obligations The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation. Target Allocation Percentages The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. Pension Other Postretirement Benefits December 31, 2019 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 12% 39% United States Small Cap 5% 5% Non-United States Developed —% 7% Non-United States Emerging —% 9% Global Equity 26% —% Global Infrastructure 3% —% Fixed Income 45% 38% Real Estate 8% —% Private Equity 1% —% Total 100% 100% Pension Fund Descriptions For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds. ESTIMATED FUTURE BENEFIT PAYMENTS TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate. (in millions) 2020 2021 2022 2023 2024 2025-2029 Pension Benefits $ 26 $ 26 $ 26 $ 27 $ 28 $ 147 Other Postretirement Benefits 5 5 5 5 5 25 DEFINED CONTRIBUTION PLAN TEP offers a defined contribution savings plan to all eligible employees. The plan meets the IRS required standards for 401(k) qualified plans. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $6 million in 2019 , $7 million in 2018 , and $6 million in 2017 . |
SHARE-BASED COMPENSATION
SHARE-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
SHARE-BASED COMPENSATION | SHARE-BASED COMPENSATION 2015 SHARE UNIT PLAN The Human Resources and Governance Committee of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (Plan) effective January 2015. Under the Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of PSUs and RSUs annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. UNS Energy accounts for forfeitures as they occur. The following table represents PSUs and RSUs awarded by UNS Energy: 2019 2018 2017 PSUs 66,978 54,426 68,126 RSUs 33,489 27,213 34,063 The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $12 million and $9 million as of December 31, 2019 and 2018 , respectively. TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2019 , $2 million in 2018 , and $4 million in 2017 based on its share of UNS Energy's compensation expense. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Years Ended December 31, (in millions) 2019 2018 2017 Interest Paid, Net of Amounts Capitalized $ 80 $ 67 $ 61 Income Tax Refunds (1) (14 ) — — (1) TEP received a refund of AMT credit carryforwards in 2019. See Note 14 for additional information regarding AMT. NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: Years Ended December 31, (in millions) 2019 2018 2017 Finance Leases $ 67 $ 164 $ — Accrued Capital Expenditures 40 31 24 Asset Retirement Obligations Increase (Decrease) (1) 26 20 10 Operating Leases (2) 8 — — Renewable Energy Credits 3 3 2 Net Cost of Removal Increase (Decrease) (3) (10 ) (4 ) (88 ) (1) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of expected future AROs. (2) On January 1 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. (3) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. |
FAIR VALUE MEASUREMENTS AND DER
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2019 | |
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. 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 Level 3 Total (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 ) (in millions) December 31, 2018 Assets Cash Equivalents (1) $ 55 $ — $ — $ 55 Restricted Cash (1) 15 — — 15 Energy Derivative Contracts, Regulatory Recovery (2) — 10 — 10 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 70 10 2 82 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (35 ) (2 ) (37 ) Total Liabilities — (35 ) (2 ) (37 ) Total Assets (Liabilities), Net $ 70 $ (25 ) $ — $ 45 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit , which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 2 as of December 31, 2019 and Level 3 as of December 31, 2018 ) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to decreases in forward market prices of natural gas and increases in volume. All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) December 31, 2019 Derivative Assets Energy Derivative Contracts $ 6 $ 4 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (76 ) (4 ) (2 ) (70 ) (in millions) December 31, 2018 Derivative Assets Energy Derivative Contracts $ 12 $ 11 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (37 ) (11 ) — (26 ) 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. The Company 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. The Company 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. Cash Flow Hedges To mitigate the exposure to volatility in variable interest rates on debt, TEP had an interest rate swap agreement that expired in January 2020 . As of December 31, 2019 , the total notional amount of the interest rate swap was $6 million . No notional amount remained as of February 12, 2020 . The after-tax unrealized gains and losses on cash flow hedge activities were reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense on the Consolidated Statements of Income are not material to TEP's financial position or results of operations. 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 in the balance sheet: Years Ended December 31, (in millions) 2019 2018 2017 Unrealized Net Loss (1) $ (45 ) $ (9 ) $ (18 ) (1) In 2019 , unrealized net loss on regulatory recoverable derivative contracts increased primarily due to decreases in forward market prices of natural gas and increases in volume. Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income: Years Ended December 31, (in millions) 2019 2018 2017 Operating Revenues $ 6 $ 5 $ 5 Derivative Volumes As of December 31, 2019 , TEP had energy contracts that will settle on various expiration dates through 2029 . The following table presents volumes associated with the energy contracts: December 31, 2019 2018 Power Contracts GWh 4,740 1,743 Gas Contracts BBtu 122,779 146,933 Level 3 Fair Value Measurements As of December 31, 2019 , TEP does not have any Level 3 assets and liabilities balances remaining. The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Approach Fair Value of Unobservable Inputs Range of Unobservable Inputs Assets Liabilities (in millions) December 31, 2018 Forward Power Contracts Market approach $ 3 $ (2 ) Market price per MWh $ 16.80 $ 47.05 Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income (loss), rather than in the income statement. 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 at the end of the period: Years Ended December 31, (in millions) 2019 2018 Beginning of Period $ 1 $ 2 Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments (12 ) (4 ) Operating Revenues 5 5 Settlements 1 (2 ) Transfers Out of Level 3 (1) 5 — End of Period $ — $ 1 Gains (Losses), Assets (Liabilities) Still Held $ — $ 1 (1) Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities. 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; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, 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 $100 million as of December 31, 2019 , compared with $41 million as of December 31, 2018 . As of December 31, 2019 , TEP had $2 million of cash posted as collateral to provide credit enhancement which was reflected in Current Assets—Other on the Consolidated Balance Sheets. As of February 12, 2020 , there was no collateral posted. If the credit risk contingent features were triggered on December 31, 2019 , TEP would have been required to post an additional $98 million of collateral of which $19 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. Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Net Carrying Value Fair Value Fair Value Hierarchy December 31, (in millions) 2019 2018 2019 2018 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,602 $ 1,615 $ 1,755 $ 1,672 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to pre-tax income due to the following: Years Ended December 31, (in millions) 2019 2018 2017 Federal Income Tax Expense at Statutory Rate $ 46 $ 49 $ 97 State Income Tax Expense, Net of Federal Deduction 9 9 9 Federal/State Tax Credits (6 ) (10 ) (9 ) Allowance for Equity Funds Used During Construction (3 ) (1 ) (2 ) Impact of Enactment, TCJA — — 7 Excess Deferred Income Taxes (9 ) (6 ) — Impact of AMT Sequestration (2 ) 2 — Other (1 ) — (1 ) Total Federal and State Income Tax Expense $ 34 $ 43 $ 101 Income Tax Expense included on the Consolidated Statements of Income consists of the following: Years Ended December 31, (in millions) 2019 2018 2017 Current Income Tax Expense Federal $ (8 ) $ (13 ) $ — State — — — Total Current Income Tax Expense (8 ) (13 ) — Deferred Income Tax Expense Federal 41 53 98 Federal Investment Tax Credits (4 ) (6 ) (6 ) State 5 9 9 Total Deferred Income Tax Expense 42 56 101 Total Federal and State Income Tax Expense $ 34 $ 43 $ 101 On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. In 2018, ACC Refund Orders were approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT activity of $9 million was amortized from Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 . See Note 2 for additional information regarding the ACC Refund Order and the FERC NOPR. Under the TCJA, AMT credit carryforwards will be refunded if not used to offset federal income tax liabilities. As of December 31, 2019 , TEP had a receivable of $7 million related to the AMT credit carryforwards in Current Assets—Other on the Consolidated Balance Sheets. In 2018, the Company recorded $2 million of income tax expense related to the estimated impact of sequestration on future AMT credit refunds. In 2019, TEP reversed the $2 million in income tax expense, as the AMT credit refunds were no longer subject to sequestration due to the IRS revising previously issued guidance. The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2019 2018 Gross Deferred Income Tax Assets Finance Lease Obligations $ 21 $ 48 Operating Loss Carryforwards, Net 3 23 Customer Advances and Contributions in Aid of Construction 19 16 AMT Credit 7 13 Other Postretirement Benefits 15 15 Investment Tax Credit Carryforward 34 34 Income Taxes Recoverable Through Future Rates 81 87 Other 79 60 Total Gross Deferred Income Tax Assets 259 296 Deferred Tax Assets Valuation Allowance — — Gross Deferred Income Tax Liabilities Plant, Net (602 ) (552 ) Plant Abandonments (17 ) (18 ) Finance Lease Assets, Net (18 ) (44 ) Pensions (17 ) (19 ) Income Taxes Payable Through Future Rates (9 ) (12 ) Other (28 ) (21 ) Total Gross Deferred Income Tax Liabilities (691 ) (666 ) Deferred Income Taxes, Net $ (432 ) $ (370 ) TEP recorded no valuation allowance against credit and net operating loss carryforward deferred income tax assets as of December 31, 2019 and 2018 . Management believes TEP will produce sufficient taxable income in the future to realize credit and net operating loss carryforwards before they expire. As of December 31, 2019 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 17 2034 - 35 State Credits 9 2022 - 29 AMT Credit 7 None Investment Tax Credits 34 2031 - 37 UNCERTAIN TAX POSITIONS A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2019 2018 Beginning of Period $ 16 $ 13 Additions Based on Tax Positions Taken in the Current Year 2 3 End of Period $ 18 $ 16 Unrecognized tax benefits, if recognized, would reduce income tax expense by less than $1 million as of December 31, 2019 and 2018 . TEP recorded no interest expense during 2019 and 2018 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2019 and 2018 . TEP has been audited by the IRS through tax year 2010. TEP's 2011 to 2018 tax years are open for audit by federal and state tax agencies. A decrease of $17 million in the Company's uncertain tax position obligations could occur within the next twelve months pending the outcome of an application for change in accounting method filed with the IRS. TAX SHARING AGREEMENT Under the terms of the tax sharing agreement with UNS Energy, TEP received $14 million in 2019 related to the 2018 Federal income tax returns and no payments in 2018 related to the 2017 Federal income tax returns. |
QUARTERLY FINANCIAL DATA (UNAUD
QUARTERLY FINANCIAL DATA (UNAUDITED) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | QUARTERLY FINANCIAL DATA (UNAUDITED) TEP's quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. TEP's utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. First Quarter Second Quarter Third Quarter Fourth Quarter (in millions) 2019 Operating Revenue $ 333 $ 326 $ 441 $ 318 Operating Income 43 67 134 39 Net Income 26 42 98 21 2018 Operating Revenue $ 275 $ 354 $ 460 $ 344 Operating Income 43 83 126 36 Net Income 24 58 95 11 |
NATURE OF OPERATIONS AND SUMM_2
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis Of Presentation and Accounting for Regulated Operations | BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. The Company records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Accounting for Regulated Operations TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers. |
Variable Interest Entity | Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if TEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP has entered into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis. As of December 31, 2019 |
New Accounting Standards Issued and Adopted and Not Yet Adopted | NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019 . 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. Leases TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 8 for additional disclosure about TEP’s leasing arrangements. Internal-Use Software TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. |
Use of Accounting Estimates | USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheet at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statement during the periods presented. Because these estimates involve judgments based upon management's evaluation of relevant facts and circumstances, actual results may differ from these estimates. |
Asset Retirement Obligations | Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets as a result of environmental regulations, decommissioning agreements, and land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs into a regulatory asset or liability account based on the ACC approval of these costs in its depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities. |
Contingencies | Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. |
Cash and Cash Equivalents | CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. |
Restricted Cash | Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. RESTRICTED CASH |
Allowance for Doubtful Accounts | ALLOWANCE FOR DOUBTFUL ACCOUNTS |
Inventory | INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory. |
Utility Plant | UTILITY PLANT Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and AFUDC, less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP determines it is probable that a utility plant asset will be abandoned or retired early, the cost of that asset is removed from utility plant-in-service and is recorded as a regulatory asset if recovery is probable. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement. |
AFUDC and Capitalized Interest | AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded in Allowance For Borrowed Funds on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Allowance For Equity Funds on the Consolidated Statements of Income. |
Depreciation | Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. |
Computer Software and Cloud Computing Costs | Computer Software and Cloud Computing Costs Costs incurred to purchase and develop internal use computer software and cloud computing arrangements that include a software license are capitalized and amortized over the estimated economic life of the product. Implementation costs incurred in a cloud computing arrangement that is a service contract are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets and amortized over the life of the service agreement. Amortization expense is presented in Operations and Maintenance Expense on the Consolidated Statements of Income. If the associated software is no longer useful or impaired, the carrying value is reduced and recorded as an expense in the income statement. |
Evaluation of Assets for Impairment | EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. If estimated future undiscounted cash flows are less than the carrying amount, the Company estimates the fair value and records an impairment for the amount by which the carrying value exceeds the fair value. For these estimates, TEP may consider data from multiple valuation methods, including data from market participants. The Company exercises judgment to: (i) estimate the future cash flows and the useful lives of long-lived assets; and (ii) determine the Company’s intent to use the assets. TEP’s intent to use or dispose of assets is subject to re-evaluation and can change over time. |
Deferred Financing Costs | DEFERRED FINANCING COSTS Costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to credit facility arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt. |
Leases | LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded in the balance sheet. |
Operating Revenues | OPERATING REVENUES TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date delinquent and charges the customer a late payment fee. No component of the transaction price is allocated to unsatisfied performance obligations. |
Purchased Power and Fuel Adjustment Clause | PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE |
Renewable Energy and Energy Efficiency Programs and Renewable Energy Credits | RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets are partially recovered through the LFCR mechanism. TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs . The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020 . The associated lost revenues attributable to meeting these targets are partially recovered through the LFCR mechanism. Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Operating Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism. |
Taxes Other Than Income Taxes | TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement. |
Income Taxes | INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities in the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Interest Expense on the Consolidated Statements of Income. TEP accounts for federal energy credits generated prior to 2013 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. TEP had an aggregate liability balance of $6 million and $7 million related to federal energy credits generated prior to 2013 included in Other on the Consolidated Balance Sheets as of December 31, 2019 and 2018 , respectively. Federal energy credits generated since 2013 are deferred and amortized as a reduction in income tax expense over the tax life of the underlying asset. TEP had an aggregate liability balance of $2 million and $6 million related to federal energy credits generated since 2013 included in Regulatory Liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018 , respectively. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS. |
Pension and Other Post Retirement Benefits | PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. |
Fair Value | FAIR VALUE |
Derivative Instruments | DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to: (i) meet forecasted load and reserve requirements; (ii) reduce exposure to energy commodity price volatility; and (iii) hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as either assets or liabilities in the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for, and may be designated as, normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity in the income statement. For derivatives designated as hedging contracts, TEP formally assesses, at inception, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy. |
NATURE OF OPERATIONS AND SUMM_3
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Restrictions on cash and cash equivalents | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported in the balance sheet and reconciles their sum to the cash flow statement: Years Ended December 31, (in millions) 2019 2018 2017 Cash and Cash Equivalents $ 10 $ 138 $ 38 Restricted Cash included in: Investments and Other Property 16 14 11 Current Assets—Other 2 1 1 Total Cash, Cash Equivalents, and Restricted Cash $ 28 $ 153 $ 50 |
Allowance for doubtful accounts | The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2019 2018 2017 Beginning of Period $ 5 $ 5 $ 5 Additions Charged to Cost and Expense 4 3 3 Write-offs (3 ) (3 ) (3 ) End of Period $ 6 $ 5 $ 5 |
AFUDC rates | The average AFUDC rates on regulated construction expenditures are included in the table below: 2019 2018 2017 Average AFUDC Rates 7.86 % 7.12 % 7.31 % |
Summary of average annual depreciation rates for all utility plants | Below are the summarized average annual depreciation rates for all utility plant: 2019 2018 2017 Average Annual Depreciation Rates 3.08 % 3.13 % 2.97 % |
Schedule of renewable energy credit | The table below summarizes the balance of TEP's RECs that are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Beginning of Period $ 55 $ 42 Purchased 45 45 Used for Compliance (37 ) (32 ) End of Period $ 63 $ 55 |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order: Years Ended December 31, (in millions) 2019 2018 Beginning of Period $ 4 $ — ACC Approved Refund (Reduction in Operating Revenues) (34 ) (33 ) Amount Returned to Customers Through Bill Credits 22 37 Regulatory Deferral 8 — End of Period $ — $ 4 |
Schedule of Purchased Power and Fuel Adjustment Rates | The table below summarizes the PPFAC regulatory asset (liability) balance: Years Ended December 31, (in millions) 2019 2018 Beginning of Period $ (17 ) $ (9 ) Deferred Fuel and Purchased Power Costs 31 2 PPFAC Refunds (Recoveries) (1) 22 (10 ) End of Period $ 36 $ (17 ) (1) In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. |
Schedule of Regulated Operating Revenue | The table below summarizes the LFCR revenues recognized in Operating Revenues on the Consolidated Statements of Income: Years Ended December 31, (in millions) 2019 2018 2017 LFCR Revenues $ 33 $ 26 $ 22 |
Schedule of Regulatory Assets and Liabilities | Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2019 2018 Regulatory Assets Pension and Other Postretirement Benefits (Note 10) Various $ 135 $ 126 Derivatives (Note 13) 10 72 27 Early Generation Retirement Costs Various 68 72 Lost Fixed Cost Recovery 2 46 35 Income Taxes Recoverable through Future Rates (1) Various 38 47 Under Recovered Purchased Energy Costs 1 36 — Property Tax Deferrals (2) 1 24 23 Final Mine Reclamation and Retiree Healthcare Costs (3) 19 19 29 Springerville Unit 1 Leasehold Improvements (4) 4 9 11 Other Regulatory Assets Various 18 30 Total Regulatory Assets 465 400 Less Current Portion 1 138 107 Total Non-Current Regulatory Assets $ 327 $ 293 Regulatory Liabilities Income Taxes Payable through Future Rates (1) Various $ 327 $ 354 Net Cost of Removal (5) Various 164 171 Renewable Energy Standard Various 59 52 Deferred Investment Tax Credits (6) Various 3 7 Over Recovered Purchased Energy Costs Various — 17 Other Regulatory Liabilities Various 20 6 Total Regulatory Liabilities 573 607 Less Current Portion 1 96 95 Total Non-Current Regulatory Liabilities $ 477 $ 512 (1) Amortized over the life of the assets. See Note 14 for additional information regarding income taxes. (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, Four Corners, and Navajo. 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 occur through 2038 . (4) Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year period. (5) Represents an estimate of the future cost of retirement, net of salvage value. These are amounts collected through revenue for transmission, distribution, generation 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. |
UTILITY PLANT AND JOINTLY-OWN_2
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Regulated Operations [Abstract] | |
Public utility PPE | The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (3) Average Remaining Life in Years (3) December 31, ($ in millions) 2019 2018 Plant in Service Generation Plant 3.19% 20 $ 3,065 $ 2,667 Transmission Plant 1.69% 37 1,060 1,010 Distribution Plant 1.56% 31 1,784 1,692 General Plant 5.89% 20 477 409 Intangible Plant, Software Costs, and Other (1) Various Various 271 239 Plant Held for Future Use — — 7 3 Total Plant in Service (2) $ 6,664 $ 6,020 (1) Primarily represents computer software. Unamortized computer software costs were $78 million and $73 million as of December 31, 2019 and 2018 , respectively. Amortized computer software costs were $26 million in 2019 , $24 million in 2018 , and $19 million in 2017 . Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of three years for large enterprise software. (2) Includes plant acquisition adjustments of $(211) million and $(134) million as of December 31, 2019 and 2018 , respectively. (3) Based on the 2015 depreciation study available for the major classes of Plant in Service, effective March 1, 2017, as approved by the ACC as part of the 2017 TEP Rate Order. TEP implemented new depreciation rates for Transmission Plant, based on the 2018 depreciation study, effective August 1, 2019, as approved in the 2019 FERC Rate Case. |
Schedule of jointly owned utility plants | As of December 31, 2019 , TEP was a participant in the following jointly-owned generation facilities and transmission systems: (in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Unit 1 50.0% $ 289 $ 1 $ (193 ) $ 97 Four Corners Units 4 and 5 7.0% 175 5 (77 ) 103 Luna 33.3% 57 — (1 ) 56 Gila River Unit 3 75.0% 200 2 (61 ) 141 Gila River Common Facilities 43.8% 71 — (23 ) 48 Springerville Coal Handling Facilities 83.0% 208 — (90 ) 118 Transmission Facilities Various 545 5 (295 ) 255 Total $ 1,545 $ 13 $ (740 ) $ 818 |
Schedule of asset retirement obligations | The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Beginning of Period $ 72 $ 46 Liabilities Incurred — 10 Liabilities Settled (1) (2 ) — Regulatory Deferral/Accretion Expense 2 3 Revisions to the Present Value of Estimated Cash Flows (2) 35 13 End of Period $ 107 $ 72 (1) Primarily related to the retirement of Navajo. (2) Primarily related to changes due to revised estimates of the timing of cash flows required to settle future liabilities of certain generation facilities. |
REVENUE (Tables)
REVENUE (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of revenue | The following table presents the disaggregation of TEP’s Operating Revenues on the Consolidated Statements of Income by type of service: Years Ended December 31, (in millions) 2019 2018 2017 Retail $ 972 $ 1,022 $ 1,017 Wholesale 247 238 152 Other Services 124 100 103 Revenues from Contracts with Customers 1,343 1,360 1,272 Alternative Revenues 35 28 24 Other 40 45 45 Total Operating Revenues $ 1,418 $ 1,433 $ 1,341 |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Receivables [Abstract] | |
Schedule of the components of Accounts Receivable, Net | The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Customer (1) $ 92 $ 99 Customer, Unbilled 42 45 Due from Affiliates (Note 6) 8 8 Other 19 25 Allowance for Doubtful Accounts (6 ) (5 ) Accounts Receivable, Net $ 155 $ 172 (1) Includes $5 million and $8 million as of December 31, 2019 and 2018 , respectively, of receivables related to revenue from derivative instruments. |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Table) | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions | The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets: December 31, (in millions) 2019 2018 Receivables from Related Parties UNS Electric $ 6 $ 7 UNS Gas 2 1 Total Due from Related Parties $ 8 $ 8 Payables to Related Parties SES $ 2 $ 2 UNS Electric 1 1 UNS Gas — 1 UNS Energy 1 1 Total Due to Related Parties $ 4 $ 5 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2019 2018 2017 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 7 $ 6 $ 7 Wholesale Revenues, UNS Electric (1) 1 1 — Control Area Services, UNS Electric (2) 4 3 3 Common Costs, UNS Energy Affiliates (3) 19 18 16 Corporate Services, Fortis Affiliates (4) — — 2 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (5) 15 15 15 Corporate Services, UNS Energy (6) 6 6 5 Corporate Services, UNS Energy Affiliates (7) 4 7 5 Capacity Charges, UNS Gas (8) 1 1 — (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices, while transmission services are sold at FERC-approved rates through the applicable OATT. (2) 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) TEP provides non-tariffed goods and services to Fortis affiliate companies at the higher of fully burdened cost or fair market value. (5) 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. (6) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 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 $6 million in 2019 , $5 million in 2018 , and $6 million in 2017 . (7) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. (8) UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities. |
DEBT AND CREDIT AGREEMENTS (Tab
DEBT AND CREDIT AGREEMENTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt instruments | The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2019 2018 Notes 2011 Notes 5.15% 2021 $ 250 $ 250 2012 Notes 3.85% 2023 150 150 2014 Notes 5.00% 2044 150 150 2015 Notes 3.05% 2025 300 300 2018 Notes 4.85% 2048 300 300 Tax-Exempt Local Furnishings Bonds (1) 2010 Pima A 5.25% 2040 100 100 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 Tax-Exempt Pollution Control Bonds (2) 2009 Pima A 4.95% 2020 80 80 2009 Coconino A 5.13% 2032 — 15 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt (3) 1,614 1,629 Less Unamortized Discount and Debt Issuance Costs 12 14 Less Current Maturities of Long-Term Debt 80 — Total Long-Term Debt, Net $ 1,522 $ 1,615 (1) The 2010 Pima A bonds can be redeemed at par on or after October 2020. TEP has the option to redeem the remaining bonds at par on dates ranging from first quarter of 2022 to first quarter of 2023 . (2) The 2009 Pima A bonds mature in October 2020. The 2012 Apache A bonds may be redeemed at par in the first quarter of 2022 . (3) As of December 31, 2019 , all of TEP's debt is unsecured. |
Schedule of maturities of long-term debt | Long-term debt matures on the following dates: (in millions) Long-Term Debt (1) 2020 $ 80 2021 250 2022 — 2023 150 2024 — Thereafter 1,134 Total $ 1,614 (1) Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount. |
Schedule of line of credit facilities | Terms are as follows: Weighted Average Interest Rate Capacity Borrowed (1) Available Pricing (in millions) December 31, 2019 Term Loan $ 225 $ 165 $ 60 4.75 % LIBOR + 0.550% or ABR + 0.00% (1) All amounts borrowed will be due and payable by December 2020. Capacity Sub-Limit LOC Borrowed Available Weighted Average Interest Rate Pricing (1) (in millions) December 31, 2019 Revolver and LOC $ 250 $ 50 $ — $ 250 — % LIBOR + 1.000% or ABR + 0.00% (in millions) December 31, 2018 Revolver and LOC $ 250 $ 50 $ — $ 250 — % LIBOR + 1.000% or ABR + 0.00% (1) Interest rates and fees are based on a pricing grid tied to TEP's credit rating. |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Assets And Liabilities, Lessee | TEP’s leases are included in the balance sheet as follows: (in millions) Lease Type December 31, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 151 Accumulated Amortization of Finance Lease Assets Finance (77 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations Finance 17 Finance Lease Obligations Finance 67 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 6 |
Lease, Cost | The following table presents TEP's cash flow information related to its leases: Year Ended (in millions) December 31, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 13 Operating Cash Flows used for Operating Leases 1 Financing Cash Flows used for Finance Leases 11 Investing Cash Flows used for Finance Leases 164 The following table presents the components of TEP’s lease cost: Year Ended (in millions) December 31, 2019 Finance Amortization of Leased Assets (1) $ 13 Interest on Lease Liabilities (2) 13 Operating 1 Variable 16 Short Term 1 Total Lease Cost $ 44 (1) TEP deferred $6 million in amortization related to Gila River Unit 2 in Regulatory and Other Assets—Regulatory Assets based on PPFAC recovery of TEP's fixed capacity payment. (2) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. Finance lease interest expense related to Gila River Unit 2 was $12 million for the year ended December 31, 2019 . TEP purchased Gila River Unit 2 in December 2019. |
Lessee, Operating Lease, Liability, Maturity | As of December 31, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases Operating Leases Total 2020 $ 18 $ 1 $ 19 2021 68 1 69 2022 — 1 1 2023 — 1 1 2024 — 1 1 Thereafter — 4 4 Total Lease Payments 86 9 95 Less Imputed Interest 2 2 4 Total Lease Obligations 84 7 91 Less Current Portion 17 1 18 Total Non-Current Lease Obligations $ 67 $ 6 $ 73 |
Finance Lease, Liability, Maturity | As of December 31, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases Operating Leases Total 2020 $ 18 $ 1 $ 19 2021 68 1 69 2022 — 1 1 2023 — 1 1 2024 — 1 1 Thereafter — 4 4 Total Lease Payments 86 9 95 Less Imputed Interest 2 2 4 Total Lease Obligations 84 7 91 Less Current Portion 17 1 18 Total Non-Current Lease Obligations $ 67 $ 6 $ 73 |
Schedule of Lease Term and Discount Rate | The following table presents TEP's lease terms and discount rate related to its leases: December 31, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 2.2 % Operating Leases 4.1 % |
Schedule of Future Minimum Rental Payments for Operating Leases | As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 |
Schedule of Future Minimum Lease Payments for Capital Leases | As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments | As of December 31, 2019 , TEP had the following unconditional minimum purchase obligations: (in millions) 2020 2021 2022 2023 2024 Thereafter Total Fuel, Including Transportation $ 94 $ 61 $ 40 $ 33 $ 33 $ 194 $ 455 Purchased Power 8 — — — — — 8 Transmission 21 16 14 3 3 6 63 Renewable Power Purchase Agreements 63 63 63 63 62 543 857 RES Performance-Based Incentives 8 7 7 7 7 33 69 Land Easements and Rights-of-Way (1) 1 2 1 1 3 79 87 Total Purchase Commitments $ 195 $ 149 $ 125 $ 107 $ 108 $ 855 $ 1,539 (1) Land easements and rights-of-way have varying terms and provisions and reflect expiration dates through 2054 . |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Retirement Benefits [Abstract] | |
Schedule of pension and other postretirement benefit amounts | The following table presents pension and other postretirement benefit amounts (excluding tax balances) included in the balance sheet: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2019 2018 2019 2018 Regulatory Assets $ 135 $ 126 $ — $ — Regulatory Liabilities — — (1 ) (3 ) Accrued Employee Expenses (2 ) (1 ) (2 ) (3 ) Pension and Other Postretirement Benefits (77 ) (63 ) (56 ) (54 ) Accumulated Other Comprehensive Loss, SERP 10 6 — — Net Amount Recognized $ 66 $ 68 $ (59 ) $ (60 ) |
Schedule of changes in funded status | All plans had projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2019 2018 2019 2018 Change in Benefit Obligation Beginning of Period $ 440 $ 475 $ 74 $ 82 Actuarial (Gain) Loss 76 (42 ) 4 (8 ) Interest Cost 18 16 3 2 Service Cost 13 15 4 5 Benefits Paid (23 ) (23 ) (6 ) (5 ) Plan Amendments 1 (1 ) — (2 ) End of Period 525 440 79 74 Change in Fair Value of Plan Assets Beginning of Period 376 403 17 17 Actual Return on Plan Assets 81 (25 ) 4 (1 ) Benefits Paid (22 ) (23 ) (6 ) (5 ) Employer Contributions (1) 11 21 6 6 End of Period 446 376 21 17 Funded Status at End of Period $ (79 ) $ (64 ) $ (58 ) $ (57 ) (1) TEP expects to contribute $11 million to the pension plans and $1 million to the VEBA trust in 2020 . |
Schedule of net periodic benefit cost not yet recognized | The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2019 2018 2019 2018 Net (Gain) Loss $ 145 $ 133 $ 1 $ (1 ) Prior Service Cost (Benefit) — — (2 ) (2 ) |
Schedule of information for the pension plans with accumulated benefit obligations in excess of pension plan | The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2019 2018 Accumulated Benefit Obligation $ 476 $ 230 Fair Value of Plan Assets 446 202 |
Components of net periodic benefit plan cost | Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2019 2018 2017 2019 2018 2017 Service Cost $ 13 $ 15 $ 13 $ 4 $ 5 $ 4 Non-Service Cost Interest Cost 18 16 15 3 2 2 Expected Return on Plan Assets (26 ) (28 ) (25 ) (2 ) (1 ) (1 ) Amortization of Net (Gain) Loss 8 7 8 — — — Net Periodic Benefit Cost $ 13 $ 10 $ 11 $ 5 $ 6 $ 5 |
Schedule of the changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI | The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2019 2018 2017 2019 2018 2017 2019 2018 2017 Current Year Actuarial (Gain) Loss $ 16 $ 12 $ 5 $ 4 $ (1 ) $ 3 $ 1 $ (6 ) $ (1 ) Amortization of Net Loss (8 ) (7 ) (7 ) (1 ) — — — — — Prior Service Credit (Cost) — — — 1 (1 ) — — (2 ) — Total Recognized (Gain) Loss $ 8 $ 5 $ (2 ) $ 4 $ (2 ) $ 3 $ 1 $ (8 ) $ (1 ) |
Schedule of weighted average assumptions used to determine benefit obligations | The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2019 2018 2019 2018 Discount Rate 3.6% 4.5% 3.3% 4.3% Rate of Compensation Increase 2.8% 2.8% N/A N/A |
Schedule of weighted average assumptions used to determine net periodic benefit costs | The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2019 2018 2017 2019 2018 2017 Discount Rate, Service Cost 4.7% 3.8% 4.4% 4.5% 3.8% 4.3% Discount Rate, Interest Cost 4.2% 3.4% 3.7% 4.0% 3.2% 3.3% Rate of Compensation Increase 2.8% 2.8% 2.8% N/A N/A N/A Expected Return on Plan Assets 7.0% 7.0% 7.0% 7.0% 7.0% 7.0% |
Schedule of healthcare cost trend rates | Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached: December 31, 2019 2018 Next Year (Pre-65) 6.3% 6.5% Next Year (Post-65) 7.5% 7.8% Ultimate Rate Assumed (Pre-65 and Post-65) 4.5% 4.5% Year Ultimate Rate is Reached (Pre-65) 2037 2037 Year Ultimate Rate is Reached (Post-65) 2037 2037 |
Schedule of asset allocations, by asset category, on the measurement date | Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement Benefits 2019 2018 2019 2018 Asset Category Equity Securities 46 % 45 % 65 % 60 % Fixed Income Securities 45 % 45 % 33 % 38 % Real Estate 8 % 8 % — % — % Other 1 % 2 % 2 % 2 % Total 100 % 100 % 100 % 100 % |
Schedule of fair value measurements of pension plan assets by level | The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2019 Asset Category Cash Equivalents $ 2 $ — $ — $ 2 Equity Securities: United States Large Cap — 55 — 55 United States Small Cap — 21 — 21 Non-United States — 80 — 80 Global — 51 — 51 Fixed Income — 199 — 199 Real Estate — 10 23 33 Private Equity — — 5 5 Total $ 2 $ 416 $ 28 $ 446 December 31, 2018 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 45 — 45 United States Small Cap — 17 — 17 Non-United States — 67 — 67 Global — 42 — 42 Fixed Income — 167 — 167 Real Estate — 9 22 31 Private Equity — — 6 6 Total $ 1 $ 347 $ 28 $ 376 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. |
Schedule of reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy | The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2017 $ 6 $ 21 $ 27 Actual Return on Plan Assets: Assets Held at Reporting Date 2 1 3 Purchases, Sales, and Settlements (2 ) — (2 ) Balance as of December 31, 2018 6 22 28 Actual Return on Plan Assets: Assets Held at Reporting Date 1 1 2 Purchases, Sales, and Settlements (2 ) — (2 ) Balance as of December 31, 2019 $ 5 $ 23 $ 28 |
Schedule of target allocation percentages for the major asset categories of the plan | The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. Pension Other Postretirement Benefits December 31, 2019 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 12% 39% United States Small Cap 5% 5% Non-United States Developed —% 7% Non-United States Emerging —% 9% Global Equity 26% —% Global Infrastructure 3% —% Fixed Income 45% 38% Real Estate 8% —% Private Equity 1% —% Total 100% 100% |
Schedule of expected benefit payments | TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate. (in millions) 2020 2021 2022 2023 2024 2025-2029 Pension Benefits $ 26 $ 26 $ 26 $ 27 $ 28 $ 147 Other Postretirement Benefits 5 5 5 5 5 25 |
SHARE-BASED COMPENSATION (Table
SHARE-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Schedule of represents PSUs and RSUs awarded by UNS Energy | The following table represents PSUs and RSUs awarded by UNS Energy: 2019 2018 2017 PSUs 66,978 54,426 68,126 RSUs 33,489 27,213 34,063 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | CASH TRANSACTIONS Years Ended December 31, (in millions) 2019 2018 2017 Interest Paid, Net of Amounts Capitalized $ 80 $ 67 $ 61 Income Tax Refunds (1) (14 ) — — (1) TEP received a refund of AMT credit carryforwards in 2019. See Note 14 for additional information regarding AMT. NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that resulted in recognition of assets and liabilities but did not result in cash receipts or payments were as follows: Years Ended December 31, (in millions) 2019 2018 2017 Finance Leases $ 67 $ 164 $ — Accrued Capital Expenditures 40 31 24 Asset Retirement Obligations Increase (Decrease) (1) 26 20 10 Operating Leases (2) 8 — — Renewable Energy Credits 3 3 2 Net Cost of Removal Increase (Decrease) (3) (10 ) (4 ) (88 ) (1) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of expected future AROs. (2) On January 1 2019, TEP adopted accounting guidance that requires lessees to recognize a lease liability and a right-of-use asset for all leases with a lease term greater than 12 months. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. (3) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. |
FAIR VALUE MEASUREMENTS AND D_2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Financial instruments measured at fair value on a recurring basis | The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Level 3 Total (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 ) (in millions) December 31, 2018 Assets Cash Equivalents (1) $ 55 $ — $ — $ 55 Restricted Cash (1) 15 — — 15 Energy Derivative Contracts, Regulatory Recovery (2) — 10 — 10 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 70 10 2 82 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (35 ) (2 ) (37 ) Total Liabilities — (35 ) (2 ) (37 ) Total Assets (Liabilities), Net $ 70 $ (25 ) $ — $ 45 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit , which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 2 as of December 31, 2019 and Level 3 as of December 31, 2018 ) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to decreases in forward market prices of natural gas and increases in volume. |
Potential offset of assets by counterparty netting and cash collateral | The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) December 31, 2019 Derivative Assets Energy Derivative Contracts $ 6 $ 4 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (76 ) (4 ) (2 ) (70 ) (in millions) December 31, 2018 Derivative Assets Energy Derivative Contracts $ 12 $ 11 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (37 ) (11 ) — (26 ) |
Potential offset of liabilities by counterparty netting and cash collateral | The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) December 31, 2019 Derivative Assets Energy Derivative Contracts $ 6 $ 4 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (76 ) (4 ) (2 ) (70 ) (in millions) December 31, 2018 Derivative Assets Energy Derivative Contracts $ 12 $ 11 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (37 ) (11 ) — (26 ) |
Financial impact of energy contracts | The table below presents amounts recorded in Operating Revenues on the Consolidated Statements of Income: Years Ended December 31, (in millions) 2019 2018 2017 Operating Revenues $ 6 $ 5 $ 5 Years Ended December 31, (in millions) 2019 2018 2017 Unrealized Net Loss (1) $ (45 ) $ (9 ) $ (18 ) (1) In 2019 , unrealized net loss on regulatory recoverable derivative contracts increased primarily due to decreases in forward market prices of natural gas and increases in volume. |
Derivative volumes | The following table presents volumes associated with the energy contracts: December 31, 2019 2018 Power Contracts GWh 4,740 1,743 Gas Contracts BBtu 122,779 146,933 |
Following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements | The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Approach Fair Value of Unobservable Inputs Range of Unobservable Inputs Assets Liabilities (in millions) December 31, 2018 Forward Power Contracts Market approach $ 3 $ (2 ) Market price per MWh $ 16.80 $ 47.05 |
Schedule of reconciliation of changes in the fair value of net assets and liabilities | 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 at the end of the period: Years Ended December 31, (in millions) 2019 2018 Beginning of Period $ 1 $ 2 Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments (12 ) (4 ) Operating Revenues 5 5 Settlements 1 (2 ) Transfers Out of Level 3 (1) 5 — End of Period $ — $ 1 Gains (Losses), Assets (Liabilities) Still Held $ — $ 1 (1) Transferred from Level 3 to Level 2 because observable market data became available for the assets and liabilities. |
Schedule of different estimation methods and/or market assumptions may yield different estimated fair value amounts | The following table includes the net carrying value and estimated fair value of TEP's long-term debt: Net Carrying Value Fair Value Fair Value Hierarchy December 31, (in millions) 2019 2018 2019 2018 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,602 $ 1,615 $ 1,755 $ 1,672 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate | Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to pre-tax income due to the following: Years Ended December 31, (in millions) 2019 2018 2017 Federal Income Tax Expense at Statutory Rate $ 46 $ 49 $ 97 State Income Tax Expense, Net of Federal Deduction 9 9 9 Federal/State Tax Credits (6 ) (10 ) (9 ) Allowance for Equity Funds Used During Construction (3 ) (1 ) (2 ) Impact of Enactment, TCJA — — 7 Excess Deferred Income Taxes (9 ) (6 ) — Impact of AMT Sequestration (2 ) 2 — Other (1 ) — (1 ) Total Federal and State Income Tax Expense $ 34 $ 43 $ 101 |
Schedule of income tax reconciliation | Income Tax Expense included on the Consolidated Statements of Income consists of the following: Years Ended December 31, (in millions) 2019 2018 2017 Current Income Tax Expense Federal $ (8 ) $ (13 ) $ — State — — — Total Current Income Tax Expense (8 ) (13 ) — Deferred Income Tax Expense Federal 41 53 98 Federal Investment Tax Credits (4 ) (6 ) (6 ) State 5 9 9 Total Deferred Income Tax Expense 42 56 101 Total Federal and State Income Tax Expense $ 34 $ 43 $ 101 |
Schedule of components of deferred income tax assets and liabilities | The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2019 2018 Gross Deferred Income Tax Assets Finance Lease Obligations $ 21 $ 48 Operating Loss Carryforwards, Net 3 23 Customer Advances and Contributions in Aid of Construction 19 16 AMT Credit 7 13 Other Postretirement Benefits 15 15 Investment Tax Credit Carryforward 34 34 Income Taxes Recoverable Through Future Rates 81 87 Other 79 60 Total Gross Deferred Income Tax Assets 259 296 Deferred Tax Assets Valuation Allowance — — Gross Deferred Income Tax Liabilities Plant, Net (602 ) (552 ) Plant Abandonments (17 ) (18 ) Finance Lease Assets, Net (18 ) (44 ) Pensions (17 ) (19 ) Income Taxes Payable Through Future Rates (9 ) (12 ) Other (28 ) (21 ) Total Gross Deferred Income Tax Liabilities (691 ) (666 ) Deferred Income Taxes, Net $ (432 ) $ (370 ) |
TEP had the following carryforward amounts | As of December 31, 2019 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 17 2034 - 35 State Credits 9 2022 - 29 AMT Credit 7 None Investment Tax Credits 34 2031 - 37 |
Summary of reconciliation of the beginning and ending balances of unrecognized tax benefits | A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2019 2018 Beginning of Period $ 16 $ 13 Additions Based on Tax Positions Taken in the Current Year 2 3 End of Period $ 18 $ 16 |
QUARTERLY FINANCIAL DATA (UNAU
QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of quarterly financial information | Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. First Quarter Second Quarter Third Quarter Fourth Quarter (in millions) 2019 Operating Revenue $ 333 $ 326 $ 441 $ 318 Operating Income 43 67 134 39 Net Income 26 42 98 21 2018 Operating Revenue $ 275 $ 354 $ 460 $ 344 Operating Income 43 83 126 36 Net Income 24 58 95 11 |
NATURE OF OPERATIONS AND SUMM_4
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Details) customer in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019USD ($)mi²customer | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||
Number of retail customers | customer | 429 | |||
Area in which subsidiary generates transmits and distributes electricity to retail electric customers (sq miles) | mi² | 1,155 | |||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Cash and Cash Equivalents | $ 9,762 | $ 138,114 | $ 38,000 | |
Total Cash, Cash Equivalents, and Restricted Cash | 28,472 | 152,747 | 49,501 | $ 43,325 |
Investments and Other Property | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted Cash | 16,000 | 14,000 | 11,000 | |
Current Assets—Other | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Restricted Cash | $ 2,000 | $ 1,000 | $ 1,000 |
NATURE OF OPERATIONS AND SUMM_5
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Allowance for Doubtful Accounts) (Details) - Allowance for Doubtful Accounts - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Beginning of Period | $ 5 | $ 5 | $ 5 |
Additions Charged to Cost and Expense | 4 | 3 | 3 |
Write-offs | (3) | (3) | (3) |
End of Period | $ 6 | $ 5 | $ 5 |
NATURE OF OPERATIONS AND SUMM_6
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Average AFUDC Rates | 7.86% | 7.12% | 7.31% |
NATURE OF OPERATIONS AND SUMM_7
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Average Annual Depreciation Rates | 3.08% | 3.13% | 2.97% |
NATURE OF OPERATIONS AND SUMM_8
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy and Energy Efficiency Programs) (Details) | 12 Months Ended | ||
Dec. 31, 2025 | Dec. 31, 2020 | Dec. 31, 2019 | |
Renewable Energy Standard | |||
Public Utilities, General Disclosures [Line Items] | |||
Renewable energy target percentage by 2025 (in percentage) | 9.00% | ||
Forecast | Renewable Energy Standard | |||
Public Utilities, General Disclosures [Line Items] | |||
Renewable energy target percentage by 2025 (in percentage) | 15.00% | ||
Distributed generation requirement target percentage (in percentage) | 30.00% | ||
Forecast | Energy Efficiency Standards | |||
Public Utilities, General Disclosures [Line Items] | |||
Percentage of electric energy efficiency standards target retail savings on sales (in percentage) | 22.00% |
NATURE OF OPERATIONS AND SUMM_9
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy Credits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Renewable Energy Credits [Roll Forward] | ||
Beginning of Period | $ 55 | $ 42 |
Purchased | 45 | 45 |
Used for Compliance | (37) | (32) |
End of Period | $ 63 | $ 55 |
NATURE OF OPERATIONS AND SUM_10
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Income Tax) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | $ 573 | $ 607 |
Federal energy credits | Prior to 2013 | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 6 | 7 |
Federal energy credits | Since 2013 | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | $ 2 | $ 6 |
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 | May 31, 2019 | Dec. 31, 2019 | Sep. 19, 2019 | Dec. 31, 2018 |
Public Utilities, General Disclosures [Line Items] | ||||
Regulatory Liabilities | $ 96,017 | $ 95,094 | ||
Regulatory Assets | $ 465,000 | $ 400,000 | ||
FERC | Transmission Services Rate | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Return on equity (percentage) | 10.40% | |||
Requested recovery in development, percentage | 100.00% | |||
Requested recovery in development | $ 9,000 | |||
Allowed cost recovery in development, percentage | 50.00% | |||
Regulatory Assets | $ 4,000 | |||
FERC | Transmission Services Rate | Revenue Subject to Refund | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Regulatory Liabilities | $ 4,000 |
REGULATORY MATTERS (Federal Tax
REGULATORY MATTERS (Federal Tax Legislation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Regulatory Assets [Roll Forward] | |||
Regulatory Deferral | $ 7,705 | $ (1,562) | $ 0 |
Arizona Corporation Commission | |||
Public Utilities, General Disclosures [Line Items] | |||
Change in tax rate, refund to customers, net of amortization | $ 35,000 | ||
Change in tax rate, customers bill as percent of returned savings | 50.00% | ||
Arizona Corporation Commission | Revenue Refund | |||
Regulatory Assets [Roll Forward] | |||
Beginning of Period | $ 4,000 | 0 | |
ACC Refund (Reduction in Operating Revenues) | (34,000) | (33,000) | |
Amount Returned to Customers through Bill Credits | 22,000 | 37,000 | |
Regulatory Deferral | 8,000 | 0 | |
End of Period | $ 0 | 4,000 | $ 0 |
FERC | |||
Regulatory Assets [Roll Forward] | |||
ACC Refund (Reduction in Operating Revenues) | $ (1,000) | ||
Regulatory commission, decrease in transmission rate | 5.30% |
REGULATORY MATTERS (Cost Recove
REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Sep. 30, 2019 | Feb. 28, 2019 | Dec. 31, 2025 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Regulatory Liabilities [Roll Forward] | |||||||
Environmental compliance adjustor, as a percentage of total retail revenue | 0.50% | ||||||
Environmental compliance adjustor, return on environmental investments | $ 2 | $ 3 | $ 1 | ||||
Purchased Power and Fuel Adjustment Clause | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Beginning of Period | $ 36 | (17) | (9) | ||||
Deferred Fuel and Purchased Power Costs | 31 | 2 | |||||
PPFAC Refunds (Recoveries) | 22 | (10) | |||||
End of Period | $ 36 | (17) | (9) | ||||
Purchased Power and Fuel Adjustment Clause | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Months approved rate in effect unless modified | 12 months | ||||||
Renewable Energy Standard | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Renewable energy target percentage | 9.00% | ||||||
Approved spending budget | $ 55 | ||||||
Recovery revenue | 1 | 1 | |||||
Renewable energy actual percentage | 16.00% | ||||||
Renewable Energy Standard | Maximum | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Recovery revenue | $ 1 | ||||||
Renewable Energy Standard | Forecast | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Renewable energy target percentage | 15.00% | ||||||
Distributed generation requirement percent of target percentage (percentage) | 30.00% | ||||||
Demand Side Management | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Recovery revenue | $ 2 | 2 | 2 | ||||
Energy Efficiency Standards | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Percentage of cumulative annual retail kilowatt savings, actual | 19.00% | ||||||
Approved recovery of spending budget | $ 23 | ||||||
Energy Efficiency Standards | Forecast | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Percentage of electric energy efficiency standards target retail savings on sales (in percentage) | 22.00% | ||||||
Lost Fixed Cost Recovery | |||||||
Regulatory Liabilities [Roll Forward] | |||||||
Recovery revenue | $ 33 | $ 26 | $ 22 | ||||
Cap on increase in lost fixed cost recovery rate (percentage) | 2.00% |
REGULATORY MATTERS (Regulatory
REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 465,000 | $ 400,000 |
Regulatory Assets | 138,412 | 106,725 |
Regulatory Assets | 326,860 | 293,078 |
Pension and Other Postretirement Benefits | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 135,000 | 126,000 |
Derivatives | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 10 years | |
Total Regulatory Assets | $ 72,000 | 27,000 |
Early Generation Retirement Costs | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 68,000 | 72,000 |
Lost Fixed Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 2 years | |
Total Regulatory Assets | $ 46,000 | 35,000 |
Income Taxes Recoverable through Future Rates | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 38,000 | 47,000 |
Under Recovered Purchased Energy Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 36,000 | 0 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 24,000 | 23,000 |
Remaining recovery period (in years) | 6 months | |
Final Mine Reclamation and Retiree Healthcare Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 19 years | |
Total Regulatory Assets | $ 19,000 | 29,000 |
Springerville Unit 1 Leasehold Improvements | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 4 years | |
Total Regulatory Assets | $ 9,000 | 11,000 |
Useful life (in years) | 10 years | |
Other Regulatory Assets | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 18,000 | $ 30,000 |
REGULATORY MATTERS (Regulator_2
REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 573,000 | $ 607,000 |
Less Current Portion | 96,017 | 95,094 |
Total Non-Current Regulatory Liabilities | 477,495 | 512,425 |
Income Taxes Payable through Future Rates | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 327,000 | 354,000 |
Net Cost of Removal | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 164,000 | 171,000 |
Renewable Energy Standard | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 59,000 | 52,000 |
Deferred Investment Tax Credits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 3,000 | 7,000 |
Over Recovered Purchased Energy Costs | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 0 | 17,000 |
Other Regulatory Liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 20,000 | $ 6,000 |
REGULATORY MATTERS (Early Gener
REGULATORY MATTERS (Early Generation Retirement Costs) (Details) | 12 Months Ended |
Dec. 31, 2019 | |
Regulatory Assets [Line Items] | |
Remaining Recovery Period (years) | 1 year |
Navajo | |
Regulatory Assets [Line Items] | |
Remaining Recovery Period (years) | 10 years |
Sundt Units 1 and 2 | |
Regulatory Assets [Line Items] | |
Remaining Recovery Period (years) | 10 years |
UTILITY PLANT AND JOINTLY-OWN_3
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Utility Plant in Service by Major Class) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 3.08% | 3.13% | 2.97% |
Plant in Service | $ 6,663,912 | $ 6,020,469 | |
Capitalized computer software, net | 78,000 | 73,000 | |
Amortization of computer software costs | $ 26,000 | 24,000 | $ 19,000 |
Acquired finite-lived intangible assets, weighted average useful life (in years) | 3 years | ||
Plant acquisition adjustments | $ (211,000) | (134,000) | |
Minimum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Acquired finite-lived intangible assets, weighted average useful life (in years) | 3 years | ||
Maximum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Acquired finite-lived intangible assets, weighted average useful life (in years) | 5 years | ||
Generation Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 3.19% | ||
Average Remaining Life in Years | 20 years | ||
Plant in Service | $ 3,065,000 | 2,667,000 | |
Transmission Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 1.69% | ||
Average Remaining Life in Years | 37 years | ||
Plant in Service | $ 1,060,000 | 1,010,000 | |
Distribution Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 1.56% | ||
Average Remaining Life in Years | 31 years | ||
Plant in Service | $ 1,784,000 | 1,692,000 | |
General Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 5.89% | ||
Average Remaining Life in Years | 20 years | ||
Plant in Service | $ 477,000 | 409,000 | |
Intangible Plant, Software Costs and Other | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Plant in Service | 271,000 | 239,000 | |
Plant Held for Future Use | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Plant in Service | $ 7,000 | $ 3,000 |
UTILITY PLANT AND JOINTLY-OWN_4
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Narrative) (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017MWh | Mar. 31, 2020MWhrice | Dec. 31, 2019USD ($)rice | Dec. 31, 2018USD ($) | |
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Public utilities, plant in service | $ 4,534,896 | $ 4,160,640 | ||
Plant in Service | 7,118,867 | $ 6,528,069 | ||
Gila River Unit 2 | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Term of contract | 20 years | |||
Generating capacity (MW) | MWh | 550 | |||
Option to purchase unit, term | 3 years | |||
Public utilities, plant in service | $ 165,000 | |||
RICE Units | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Number of units in service | rice | 5 | |||
Number of units | rice | 10 | |||
Plant in Service | $ 82,000 | |||
RICE Units | Forecast | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Generating capacity (MW) | MWh | 188 | |||
Number of units | rice | 5 |
UTILITY PLANT AND JOINTLY-OWN_5
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Jointly-Owned Facilities) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Aug. 30, 2019 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant in Service | $ 1,545 | |
Construction Work in Progress | 13 | |
Accumulated Depreciation | (740) | |
Net Book Value | $ 818 | |
San Juan Unit 1 | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Percentage (in percentage) | 50.00% | 50.00% |
Plant in Service | $ 289 | |
Construction Work in Progress | 1 | |
Accumulated Depreciation | (193) | |
Net Book Value | $ 97 | |
Four Corners Units 4 and 5 | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Percentage (in percentage) | 7.00% | |
Plant in Service | $ 175 | |
Construction Work in Progress | 5 | |
Accumulated Depreciation | (77) | |
Net Book Value | $ 103 | |
Luna | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Percentage (in percentage) | 33.30% | |
Plant in Service | $ 57 | |
Construction Work in Progress | 0 | |
Accumulated Depreciation | (1) | |
Net Book Value | $ 56 | |
Gila River Unit 3 | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Percentage (in percentage) | 75.00% | |
Plant in Service | $ 200 | |
Construction Work in Progress | 2 | |
Accumulated Depreciation | (61) | |
Net Book Value | $ 141 | |
Gila River Common Facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Percentage (in percentage) | 43.80% | |
Plant in Service | $ 71 | |
Construction Work in Progress | 0 | |
Accumulated Depreciation | (23) | |
Net Book Value | $ 48 | |
Springerville Coal Handling Facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Percentage (in percentage) | 83.00% | |
Plant in Service | $ 208 | |
Construction Work in Progress | 0 | |
Accumulated Depreciation | (90) | |
Net Book Value | 118 | |
Transmission Facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant in Service | 545 | |
Construction Work in Progress | 5 | |
Accumulated Depreciation | (295) | |
Net Book Value | $ 255 |
UTILITY PLANT AND JOINTLY-OWN_6
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning of Period | $ 72 | $ 46 |
Liabilities Incurred | 0 | 10 |
Liabilities Settled | (2) | 0 |
Regulatory Deferral/Accretion Expense | 2 | 3 |
Revisions to the Present Value of Estimated Cash Flows | 35 | 13 |
End of Period | $ 107 | $ 72 |
REVENUE (Details)
REVENUE (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | |||||||||||
Revenues from Contracts with Customers | $ 1,343,000 | $ 1,360,000 | $ 1,272,000 | ||||||||
Alternative Revenues | 35,000 | 28,000 | 24,000 | ||||||||
Other | 40,000 | 45,000 | 45,000 | ||||||||
Total Operating Revenues | $ 318,000 | $ 441,000 | $ 326,000 | $ 333,000 | $ 344,000 | $ 460,000 | $ 354,000 | $ 275,000 | 1,418,338 | 1,432,618 | 1,340,935 |
Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenues from Contracts with Customers | 972,000 | 1,022,000 | 1,017,000 | ||||||||
Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenues from Contracts with Customers | 247,000 | 238,000 | 152,000 | ||||||||
Other Services | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenues from Contracts with Customers | $ 124,000 | $ 100,000 | $ 103,000 | ||||||||
Lost Fixed Cost Recovery Mechanism | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Cap on increase in lost fixed cost recovery rate (percentage) | 2.00% |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts | $ (6,000) | $ (5,000) |
Accounts Receivable, Net | 154,847 | 172,367 |
Customer | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 92,000 | 99,000 |
Customer | Derivatives | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 5,000 | 8,000 |
Customer | Due from Affiliates | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 8,000 | 8,000 |
Customer | Customer, Unbilled | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 42,000 | 45,000 |
Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | $ 19,000 | $ 25,000 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2020USD ($) | Dec. 31, 2019USD ($)facility | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Receivables from Related Parties | $ 8,000 | $ 8,000 | ||
Payables to Related Parties | 4,000 | 5,000 | ||
Supplemental Workforce, SES | 505,796 | 543,143 | $ 425,555 | |
Transmission Revenues, UNS Electric | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Transmission and Wholesale Revenue | 7,000 | 6,000 | 7,000 | |
Wholesale Revenues, UNS Electric | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Transmission and Wholesale Revenue | 1,000 | 1,000 | 0 | |
Control Area Services, UNS Electric | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Control Area Services and Corporate Services | 4,000 | 3,000 | 3,000 | |
Common Costs, UNS Energy Affiliates | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Common Costs, UNS Energy Affiliates | 19,000 | 18,000 | 16,000 | |
Corporate Services, Fortis Affiliates | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Corporate Services | 0 | 0 | 2,000 | |
Supplemental Workforce, SES | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Supplemental Workforce, SES | 15,000 | 15,000 | 15,000 | |
Corporate Services, UNS Energy | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Corporate Services | $ 6,000 | 6,000 | 5,000 | |
Intercompany allocation parent to subsidiary (in percentage) | 83.00% | |||
Management fee | $ 6,000 | 5,000 | 6,000 | |
Corporate Services, UNS Energy Affiliates | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Corporate Services | 4,000 | 7,000 | 5,000 | |
Capacity Charges, UNS Gas | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Capacity Charges, UNS Gas | $ 1,000 | 1,000 | $ 0 | |
Number of generation facilities | facility | 1 | |||
UNS Electric | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Receivables from Related Parties | $ 6,000 | 7,000 | ||
Payables to Related Parties | 1,000 | 1,000 | ||
UNS Gas | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Receivables from Related Parties | 2,000 | 1,000 | ||
Payables to Related Parties | 0 | 1,000 | ||
SES | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Payables to Related Parties | 2,000 | 2,000 | ||
UNS Energy | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Payables to Related Parties | $ 1,000 | $ 1,000 | ||
UNS Energy | Subsequent Event | ||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | ||||
Equity contributions | $ 125,000 |
DEBT AND CREDIT AGREEMENTS (Lon
DEBT AND CREDIT AGREEMENTS (Long-term Debt) (Detail) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||
Total Long-Term Debt | $ 1,614,000 | $ 1,629,000 |
Less Unamortized Discount and Debt Issuance Costs | 12,000 | 14,000 |
Current Maturities of Long-Term Debt | 80,000 | 0 |
Total Long-Term Debt, Net | $ 1,522,087 | 1,615,252 |
2011 Notes | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 5.15% | |
Total Long-Term Debt | $ 250,000 | 250,000 |
2012 Notes | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 3.85% | |
Total Long-Term Debt | $ 150,000 | 150,000 |
2014 Notes | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 5.00% | |
Total Long-Term Debt | $ 150,000 | 150,000 |
2015 Notes | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 3.05% | |
Total Long-Term Debt | $ 300,000 | 300,000 |
2018 Notes | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 4.85% | |
Total Long-Term Debt | $ 300,000 | 300,000 |
2010 Pima A | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 5.25% | |
Total Long-Term Debt | $ 100,000 | 100,000 |
2012 Pima A | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 4.50% | |
Total Long-Term Debt | $ 16,000 | 16,000 |
2013 Pima A | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 4.00% | |
Total Long-Term Debt | $ 91,000 | 91,000 |
2009 Pima A | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 4.95% | |
Total Long-Term Debt | $ 80,000 | 80,000 |
2009 Coconino A | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 5.13% | |
Total Long-Term Debt | $ 0 | 15,000 |
2012 Apache A | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Interest Rate | 4.50% | |
Total Long-Term Debt | $ 177,000 | $ 177,000 |
DEBT AND CREDIT AGREEMENTS (Iss
DEBT AND CREDIT AGREEMENTS (Issuances and Redemptions) (Details) - USD ($) | 1 Months Ended | ||
Nov. 30, 2019 | Dec. 31, 2018 | Nov. 30, 2018 | |
Secured Debt | Tax Exempt Variable Rate | |||
Debt Instrument [Line Items] | |||
Debt extinguishment | $ 37,000,000 | ||
Unsecured Debt | Tax Exempt Variable Rate | |||
Debt Instrument [Line Items] | |||
Debt extinguishment | $ 15,000,000 | $ 100,000,000 | |
Unsecured Debt | Notes 2018, Due June 1, 2048 | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 300,000,000 |
DEBT AND CREDIT AGREEMENTS (Mat
DEBT AND CREDIT AGREEMENTS (Maturities of Long-term Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Long-Term Debt Maturities | ||
2020 | $ 80 | |
2021 | 250 | |
2022 | 0 | |
2023 | 150 | |
2024 | 0 | |
Thereafter | 1,134 | |
Total Long-Term Debt | 1,614 | $ 1,629 |
Unamortized debt issuance expense | 10 | |
Debt discount | $ 2 |
DEBT AND CREDIT AGREEMENTS (Cre
DEBT AND CREDIT AGREEMENTS (Credit Agreement) (Details) - Line of Credit - USD ($) | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Feb. 12, 2020 | Jan. 31, 2020 | |
Term Loan | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | $ 225,000,000 | |||
Borrowed | 165,000,000 | |||
Available | $ 60,000,000 | |||
Weighted Average Interest Rate (in percentage) | 4.75% | |||
Term Loan | Subsequent Event | ||||
Debt Instrument [Line Items] | ||||
Available | $ 0 | |||
Term Loan | LIBOR | ||||
Debt Instrument [Line Items] | ||||
Basis of variable spread (in percentage) | 0.55% | |||
Term Loan | Base Rate | ||||
Debt Instrument [Line Items] | ||||
Basis of variable spread (in percentage) | 0.00% | |||
Revolver | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | $ 250,000,000 | $ 250,000,000 | ||
Borrowed | 0 | 0 | ||
Available | $ 250,000,000 | $ 250,000,000 | ||
Weighted Average Interest Rate (in percentage) | 0.00% | 0.00% | ||
Revolver | Subsequent Event | ||||
Debt Instrument [Line Items] | ||||
Available | $ 173,000,000 | |||
Revolver | LIBOR | ||||
Debt Instrument [Line Items] | ||||
Basis of variable spread (in percentage) | 1.00% | 1.00% | ||
Revolver | Base Rate | ||||
Debt Instrument [Line Items] | ||||
Basis of variable spread (in percentage) | 0.00% | 0.00% | ||
Sub-Limit LOC | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | $ 50,000,000 | $ 50,000,000 | ||
Sub-Limit LOC | Subsequent Event | ||||
Debt Instrument [Line Items] | ||||
Borrowed | $ 12,000,000 |
LEASES (Narrative) (Details)
LEASES (Narrative) (Details) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2019USD ($)option | Dec. 31, 2018USD ($) | Dec. 31, 2017MWh | Jan. 31, 2021 | May 31, 2018 | |
Lessee, Lease, Description [Line Items] | |||||
Renewal term | 15 years | ||||
Number of renewal options | option | 1 | ||||
Operating lease income | $ 1 | ||||
Operating lease cost | 1 | $ 1 | |||
Lessor, Operating Lease, Payments, Fiscal Year Maturity | |||||
2020 | 1 | ||||
2021 | 1 | ||||
2022 | 1 | ||||
2023 | 1 | ||||
2024 | 1 | ||||
Thereafter | $ 1 | ||||
Tolling PPA | |||||
Lessee, Lease, Description [Line Items] | |||||
Term of contract | 20 years | ||||
Generating capacity (MW) | MWh | 550 | ||||
Option to purchase unit, term | 3 years | ||||
Energy Storage | |||||
Lessee, Lease, Description [Line Items] | |||||
Lease not yet commenced, term of contract | 20 years | ||||
Office Facility and Utility Property | |||||
Lessee, Lease, Description [Line Items] | |||||
Remaining lease term | 3 years | ||||
Springerville Common Facilities | |||||
Lessee, Lease, Description [Line Items] | |||||
Commitment to purchase finance lease interest | $ 68 | ||||
Springerville Common Facilities | Forecast | |||||
Lessee, Lease, Description [Line Items] | |||||
Percentage of interest to be purchased (in percentage) | 32.20% | ||||
Springerville Common Facilities | Tri-State | |||||
Lessee, Lease, Description [Line Items] | |||||
Percentage of interest to be purchased (in percentage) | 14.00% | ||||
Springerville Common Facilities | SRP | |||||
Lessee, Lease, Description [Line Items] | |||||
Percentage of interest to be purchased (in percentage) | 14.00% | ||||
Minimum | |||||
Lessee, Lease, Description [Line Items] | |||||
Remaining lease term | 1 year | ||||
Minimum | Office Facility and Utility Property | |||||
Lessee, Lease, Description [Line Items] | |||||
Renewal term | 4 years | ||||
Maximum | |||||
Lessee, Lease, Description [Line Items] | |||||
Remaining lease term | 22 years | ||||
Maximum | Office Facility and Utility Property | |||||
Lessee, Lease, Description [Line Items] | |||||
Remaining lease term | 13 years |
LEASES (Assets and Liabilities)
LEASES (Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Lease Assets | ||
Utility Plant Under Finance Leases | $ 151,467 | $ 248,635 |
Accumulated Amortization of Finance Lease Assets | (77,285) | $ (73,646) |
Regulatory and Other Assets, Other | 8,000 | |
Lease Liabilities | ||
Current Liabilities, Finance Lease Obligations | 17,086 | |
Total Non-Current Lease Obligations | 67,316 | |
Current Liabilities, Other | 1,000 | |
Regulatory and Other Liabilities, Other | $ 6,000 |
LEASES (Lease Cost) (Details)
LEASES (Lease Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Finance | ||
Amortization of Leased Assets | $ 13 | |
Interest on Lease Liabilities | 13 | |
Operating | 1 | $ 1 |
Variable | 16 | |
Short Term | 1 | |
Total Lease Cost | 44 | |
Gila River Unit 2 | ||
Finance | ||
Amortization of Leased Assets | 6 | |
Interest on Lease Liabilities | $ 12 |
LEASES (Lease Liability) (Detai
LEASES (Lease Liability) (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Finance Leases | |
2020 | $ 18,000 |
2021 | 68,000 |
2022 | 0 |
2023 | 0 |
2024 | 0 |
Thereafter | 0 |
Total Lease Payments | 86,000 |
Less Imputed Interest | 2,000 |
Total Lease Obligations | 84,000 |
Less Current Portion | 17,086 |
Total Non-Current Lease Obligations | 67,316 |
Operating Leases | |
2020 | 1,000 |
2021 | 1,000 |
2022 | 1,000 |
2023 | 1,000 |
2024 | 1,000 |
Thereafter | 4,000 |
Total Lease Payments | 9,000 |
Less Imputed Interest | 2,000 |
Total Lease Obligations | 7,000 |
Less Current Portion | 1,000 |
Total Non-Current Lease Obligations | 6,000 |
Total | |
2020 | 19,000 |
2021 | 69,000 |
2022 | 1,000 |
2023 | 1,000 |
2024 | 1,000 |
Thereafter | 4,000 |
Total Lease Payments | 95,000 |
Less Imputed Interest | 4,000 |
Total Lease Obligations | 91,000 |
Less Current Portion | 18,000 |
Total Non-Current Lease Obligations | $ 73,000 |
LEASES (Term and Rate) (Details
LEASES (Term and Rate) (Details) | Dec. 31, 2019 |
Weighted-Average Remaining Lease Term (years) | |
Weighted-Average Remaining Lease Term (years), Finance Lease | 1 year |
Weighted-Average Remaining Lease Term (years), Operating Lease | 12 years |
Weighted-Average Discount Rate | |
Weighted-Average Discount Rate, Finance Lease | 2.20% |
Weighted-Average Discount Rate, Operating Lease | 4.10% |
LEASES (Cash Flows) (Details)
LEASES (Cash Flows) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Cash Paid for Amounts Included in the Measurement of Lease Liabilities | |
Operating Cash Flows used for Finance Leases | $ 13,000 |
Operating Cash Flows used for Operating Leases | 1,000 |
Financing Cash Flows used for Finance Leases | 10,890 |
Investing Cash Flows used for Finance Leases | $ 164,000 |
LEASES (Future Minimum Lease Pa
LEASES (Future Minimum Lease Payments) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Capital Leases | |
2019 | $ 187,000 |
2020 | 20,000 |
2021 | 0 |
2022 | 0 |
2023 | 0 |
Thereafter | 0 |
Total Lease Payments | 207,000 |
Less: Imputed Interest | 14,000 |
Total Lease Obligations | 193,000 |
Less: Current Portion | 172,510 |
Total Non-Current Lease Obligations | 19,773 |
Operating Leases | |
2019 | 1,000 |
2020 | 1,000 |
2021 | 1,000 |
2022 | 1,000 |
2023 | 1,000 |
Thereafter | 5,000 |
Total Lease Payments | $ 10,000 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Mar. 31, 2019USD ($)MWh | |
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | $ 195,000 | ||||
2021 | 149,000 | ||||
2022 | 125,000 | ||||
2023 | 107,000 | ||||
2024 | 108,000 | ||||
Thereafter | 855,000 | ||||
Total | 1,539,000 | ||||
Capital expenditures | 607,593 | $ 392,522 | $ 345,617 | ||
New Mexico | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
Nominal capacity wind-powered electric generation facility | MWh | 250 | ||||
Contractual obligation | $ 384,000 | ||||
Capital expenditures | 47,000 | ||||
New Mexico | Subsequent Event | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
Capital expenditures | $ 226,000 | ||||
Fuel, Including Transportation | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | 94,000 | ||||
2021 | 61,000 | ||||
2022 | 40,000 | ||||
2023 | 33,000 | ||||
2024 | 33,000 | ||||
Thereafter | 194,000 | ||||
Total | 455,000 | ||||
Purchased Power | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | 8,000 | ||||
2021 | 0 | ||||
2022 | 0 | ||||
2023 | 0 | ||||
2024 | 0 | ||||
Thereafter | 0 | ||||
Total | 8,000 | ||||
Transmission | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | 21,000 | ||||
2021 | 16,000 | ||||
2022 | 14,000 | ||||
2023 | 3,000 | ||||
2024 | 3,000 | ||||
Thereafter | 6,000 | ||||
Total | 63,000 | ||||
Renewable Power Purchase Agreements | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | 63,000 | ||||
2021 | 63,000 | ||||
2022 | 63,000 | ||||
2023 | 63,000 | ||||
2024 | 62,000 | ||||
Thereafter | 543,000 | ||||
Total | $ 857,000 | ||||
Percentage of purchase power obligations (in percentage) | 100.00% | ||||
RES Performance-Based Incentives | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | $ 8,000 | ||||
2021 | 7,000 | ||||
2022 | 7,000 | ||||
2023 | 7,000 | ||||
2024 | 7,000 | ||||
Thereafter | 33,000 | ||||
Total | 69,000 | ||||
Land Easements and Rights-of-Way | |||||
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract] | |||||
2020 | 1,000 | ||||
2021 | 2,000 | ||||
2022 | 1,000 | ||||
2023 | 1,000 | ||||
2024 | 3,000 | ||||
Thereafter | 79,000 | ||||
Total | $ 87,000 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Aug. 30, 2019 | Dec. 31, 2018 | |
San Juan Unit 1 | |||
Commitments And Contingencies [Line Items] | |||
Percentage of ownership (in percentage) | 50.00% | 50.00% | |
San Juan and Four Corners | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs | $ 57 | ||
San Juan and Four Corners | Other Liabilities | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs accrued | 36 | $ 31 | |
Navajo | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs | 17 | ||
Reclamation costs accrued | 0 | ||
Navajo | Other Liabilities | |||
Commitments And Contingencies [Line Items] | |||
Reclamation costs accrued | $ 5 | ||
Settlement paid | $ 8 |
COMMITMENTS AND CONTINGENCIES_4
COMMITMENTS AND CONTINGENCIES (Performance Guarantees) (Details) - Performance Guarantee | Dec. 31, 2019USD ($) |
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 (Additio
EMPLOYEE BENEFIT PLANS (Additional Information) (Details) | 12 Months Ended | ||
Dec. 31, 2019USD ($)plan | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Number of defined benefit pension plans | plan | 3 | ||
Number of qualified defined benefit pension plans | plan | 2 | ||
Increase in pension benefit obligation | $ 85,000,000 | ||
Increase in pension plan assets | $ 70,000,000 | ||
Percentage of service cost that was capitalized (in percentage) | 21.00% | 19.00% | |
Investment return model best-estimate range (in years) | 20 years | ||
Matching 401(k) contributions made | $ 6,000,000 | $ 7,000,000 | $ 6,000,000 |
Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 28,000,000 | 28,000,000 | 27,000,000 |
Other Postretirement Benefits | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Employer Contribution to VEBA Trust | 1,000,000 | 3,000,000 | 3,000,000 |
Fair value measurements of plan assets | 21,000,000 | 17,000,000 | 17,000,000 |
Other Postretirement Benefits | Level 1 and Level 2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 21,000,000 | 17,000,000 | |
Other Postretirement Benefits | Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 0 | ||
Pension Benefits | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Accumulated benefit obligation | 476,000,000 | 402,000,000 | |
Fair value measurements of plan assets | 446,000,000 | 376,000,000 | $ 403,000,000 |
Pension Benefits | Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 28,000,000 | 28,000,000 | |
Transfers | $ 0 | ||
Minimum | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Percentile of investment return model range used (in percentage) | 25.00% | ||
Maximum | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Percentile of investment return model range used (in percentage) | 75.00% | ||
Fixed Income Securities | Other Postretirement Benefits | Level 1 and Level 2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | $ 7,000,000 | 7,000,000 | |
Equities | Other Postretirement Benefits | Level 1 and Level 2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | $ 14,000,000 | $ 10,000,000 |
EMPLOYEE BENEFIT PLANS (Pension
EMPLOYEE BENEFIT PLANS (Pension and Other Postretirement Benefit Amounts included in Consolidated Balance Sheet ) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | $ 465 | $ 400 |
Regulatory Liabilities | (573) | (607) |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | 135 | 126 |
Regulatory Liabilities | 0 | 0 |
Accrued Employee Expenses | (2) | (1) |
Pension and Other Postretirement Benefits | (77) | (63) |
Accumulated Other Comprehensive Loss, SERP | 10 | 6 |
Net Amount Recognized | 66 | 68 |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | 0 | 0 |
Regulatory Liabilities | (1) | (3) |
Accrued Employee Expenses | (2) | (3) |
Pension and Other Postretirement Benefits | (56) | (54) |
Accumulated Other Comprehensive Loss, SERP | 0 | 0 |
Net Amount Recognized | $ (59) | $ (60) |
EMPLOYEE BENEFIT PLANS (Change
EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Benefits | |||
Change in Benefit Obligation | |||
Beginning of Period | $ 440 | $ 475 | |
Actuarial (Gain) Loss | 76 | (42) | |
Interest Cost | 18 | 16 | $ 15 |
Service Cost | 13 | 15 | 13 |
Benefits Paid | (23) | (23) | |
Plan Amendments | 1 | (1) | |
End of Period | 525 | 440 | 475 |
Change in Fair Value of Plan Assets | |||
Beginning of Period | 376 | 403 | |
Actual Return on Plan Assets | 81 | (25) | |
Benefits Paid | (22) | (23) | |
Employer Contributions | 11 | 21 | |
End of Period | 446 | 376 | 403 |
Funded Status at End of Period | (79) | (64) | |
Expected future contribution | 11 | ||
Other Postretirement Benefits | |||
Change in Benefit Obligation | |||
Beginning of Period | 74 | 82 | |
Actuarial (Gain) Loss | 4 | (8) | |
Interest Cost | 3 | 2 | 2 |
Service Cost | 4 | 5 | 4 |
Benefits Paid | (6) | (5) | |
Plan Amendments | 0 | (2) | |
End of Period | 79 | 74 | 82 |
Change in Fair Value of Plan Assets | |||
Beginning of Period | 17 | 17 | |
Actual Return on Plan Assets | 4 | (1) | |
Benefits Paid | (6) | (5) | |
Employer Contributions | 6 | 6 | |
End of Period | 21 | 17 | $ 17 |
Funded Status at End of Period | (58) | $ (57) | |
Expected future contribution | $ 1 |
EMPLOYEE BENEFIT PLANS (Compone
EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net (Gain) Loss | $ 145 | $ 133 |
Prior Service Cost (Benefit) | 0 | 0 |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net (Gain) Loss | 1 | (1) |
Prior Service Cost (Benefit) | $ (2) | $ (2) |
EMPLOYEE BENEFIT PLANS (Informa
EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Details) - Pension Benefits - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items] | ||
Accumulated Benefit Obligation | $ 476 | $ 230 |
Fair Value of Plan Assets | $ 446 | $ 202 |
EMPLOYEE BENEFIT PLANS (Compo_2
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | $ 13 | $ 15 | $ 13 |
Non-Service Cost | |||
Interest Cost | 18 | 16 | 15 |
Expected Return on Plan Assets | (26) | (28) | (25) |
Amortization of Net (Gain) Loss | 8 | 7 | 8 |
Net Periodic Benefit Cost | 13 | 10 | 11 |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 4 | 5 | 4 |
Non-Service Cost | |||
Interest Cost | 3 | 2 | 2 |
Expected Return on Plan Assets | (2) | (1) | (1) |
Amortization of Net (Gain) Loss | 0 | 0 | 0 |
Net Periodic Benefit Cost | $ 5 | $ 6 | $ 5 |
EMPLOYEE BENEFIT PLANS (Changes
EMPLOYEE BENEFIT PLANS (Changes in Regulatory Assets and Accumulated Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Benefits | Regulatory Asset | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | $ 16 | $ 12 | $ 5 |
Amortization of Net Loss | (8) | (7) | (7) |
Prior Service Credit (Cost) | 0 | 0 | 0 |
Total Recognized (Gain) Loss | 8 | 5 | (2) |
Pension Benefits | AOCI | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | 4 | (1) | 3 |
Amortization of Net Loss | (1) | 0 | 0 |
Prior Service Credit (Cost) | 1 | (1) | 0 |
Total Recognized (Gain) Loss | 4 | (2) | 3 |
Other Postretirement Benefits | Regulatory Asset | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | 1 | (6) | (1) |
Amortization of Net Loss | 0 | 0 | 0 |
Prior Service Credit (Cost) | 0 | (2) | 0 |
Total Recognized (Gain) Loss | $ 1 | $ (8) | $ (1) |
EMPLOYEE BENEFIT PLANS (Weighte
EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Details) | Dec. 31, 2019 | Dec. 31, 2018 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount Rate (in percentage) | 3.60% | 4.50% |
Rate of Compensation Increase (in percentage) | 2.80% | 2.80% |
Other Postretirement Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount Rate (in percentage) | 3.30% | 4.30% |
EMPLOYEE BENEFIT PLANS (Weigh_2
EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Rate of Compensation Increase (in percentage) | 2.80% | 2.80% | 2.80% |
Expected Return on Plan Assets (in percentage) | 7.00% | 7.00% | 7.00% |
Pension Benefits | Service cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 4.70% | 3.80% | 4.40% |
Pension Benefits | Interest Cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 4.20% | 3.40% | 3.70% |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected Return on Plan Assets (in percentage) | 7.00% | 7.00% | 7.00% |
Other Postretirement Benefits | Service cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 4.50% | 3.80% | 4.30% |
Other Postretirement Benefits | Interest Cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 4.00% | 3.20% | 3.30% |
EMPLOYEE BENEFIT PLANS(Assumed
EMPLOYEE BENEFIT PLANS(Assumed Health Care Cost Trend Rates) (Details) | Dec. 31, 2019 | Dec. 31, 2018 |
Retirement Benefits [Abstract] | ||
Next Year (Pre-65) (in percentage) | 6.30% | 6.50% |
Next Year (Post-65) (in percentage) | 7.50% | 7.80% |
Ultimate Rate Assumed (Pre-65 and Post-65) (in percentage) | 4.50% | 4.50% |
EMPLOYEE BENEFIT PLANS (Percent
EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Details) | Dec. 31, 2019 | Dec. 31, 2018 |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 100.00% | 100.00% |
Pension Benefits | Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 46.00% | 45.00% |
Pension Benefits | Fixed Income Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 45.00% | 45.00% |
Pension Benefits | Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 8.00% | 8.00% |
Pension Benefits | Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 1.00% | 2.00% |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 100.00% | 100.00% |
Other Postretirement Benefits | Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 65.00% | 60.00% |
Other Postretirement Benefits | Fixed Income Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 33.00% | 38.00% |
Other Postretirement Benefits | Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 0.00% | 0.00% |
Other Postretirement Benefits | Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation (in percentage) | 2.00% | 2.00% |
EMPLOYEE BENEFIT PLANS (Fair Va
EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Plan Assets By Level) (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Level 3 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $ 28 | $ 28 | $ 27 |
Level 3 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 23 | 22 | 21 |
Level 3 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 5 | 6 | 6 |
Pension Benefits | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 446 | 376 | $ 403 |
Pension Benefits | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 2 | 1 | |
Pension Benefits | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 55 | 45 | |
Pension Benefits | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 21 | 17 | |
Pension Benefits | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 80 | 67 | |
Pension Benefits | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 51 | 42 | |
Pension Benefits | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 199 | 167 | |
Pension Benefits | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 33 | 31 | |
Pension Benefits | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 5 | 6 | |
Pension Benefits | Level 1 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 2 | 1 | |
Pension Benefits | Level 1 | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 2 | 1 | |
Pension Benefits | Level 1 | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 2 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 416 | 347 | |
Pension Benefits | Level 2 | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 2 | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 55 | 45 | |
Pension Benefits | Level 2 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 21 | 17 | |
Pension Benefits | Level 2 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 80 | 67 | |
Pension Benefits | Level 2 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 51 | 42 | |
Pension Benefits | Level 2 | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 199 | 167 | |
Pension Benefits | Level 2 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 10 | 9 | |
Pension Benefits | Level 2 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 28 | 28 | |
Pension Benefits | Level 3 | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 23 | 22 | |
Pension Benefits | Level 3 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $ 5 | $ 6 |
EMPLOYEE BENEFIT PLANS (Reconci
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Details) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Beginning of Period | $ 28 | $ 27 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 2 | 3 |
Purchases, Sales, and Settlements | (2) | (2) |
End of Period | 28 | 28 |
Private Equity | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Beginning of Period | 6 | 6 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 1 | 2 |
Purchases, Sales, and Settlements | (2) | (2) |
End of Period | 5 | 6 |
Real Estate | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Beginning of Period | 22 | 21 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 1 | 1 |
Purchases, Sales, and Settlements | 0 | 0 |
End of Period | $ 23 | $ 22 |
EMPLOYEE BENEFIT PLANS (Target
EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Details) | Dec. 31, 2019 |
Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 100.00% |
Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 100.00% |
Cash/Treasury Bills | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Cash/Treasury Bills | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 2.00% |
United States Large Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 12.00% |
United States Large Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 39.00% |
United States Small Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 5.00% |
United States Small Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 5.00% |
Non-United States Developed | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Non-United States Developed | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 7.00% |
Non-United States Emerging | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Non-United States Emerging | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 9.00% |
Global Equity | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 26.00% |
Global Equity | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Global Infrastructure | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 3.00% |
Global Infrastructure | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Fixed Income Securities | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 45.00% |
Fixed Income Securities | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 38.00% |
Real Estate | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 8.00% |
Real Estate | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Private Equity | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 1.00% |
Private Equity | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
EMPLOYEE BENEFIT PLANS (Future
EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Pension Benefits | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2020 | $ 26 |
2021 | 26 |
2022 | 26 |
2023 | 27 |
2024 | 28 |
Years 2025-2029 | 147 |
Other Postretirement Benefits | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2020 | 5 |
2021 | 5 |
2022 | 5 |
2023 | 5 |
2024 | 5 |
Years 2025-2029 | $ 25 |
SHARE-BASED COMPENSATION (Detai
SHARE-BASED COMPENSATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated share of probable payout | $ 12 | $ 9 | |
Allocated share-based compensation expense | $ 4 | $ 2 | $ 4 |
2015 Share Unit Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation, valuation, share equivalent, number (in shares) | 1 | ||
2015 Share Unit Plan | PSUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options awarded during the period (in shares) | 66,978 | 54,426 | 68,126 |
2015 Share Unit Plan | RSUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options awarded during the period (in shares) | 33,489 | 27,213 | 34,063 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Cash Transactions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |||
Interest Paid, Net of Amounts Capitalized | $ 80 | $ 67 | $ 61 |
Income Tax Refunds | $ (14) | $ 0 | $ 0 |
SUPPLEMENTAL CASH FLOW INFORM_4
SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |||
Finance Leases | $ 67 | ||
Finance Leases | $ 164 | $ 0 | |
Accrued Capital Expenditures | 40 | 31 | 24 |
Asset Retirement Obligations Increase (Decrease) | 26 | 20 | 10 |
Operating Leases | 8 | ||
Renewable Energy Credits | 3 | 3 | 2 |
Net Cost of Removal Increase (Decrease) | $ (10) | $ (4) | $ (88) |
FAIR VALUE MEASUREMENTS AND D_3
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Assets | ||
Cash Equivalents | $ 55 | |
Restricted Cash | $ 18 | 15 |
Energy Derivative Contract, Regulatory Recovery | 3 | 10 |
Energy Derivative Contract, No Regulatory Recovery | 3 | 2 |
Total Assets | 24 | 82 |
Liabilities | ||
Energy Derivative Contracts, Regulatory Recovery | (76) | (37) |
Total Liabilities | (76) | (37) |
Total Assets (Liabilities), Net | (52) | 45 |
Level 1 | ||
Assets | ||
Cash Equivalents | 55 | |
Restricted Cash | 18 | 15 |
Energy Derivative Contract, Regulatory Recovery | 0 | 0 |
Energy Derivative Contract, No Regulatory Recovery | 0 | 0 |
Total Assets | 18 | 70 |
Liabilities | ||
Energy Derivative Contracts, Regulatory Recovery | 0 | 0 |
Total Liabilities | 0 | 0 |
Total Assets (Liabilities), Net | 18 | 70 |
Level 2 | ||
Assets | ||
Cash Equivalents | 0 | |
Restricted Cash | 0 | 0 |
Energy Derivative Contract, Regulatory Recovery | 3 | 10 |
Energy Derivative Contract, No Regulatory Recovery | 3 | 0 |
Total Assets | 6 | 10 |
Liabilities | ||
Energy Derivative Contracts, Regulatory Recovery | (76) | (35) |
Total Liabilities | (76) | (35) |
Total Assets (Liabilities), Net | (70) | (25) |
Level 3 | ||
Assets | ||
Cash Equivalents | 0 | |
Restricted Cash | 0 | 0 |
Energy Derivative Contract, Regulatory Recovery | 0 | 0 |
Energy Derivative Contract, No Regulatory Recovery | 0 | 2 |
Total Assets | 0 | 2 |
Liabilities | ||
Energy Derivative Contracts, Regulatory Recovery | 0 | (2) |
Total Liabilities | 0 | (2) |
Total Assets (Liabilities), Net | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS AND D_4
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative Asset [Abstract] | ||
Derivative Asset, Gross Amount Recognized in the Balance Sheets | $ 6 | $ 12 |
Derivative Asset, Counterparty Netting | 4 | 11 |
Derivative Asset, Cash Collateral Received/Posted | 0 | 0 |
Derivative Asset, Net Amount | 2 | 1 |
Derivative Liability [Abstract] | ||
Derivative Liability, Gross Amount Recognized in the Balance Sheets | (76) | (37) |
Derivative Liability, Counterparty Netting | (4) | (11) |
Derivative Liability, Cash Collateral Received/Posted | (2) | 0 |
Derivative Liability, Net Amount | $ (70) | $ (26) |
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 | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||||||||||
Percent of gains shared with ratepayers | 10.00% | ||||||||||
Operating Revenues | $ 318,000 | $ 441,000 | $ 326,000 | $ 333,000 | $ 344,000 | $ 460,000 | $ 354,000 | $ 275,000 | $ 1,418,338 | $ 1,432,618 | $ 1,340,935 |
Energy Derivative | Not Designated | |||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||||||
Unrealized Net Loss | (45,000) | (9,000) | (18,000) | ||||||||
Operating Revenues | $ 6,000 | $ 5,000 | $ 5,000 |
FAIR VALUE MEASUREMENTS AND D_6
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) $ in Millions, BBtu in Billions | Dec. 31, 2019USD ($)BBtuGWh | Dec. 31, 2018BBtuGWh |
Interest Rate Swap | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative liability, notional amount | $ | $ 6 | |
Power Contracts GWh | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, nonmonetary notional amount | GWh | 4,740 | 1,743 |
Gas Contracts BBtu | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, nonmonetary notional amount | BBtu | 122,779 | 146,933 |
FAIR VALUE MEASUREMENTS AND D_7
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Forward Power Contracts - Level 3 $ in Millions | Dec. 31, 2018USD ($)$ / megawatt_hour |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |
Derivative Assets | $ | $ 3 |
Derivative Liabilities | $ | $ (2) |
Minimum | |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |
Market Price | $ / megawatt_hour | 16.80 |
Maximum | |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |
Market Price | $ / megawatt_hour | 47.05 |
FAIR VALUE MEASUREMENTS AND D_8
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Roll-forward | ||
Beginning of Period | $ 1 | $ 2 |
Gains (Losses) Recorded | ||
Regulatory Assets or Liabilities, Derivative Instruments | (12) | (4) |
Operating Revenues | 5 | 5 |
Settlements | 1 | (2) |
Transfers Out of Level 3 | 5 | 0 |
End of Period | 0 | 1 |
Gains (Losses), Assets (Liabilities) Still Held | $ 0 | $ 1 |
FAIR VALUE MEASUREMENTS AND D_9
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) | Feb. 12, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative [Line Items] | |||
FV of derivative instruments in net liability positions with credit risk related features, including normal purchase normal sale | $ 100,000,000 | $ 41,000,000 | |
Collateral posted | 2,000,000 | ||
Additional collateral to post if credit-risk contingent features are triggered | 98,000,000 | ||
Outstanding Net Payable Balances for Settled Positions | |||
Derivative [Line Items] | |||
Additional collateral to post if credit-risk contingent features are triggered | 19,000,000 | ||
Interest Rate Swap | |||
Derivative [Line Items] | |||
Derivative liability, notional amount | $ 6,000,000 | ||
Interest Rate Swap | Subsequent Event | |||
Derivative [Line Items] | |||
Derivative liability, notional amount | $ 0 |
FAIR VALUE MEASUREMENTS AND _10
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Net Carrying Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 1,602 | $ 1,615 |
Fair Value | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Long-Term Debt, including Current Maturities | $ 1,755 | $ 1,672 |
INCOME TAXES (Reconciliation of
INCOME TAXES (Reconciliation of Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Federal Income Tax Expense at Statutory Rate | $ 46,000 | $ 49,000 | $ 97,000 |
State Income Tax Expense, Net of Federal Deduction | 9,000 | 9,000 | 9,000 |
Federal/State Tax Credits | (6,000) | (10,000) | (9,000) |
Allowance for Equity Funds Used During Construction | (3,000) | (1,000) | (2,000) |
Impact of Enactment, TCJA | 0 | 0 | 7,000 |
Excess Deferred Income Taxes | (9,000) | (6,000) | 0 |
Impact of AMT Sequestration | (2,000) | 2,000 | 0 |
Other | (1,000) | 0 | (1,000) |
Total Federal and State Income Tax Expense | $ 34,053 | $ 42,982 | $ 100,763 |
INCOME TAXES (Income Tax Expens
INCOME TAXES (Income Tax Expense Included in Income Statements) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Current Income Tax Expense | |||
Federal | $ (8,000) | $ (13,000) | $ 0 |
State | 0 | 0 | 0 |
Total Current Income Tax Expense | (8,000) | (13,000) | 0 |
Deferred Income Tax Expense | |||
Federal | 41,000 | 53,000 | 98,000 |
Federal Investment Tax Credits | (4,000) | (6,000) | (6,000) |
State | 5,000 | 9,000 | 9,000 |
Total Deferred Income Tax Expense | 42,000 | 56,000 | 101,000 |
Total Federal and State Income Tax Expense | $ 34,053 | $ 42,982 | $ 100,763 |
INCOME TAXES (Additional Inform
INCOME TAXES (Additional Information) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Loss Carryforwards [Line Items] | |||
Increase in regulated liabilities due to change in tax rate | $ 9,000,000 | ||
Impact of AMT Sequestration | 2,000,000 | $ (2,000,000) | $ 0 |
Valuation allowance | 0 | 0 | |
Unrecognized tax benefits, if recognized, decrease in income tax expense (benefit) | 1,000,000 | 1,000,000 | |
Interest expense related to uncertain tax position | 0 | 0 | |
Interest payable | 0 | 0 | |
Penalties accrued | 0 | 0 | |
Decrease in uncertain tax position obligations | 17,000,000 | ||
Federal tax return | 8,000,000 | 13,000,000 | $ 0 |
UNS Energy | |||
Operating Loss Carryforwards [Line Items] | |||
Federal tax return | 14,000,000 | $ 0 | |
Internal Revenue Service (IRS) | |||
Operating Loss Carryforwards [Line Items] | |||
Tax credits | $ 7,000,000 |
INCOME TAXES (The Significant C
INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 |
Gross Deferred Income Tax Assets | ||
Finance Lease Obligations | $ 21,000,000 | |
Finance Lease Obligations | $ 48,000,000 | |
Operating Loss Carryforwards, Net | 3,000,000 | 23,000,000 |
Customer Advances and Contributions in Aid of Construction | 19,000,000 | 16,000,000 |
AMT Credit | 7,000,000 | 13,000,000 |
Other Postretirement Benefits | 15,000,000 | 15,000,000 |
Investment Tax Credit Carryforward | 34,000,000 | 34,000,000 |
Income Taxes Recoverable Through Future Rates | 81,000,000 | 87,000,000 |
Other | 79,000,000 | 60,000,000 |
Total Gross Deferred Income Tax Assets | 259,000,000 | 296,000,000 |
Deferred Tax Assets Valuation Allowance | 0 | 0 |
Gross Deferred Income Tax Liabilities | ||
Plant, Net | (602,000,000) | (552,000,000) |
Plant Abandonments | (17,000,000) | (18,000,000) |
Finance Lease Assets, Net | (18,000,000) | (44,000,000) |
Pensions | (17,000,000) | (19,000,000) |
Income Taxes Payable Through Future Rates | (9,000,000) | (12,000,000) |
Other | (28,000,000) | (21,000,000) |
Total Gross Deferred Income Tax Liabilities | (691,000,000) | (666,000,000) |
Deferred Income Taxes, Net | $ (432,000,000) | $ (370,000,000) |
INCOME TAXES (Summary of Tax Ca
INCOME TAXES (Summary of Tax Carryforwards) (Details) $ in Millions | Dec. 31, 2019USD ($) |
Internal Revenue Service (IRS) | |
Income Tax Contingency [Line Items] | |
Federal Net Operating Loss | $ 17 |
Tax Credits | 7 |
Investment Tax Credits | 34 |
State Tax Jurisdiction | |
Income Tax Contingency [Line Items] | |
Tax Credits | $ 9 |
INCOME TAXES (Uncertain Tax Pos
INCOME TAXES (Uncertain Tax Positions) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning of Period | $ 16 | $ 13 |
Additions Based on Tax Positions Taken in the Current Year | 2 | 3 |
End of Period | $ 18 | $ 16 |
QUARTERLY FINANCIAL DATA (UNA_2
QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating Revenue | $ 318,000 | $ 441,000 | $ 326,000 | $ 333,000 | $ 344,000 | $ 460,000 | $ 354,000 | $ 275,000 | $ 1,418,338 | $ 1,432,618 | $ 1,340,935 |
Operating Income | 39,000 | 134,000 | 67,000 | 43,000 | 36,000 | 126,000 | 83,000 | 43,000 | 282,589 | 288,144 | 326,326 |
Net Income | $ 21,000 | $ 98,000 | $ 42,000 | $ 26,000 | $ 11,000 | $ 95,000 | $ 58,000 | $ 24,000 | $ 186,515 | $ 188,323 | $ 176,668 |