Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 10, 2022 | Jun. 30, 2021 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2021 | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | TAMPA ELECTRIC COMPANY | ||
Entity Central Index Key | 0000096271 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
ICFR Auditor Attestation Flag | false | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity File Number | 1-5007 | ||
Entity Address, Address Line One | TECO Plaza | ||
Entity Address, Address Line Two | 702 N. Franklin Street | ||
Entity Address, City or Town | Tampa | ||
Entity Address, State or Province | FL | ||
Entity Tax Identification Number | 59-0475140 | ||
Entity Incorporation, State or Country Code | FL | ||
Entity Address, Postal Zip Code | 33602 | ||
City Area Code | (813) | ||
Local Phone Number | 228-1111 | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Entity Interactive Data Current | Yes | ||
Entity Common Stock, Shares Outstanding | 10 | ||
Entity Public Float | $ 0 | ||
Auditor Name | Ernst & Young LLP | ||
Auditor Location | Tampa, Florida | ||
Auditor Firm ID | 42 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Property, plant and equipment | ||
Utility plant, at original costs | $ 14,189 | $ 13,818 |
Accumulated depreciation | (3,601) | (3,712) |
Utility plant, net | 10,588 | 10,106 |
Other property | 14 | 14 |
Total property, plant and equipment, net | 10,602 | 10,120 |
Current assets | ||
Cash and cash equivalents | 18 | 10 |
Receivables, less allowance for credit losses of $7 and $7 at December 31, 2021 and 2020, respectively | 254 | 219 |
Due from affiliates | 8 | 11 |
Inventories, at average cost | ||
Regulatory assets | 136 | 79 |
Prepayments and other current assets | 22 | 10 |
Total current assets | 579 | 462 |
Deferred debits | ||
Regulatory assets | 866 | 406 |
Other | 149 | 60 |
Total deferred debits | 1,015 | 466 |
Total assets | 12,196 | 11,048 |
Capitalization | ||
Common stock | 4,470 | 3,890 |
Accumulated other comprehensive loss | (1) | (1) |
Retained earnings | 323 | 327 |
Total capital | 4,792 | 4,216 |
Long-term debt | 3,136 | 2,594 |
Total capital | 7,928 | 6,810 |
Current liabilities | ||
Long-term debt due within one year | 250 | 278 |
Notes payable | 745 | 775 |
Accounts payable | 390 | 321 |
Due to affiliates | 44 | 46 |
Customer deposits | 132 | 130 |
Regulatory liabilities | 78 | 67 |
Accrued interest | 18 | 13 |
Accrued taxes | 19 | 22 |
Other | 51 | 57 |
Total current liabilities | 1,727 | 1,709 |
Long-term liabilities | ||
Deferred income taxes | 858 | 783 |
Regulatory liabilities | 1,092 | 1,194 |
Investment tax credits | 249 | 216 |
Deferred credits and other liabilities | 342 | 336 |
Total deferred credits | 2,541 | 2,529 |
Commitments and Contingencies (see Note 8) | ||
Total liabilities and capital | 12,196 | 11,048 |
Fuel [Member] | ||
Inventories, at average cost | ||
Utility inventories | 20 | 26 |
Materials and Supplies [Member] | ||
Inventories, at average cost | ||
Utility inventories | 121 | 107 |
Electric [Member] | ||
Property, plant and equipment | ||
Utility plant, at original costs | 11,563 | 11,486 |
Gas [Member] | ||
Property, plant and equipment | ||
Utility plant, at original costs | $ 2,626 | $ 2,332 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Statement Of Financial Position [Abstract] | ||
Allowance for credit losses | $ 7 | $ 7 |
Consolidated Statements of Inco
Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Revenues | |||
Electric | $ 2,170 | $ 1,845 | $ 1,961 |
Gas | 525 | 427 | 443 |
Total revenues | 2,695 | 2,272 | 2,404 |
Expenses | |||
Fuel | 604 | 340 | 516 |
Purchased power | 106 | 83 | 49 |
Cost of natural gas sold | 155 | 121 | 152 |
Operations & maintenance | 566 | 542 | 543 |
Depreciation and amortization | 430 | 384 | 377 |
Taxes, other than income | 228 | 202 | 206 |
Total expenses | 2,089 | 1,672 | 1,843 |
Income from operations | 606 | 600 | 561 |
Other income | |||
Allowance for other funds used during construction | 45 | 30 | 11 |
Other income, net | 5 | 6 | 9 |
Total other income | 50 | 36 | 20 |
Interest charges | |||
Interest expense | 151 | 144 | 139 |
Allowance for borrowed funds used during construction | (21) | (14) | (5) |
Total interest charges | 130 | 130 | 134 |
Income before provision for income taxes | 526 | 506 | 447 |
Provision for income taxes | 80 | 82 | 77 |
Net income | 446 | 424 | 370 |
Other comprehensive income, net of tax | |||
Comprehensive income | $ 446 | $ 424 | $ 370 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Cash flows from or used in operating activities | |||
Net income | $ 446 | $ 424 | $ 370 |
Adjustments to reconcile net income to net cash from operating activities: | |||
Depreciation and amortization | 430 | 384 | 377 |
Deferred income taxes and investment tax credits | 28 | 54 | 15 |
Allowance for equity funds used during construction | (45) | (30) | (11) |
Deferred recovery clauses | (58) | (40) | 63 |
Receivables, less allowance for credit losses | (32) | (10) | 52 |
Inventories | (8) | 7 | 6 |
Taxes accrued | (13) | 23 | 1 |
Accounts payable | 53 | 34 | (4) |
Regulatory assets and liabilities | (10) | (18) | 1 |
Other | 6 | 1 | (29) |
Cash flows from operating activities | 797 | 829 | 841 |
Cash flows from or used in investing activities | |||
Capital expenditures | (1,397) | (1,361) | (1,283) |
Net proceeds from sale of assets | 0 | 6 | 0 |
Cash flows used in investing activities | (1,397) | (1,355) | (1,283) |
Cash flows from or used in financing activities | |||
Equity contributions from Parent | 580 | 505 | 395 |
Proceeds from long-term debt issuance | 790 | 0 | 292 |
Repayment of long-term debt | (279) | 0 | 0 |
Net change in short-term debt (maturities of 90 days or less) | (230) | 127 | 127 |
Proceeds from other short-term debt (maturities over 90 days) | 500 | 300 | 0 |
Repayment of other short-term debt (maturities over 90 days) | (300) | 0 | 0 |
Dividends to Parent | (450) | (408) | (373) |
Other financing activities | (3) | (2) | 0 |
Cash flows from financing activities | 608 | 522 | 441 |
Net increase (decrease) in cash and cash equivalents | 8 | (4) | (1) |
Cash and cash equivalents at beginning of the year | 10 | 14 | 15 |
Cash and cash equivalents at end of the year | 18 | 10 | 14 |
Supplemental disclosure of cash paid (received): | |||
Interest | 120 | 126 | 134 |
Income taxes | 62 | 14 | 63 |
Supplemental disclosure of non-cash activities | |||
Change in accrued capital expenditures | $ 25 | $ 1 | $ 17 |
Consolidated Statements of Capi
Consolidated Statements of Capitalization - Capital Stock - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Beginning balance | $ 4,216 | $ 3,695 | $ 3,303 |
Net income | 446 | 424 | 370 |
Equity contributions from Parent | 580 | 505 | 395 |
Dividends to Parent | (450) | (408) | (373) |
Ending balance | 4,792 | 4,216 | 3,695 |
Common Stock [Member] | |||
Beginning balance | $ 3,890 | $ 3,385 | $ 2,990 |
Beginning balance | 10 | 10 | 10 |
Equity contributions from Parent | $ 580 | $ 505 | $ 395 |
Ending balance | $ 4,470 | $ 3,890 | $ 3,385 |
Ending balance | 10 | 10 | 10 |
Retained Earnings [Member] | |||
Beginning balance | $ 327 | $ 311 | $ 314 |
Net income | 446 | 424 | 370 |
Dividends to Parent | (450) | (408) | (373) |
Ending balance | 323 | 327 | 311 |
Accumulated Other Comprehensive Loss [Member] | |||
Beginning balance | (1) | (1) | (1) |
Ending balance | $ (1) | $ (1) | $ (1) |
Consolidated Statements of Ca_2
Consolidated Statements of Capitalization - Capital Stock (Parenthetical) | Dec. 31, 2021$ / sharesshares |
Preferred stock - par value | $ / shares | $ 100 |
Common equity, shares authorized | 25,000,000 |
Preferred Stock Par Value [Member] | |
Preferred stock, shares authorized | 1,500,000 |
Preferred stock, shares outstanding | 0 |
Preferred Stock No Par Value [Member] | |
Preferred stock, shares authorized | 2,500,000 |
Preferred stock, shares outstanding | 0 |
Preferred stock, no par value | $ / shares | $ 0 |
Preference Stock No Par Value Subordinate to the Preferred Stock [Member] | |
Preferred stock, shares authorized | 2,500,000 |
Preferred stock, shares outstanding | 0 |
Preferred stock, no par value | $ / shares | $ 0 |
Consolidated Statements of Ca_3
Consolidated Statements of Capitalization - Long-Term Debt - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Debt Instrument [Line Items] | ||
Long-term debt, total | $ 3,425 | $ 2,903 |
Unamortized debt discount, net | (12) | (10) |
Debt issuance costs | (27) | (21) |
Long-term debt, carrying amount | 3,386 | 2,872 |
Less amount due within one year | 250 | 278 |
Total long-term debt | 3,136 | 2,594 |
Long-term debt, fair value | 4,036 | 3,597 |
Tampa Electric [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, total | 2,905 | 2,566 |
Long-term debt, carrying amount | $ 2,905 | |
Tampa Electric [Member] | 5.40% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2021 | |
Long-term debt, total | $ 0 | 231 |
Tampa Electric [Member] | 2.60% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2022 | |
Long-term debt, total | $ 225 | 225 |
Tampa Electric [Member] | 2.40% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2031 | |
Long-term debt, total | $ 285 | 0 |
Tampa Electric [Member] | 6.55% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2036 | |
Long-term debt, total | $ 250 | 250 |
Tampa Electric [Member] | 6.15% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2037 | |
Long-term debt, total | $ 190 | 190 |
Tampa Electric [Member] | 4.10% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2042 | |
Long-term debt, total | $ 250 | 250 |
Tampa Electric [Member] | 4.35% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2044 | |
Long-term debt, total | $ 290 | 290 |
Tampa Electric [Member] | 4.20% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2045 | |
Long-term debt, total | $ 230 | 230 |
Tampa Electric [Member] | 4.30% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2048 | |
Long-term debt, total | $ 275 | 275 |
Tampa Electric [Member] | 4.45% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2049 | |
Long-term debt, total | $ 350 | 350 |
Tampa Electric [Member] | 3.63% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2050 | |
Long-term debt, total | $ 275 | 275 |
Tampa Electric [Member] | 3.45% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2051 | |
Long-term debt, total | $ 285 | 0 |
PGS [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, total | 520 | 337 |
Long-term debt, carrying amount | $ 520 | |
PGS [Member] | 5.40% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2021 | |
Long-term debt, total | $ 0 | 47 |
PGS [Member] | 2.60% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2022 | |
Long-term debt, total | $ 25 | 25 |
PGS [Member] | 2.40% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2031 | |
Long-term debt, total | $ 115 | 0 |
PGS [Member] | 6.15% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2037 | |
Long-term debt, total | $ 60 | 60 |
PGS [Member] | 4.10% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2042 | |
Long-term debt, total | $ 50 | 50 |
PGS [Member] | 4.35% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2044 | |
Long-term debt, total | $ 10 | 10 |
PGS [Member] | 4.20% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2045 | |
Long-term debt, total | $ 20 | 20 |
PGS [Member] | 4.30% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2048 | |
Long-term debt, total | $ 75 | 75 |
PGS [Member] | 4.45% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2049 | |
Long-term debt, total | $ 25 | 25 |
PGS [Member] | 3.63% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2050 | |
Long-term debt, total | $ 25 | 25 |
PGS [Member] | 3.45% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2051 | |
Long-term debt, total | $ 115 | $ 0 |
Consolidated Statements of Ca_4
Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) | Dec. 31, 2021 |
Tampa Electric [Member] | 5.40% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 5.40% |
Tampa Electric [Member] | 2.60% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 2.60% |
Tampa Electric [Member] | 2.40% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 2.40% |
Tampa Electric [Member] | 6.55% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 6.55% |
Tampa Electric [Member] | 6.15% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 6.15% |
Tampa Electric [Member] | 4.10% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.10% |
Tampa Electric [Member] | 4.35% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.35% |
Tampa Electric [Member] | 4.20% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.20% |
Tampa Electric [Member] | 4.30% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.30% |
Tampa Electric [Member] | 4.45% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.45% |
Tampa Electric [Member] | 3.63% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 3.63% |
Tampa Electric [Member] | 3.45% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 3.45% |
PGS [Member] | 5.40% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 5.40% |
PGS [Member] | 2.60% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 2.60% |
PGS [Member] | 2.40% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 2.40% |
PGS [Member] | 6.15% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 6.15% |
PGS [Member] | 4.10% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.10% |
PGS [Member] | 4.35% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.35% |
PGS [Member] | 4.20% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.20% |
PGS [Member] | 4.30% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.30% |
PGS [Member] | 4.45% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 4.45% |
PGS [Member] | 3.63% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 3.63% |
PGS [Member] | 3.45% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 3.45% |
Consolidated Statements of Ca_5
Consolidated Statements of Capitalization - Long-term Debt Maturities $ in Millions | Dec. 31, 2021USD ($) |
Debt Instrument [Line Items] | |
Long-term debt, carrying amount | $ 3,386 |
Long Term Debt Maturities | |
Debt Instrument [Line Items] | |
2022 | 250 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 3,175 |
Long-term debt, carrying amount | 3,425 |
Tampa Electric [Member] | |
Debt Instrument [Line Items] | |
2022 | 225 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 2,680 |
Long-term debt, carrying amount | 2,905 |
PGS [Member] | |
Debt Instrument [Line Items] | |
2022 | 25 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 495 |
Long-term debt, carrying amount | $ 520 |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | 1. Significant Accounting Policies Description of the Business TEC has two operating segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, its natural gas division, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. TEC’s significant accounting policies are as follows: Principles of Consolidation and Basis of Presentation TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. TEC is a wholly owned subsidiary of TECO Energy, Inc. and contains electric and natural gas divisions. Intercompany balances and transactions within the divisions have been eliminated in consolidation. TECO Energy is a wholly owned indirect subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera. Since 2020, the outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of December 31, 2021 and 2020 and for the years then ended were not materially impacted by the COVID-19 pandemic. Cash Equivalents Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments. Property, Plant and Equipment Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred. As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation. The original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized. Property, plant and equipment consisted of the following assets: (millions) Estimated Useful Lives December 31, 2021 December 31, 2020 Electric generation 21 - 56 years $ 5,395 $ 5,694 Electric transmission 28 - 77 years 1,068 1,008 Electric distribution 14 - 56 years 3,064 2,859 Gas transmission and distribution 16 - 77 years 2,360 2,076 General plant and other 8 - 43 year s 946 723 Total cost 12,833 12,360 Less accumulated depreciation ( 3,601 ) ( 3,712 ) Construction work in progress 1,370 1,472 Total property, plant and equipment, net $ 10,602 $ 10,120 Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5 %, 3.2 % and 3.4 % for 2021, 2020 and 2019, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $ 408 million, $ 381 million and $ 359 million, respectively. See Note 3 for information regarding agreements approved by the FPSC that, among other things, allowed Tampa Electric to continue to depreciate certain retired assets through December 31, 2021 and allowed Tampa Electric to eliminate its $ 16 million accumulated depreciation and amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. Tampa Electric and PGS compute depreciation and amortization using the following methods: • the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; • the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. Allowance for Funds Used During Construction AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rates used to calculate AFUDC are revised periodically to reflect significant changes in cost of capital. In 2021, 2020 and 2019, Tampa Electric’s rate was 6.46 %. PGS’s rate used to calculate its AFUDC in 2021 and 2020 was 6.00 % and 5.97 %, respectively. Total AFUDC for the years ended December 31, 2021, 2020 and 2019 was $ 66 million, $ 44 million and $ 16 million, respectively. Inventory TEC values materials, supplies and fossil fuel inventory (natural gas, coal and oil) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or net realizable value. Regulatory Assets and Liabilities Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 ). Deferred Income Taxes TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details. Investment Tax Credits ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property. Stranded Tax Effects in Accumulated Other Comprehensive Income TEC utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released. Revenue Recognition Regulated electric revenue Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. Tampa Electric’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWH delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, timing of meter reads and line losses. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. PGS’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes. Other See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue. Revenues and Cost Recovery Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation, environmental and storm protection plan costs for Tampa Electric and purchased gas, interstate pipeline capacity, replacement of cast iron/bare steel pipe and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets. Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are recognized. Receivables and Allowance for Credit Losses Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $ 252 million and $ 214 million as of December 31, 2021 and 2020, respectively. An allowance for credit losses is established based on TEC’s collection experience and reasonable and supportable forecasts that affect the collectibility of the reported amount. Circumstances that impact Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible. The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3 ). As of December 31, 2021 and 2020, unbilled revenues of $ 74 million and $ 73 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets. Accounting for Franchise Fees and Gross Receipts Taxes Tampa Electric and PGS are allowed to recover certain costs incurred on a dollar-for-dollar basis from customers through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $ 129 million, $ 109 million and $ 117 million for the years ended December 31, 2021, 2020 and 2019, respectively. Deferred Charges and Other Assets Deferred charges and other assets consist primarily of pension assets net of accrued pension liabilities (see Note 5 ), right-of-use assets related to operating leases (see Note 13 ) and a contribution made by TEC in order to fully fund its SERP obligation (see Note 5 ). Deferred Credits and Other Liabilities Other deferred credits primarily include accrued other postretirement benefits (see Note 5 ), MGP environmental remediation liability (see Note 8 ), asset retirement obligations (see Note 12 ), lease liabilities (see Note 13 ) and a reserve for auto, general and workers’ compensation liability claims. TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2021 and 2020 ranged from 1.63 % to 4.00 % and 2.43 % to 4.00 %, respectively. Derivatives and Hedging Activities On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which included a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022. On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric related to its 2021 rate case that extended the moratorium to December 31, 2024 (see Note 3 for further information on the settlement agreements). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had zero derivative liabilities related to natural gas storage optimization as of December 31, 2021 and 2020 and zero derivative assets on its Consolidated Balance Sheets as of December 31, 2021 and 2020. TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2021 and 2020, all of TEC’s physical contracts qualified for the NPNS exception, which was elected. TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Changes And Error Corrections [Abstract] | |
New Accounting Pronouncements | 2. New Accounting Pronouncements TEC considers the applicability and impact of all ASUs issued by the FASB. TEC was not required to and did not adopt any new ASUs in 2021. |
Regulatory
Regulatory | 12 Months Ended |
Dec. 31, 2021 | |
Regulated Operations [Abstract] | |
Regulatory | 3. Regulatory Tampa Electric’s retail business and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. The FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirements) equal to their prudently incurred cost of providing service or products, plus a reasonable return on equity invested or assets. As a result, Tampa Electric and PGS qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between U.S. GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred. In addition to regulatory assets and regulatory liabilities, rate regulation impacts other financial statement balances and activity, including, but not limited to, property, plant, and equipment, revenues, and expenses. Tampa Electric Base Rates Tampa Electric’s results for 2021, 2020 and 2019 reflected an amended and restated settlement agreement, approved by the FPSC on November 6, 2017 , that replaced the previous 2013 base rate settlement agreement and extended it another four years through 2021 . The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25 % with a range of plus or minus 1 % . The agreement stated that Tampa Electric could not file for additional base rate increases to be effective sooner than December 31, 2021, unless its earned ROE were to fall below 9.25 % before that time. If its earned ROE were to rise above 11.25 %, any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure was 54 % from investor sources of capital. The amended agreement provided for SoBRAs for Tampa Electric’s substantial investments in solar generation. Tampa Electric invested approximately $ 850 million in these solar projects during 2017 to 2021 and accrued AFUDC during construction. The agreement included a sharing provision that allowed customers to benefit from 75 % of any cost savings for projects below $ 1,500 /kWac. Between 2017 and 2021, TEC filed annual SoBRA petitions along with supporting tariffs demonstrating the cost-effectiveness of four tranches representing 600 MW and $ 104 million in estimated revenue requirements. The FPSC approved the tariffs on each of the SoBRA filings and Tampa Electric began receiving the applicable revenues after each of the tranches was commercially completed (tranche 1 for $ 24 million in revenue starting September 2018, tranche 2 for $ 46 million in revenue starting January 2019, tranche 3 for $ 26 million in revenue starting January 2020 and tranche 4 for $ 8 million in revenue starting January 2021). The true-up filing for SoBRA tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. The $ 5 million true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was approved by the FPSC on October 12, 2021. A $ 4 million true-up was returned to customers during 2021. The true-up for SoBRA tranche 4 will be filed in early 2022. The 2017 settlement agreement further contained a provision related to tax reform. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are achieved is also included. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make no investments in gas reserves. On November 13, 2019, as required by the 2017 settlement agreement, Tampa Electric filed its petition to reduce base rates and charges to reflect the impact of the temporary reduction of the state corporate income tax from 5.5 % to 4.5 %. The tax rate reduction was issued on September 12, 2019 and was effective retroactive from January 1, 2019 through December 31, 2021. The estimated base rate reduction due to customers of $ 5 million is subject to true-up, and the actual rate reduction may vary from year to year. The base rate reduction was approved on December 10, 2019 for rates effective January 2020. On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 (the Settlement Agreement) by and among Tampa Electric and the intervenors in Tampa Electric’s rate case filed with the FPSC in April 2021. The Settlement Agreement agrees to an increase in base rates annually effective with January 2022 bills, to generate a $ 191 million increase in revenue consisting of $ 123 million of traditional base rate charges and $ 68 million in a new charge to recover the costs of retiring assets. The Settlement Agreement further includes two subsequent year adjustments of $ 90 million and $ 21 million, effective January 2023 and January 2024, respectively. Under the agreement, the allowed equity in the capital structure will continue to be 54 % from investor sources of capital. The Settlement Agreement includes an allowed regulatory ROE range of 9.0 % to 11.0 % with a 9.95 % midpoint. The Settlement Agreement allows a 25 basis point increase in the allowed ROE range and mid-point, and $ 10 million of additional revenue, if the average 30 -year United States Treasury Bond yield rate for any period of six consecutive months is at least 50 basis points greater than the yield rate on the date the FPSC votes to approve the agreement. Under the agreement, base rates will no t change from January 1, 2022 through December 31, 2024 , unless Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby Tampa Electric agrees to quantify the future impact of a decrease or increase in corporate income tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of that agreement. The Settlement Agreement sets new depreciation and dismantlement rates effective January 1, 2022 and contains the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2024. On October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting such approval, was issued on November 10, 2021. Tampa Electric Big Bend Modernization Project Tampa Elect ric expects to invest approximately $ 850 million during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $ 695 million h as been invested through December 31, 2021. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the Big Bend modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of customers from economic, environmental risk and operational perspectives. At December 31, 2020, Tampa Electric’s balance sheet included $ 636 million in electric utility plant and $ 267 million in accumulated d epreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric continued to account for its investment in Units 1, 2 and 3 in electric utility plant and depreciate the assets using the current depreciation rates until December 31, 2021, at which point they were reclassified to a regulatory asset on the balance sheet. Tampa Electric’s Settlement Agreement provides recovery for the Big Bend modernization project in two phases. The first phase is a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. The Settlement Agreement also includes a new charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread over 15 years and will survive the term of the Settlement Agreement. The special capital recovery schedule for all three units was applied beginning January 1, 2022. Tampa Electric Mid-Course Adjustment to Fuel Recovery In July 2021, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover $ 83 million of additional costs during the months of September through December 2021. In January 2022, Tampa Electric requested a mid-course adjustment t o its fuel and capacity charges to recover an additional $ 169 million, effective with April 2022 customer bills, due to an increase in fuel commodity and capacity cos ts. The FPSC is expected to issue its decision in March 2022. Tampa Electric Storm Protection Cost Recovery Clause and Settlement Agreement On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $ 15 million base rate reduction for SPP program costs previously recovered in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $ 39 million in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $ 15 million of costs removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in April 2022 to determine cost recovery in 2023, 2024, and 2025. The June 9, 2020 settlement agreement approved by the FPSC disclosed above also included approval of Tampa Electric’s petition to eliminate its $ 16 million accumulated amortization reserve surplus for intangible software assets through a credit to depreciation and amortization expense in 2020. Tampa Electric Storm Restoration Cost Recovery As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12 -month period or longer as determined by the FPSC, as well as replenish its reserve to $ 56 million, the level of the reserve as of October 31, 2013. This provision was also included in Tampa Electric’s subsequent 2017 amended and restated settlement agreement and in Tampa Electric’s 2021 rate case settlement agreement. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $ 102 million, of which $ 90 million was charged to the storm reserve, $3 million was charged to O&M expense and $ 9 million was charged to capital expenditures. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated Hurricane Irma storm costs plus approximately $ 10 million in restoration costs from prior named storms and to replenish the balance in the reserve to the $ 56 million level that existed as of October 31, 2013. On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $ 12 million to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income. In 2021, 2020 and 2019, Tampa Electric incurred total storm restoration preparation costs for multiple hurricanes of approximately $ 10 million, which was charged to the storm reserve regulatory liability. PGS Base Rates PGS’s base rates for 2021 were established in 2020, and its base rates for 2020 and 2019 were originally established in May 2009. On February 7, 2017, the FPSC approved a settlement agreement filed by PGS and the OPC in which PGS agreed to adopt new depreciation rates, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and establish an ROE range of 9.25 % to 11.75 %. The settlement agreement provided that the bottom of the range would remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020 and the ROE of 10.75 % would continue to be used for the calculation of return on investment for clauses and riders. The allowed equity in its capital structure was 54.7 % from all investor sources of capital. As part of the 2017 settlement, PGS and the OPC agreed that at least $ 32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, would be amortized over the period 2016 through 2020 . In 2018, the FPSC approved a settlement agreement authorizing PGS to accelerate in 2018 the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability of $ 11 million to net it against the estimated 2018 tax reform benefits. In January 2019, PGS reduced its base rates by $ 12 million for the impact of tax reform and reduced depreciation rates by $ 10 million in accordance with the settlement agreement. On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS and OPC. The settlement agreement provides for an increase in base rates by $ 58 million annually effective January 2021, which is a $ 34 million increase in revenue and $ 24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90 % to 11.00 % with a 9.90 % midpoint , including the ability to reverse a total of $ 34 million of accumulated depreciation through 2023. PGS has not reversed any of this accumulated depreciation to date. In addition, the agreement sets new depreciation rates effective January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023 , unless its earned ROE were to fall below 8.90 % before that time with an allowed equity in the capital structure of 54.7 % from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024. Regulatory Assets and Liabilities Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2021 2020 Regulatory assets: Regulatory tax asset (1) $ 117 $ 90 Cost-recovery clauses (2) 89 38 Capital cost recovery for early retired assets (3) 518 0 Environmental remediation (4) 22 22 Postretirement benefits (5) 230 309 Asset retirement obligation (6) 11 13 Other 15 13 Total regulatory assets 1,002 485 Less: Current portion 136 79 Long-term regulatory assets $ 866 $ 406 Regulatory liabilities: Regulatory tax liability (7) $ 638 $ 691 Cost-recovery clauses - deferred balances (2) 16 23 Accumulated reserve—cost of removal (8) 468 498 Storm reserve (9) 46 48 Other 2 1 Total regulatory liabilities 1,170 1,261 Less: Current portion 78 67 Long-term regulatory liabilities $ 1,092 $ 1,194 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal corporate income tax rate reduction. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in a subsequent period. (3) This regulatory asset is related to the remaining net book value of Big Bend Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years . See “Tampa Electric Big Bend Modernization Project” above for further information. (4) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. (5) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC. (6) This asset is related to costs associated with an asset retirement obligation, which is a legal obligation for the future retirement of certain tangible, long-lived assets. This regulatory asset does not earn a return because it is offset with related assets and liabilities within rate base. It is recovered and removed as the obligation is settled and removed as the activities for the retirement of the related assets have been completed. (7) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower corporate income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC. (8) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (9) See “Tampa Electric Storm Restoration Cost Recovery” discussion above for information regarding this reserve. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 4. Income Taxes CARES Act On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (CARES) Act was signed into law. The CARES Act includes several business provisions including deferral in employer payroll taxes and an employee retention payroll tax credit. On December 27, 2020, the Consolidated Appropriations Act, 2021 (the 2021 Act) was signed into law. The 2021 Act provides for modifications and expansion of the employee retention payroll tax credit enacted under the CARES Act. The 2021 Act also extends the solar ITC for two years. These laws did not have a material impact on TEC’s financial statements. Employee Retention Payroll Tax Credit On March 11, 2021, the American Rescue Plan Act of 2021 was signed into law. This law included an extension of the employee retention payroll tax credit through December 31, 2021. On November 15, 2021, the Infrastructure Investment and Jobs Act, which provides for termination of the employee retention payroll tax credit as of September 30, 2021, was signed into law. These laws did not have a material impact on TEC’s financial statements. Change in Florida Corporate Income Tax Rate On September 14, 2021, the state of Florida issued a corporate tax rate reduction from 4.46 % to 3.53 % effective January 1, 2021 through December 31, 2021. In 2021, TEC recorded a $ 4 million regulatory liability in recognition of its obligation to pass the tax rate reduction expense benefit to customers per the 2017 settlement agreement. Income Tax Expense TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements of TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution. In 2021, 2020 and 2019, TEC recorded net tax provisions of $ 80 million, $ 82 million and $ 77 million, respectively. Income tax expense consists of the following components: Income Tax Expense (Benefit) (millions) For the year ended December 31, 2021 2020 2019 Current income taxes Federal $ 48 $ 35 $ 56 State 4 ( 7 ) 6 Deferred income taxes Federal 24 32 7 State 13 29 13 Investment tax credits amortization ( 9 ) ( 7 ) ( 5 ) Total income tax expense $ 80 $ 82 $ 77 For the three years presented, the overall effective tax rate differs from the U.S. federal statutory rate as presented below: Effective Income Tax Rate (millions) For the year ended December 31, 2021 2020 2019 Income before provision for income taxes $ 526 $ 506 $ 447 Federal statutory income tax rates 21 % 21 % 21 % Income taxes, at statutory income tax rate 110 106 94 Increase (decrease) due to State income tax, net of federal income tax 13 17 15 Excess deferred tax amortization ( 26 ) ( 26 ) ( 25 ) ITC amortization ( 9 ) ( 7 ) ( 5 ) AFUDC-equity ( 9 ) ( 6 ) ( 2 ) Tax credits ( 3 ) ( 8 ) ( 1 ) Other 4 6 1 Total income tax expense on consolidated statements of income $ 80 $ 82 $ 77 Income tax expense as a percent of income before income taxes 15.2 % 16.2 % 17.2 % Deferred Income Taxes Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows: (millions) As of December 31, 2021 2020 Deferred tax liabilities (1) Property related $ 1,210 $ 1,121 Pension and postretirement benefits 98 116 Total deferred tax liabilities 1,308 1,237 Deferred tax assets (1) Loss and credit carryforwards (2) 340 301 Medical benefits 26 27 Insurance reserves 15 16 Pension and postretirement benefits 46 66 Capitalized energy conservation assistance costs 20 18 Other 3 26 Total deferred tax assets 450 454 Total deferred tax liability, net $ 858 $ 783 (1) Certain property related assets and liabilities have been netted. (2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $ 6 million and $ 9 million at December 31, 2021 and 2020, respectively. At December 31, 2021, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $ 312 million and $ 83 million, respectively, expiring between 2032 and 2037 . TEC has unused general business credits of $ 286 million expiring between 2027 and 2041 , of which $ 264 million relate to ITCs expiring between 2034 and 2041 . As a result of TECO Energy's merger with Emera in 2016, TECs NOLs and credits will be utilized by EUSHI, in accordance with the benefits-for-loss allocation which provide that tax attributes are utilized by the consolidated tax return group of EUSHI. Unrecognized Tax Benefits TEC accounts for uncertain tax positions as required by U.S. GAAP. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes. The following table provides details of the change in unrecognized tax benefits as follows: (millions) 2021 2020 2019 Balance at January 1, $ 9 $ 9 $ 8 Decreases due to tax positions related to prior year 0 ( 2 ) 0 Increases due to tax positions related to prior year 1 1 1 Increases due to tax positions related to current year 1 1 0 Decreases due to settlements with tax authorities ( 5 ) 0 0 Balance at December 31, $ 6 $ 9 $ 9 As of December 31, 2021 and 2020, TEC’s uncertain tax positions for federal R&D tax credits were $ 6 million and $ 9 million, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC’s unrecognized federal tax benefits decreased in 2021 and 2020 by approximately $ 5 million and $ 2 million, respectively, due to the resolution of its 2016 federal tax credits issue with IRS Appeals. The recognition of the 2020 tax benefits decreased the effective tax rate resulting in an income tax benefit of approximately $ 2 million in 2020. The settlement of the federal R&D credits audit did no t impact the effective tax rate during 2021. TEC had $ 6 million and $ 9 million of unrecognized tax benefits at December 31, 2021 and 2020, respectively, that, if recognized, would reduce TEC’s effective tax rate. TEC recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance expense” in the Consolidated Statements of Income. In 2021, 2020 and 2019, TEC did no t recognize any pre-tax charges (benefits) for interest. Additionally, TEC did no t have any accrued interest or amounts recorded for penalties at December 31, 2021, 2020 and 2019. The IRS concluded the Compliance Assurance Program (CAP) audit for the short tax year ending June 30, 2016 and the EUSHI 2016 federal consolidated tax return, which includes TEC's short tax year ending December 31, 2016. The U.S. federal statute of limitations remains open for the year 2017 and forward. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. |
Employee Postretirement Benefit
Employee Postretirement Benefits | 12 Months Ended |
Dec. 31, 2021 | |
Compensation And Retirement Disclosure [Abstract] | |
Employee Postretirement Benefits | 5. Employee Postretirement Benefits Pension Benefits TEC is a participant in the comprehensive retirement plans of TECO Energy, including a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans. Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP and the unfunded obligations of the Restoration Plan. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. The Restoration Plan is a non-qualified, non-contributory defined benefit retirement plan that allows certain members of senior management to receive contributions as if no IRS limits were in place. Effective October 21, 2019, the defined benefit retirement plan was amended to freeze further crediting of service and earnings for certain participants covered by the International Brotherhood of Electrical Workers (the IBEW) collective bargaining agreement. As of December 31, 2019, 24 % of TEC’s employees were represented by the IBEW. As a result, a curtailment and a remeasurement of the plan occurred in the fourth quarter of 2019. See curtailment-related line items in tables below. As the result of the reorganization of shared services functions, certain employees and their associated pension benefits were transferred from TSI to TEC effective December 2019. Deferred costs related to pension benefits that were recognized by TSI in AOCI are now recognized in TEC as regulatory assets. The balances at December 31, 2021, 2020 and 2019 are reflective of this transfer. Other Postretirement Benefits TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (other benefits) for most employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time. As the result of a reorganization of shared services functions, certain employees and their associated other postretirement benefits were transferred from TSI to TEC effective December 2019. Deferred costs related to other postretirement benefits that were recognized by TSI in AOCI are now recognized in TEC as regulatory assets. The balances at December 31, 2021 and 2020 are reflective of this transfer. Obligations and Funded Status TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted. The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and TECO Energy’s Florida-based other postretirement benefit plan (other benefits). TECO Energy Pension Benefits Other Benefits (2) Obligations and Funded Status (millions) 2021 2020 2021 2020 Change in benefit obligation Benefit obligation at beginning of year $ 919 $ 843 $ 212 $ 180 Service cost 19 20 2 2 Interest cost 21 26 5 6 Plan participants’ contributions 0 0 4 4 Benefits paid ( 77 ) ( 54 ) ( 17 ) ( 17 ) Actuarial (gain) loss ( 32 ) 84 ( 6 ) 37 Benefit obligation at end of year $ 850 $ 919 $ 200 $ 212 Change in plan assets Fair value of plan assets at beginning of year $ 903 $ 796 $ 0 $ 0 Actual return on plan assets 76 142 0 0 Employer contributions 21 19 0 0 Employer direct benefit payments 1 1 13 13 Plan participants’ contributions 0 0 4 4 Benefits paid ( 76 ) ( 54 ) 0 0 Direct benefit payments ( 1 ) ( 1 ) ( 17 ) ( 17 ) Fair value of plan assets at end of year (1) $ 924 $ 903 $ 0 $ 0 (1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years . (2) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. Decreases in the benefit obligation for the period ended December 31, 2021 are the result of increases in the discount rate used to calculate the benefit obligation, incorporation of new census data as of January 1, 2021 and the updating of the retirement rate as the result of an experience study performed during the year. At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with projected benefit obligations and accumulated projected benefit obligations in excess of plan assets was as follows: TECO Energy Pension Benefits Other Benefits (1) Funded Status (millions) 2021 2020 2021 2020 Benefit obligation (PBO/APBO) $ 850 $ 919 $ 200 $ 212 Less: Fair value of plan assets 924 903 0 0 Funded status at end of year $ 74 $ ( 16 ) $ ( 200 ) $ ( 212 ) (1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $ 819 million at December 31, 2021 and $ 876 million at December 31, 2020. The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations and plan assets at December 31 were as follows: TEC Pension Benefits Other Benefits Amounts recognized in balance sheet (millions) 2021 2020 2021 2020 Noncurrent assets $ 78 $ 0 $ 0 $ 0 Accrued benefit costs and other current liabilities ( 3 ) ( 1 ) ( 12 ) ( 12 ) Deferred credits and other liabilities ( 12 ) ( 15 ) ( 175 ) ( 186 ) $ 63 $ ( 16 ) $ ( 187 ) $ ( 198 ) Unrecognized gains and losses and prior service credits and costs are recorded in regulatory assets for TEC. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs. TEC Pension Benefits Other Benefits Amounts recognized in regulatory assets (millions) 2021 2020 2021 2020 Net actuarial loss (gain) $ 150 $ 221 $ 79 $ 88 Amount recognized $ 150 $ 221 $ 79 $ 88 Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2021 2020 2021 2020 Discount rate 2.77 % 2.37 % 2.84 % 2.47 % Rate of compensation increase 3.05 % 3.07 % 3.04 % 3.07 % Healthcare cost trend rate Immediate rate n/a n/a 5.61 % 5.74 % Ultimate rate n/a n/a 4.00 % 4.50 % Year rate reaches ultimate trend rate n/a n/a 2045 2038 The discount rate assumption used to determine the December 31, 2021 and 2020 benefit obligation was based on a cash flow matching technique that matches yields from high-quality (AA-rated, non-callable) corporate bonds to TECO Energy’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption. Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets TECO Energy Pension Benefits Other Benefits (1) 2021 2020 2019 2021 2020 2019 (millions) Service cost $ 19 $ 20 $ 20 $ 2 $ 2 $ 1 Interest cost 21 26 31 5 6 7 Expected return on plan assets ( 52 ) ( 50 ) ( 51 ) 0 0 0 Amortization of: Actuarial loss 24 20 16 4 1 1 Prior service (benefit) cost 0 0 0 ( 2 ) ( 3 ) ( 2 ) Settlement loss 0 0 1 (2) 0 0 0 Net periodic benefit cost $ 12 $ 16 $ 17 $ 9 $ 6 $ 7 Net loss (gain) arising during the year (includes curtailment gain) $ ( 56 ) $ ( 8 ) $ ( 17 ) $ ( 5 ) $ 38 $ 9 Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service credit 0 0 0 2 2 2 Amortization or settlement of actuarial loss ( 23 ) ( 20 ) ( 17 ) ( 4 ) ( 1 ) ( 1 ) Total recognized in OCI and regulatory assets $ ( 79 ) $ ( 28 ) $ ( 34 ) $ ( 7 ) $ 39 $ 10 Total recognized in net periodic benefit cost, OCI and regulatory assets $ ( 67 ) $ ( 12 ) $ ( 17 ) $ 2 $ 45 $ 17 (1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan (2) Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements. TEC’s portion of the net periodic benefit costs for pension benefits was $ 10 million, $ 12 million and $ 12 million for 2021, 2020 and 2019, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $ 11 million, $ 7 million and $ 7 million for 2021, 2020 and 2019, respectively. TEC’s portion of net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Statements of Income in “Operations & maintenance”. Assumptions used to determine net periodic benefit cost for years ended December 31: Pension Benefits Other Benefits 2021 2020 2019 2021 2020 2019 Discount rate 2.37 % 3.21 % 4.33 % 2.47 % 3.32 % 4.38 % Expected long-term return on plan assets 6.70 % 7.00 % 7.35 %/ 7.00 % (1) n/a n/a n/a Rate of compensation increase 3.08 % 3.79 % 3.75 % 3.07 % 3.79 % 3.75 % Healthcare cost trend rate Initial rate n/a n/a n/a 5.74 % 6.03 % 6.31 % Ultimate rate n/a n/a n/a 4.50 % 4.50 % 4.50 % Year rate reaches ultimate trend rate n/a n/a n/a 2038 2038 2038 (1) The expected return on assets was 7.35 % as of January 1, 2019 and 7.00 % as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment. The discount rate assumption used to determine the benefit cost for 2021, 2020 and 2019 was based on the same technique that was used to determine the December 31, 2021 and 2020 benefit obligation as discussed above. The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended December 31, 2021, TECO Energy’s pension plan’s actual earned returns were approximately 9 %. The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. Pension Plan Assets Pension plan assets (plan assets) are invested in a mix of equity and fixed-income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses. TECO Energy 2021 2020 Actual Allocation, End of Year Asset Category 2021 2020 Equity securities 50 %- 70 % 50 %- 70 % 59 % 60 % Fixed income securities 30 %- 50 % 30 %- 50 % 41 % 40 % Total 100 % 100 % 100 % 100 % TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy expects to take additional steps to more closely match plan assets with plan liabilities over the long term. The plan’s investments are held by a trust fund administered by The Bank of New York Mellon. Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value. If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable. As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments. Pension Plan Investments TECO Energy At Fair Value as of December 31, 2021 (millions) Level 1 Level 2 Level 3 Using NAV (1) Total Cash $ 4 $ 0 $ 0 $ 0 $ 4 Accounts receivable 4 0 0 0 4 Accounts payable ( 70 ) 0 0 0 ( 70 ) Short-term investment funds (STIFs) 31 0 0 0 31 Common stocks 46 0 0 0 46 Real estate investment trusts (REITs) 6 0 0 0 6 Mutual funds 68 0 0 0 68 Municipal bonds 0 1 0 0 1 Government bonds 0 81 0 0 81 Corporate bonds 0 78 0 0 78 Mortgage backed securities (MBS) 0 1 0 0 1 Collateralized mortgage obligations (CMOs) 0 1 0 0 1 Short Sales 0 ( 2 ) 0 0 ( 2 ) Long Futures 1 0 0 0 1 Swaps 0 1 0 0 1 Investments not utilizing the practical expedient 90 161 0 0 251 Common and collective trusts (1) 0 0 0 592 592 Mutual fund (1) 0 0 0 81 81 Total investments $ 90 $ 161 $ 0 $ 673 $ 924 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet of TECO Energy. TECO Energy At Fair Value as of December 31, 2020 (millions) Level 1 Level 2 Level 3 Using NAV (1) Total Cash $ 9 $ 0 $ 0 $ 0 $ 9 Accounts receivable 10 0 0 0 10 Accounts payable ( 88 ) 0 0 0 ( 88 ) Short-term investment funds (STIFs) 35 0 0 0 35 Common stocks 66 0 0 0 66 Real estate investment trusts (REITs) 8 0 0 0 8 Mutual funds 69 0 0 0 69 Municipal bonds 0 1 0 0 1 Government bonds 0 90 0 0 90 Corporate bonds 0 79 0 0 79 Mortgage backed securities (MBS) 0 1 0 0 1 Collateralized mortgage obligations (CMOs) 0 1 0 0 1 Short Sales 0 ( 4 ) 0 0 ( 4 ) Long Futures ( 2 ) 0 0 0 ( 2 ) Swaps 0 1 0 0 1 Investments not utilizing the practical expedient 107 169 0 0 276 Common and collective trusts (1) 0 0 0 553 553 Mutual fund (1) 0 0 0 74 74 Total investments $ 107 $ 169 $ 0 $ 627 $ 903 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet of TECO Energy. The following list details the pricing inputs and methodologies used to value the investments in the pension plan: • Cash collateral is valued at cash posted due to its short-term nature. • The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset. • The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets. • The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-end mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets. • The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. • Swaps are valued using benchmark yields, swap curves, and cash flow analyses. • The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-end mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is an open-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. The redemption frequency is daily. The redemption notice period is the same day. There were no unfunded commitments as of December 31, 2021. • The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days. There were no unfunded commitments as of December 31, 2021. • Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities. • Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. Additionally, the non-qualified SERP had $ 10 million and $ 10 million of assets as of December 31, 2021 and 2020, respectively. Since the plan is non-qualified, its assets are included in the “Deferred charges and other assets” line item in the Consolidated Balance Sheets rather than being netted with the related liability. The non-qualified trust holds investments in a money market fund. The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make it a level 1 asset. The SERP was fully funded as of December 31, 2021 and 2020. Other Postretirement Benefit Plan Assets There are no assets associated with TECO Energy’s Florida-based other postretirement benefits plan. Contributions The qualified pension plan’s actuarial value of assets, including credit balance, was 122.19 % of the Pension Protection Act funded target as of January 1, 2021 and is estimated at 133.60 % of the Pension Protection Act funded target as of January 1, 2022. TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TEC’s contribution is first set equal to its service cost. If a contribution in excess of service cost for the year is made, TEC’s portion is based on TEC’s proportion of the TECO Energy unfunded liability. TECO Energy made contributions to this plan in 2021, 2020 and 2019, which met the minimum funding requirements for 2021, 2020 and 2019. TEC’s portion of the contribution in 2021 was $ 17 million and in 2020 was $ 16 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2022 contribution to be $ 15 million. The amount TECO Energy expects to contribute is in excess of the minimum funding required under ERISA guidelines. TEC’s portion of the contributions to the SERP in 2021, 2020 and 2019 was zero . Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2022. TEC made SERP payments of approximately $ 1 million, $ 1 million and $ 5 million from the trust in 2021, 2020 and 2019, respectively, and expects to make a SERP payment of approximately $ 1 million from the trust in 2022. The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between January 1, 1990 and June 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2022, TEC expects to make a contribution of about $ 12 million. Postretirement benefit levels are substantially unrelated to salary. Benefit Payments The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Expected Benefit Payments TECO Energy Other (including projected service and net of employee contributions) Pension Postretirement Benefits Benefits (millions) 2022 $ 69 $ 13 2023 72 14 2024 69 14 2025 68 14 2026 66 13 2027-2031 302 61 Defined Contribution Plan TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match 75 % of the first 6 % of the participant’s payroll savings deductions. Effective January 1, 2017, the employer matching contributions increased from 70 % to 75 % with an additional incentive match of up to 25 % of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended December 31, 2021, 2020 and 2019, TEC’s portion of expense totaled $ 22 million, $ 21 million and $ 11 million, respectively, related to the matching contributions made to this plan. TEC’s portion of the expense related to the matching contribution is included on the Consolidated Statements of Income in “Operations & maintenance”. Effective October 21, 2019, TECO Energy amended the defined contribution plan such that certain participants covered by the IBEW collective bargaining agreement shall not be eligible to participate in the plan for purposes of receiving the fixed matching contribution. This has been replaced with a non-elective employer contribution on a bi-weekly basis equal to a percentage of the member’s compensation for that period based on years of tenure of employment. For the years ended December 31, 2021, 2020 and 2019, TEC recognized expense totaling $ 10 million, $ 9 million and $ 1 million, respectively, related to the contributions made to this plan. TEC’s portion of the expense related to this contribution is included on the Consolidated Statements of Income in “Operations & maintenance”. |
Short-Term Debt
Short-Term Debt | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Short-Term Debt | 6. Short-Term Debt Credit Facilities December 31, 2021 December 31, 2020 Borrowings Borrowings Letters Letters Credit Outstanding - Outstanding - of Credit Credit Borrowings of Credit (millions) Facilities Credit Facilities (1) Commercial Paper (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 800 $ 0 $ 245 $ 1 $ 800 $ 345 $ 1 3-year accounts receivable facility (3) 0 0 0 0 150 130 0 1-year term facility (4) 500 500 0 0 300 300 0 Total $ 1,300 $ 500 $ 245 $ 1 $ 1,250 $ 775 $ 1 (1) Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets. (2) This 5-year facility matures on December 17, 2026 . TEC also has an active commercial paper program for up to $ 800 million, of which the full amount outstanding is backed by TEC’s credit facility. The amount of commercial paper issued results in an equal amount of its credit facility being considered drawn and unavailable. (3) This 3-year facility matured on March 22, 2021 . (4) This 1-year term facility was terminated on March 23, 2021 . On December 17, 2021, TEC entered into another 1-year term facility that matures on December 16, 2022 . At December 31, 2021, this credit facility required a commitment fee of 12.5 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities and commercial paper at December 31, 2021 and 2020 was 0.58 % and 0.89 %, respectively. Commercial Paper Program On May 25, 2021, TEC established a commercial paper program (the Program) under which TEC may issue on a private placement basis unsecured commercial paper notes (the Notes). Amounts available under the Program may be borrowed, repaid and reborrowed with the aggregate amount of the Notes outstanding under the Program at any time not to exceed $ 800 million. The maturities of the Notes will vary, but may not exceed 270 days from the date of issue. The rates of interest will depend on whether the Note will be a fixed or floating rate. TEC must have credit facilities in place, at least equal to the amount of its commercial paper program. TEC cannot issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. TEC Term Loan On February 6, 2020, TEC entered into a 364-day , $ 300 million credit agreement with a group of banks. On January 29, 2021, TEC extended the maturity date of the agreement to April 29, 2021 . On March 23, 2021 , this loan was repaid and terminated. On December 17, 2021, TEC entered into a 364-day , $ 500 million credit agreement with a group of banks. The credit agreement has a maturity date of D ecember 16, 2022 ; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. Accounts Receivable Facility On July 14, 2020 and October 30, 2020 , TEC amended its $ 150 million accounts receivable collateralized borrowing facility (Loan Agreement) in order to change certain performance ratios. On March 22, 2021, this agreement matured and terminated. 5-Year Credit Facility On December 18, 2020, TEC amended and restated its bank credit facility, entering into a Sixth Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2022 to March 22, 2023 (subject to further extension with the consent of each lender); increased the amount of the commitment by the lenders to $ 800 million; and provided for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $ 100 million in the aggregate; and made other technical changes. On December 17, 2021, TEC amended and restated its bank credit facility, entering into a Seventh Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2023 to December 17, 2026 (subject to further extension with the consent of each lend er); and provided for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $ 100 million in the aggregate; and made other technical changes. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 7. Long-Term Debt A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Tampa Electric Company 2.40% Notes due 2031 and 3.45% Notes due 2051 On March 18, 2021 , TEC completed a sale of (i) $ 400 million aggregate principal amount of 2.40 % Notes due March 15, 2031 (the 2031 Notes) and (ii) $ 400 million aggregate principal amount of 3.45 % Notes due March 15, 2051 (the 2051 Notes, and collectively, the Notes). Until December 15, 2030, in the case of the 2031 Notes, or September 15, 2050, in the case of the 2051 Notes, TEC may redeem all or any part of such series of Notes at its op tion at a redemption price equal to the greater of (i) 100 % of the principal amount of such series of Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the Notes to be redeemed that would be due if the Notes matured on (a) December 15, 2030, in the case of the 2031 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate (as defined in the Indenture), plus 15 basis points, or (b) September 15, 2050, in the case of the 2051 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2030 , in the case of the 2031 Notes or September 15, 2050 , in the case of the 2051 Notes, TEC may, at its option, redeem such series of the Notes, in whole or in part, at 100 % of the principal amount of such series of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2021 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 8. Commitments and Contingencies Legal Contingencies From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 2021 and 2020, TEC has estimated its ultimate financial liability to be $ 14 million and $ 17 million, respectively, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. Long-Term Commitments TEC has commitments for various purchases as disclosed below, including payment obligations for capital projects, such as Tampa Electric’s solar projects (see Note 3 ) and the modernization of the Big Bend power station, and contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under minimum lease payments with non-cancelable lease terms in excess of one year and other net purchase obligations/commitments at December 31, 2021: Purchased Capital Fuel and Gas Long-term Service Operating Demand Side (millions) Power Transportation (1) Projects Supply Agreements Leases Management Total Year ended December 31: 2022 $ 2 $ 244 $ 202 $ 349 $ 20 $ 3 $ 2 $ 822 2023 0 224 63 27 42 3 1 360 2024 0 215 0 0 27 3 1 246 2025 0 200 0 0 19 2 0 221 2026 0 197 0 0 20 1 0 218 Thereafter 0 1,871 0 0 52 48 0 1,971 Total future minimum payments $ 2 $ 2,951 $ 265 $ 376 $ 180 $ 60 $ 4 $ 3,838 (1) As of December 31, 2021, $ 112 million is related to a gas transportation contract through 2040 between PGS and SeaCoast, a related party. Financial Covenants TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2021 and 2020, TEC was in compliance with all required financial covenants. |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2021 | |
Revenues [Abstract] | |
Revenue | 9. Revenue The following disaggregates TEC’s revenue by major source: (millions) Tampa Tampa Electric For the year ended December 31, 2021 Electric PGS Eliminations Company Electric revenue Residential $ 1,156 $ 0 $ 0 $ 1,156 Commercial 602 0 0 602 Industrial 172 0 0 172 Regulatory deferrals and unbilled revenue ( 8 ) 0 0 ( 8 ) Other (1) 252 0 ( 4 ) 248 Total electric revenue 2,174 0 ( 4 ) 2,170 Gas revenue Residential 0 212 0 212 Commercial 0 191 0 191 Industrial (2) 0 25 0 25 Other (3) 0 100 ( 3 ) 97 Total gas revenue 0 528 ( 3 ) 525 Total revenue $ 2,174 $ 528 $ ( 7 ) $ 2,695 For the year ended December 31, 2020 Electric revenue Residential $ 1,018 $ 0 $ 0 $ 1,018 Commercial 506 0 0 506 Industrial 133 0 0 133 Regulatory deferrals and unbilled revenue ( 25 ) 0 0 ( 25 ) Other (1) 217 0 ( 4 ) 213 Total electric revenue 1,849 0 ( 4 ) 1,845 Gas revenue Residential 0 158 0 158 Commercial 0 135 0 135 Industrial (2) 0 23 0 23 Other (3) 0 117 ( 6 ) 111 Total gas revenue 0 433 ( 6 ) 427 Total revenue $ 1,849 $ 433 $ ( 10 ) $ 2,272 For the year ended December 31, 2019 Electric revenue Residential $ 1,046 $ 0 $ 0 $ 1,046 Commercial 562 0 0 562 Industrial 156 0 0 156 Regulatory deferrals and unbilled revenue ( 49 ) 0 0 ( 49 ) Other (1) 250 0 ( 4 ) 246 Total electric revenue 1,965 0 ( 4 ) 1,961 Gas revenue Residential 0 154 0 154 Commercial 0 146 0 146 Industrial (2) 0 21 0 21 Other (3) 0 140 ( 18 ) 122 Total gas revenue 0 461 ( 18 ) 443 Total revenue $ 1,965 $ 461 $ ( 22 ) $ 2,404 (1) Other includes sales to public authorities, off-system sales to other utilities and various other items. (2) Industrial includes sales to power generation customers. (3) Other includes off-system sales to other utilities and various other items. Remaining Performance Obligations Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of December 31, 2021 and 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $ 135 million. This amount includes $ 112 million of future performance obligations related to a gas transportation contract between SeaCoast and PGS through 2040 . As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2041 . |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 10. Related Party Transactions A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2021 2020 2019 Natural gas sales to/(from) affiliates $ ( 236 ) $ ( 139 ) $ ( 111 ) Services received from affiliates 7 6 65 Dividends to TECO Energy 450 408 373 Equity contributions from TECO Energy 580 505 395 In 2019, services received from affiliates primarily included shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary. In December 2019, most TSI employees were transferred to Tampa Electric. The transfer of these employees to Tampa Electric did not materially impact shared service costs or the TEC Consolidated Statement of Income. In 2021 and 2020, the shared service costs were not recorded through TSI but rather directly recorded in TEC’s O&M expenses on the TEC Consolidated Statement of Income. Amounts due from or to affiliates at December 31, (millions) 2021 2020 Accounts receivable related to asset management agreements to Emera Energy Services Inc. (1) $ 4 $ 4 Accounts receivable excluding asset management agreements (1) 4 7 Accounts payable (1) 35 27 Taxes payable (2) 9 19 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2) Taxes payable were due to EUSHI. See Note 4 for additional information. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
Segment Information | 11. Segment Information Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. Management reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TEC but are included in determining reportable segments. TEC is a public utility operating within the State of Florida and has two segments, Tampa Electric and PGS. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 810,600 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 445,300 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 2021 Revenues - external $ 2,170 $ 525 $ 0 $ 2,695 Sales to affiliates 4 3 ( 7 ) 0 Total revenues 2,174 528 ( 7 ) 2,695 Depreciation and amortization 374 56 0 430 Total interest charges 110 20 0 130 Provision for income taxes 57 23 0 80 Net income 369 77 0 446 Total assets 10,650 2,209 ( 663 ) (1) 12,196 Capital expenditures 1,081 316 0 1,397 2020 Revenues - external $ 1,845 $ 427 $ 0 $ 2,272 Sales to affiliates 4 6 ( 10 ) 0 Total revenues 1,849 433 ( 10 ) 2,272 Depreciation and amortization 339 45 0 384 Total interest charges 113 17 0 130 Provision for income taxes 66 16 0 82 Net income 372 52 0 424 Total assets 9,800 1,901 ( 653 ) (1) 11,048 Capital expenditures 1,028 333 0 1,361 2019 Revenues - external $ 1,961 $ 443 $ 0 $ 2,404 Sales to affiliates 4 18 ( 22 ) 0 Total revenues 1,965 461 ( 22 ) 2,404 Depreciation and amortization 336 41 0 377 Total interest charges 117 17 0 134 Provision for income taxes 59 18 0 77 Net income 316 54 0 370 Total assets 9,007 1,593 ( 593 ) (1) 10,007 Capital expenditures 1,055 228 0 1,283 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 12. Asset Retirement Obligations TEC accounts for AROs at fair value at inception of the obligation if there is a legal obligation under applicable law, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. When the liability is initially recorded in “Deferred credits and other liabilities” in the Consolidated Balance Sheets, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The ARO estimates are reviewed quarterly. Any updates are revalued based on current market prices. Reconciliation of beginning and ending carrying amount of asset retirement obligations: December 31, (millions) 2021 2020 Beginning balance $ 39 $ 49 Additional liabilities 0 8 Liabilities settled (1) ( 9 ) ( 19 ) Other 1 1 Ending balance $ 31 $ 39 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The decrease in the ARO in 2021 and 2020 is due to the closure of CCR management facilities. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Leases | 13. Leases TEC determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating lease ROU assets and operating lease liabilities are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of TEC’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operations and maintenance expenses” on the Consolidated Statements of Income. Where TEC is the lessor, a lease is a sales-type lease if certain criteria is met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. TEC has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases in which TEC is the lessee. Lessee TEC has operating leases for buildings, land, telecommunication services and rail cars. TEC’s leases have remaining lease terms of 1 year to 64 years, some of which include options to extend the leases for up to an additional 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised. (millions) Classification December 31, 2021 December 31, 2020 Right-of-use asset Other deferred debits $ 24 $ 26 Lease liabilities Current Other current liabilities $ 2 $ 2 Long-term Deferred credits and other liabilities 23 25 Total lease liabilities $ 25 $ 27 TEC has recorded operating lease expense for the year ended December 31, 2021, 2020 and 2019 of $ 5 million, $ 4 million and $ 4 million, respectively. Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at December 31, 2021: (millions) Year ended December 31: 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments $ 3 $ 3 $ 3 $ 2 $ 1 $ 47 $ 59 Less imputed interest ( 34 ) Total future minimum payments $ 25 Additional information related to TEC’s leases is as follows: Year ended December 31, 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions) $ 4 $ 5 Weighted average remaining lease term (years) 44 43 Weighted average discount rate - operating leases 4.4 % 4.3 % Lessor TEC leases CNG stations to other companies, which are classified as direct finance leases. The net investment in direct finance leases consists of the following: (millions) December 31, 2021 December 31, 2020 Total minimum lease payments to be received $ 29 $ 31 Less amounts representing estimated executory costs ( 11 ) ( 12 ) Minimum lease payments receivable $ 18 $ 19 Less unearned finance lease income ( 9 ) ( 10 ) Net investment in direct finance and sales-type leases $ 9 $ 9 Principal due within one year (included in "Receivables") ( 2 ) ( 2 ) Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits") $ 7 $ 7 The unearned income related to these direct finance leases is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Gas revenues” on the Consolidated Statements of Income. Customers have the option to purchase the assets related to the CNG stations at any time after year five of the agreements, which was in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. This option was not exercised by any customer in 2021. Alternatively, the customer may take possession of the CNG station asset at the end of the lease term for no cost. As of December 31, 2021, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following: (millions) Year ended December 31: 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments to be received $ 2 $ 2 $ 2 $ 2 $ 2 $ 19 $ 29 Less executory costs ( 11 ) Total minimum lease payments receivable $ 18 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | . Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. There were no Level 3 assets or liabilities for the periods presented. As of December 31, 2021 and 2020, the fair value of TEC’s short-term debt was not materially different from the carrying value due to the short-term nature of the instruments and because the stated rates approximate market rates. The fair value of TEC’s short-term debt is determined using Level 2 measurements. See Note 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2021 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-Based Compensation | 15. Stock-Based Compensation Performance Share Unit Plan Emera has a performance share unit (PSU) plan. The PSU liability is marked-to-market at the end of each period based on an average common share price at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA. Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and are paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the Emera Management Resources and Compensation Committee (MRCC) early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. A summary of the activity related to TEC employee PSUs is presented in the following table: Weighted Aggregate Number of Average Grant Intrinsic Units Date Fair Value Value (Thousands) (Per Unit) (Millions) Outstanding as of December 31, 2020 390 46.87 21 Granted including DRIP 91 52.25 5 Exercised ( 175 ) 48.12 10 Forfeited ( 26 ) 47.82 1 Transferred 5 47.18 0 Outstanding as of December 31, 2021 285 47.74 18 Compensation cost recognized for the PSU plan for the years ended December 31, 2021, 2020 and 2019 was $ 3 million, $ 8 million and $ 8 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2021, 2020 and 2019 were $ 1 million, $ 2 million and $ 2 million, respectively. Cash payments made during the year ended December 31, 2021, 2020 and 2019 associated with the PSU plan were $ 10 million, $ 9 million and zero , respectively. As of December 31, 2021 and 2020, there was $ 3 million and $ 5 million, respectively, of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years . |
Long-Term PPAs
Long-Term PPAs | 12 Months Ended |
Dec. 31, 2021 | |
Contractors [Abstract] | |
Long-Term PPAs | 16. Long-Term PPAs In 2019, Tampa Electric entered into a long-term PPA with a wholesale energy provider in Florida with up to 515 MW of available capacity, which expires in 2022. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric reviewed these risks and determined that the owners of these entities retain the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric was not the primary beneficiary and was not required to consolidate any of these entities. Tampa Electric purchased $ 46 million, $ 36 million and $ 25 million under these long-term PPAs for the three years ended December 31, 2021, 2020 and 2019, respectively. TEC does not provide any material financial or other support to any of the variable interests it is involved with, nor is TEC under any obligation to absorb losses associated with these variable interests. Excluding the payments for energy under these contracts, TEC’s involvement with these variable interests does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows. |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts and Reserves | 12 Months Ended |
Dec. 31, 2021 | |
Valuation And Qualifying Accounts [Abstract] | |
Schedule II - Valuation and Qualifying Accounts and Reserves | SC HEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES TAMPA ELECTRIC COMPANY VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 2021, 2020 and 2019 (millions) Balance at Additions Balance at Beginning Charged to Other Payments & End of of Period Income Charges Deductions (1) Period Allowance for Credit Losses: 2021 $ 7 $ 8 $ 0 $ 8 $ 7 2020 $ 2 $ 9 $ 0 $ 4 $ 7 2019 $ 2 $ 5 $ 0 $ 5 $ 2 (1) Write-off of individual bad debt accounts |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Principles of Consolidation and Basis of Presentation | Principles of Consolidation and Basis of Presentation TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. TEC is a wholly owned subsidiary of TECO Energy, Inc. and contains electric and natural gas divisions. Intercompany balances and transactions within the divisions have been eliminated in consolidation. TECO Energy is a wholly owned indirect subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera. Since 2020, the outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of December 31, 2021 and 2020 and for the years then ended were not materially impacted by the COVID-19 pandemic. |
Cash Equivalents | Cash Equivalents Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred. As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation. The original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized. Property, plant and equipment consisted of the following assets: (millions) Estimated Useful Lives December 31, 2021 December 31, 2020 Electric generation 21 - 56 years $ 5,395 $ 5,694 Electric transmission 28 - 77 years 1,068 1,008 Electric distribution 14 - 56 years 3,064 2,859 Gas transmission and distribution 16 - 77 years 2,360 2,076 General plant and other 8 - 43 year s 946 723 Total cost 12,833 12,360 Less accumulated depreciation ( 3,601 ) ( 3,712 ) Construction work in progress 1,370 1,472 Total property, plant and equipment, net $ 10,602 $ 10,120 |
Depreciation | Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5 %, 3.2 % and 3.4 % for 2021, 2020 and 2019, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $ 408 million, $ 381 million and $ 359 million, respectively. See Note 3 for information regarding agreements approved by the FPSC that, among other things, allowed Tampa Electric to continue to depreciate certain retired assets through December 31, 2021 and allowed Tampa Electric to eliminate its $ 16 million accumulated depreciation and amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020. Tampa Electric and PGS compute depreciation and amortization using the following methods: • the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; • the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. |
Allowance for Funds Used During Construction | Allowance for Funds Used During Construction AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rates used to calculate AFUDC are revised periodically to reflect significant changes in cost of capital. In 2021, 2020 and 2019, Tampa Electric’s rate was 6.46 %. PGS’s rate used to calculate its AFUDC in 2021 and 2020 was 6.00 % and 5.97 %, respectively. Total AFUDC for the years ended December 31, 2021, 2020 and 2019 was $ 66 million, $ 44 million and $ 16 million, respectively. |
Inventory | Inventory TEC values materials, supplies and fossil fuel inventory (natural gas, coal and oil) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or net realizable value. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 ). |
Deferred Income Taxes | Deferred Income Taxes TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details. |
Investment Tax Credits | Investment Tax Credits ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property. |
Stranded Tax Effects in Accumulated Other Comprehensive Income | Stranded Tax Effects in Accumulated Other Comprehensive Income TEC utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released. |
Revenue Recognition | Revenue Recognition Regulated electric revenue Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. Tampa Electric’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWH delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, timing of meter reads and line losses. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. PGS’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes. Other See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue. |
Revenues and Cost Recovery | Revenues and Cost Recovery Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation, environmental and storm protection plan costs for Tampa Electric and purchased gas, interstate pipeline capacity, replacement of cast iron/bare steel pipe and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets. Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are recognized. |
Receivables and Allowance for Credit Losses | Receivables and Allowance for Credit Losses Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $ 252 million and $ 214 million as of December 31, 2021 and 2020, respectively. An allowance for credit losses is established based on TEC’s collection experience and reasonable and supportable forecasts that affect the collectibility of the reported amount. Circumstances that impact Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible. The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3 ). As of December 31, 2021 and 2020, unbilled revenues of $ 74 million and $ 73 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets. |
Accounting for Franchise Fees and Gross Receipts Taxes | Accounting for Franchise Fees and Gross Receipts Taxes Tampa Electric and PGS are allowed to recover certain costs incurred on a dollar-for-dollar basis from customers through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $ 129 million, $ 109 million and $ 117 million for the years ended December 31, 2021, 2020 and 2019, respectively. |
Deferred Charges and Other Assets | Deferred Charges and Other Assets Deferred charges and other assets consist primarily of pension assets net of accrued pension liabilities (see Note 5 ), right-of-use assets related to operating leases (see Note 13 ) and a contribution made by TEC in order to fully fund its SERP obligation (see Note 5 ). |
Deferred Credits and Other Liabilities | Deferred Credits and Other Liabilities Other deferred credits primarily include accrued other postretirement benefits (see Note 5 ), MGP environmental remediation liability (see Note 8 ), asset retirement obligations (see Note 12 ), lease liabilities (see Note 13 ) and a reserve for auto, general and workers’ compensation liability claims. TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2021 and 2020 ranged from 1.63 % to 4.00 % and 2.43 % to 4.00 %, respectively. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which included a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022. On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric related to its 2021 rate case that extended the moratorium to December 31, 2024 (see Note 3 for further information on the settlement agreements). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had zero derivative liabilities related to natural gas storage optimization as of December 31, 2021 and 2020 and zero derivative assets on its Consolidated Balance Sheets as of December 31, 2021 and 2020. TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2021 and 2020, all of TEC’s physical contracts qualified for the NPNS exception, which was elected. TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows. |
Significant Accounting Polici_3
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Schedule of Property, Plant and Equipment | Property, plant and equipment consisted of the following assets: (millions) Estimated Useful Lives December 31, 2021 December 31, 2020 Electric generation 21 - 56 years $ 5,395 $ 5,694 Electric transmission 28 - 77 years 1,068 1,008 Electric distribution 14 - 56 years 3,064 2,859 Gas transmission and distribution 16 - 77 years 2,360 2,076 General plant and other 8 - 43 year s 946 723 Total cost 12,833 12,360 Less accumulated depreciation ( 3,601 ) ( 3,712 ) Construction work in progress 1,370 1,472 Total property, plant and equipment, net $ 10,602 $ 10,120 |
Regulatory (Tables)
Regulatory (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets and Regulatory Liabilities | Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2021 2020 Regulatory assets: Regulatory tax asset (1) $ 117 $ 90 Cost-recovery clauses (2) 89 38 Capital cost recovery for early retired assets (3) 518 0 Environmental remediation (4) 22 22 Postretirement benefits (5) 230 309 Asset retirement obligation (6) 11 13 Other 15 13 Total regulatory assets 1,002 485 Less: Current portion 136 79 Long-term regulatory assets $ 866 $ 406 Regulatory liabilities: Regulatory tax liability (7) $ 638 $ 691 Cost-recovery clauses - deferred balances (2) 16 23 Accumulated reserve—cost of removal (8) 468 498 Storm reserve (9) 46 48 Other 2 1 Total regulatory liabilities 1,170 1,261 Less: Current portion 78 67 Long-term regulatory liabilities $ 1,092 $ 1,194 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal corporate income tax rate reduction. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in a subsequent period. (3) This regulatory asset is related to the remaining net book value of Big Bend Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years . See “Tampa Electric Big Bend Modernization Project” above for further information. (4) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. (5) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC. (6) This asset is related to costs associated with an asset retirement obligation, which is a legal obligation for the future retirement of certain tangible, long-lived assets. This regulatory asset does not earn a return because it is offset with related assets and liabilities within rate base. It is recovered and removed as the obligation is settled and removed as the activities for the retirement of the related assets have been completed. (7) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower corporate income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC. (8) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (9) See “Tampa Electric Storm Restoration Cost Recovery” discussion above for information regarding this reserve. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income Tax Expense | Income tax expense consists of the following components: (millions) For the year ended December 31, 2021 2020 2019 Current income taxes Federal $ 48 $ 35 $ 56 State 4 ( 7 ) 6 Deferred income taxes Federal 24 32 7 State 13 29 13 Investment tax credits amortization ( 9 ) ( 7 ) ( 5 ) Total income tax expense $ 80 $ 82 $ 77 |
Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes | For the three years presented, the overall effective tax rate differs from the U.S. federal statutory rate as presented below: (millions) For the year ended December 31, 2021 2020 2019 Income before provision for income taxes $ 526 $ 506 $ 447 Federal statutory income tax rates 21 % 21 % 21 % Income taxes, at statutory income tax rate 110 106 94 Increase (decrease) due to State income tax, net of federal income tax 13 17 15 Excess deferred tax amortization ( 26 ) ( 26 ) ( 25 ) ITC amortization ( 9 ) ( 7 ) ( 5 ) AFUDC-equity ( 9 ) ( 6 ) ( 2 ) Tax credits ( 3 ) ( 8 ) ( 1 ) Other 4 6 1 Total income tax expense on consolidated statements of income $ 80 $ 82 $ 77 Income tax expense as a percent of income before income taxes 15.2 % 16.2 % 17.2 % |
Schedule of Deferred Tax Assets and Liabilities | The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows: (millions) As of December 31, 2021 2020 Deferred tax liabilities (1) Property related $ 1,210 $ 1,121 Pension and postretirement benefits 98 116 Total deferred tax liabilities 1,308 1,237 Deferred tax assets (1) Loss and credit carryforwards (2) 340 301 Medical benefits 26 27 Insurance reserves 15 16 Pension and postretirement benefits 46 66 Capitalized energy conservation assistance costs 20 18 Other 3 26 Total deferred tax assets 450 454 Total deferred tax liability, net $ 858 $ 783 (1) Certain property related assets and liabilities have been netted. (2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $ 6 million and $ 9 million at December 31, 2021 and 2020, respectively. |
Schedule of Unrecognized Tax Benefits | The following table provides details of the change in unrecognized tax benefits as follows: (millions) 2021 2020 2019 Balance at January 1, $ 9 $ 9 $ 8 Decreases due to tax positions related to prior year 0 ( 2 ) 0 Increases due to tax positions related to prior year 1 1 1 Increases due to tax positions related to current year 1 1 0 Decreases due to settlements with tax authorities ( 5 ) 0 0 Balance at December 31, $ 6 $ 9 $ 9 |
Employee Postretirement Benef_2
Employee Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Schedule of Amount Recognized in Balance Sheet | The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations and plan assets at December 31 were as follows: TEC Pension Benefits Other Benefits Amounts recognized in balance sheet (millions) 2021 2020 2021 2020 Noncurrent assets $ 78 $ 0 $ 0 $ 0 Accrued benefit costs and other current liabilities ( 3 ) ( 1 ) ( 12 ) ( 12 ) Deferred credits and other liabilities ( 12 ) ( 15 ) ( 175 ) ( 186 ) $ 63 $ ( 16 ) $ ( 187 ) $ ( 198 ) |
Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets | The following table provides a detail of the unrecognized gains and losses and prior service credits and costs. TEC Pension Benefits Other Benefits Amounts recognized in regulatory assets (millions) 2021 2020 2021 2020 Net actuarial loss (gain) $ 150 $ 221 $ 79 $ 88 Amount recognized $ 150 $ 221 $ 79 $ 88 |
Benefit Obligations [Member] | |
Schedule of Assumptions Used to Determine Benefit | Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2021 2020 2021 2020 Discount rate 2.77 % 2.37 % 2.84 % 2.47 % Rate of compensation increase 3.05 % 3.07 % 3.04 % 3.07 % Healthcare cost trend rate Immediate rate n/a n/a 5.61 % 5.74 % Ultimate rate n/a n/a 4.00 % 4.50 % Year rate reaches ultimate trend rate n/a n/a 2045 2038 |
Net Periodic Benefit Cost [Member] | |
Schedule of Assumptions Used to Determine Benefit | Assumptions used to determine net periodic benefit cost for years ended December 31: Pension Benefits Other Benefits 2021 2020 2019 2021 2020 2019 Discount rate 2.37 % 3.21 % 4.33 % 2.47 % 3.32 % 4.38 % Expected long-term return on plan assets 6.70 % 7.00 % 7.35 %/ 7.00 % (1) n/a n/a n/a Rate of compensation increase 3.08 % 3.79 % 3.75 % 3.07 % 3.79 % 3.75 % Healthcare cost trend rate Initial rate n/a n/a n/a 5.74 % 6.03 % 6.31 % Ultimate rate n/a n/a n/a 4.50 % 4.50 % 4.50 % Year rate reaches ultimate trend rate n/a n/a n/a 2038 2038 2038 The expected return on assets was 7.35 % as of January 1, 2019 and 7.00 % as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment. |
TECO Energy [Member] | |
Schedule of Change in Plan Assets | Change in plan assets Fair value of plan assets at beginning of year $ 903 $ 796 $ 0 $ 0 Actual return on plan assets 76 142 0 0 Employer contributions 21 19 0 0 Employer direct benefit payments 1 1 13 13 Plan participants’ contributions 0 0 4 4 Benefits paid ( 76 ) ( 54 ) 0 0 Direct benefit payments ( 1 ) ( 1 ) ( 17 ) ( 17 ) Fair value of plan assets at end of year (1) $ 924 $ 903 $ 0 $ 0 (1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years . (2) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Schedule of Net Periodic Benefit Cost | TECO Energy Pension Benefits Other Benefits (1) 2021 2020 2019 2021 2020 2019 (millions) Service cost $ 19 $ 20 $ 20 $ 2 $ 2 $ 1 Interest cost 21 26 31 5 6 7 Expected return on plan assets ( 52 ) ( 50 ) ( 51 ) 0 0 0 Amortization of: Actuarial loss 24 20 16 4 1 1 Prior service (benefit) cost 0 0 0 ( 2 ) ( 3 ) ( 2 ) Settlement loss 0 0 1 (2) 0 0 0 Net periodic benefit cost $ 12 $ 16 $ 17 $ 9 $ 6 $ 7 |
Schedule of Amounts Recognized in OCI and Regulatory Assets | Net loss (gain) arising during the year (includes curtailment gain) $ ( 56 ) $ ( 8 ) $ ( 17 ) $ ( 5 ) $ 38 $ 9 Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service credit 0 0 0 2 2 2 Amortization or settlement of actuarial loss ( 23 ) ( 20 ) ( 17 ) ( 4 ) ( 1 ) ( 1 ) Total recognized in OCI and regulatory assets $ ( 79 ) $ ( 28 ) $ ( 34 ) $ ( 7 ) $ 39 $ 10 Total recognized in net periodic benefit cost, OCI and regulatory assets $ ( 67 ) $ ( 12 ) $ ( 17 ) $ 2 $ 45 $ 17 (1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan (2) Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements. |
Schedule of Pension Plan Assets | TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses. TECO Energy 2021 2020 Actual Allocation, End of Year Asset Category 2021 2020 Equity securities 50 %- 70 % 50 %- 70 % 59 % 60 % Fixed income securities 30 %- 50 % 30 %- 50 % 41 % 40 % Total 100 % 100 % 100 % 100 % |
Schedule of Fair Value Hierarchy Plan's Investments | The following table sets forth by level within the fair value hierarchy the plan’s investments. Pension Plan Investments TECO Energy At Fair Value as of December 31, 2021 (millions) Level 1 Level 2 Level 3 Using NAV (1) Total Cash $ 4 $ 0 $ 0 $ 0 $ 4 Accounts receivable 4 0 0 0 4 Accounts payable ( 70 ) 0 0 0 ( 70 ) Short-term investment funds (STIFs) 31 0 0 0 31 Common stocks 46 0 0 0 46 Real estate investment trusts (REITs) 6 0 0 0 6 Mutual funds 68 0 0 0 68 Municipal bonds 0 1 0 0 1 Government bonds 0 81 0 0 81 Corporate bonds 0 78 0 0 78 Mortgage backed securities (MBS) 0 1 0 0 1 Collateralized mortgage obligations (CMOs) 0 1 0 0 1 Short Sales 0 ( 2 ) 0 0 ( 2 ) Long Futures 1 0 0 0 1 Swaps 0 1 0 0 1 Investments not utilizing the practical expedient 90 161 0 0 251 Common and collective trusts (1) 0 0 0 592 592 Mutual fund (1) 0 0 0 81 81 Total investments $ 90 $ 161 $ 0 $ 673 $ 924 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet of TECO Energy. TECO Energy At Fair Value as of December 31, 2020 (millions) Level 1 Level 2 Level 3 Using NAV (1) Total Cash $ 9 $ 0 $ 0 $ 0 $ 9 Accounts receivable 10 0 0 0 10 Accounts payable ( 88 ) 0 0 0 ( 88 ) Short-term investment funds (STIFs) 35 0 0 0 35 Common stocks 66 0 0 0 66 Real estate investment trusts (REITs) 8 0 0 0 8 Mutual funds 69 0 0 0 69 Municipal bonds 0 1 0 0 1 Government bonds 0 90 0 0 90 Corporate bonds 0 79 0 0 79 Mortgage backed securities (MBS) 0 1 0 0 1 Collateralized mortgage obligations (CMOs) 0 1 0 0 1 Short Sales 0 ( 4 ) 0 0 ( 4 ) Long Futures ( 2 ) 0 0 0 ( 2 ) Swaps 0 1 0 0 1 Investments not utilizing the practical expedient 107 169 0 0 276 Common and collective trusts (1) 0 0 0 553 553 Mutual fund (1) 0 0 0 74 74 Total investments $ 107 $ 169 $ 0 $ 627 $ 903 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet of TECO Energy. The following list details the pricing inputs and methodologies used to value the investments in the pension plan: • Cash collateral is valued at cash posted due to its short-term nature. • The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset. • The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets. • The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-end mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets. • The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. • Swaps are valued using benchmark yields, swap curves, and cash flow analyses. • The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-end mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is an open-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. The redemption frequency is daily. The redemption notice period is the same day. There were no unfunded commitments as of December 31, 2021. • The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days. There were no unfunded commitments as of December 31, 2021. • Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities. Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses. |
Schedule of Benefit Payments | Expected Benefit Payments TECO Energy Other (including projected service and net of employee contributions) Pension Postretirement Benefits Benefits (millions) 2022 $ 69 $ 13 2023 72 14 2024 69 14 2025 68 14 2026 66 13 2027-2031 302 61 |
TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member] | |
Schedule of Change in Benefit Obligation | The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and TECO Energy’s Florida-based other postretirement benefit plan (other benefits). TECO Energy Pension Benefits Other Benefits (2) Obligations and Funded Status (millions) 2021 2020 2021 2020 Change in benefit obligation Benefit obligation at beginning of year $ 919 $ 843 $ 212 $ 180 Service cost 19 20 2 2 Interest cost 21 26 5 6 Plan participants’ contributions 0 0 4 4 Benefits paid ( 77 ) ( 54 ) ( 17 ) ( 17 ) Actuarial (gain) loss ( 32 ) 84 ( 6 ) 37 Benefit obligation at end of year $ 850 $ 919 $ 200 $ 212 |
Schedule of Funded status | At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with projected benefit obligations and accumulated projected benefit obligations in excess of plan assets was as follows: TECO Energy Pension Benefits Other Benefits (1) Funded Status (millions) 2021 2020 2021 2020 Benefit obligation (PBO/APBO) $ 850 $ 919 $ 200 $ 212 Less: Fair value of plan assets 924 903 0 0 Funded status at end of year $ 74 $ ( 16 ) $ ( 200 ) $ ( 212 ) (1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Short-Term Debt (Tables)
Short-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Short-Term Debt Credit Facilities | December 31, 2021 December 31, 2020 Borrowings Borrowings Letters Letters Credit Outstanding - Outstanding - of Credit Credit Borrowings of Credit (millions) Facilities Credit Facilities (1) Commercial Paper (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 800 $ 0 $ 245 $ 1 $ 800 $ 345 $ 1 3-year accounts receivable facility (3) 0 0 0 0 150 130 0 1-year term facility (4) 500 500 0 0 300 300 0 Total $ 1,300 $ 500 $ 245 $ 1 $ 1,250 $ 775 $ 1 (1) Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets. (2) This 5-year facility matures on December 17, 2026 . TEC also has an active commercial paper program for up to $ 800 million, of which the full amount outstanding is backed by TEC’s credit facility. The amount of commercial paper issued results in an equal amount of its credit facility being considered drawn and unavailable. (3) This 3-year facility matured on March 22, 2021 . (4) This 1-year term facility was terminated on March 23, 2021 . On December 17, 2021, TEC entered into another 1-year term facility that matures on December 16, 2022 . |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Commitments And Contingencies Disclosure [Abstract] | |
Schedule of Long-term Commitments | The following is a schedule of future payments under minimum lease payments with non-cancelable lease terms in excess of one year and other net purchase obligations/commitments at December 31, 2021: Purchased Capital Fuel and Gas Long-term Service Operating Demand Side (millions) Power Transportation (1) Projects Supply Agreements Leases Management Total Year ended December 31: 2022 $ 2 $ 244 $ 202 $ 349 $ 20 $ 3 $ 2 $ 822 2023 0 224 63 27 42 3 1 360 2024 0 215 0 0 27 3 1 246 2025 0 200 0 0 19 2 0 221 2026 0 197 0 0 20 1 0 218 Thereafter 0 1,871 0 0 52 48 0 1,971 Total future minimum payments $ 2 $ 2,951 $ 265 $ 376 $ 180 $ 60 $ 4 $ 3,838 (1) As of December 31, 2021, $ 112 million is related to a gas transportation contract through 2040 between PGS and SeaCoast, a related party. |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue Recognition [Abstract] | |
Summary of Disaggregates TEC Revenue by Major Source | The following disaggregates TEC’s revenue by major source: (millions) Tampa Tampa Electric For the year ended December 31, 2021 Electric PGS Eliminations Company Electric revenue Residential $ 1,156 $ 0 $ 0 $ 1,156 Commercial 602 0 0 602 Industrial 172 0 0 172 Regulatory deferrals and unbilled revenue ( 8 ) 0 0 ( 8 ) Other (1) 252 0 ( 4 ) 248 Total electric revenue 2,174 0 ( 4 ) 2,170 Gas revenue Residential 0 212 0 212 Commercial 0 191 0 191 Industrial (2) 0 25 0 25 Other (3) 0 100 ( 3 ) 97 Total gas revenue 0 528 ( 3 ) 525 Total revenue $ 2,174 $ 528 $ ( 7 ) $ 2,695 For the year ended December 31, 2020 Electric revenue Residential $ 1,018 $ 0 $ 0 $ 1,018 Commercial 506 0 0 506 Industrial 133 0 0 133 Regulatory deferrals and unbilled revenue ( 25 ) 0 0 ( 25 ) Other (1) 217 0 ( 4 ) 213 Total electric revenue 1,849 0 ( 4 ) 1,845 Gas revenue Residential 0 158 0 158 Commercial 0 135 0 135 Industrial (2) 0 23 0 23 Other (3) 0 117 ( 6 ) 111 Total gas revenue 0 433 ( 6 ) 427 Total revenue $ 1,849 $ 433 $ ( 10 ) $ 2,272 For the year ended December 31, 2019 Electric revenue Residential $ 1,046 $ 0 $ 0 $ 1,046 Commercial 562 0 0 562 Industrial 156 0 0 156 Regulatory deferrals and unbilled revenue ( 49 ) 0 0 ( 49 ) Other (1) 250 0 ( 4 ) 246 Total electric revenue 1,965 0 ( 4 ) 1,961 Gas revenue Residential 0 154 0 154 Commercial 0 146 0 146 Industrial (2) 0 21 0 21 Other (3) 0 140 ( 18 ) 122 Total gas revenue 0 461 ( 18 ) 443 Total revenue $ 1,965 $ 461 $ ( 22 ) $ 2,404 (1) Other includes sales to public authorities, off-system sales to other utilities and various other items. (2) Industrial includes sales to power generation customers. Other includes off-system sales to other utilities and various other items. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2021 2020 2019 Natural gas sales to/(from) affiliates $ ( 236 ) $ ( 139 ) $ ( 111 ) Services received from affiliates 7 6 65 Dividends to TECO Energy 450 408 373 Equity contributions from TECO Energy 580 505 395 Amounts due from or to affiliates at December 31, (millions) 2021 2020 Accounts receivable related to asset management agreements to Emera Energy Services Inc. (1) $ 4 $ 4 Accounts receivable excluding asset management agreements (1) 4 7 Accounts payable (1) 35 27 Taxes payable (2) 9 19 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2) Taxes payable were due to EUSHI. See Note 4 for additional information. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Segment Reporting [Abstract] | |
Schedule of Segment Information | Tampa (millions) Electric PGS Eliminations TEC 2021 Revenues - external $ 2,170 $ 525 $ 0 $ 2,695 Sales to affiliates 4 3 ( 7 ) 0 Total revenues 2,174 528 ( 7 ) 2,695 Depreciation and amortization 374 56 0 430 Total interest charges 110 20 0 130 Provision for income taxes 57 23 0 80 Net income 369 77 0 446 Total assets 10,650 2,209 ( 663 ) (1) 12,196 Capital expenditures 1,081 316 0 1,397 2020 Revenues - external $ 1,845 $ 427 $ 0 $ 2,272 Sales to affiliates 4 6 ( 10 ) 0 Total revenues 1,849 433 ( 10 ) 2,272 Depreciation and amortization 339 45 0 384 Total interest charges 113 17 0 130 Provision for income taxes 66 16 0 82 Net income 372 52 0 424 Total assets 9,800 1,901 ( 653 ) (1) 11,048 Capital expenditures 1,028 333 0 1,361 2019 Revenues - external $ 1,961 $ 443 $ 0 $ 2,404 Sales to affiliates 4 18 ( 22 ) 0 Total revenues 1,965 461 ( 22 ) 2,404 Depreciation and amortization 336 41 0 377 Total interest charges 117 17 0 134 Provision for income taxes 59 18 0 77 Net income 316 54 0 370 Total assets 9,007 1,593 ( 593 ) (1) 10,007 Capital expenditures 1,055 228 0 1,283 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | Reconciliation of beginning and ending carrying amount of asset retirement obligations: December 31, (millions) 2021 2020 Beginning balance $ 39 $ 49 Additional liabilities 0 8 Liabilities settled (1) ( 9 ) ( 19 ) Other 1 1 Ending balance $ 31 $ 39 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The decrease in the ARO in 2021 and 2020 is due to the closure of CCR management facilities. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Summary of Lease Assets and Liabilities | (millions) Classification December 31, 2021 December 31, 2020 Right-of-use asset Other deferred debits $ 24 $ 26 Lease liabilities Current Other current liabilities $ 2 $ 2 Long-term Deferred credits and other liabilities 23 25 Total lease liabilities $ 25 $ 27 |
Future Minimum Lease Payments | Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at December 31, 2021: (millions) Year ended December 31: 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments $ 3 $ 3 $ 3 $ 2 $ 1 $ 47 $ 59 Less imputed interest ( 34 ) Total future minimum payments $ 25 |
Additional Information Related to Leases | Additional information related to TEC’s leases is as follows: Year ended December 31, 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions) $ 4 $ 5 Weighted average remaining lease term (years) 44 43 Weighted average discount rate - operating leases 4.4 % 4.3 % |
Net Investment in Direct Finance Leases | The net investment in direct finance leases consists of the following: (millions) December 31, 2021 December 31, 2020 Total minimum lease payments to be received $ 29 $ 31 Less amounts representing estimated executory costs ( 11 ) ( 12 ) Minimum lease payments receivable $ 18 $ 19 Less unearned finance lease income ( 9 ) ( 10 ) Net investment in direct finance and sales-type leases $ 9 $ 9 Principal due within one year (included in "Receivables") ( 2 ) ( 2 ) Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits") $ 7 $ 7 |
Future Minimum Direct Finance Lease Payments to be Received | As of December 31, 2021, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following: (millions) Year ended December 31: 2022 2023 2024 2025 2026 Thereafter Total Minimum lease payments to be received $ 2 $ 2 $ 2 $ 2 $ 2 $ 19 $ 29 Less executory costs ( 11 ) Total minimum lease payments receivable $ 18 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Summary of Activity Related to TEC Employee PSUs | A summary of the activity related to TEC employee PSUs is presented in the following table: Weighted Aggregate Number of Average Grant Intrinsic Units Date Fair Value Value (Thousands) (Per Unit) (Millions) Outstanding as of December 31, 2020 390 46.87 21 Granted including DRIP 91 52.25 5 Exercised ( 175 ) 48.12 10 Forfeited ( 26 ) 47.82 1 Transferred 5 47.18 0 Outstanding as of December 31, 2021 285 47.74 18 |
Significant Accounting Polici_4
Significant Accounting Policies - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2021USD ($)Segment | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jun. 09, 2020USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | ||||
Number of operating segments | Segment | 2 | |||
Percentage of original cost of depreciable property | 3.50% | 3.20% | 3.40% | |
Depreciation expense | $ 408,000,000 | $ 381,000,000 | $ 359,000,000 | |
Allowance for funds used during construction rate | 6.46% | 6.46% | 6.46% | |
Allowance for funds used during construction | $ 66,000,000 | $ 44,000,000 | $ 16,000,000 | |
Receivables from contracts with customers | 252,000,000 | 214,000,000 | ||
Unbilled revenues | 74,000,000 | 73,000,000 | ||
Franchise fees and gross receipts taxes | $ 129,000,000 | 109,000,000 | $ 117,000,000 | |
Natural Gas Contracts [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Maximum length of time hedging in future cash flow | Nov. 30, 2018 | |||
Natural Gas Storage and Transportation [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Derivative Liabilities | $ 0 | 0 | ||
Derivative Assets | $ 0 | $ 0 | ||
Minimum [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Discount rates used in estimating other self-insurance liabilities | 1.63% | 2.43% | ||
Maximum [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Discount rates used in estimating other self-insurance liabilities | 4.00% | 4.00% | ||
Intangible Software Assets [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Accumulated depreciation and amortization reserve surplus | $ 16,000,000 | |||
PGS [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Allowance for funds used during construction rate | 6.00% | 5.97% |
Significant Accounting Polici_5
Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Property Plant And Equipment [Line Items] | ||
Total cost | $ 12,833 | $ 12,360 |
Less accumulated depreciation | (3,601) | (3,712) |
Construction work in progress | 1,370 | 1,472 |
Total property, plant and equipment, net | 10,602 | 10,120 |
Electric Generation [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | 5,395 | 5,694 |
Gas Transmission and Distribution [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | 2,360 | 2,076 |
General Plant and Other [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | $ 946 | 723 |
Minimum [Member] | Electric Generation [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 21 years | |
Minimum [Member] | Gas Transmission and Distribution [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 16 years | |
Minimum [Member] | General Plant and Other [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 8 years | |
Maximum [Member] | Electric Generation [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 56 years | |
Maximum [Member] | Gas Transmission and Distribution [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 77 years | |
Maximum [Member] | General Plant and Other [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 43 years | |
Electric Transmission [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | $ 1,068 | 1,008 |
Electric Transmission [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 28 years | |
Electric Transmission [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 77 years | |
Electric Distribution [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | $ 3,064 | $ 2,859 |
Electric Distribution [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 14 years | |
Electric Distribution [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful lives | 56 years |
Regulatory - Additional Informa
Regulatory - Additional Information (Detail) | Oct. 12, 2021USD ($) | Aug. 06, 2021USD ($) | Aug. 03, 2021USD ($) | Nov. 19, 2020USD ($) | Aug. 18, 2020USD ($) | Aug. 03, 2020USD ($) | Apr. 27, 2020USD ($) | Apr. 09, 2019USD ($) | Dec. 28, 2017USD ($) | Feb. 07, 2017 | Sep. 06, 2013 | Jan. 31, 2024USD ($) | Jan. 31, 2023USD ($) | Jan. 31, 2022USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2021USD ($)Unit$ / Kwac | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016 | Dec. 31, 2021USD ($)$ / KwacMW | Jun. 09, 2020USD ($) | Dec. 31, 2018USD ($) | Oct. 31, 2013USD ($) |
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 10.25% | |||||||||||||||||||||||
Return on equity range | range of plus or minus 1% | |||||||||||||||||||||||
Percentage change in ROE Percentage | 1.00% | |||||||||||||||||||||||
Allowed equity in the capital structure | 54.00% | |||||||||||||||||||||||
Federal statutory tax rate | 4.50% | 5.50% | ||||||||||||||||||||||
Decrease in deferred income taxes offset to regulatory liability | $ 5,000,000 | |||||||||||||||||||||||
Utility plant, at original costs | 14,189,000,000 | $ 13,818,000,000 | $ 14,189,000,000 | |||||||||||||||||||||
Accumulated depreciation | $ 3,601,000,000 | 3,712,000,000 | 3,601,000,000 | |||||||||||||||||||||
Number of units applied for recovery | Unit | 3 | |||||||||||||||||||||||
Additional cost recovery from settlement agreement | $ 83,000,000 | |||||||||||||||||||||||
Storm restoration costs | $ 10,000,000 | |||||||||||||||||||||||
Regulatory assets | $ 1,002,000,000 | 485,000,000 | 1,002,000,000 | |||||||||||||||||||||
O&M expense | 566,000,000 | 542,000,000 | $ 543,000,000 | |||||||||||||||||||||
Regulatory liability | 1,170,000,000 | 1,261,000,000 | 1,170,000,000 | |||||||||||||||||||||
Provision for income taxes | 80,000,000 | 82,000,000 | 77,000,000 | |||||||||||||||||||||
Amount refundable on settlement | $ 12,000,000 | |||||||||||||||||||||||
Regulatory asset amortization ending period | 2020 | |||||||||||||||||||||||
Reduction in regulatory asset for amortization | 10,000,000 | 18,000,000 | (1,000,000) | |||||||||||||||||||||
Subsequent Event [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Additional cost recovery from settlement agreement | $ 169,000,000 | |||||||||||||||||||||||
Peoples Gas System [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 10.75% | |||||||||||||||||||||||
Allowed equity in the capital structure | 54.70% | |||||||||||||||||||||||
Reduction in annual base rates | 12,000,000 | |||||||||||||||||||||||
Regulatory assets | $ 11,000,000 | |||||||||||||||||||||||
Reduction in annual depreciation rates | 10,000,000 | |||||||||||||||||||||||
PGS and OPC [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Allowed equity in the capital structure | 54.70% | |||||||||||||||||||||||
Increase in revenue | $ 34,000,000 | |||||||||||||||||||||||
Impact of tax reform through reduction in base revenue days | 120 days | |||||||||||||||||||||||
Accumulated depreciation | $ 34,000,000 | |||||||||||||||||||||||
Regulatory assets | $ 32,000,000 | |||||||||||||||||||||||
Date new bottom of return on equity range will remain in effect | Dec. 31, 2020 | |||||||||||||||||||||||
Regulatory asset amortization beginning period | 2016 | |||||||||||||||||||||||
Increase in annual base rate | 58,000,000 | |||||||||||||||||||||||
Hurricanes [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Storm restoration preparation costs | 10,000,000 | 10,000,000 | $ 10,000,000 | |||||||||||||||||||||
Storm Reserve [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Regulatory liability | 46,000,000 | 48,000,000 | 46,000,000 | |||||||||||||||||||||
Hurricane Irma [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Storm restoration costs | $ 102,000,000 | |||||||||||||||||||||||
Hurricane Irma [Member] | Storm Reserve [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Storm restoration costs | 90,000,000 | |||||||||||||||||||||||
Hurricane Irma [Member] | Capital Expenditures [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Storm restoration costs | $ 9,000,000 | |||||||||||||||||||||||
Intangible Software Assets [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Accumulated amortization reserve surplus | $ 16,000,000 | |||||||||||||||||||||||
Electric Utility Plant [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Utility plant, at original costs | $ 11,563,000,000 | 11,486,000,000 | $ 11,563,000,000 | |||||||||||||||||||||
Cast Iron and Bare Steel Replacement Rider [Member] | PGS and OPC [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Increase in revenue | $ 24,000,000 | |||||||||||||||||||||||
Settlement Agreement [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Settlement agreement, approval date | Aug. 6, 2021 | |||||||||||||||||||||||
Allowed equity in the capital structure | 54.00% | |||||||||||||||||||||||
Base rate adjustment amount | $ 123,000,000 | |||||||||||||||||||||||
Increase in revenue | $ 191,000,000 | |||||||||||||||||||||||
Settlement agreement number of subsequent years adjustments | 2 years | |||||||||||||||||||||||
Basis point increase applicable | 0.25% | |||||||||||||||||||||||
Additional attainable revenue under settlement agreement | $ 10,000,000 | |||||||||||||||||||||||
Changes in base rate under agreement | $ 0 | |||||||||||||||||||||||
Impact of tax reform through reduction in base revenue days | 180 days | |||||||||||||||||||||||
Settlement Agreement [Member] | Scenario Forecast [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Settlement agreement adjustment amount | $ 21,000,000 | $ 90,000,000 | ||||||||||||||||||||||
Settlement Agreement [Member] | US Treasury Bond [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Calculating period | 30 years | |||||||||||||||||||||||
Determining period | 6 months | |||||||||||||||||||||||
Minimum [Member] | PGS and OPC [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 8.90% | |||||||||||||||||||||||
Base rate agreement frozen period | Jan. 1, 2021 | |||||||||||||||||||||||
Decrease bottom return on equity | 11.75% | |||||||||||||||||||||||
Minimum [Member] | Settlement Agreement [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 9.00% | |||||||||||||||||||||||
Base rate agreement frozen period | Jan. 1, 2022 | |||||||||||||||||||||||
Minimum [Member] | Settlement Agreement [Member] | US Treasury Bond [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
ROE revenue basis point on yield rate | 0.50% | |||||||||||||||||||||||
Maximum [Member] | PGS and OPC [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 11.00% | |||||||||||||||||||||||
Base rate agreement frozen period | Dec. 31, 2023 | |||||||||||||||||||||||
Decrease bottom return on equity | 9.25% | |||||||||||||||||||||||
Maximum [Member] | Settlement Agreement [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 11.00% | |||||||||||||||||||||||
Base rate agreement frozen period | Dec. 31, 2024 | |||||||||||||||||||||||
Mid Point [Member] | PGS and OPC [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 9.90% | |||||||||||||||||||||||
Mid Point [Member] | Settlement Agreement [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Percentage of ROE | 9.95% | |||||||||||||||||||||||
Condition One [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
ROE lower range limit | 9.25% | |||||||||||||||||||||||
Condition Two [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
ROE lower range limit | 11.25% | |||||||||||||||||||||||
Solar Project Cost Recovery [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Settlement agreement, extended terms | four years through 2021 | |||||||||||||||||||||||
Settlement agreement, approval date | Nov. 6, 2017 | |||||||||||||||||||||||
Cost cap of project | $ / Kwac | 1,500 | 1,500 | ||||||||||||||||||||||
Cost savings benefit percentage for projects below cost cap | 75.00% | |||||||||||||||||||||||
Solar generation capacity investments | $ 850,000,000 | $ 850,000,000 | ||||||||||||||||||||||
Solar energy capacity | MW | 600 | |||||||||||||||||||||||
Estimated revenue requirements | 104,000,000 | $ 104,000,000 | ||||||||||||||||||||||
Investments in gas reserves | 0 | 0 | ||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Solar Base Rate Adjustments [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
True-up amount returned to customers | $ 4,000,000 | $ 5,000,000 | ||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Effective September 2018 [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Estimated revenue requirements | 24,000,000 | 24,000,000 | ||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Effective January 2019 [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Estimated revenue requirements | 46,000,000 | 46,000,000 | ||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Effective January 2020 [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Estimated revenue requirements | 26,000,000 | 26,000,000 | ||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Effective January 2021 [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Estimated revenue requirements | $ 8,000,000 | 8,000,000 | ||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Minimum [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Solar project investment term | 2017 | |||||||||||||||||||||||
Solar Project Cost Recovery [Member] | Maximum [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Solar project investment term | 2021 | |||||||||||||||||||||||
Retiring Assets [Member] | Settlement Agreement [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Cost recovery from settlement agreement | $ 68,000,000 | |||||||||||||||||||||||
Retiring Coal Generation Units and Meter Assets [Member] | Settlement Agreement [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Settlement agreement cost recovery period | 15 years | |||||||||||||||||||||||
Big Bend Modernization Project [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Energy generation capacity investments | $ 850,000,000 | 850,000,000 | ||||||||||||||||||||||
Investments in energy projects till date | $ 695,000,000 | $ 695,000,000 | ||||||||||||||||||||||
Accumulated depreciation | 267,000,000 | |||||||||||||||||||||||
Settlement agreement recovery description | Tampa Electric’s Settlement Agreement provides recovery for the Big Bend modernization project in two phases. The first phase is a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. | |||||||||||||||||||||||
Big Bend Modernization Project [Member] | Electric Utility Plant [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Utility plant, at original costs | $ 636,000,000 | |||||||||||||||||||||||
Big Bend Modernization Project [Member] | Minimum [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Energy project investment term | 2018 | |||||||||||||||||||||||
Big Bend Modernization Project [Member] | Maximum [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Energy project investment term | 2023 | |||||||||||||||||||||||
Big Bend Coal Generation Assets [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Settlement agreement cost recovery period | 15 years | |||||||||||||||||||||||
Storm Protection Plan [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Cost recovery from settlement agreement | $ 39,000,000 | |||||||||||||||||||||||
Reduction in annual base rates | $ 15,000,000 | |||||||||||||||||||||||
Storm Restoration Cost Recovery [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Minimum cost recovery period | 12 months | |||||||||||||||||||||||
Replenishment reserve for recovery of cost | $ 56,000,000 | |||||||||||||||||||||||
Storm Reserve [Member] | ||||||||||||||||||||||||
Public Utilities General Disclosures [Line Items] | ||||||||||||||||||||||||
Regulatory assets | $ 56,000,000 |
Regulatory - Schedule of Regula
Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Regulatory assets: | ||
Regulatory assets | $ 1,002 | $ 485 |
Less: Current portion | 136 | 79 |
Long-term regulatory assets | 866 | 406 |
Regulatory liabilities: | ||
Regulatory liabilities | 1,170 | 1,261 |
Less: Current portion | 78 | 67 |
Long-term regulatory liabilities | 1,092 | 1,194 |
Regulatory Tax Asset [Member] | ||
Regulatory assets: | ||
Regulatory assets | 117 | 90 |
Cost-Recovery Clauses [Member] | ||
Regulatory assets: | ||
Regulatory assets | 89 | 38 |
Capital Cost Recovery for Early Retired Assets [Member] | ||
Regulatory assets: | ||
Regulatory assets | 518 | 0 |
Environmental Remediation [Member] | ||
Regulatory assets: | ||
Regulatory assets | 22 | 22 |
Postretirement Benefits [Member] | ||
Regulatory assets: | ||
Regulatory assets | 230 | 309 |
Asset Retirement Obligation [Member] | ||
Regulatory assets: | ||
Regulatory assets | 11 | 13 |
Other [Member] | ||
Regulatory assets: | ||
Regulatory assets | 15 | 13 |
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 638 | 691 |
Cost-recovery Clauses - Deferred Balances [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 16 | 23 |
Accumulated Reserve - Cost of Removal [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 468 | 498 |
Storm Reserve [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 46 | 48 |
Other [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | $ 2 | $ 1 |
Regulatory - Schedule of Regu_2
Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail) | 12 Months Ended |
Dec. 31, 2021 | |
Capital Cost Recovery for Early Retired Assets [Member] | |
Schedule Of Regulatory Assets And Liabilities [Line Items] | |
Settlement agreement cost recovery period | 15 years |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) | Sep. 14, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Income Taxes [Line Items] | |||||
Federal statutory tax rate | 21.00% | 21.00% | 21.00% | ||
Federal statutory tax rate | 4.50% | 5.50% | |||
Provision for income taxes | $ 80,000,000 | $ 82,000,000 | $ 77,000,000 | ||
Deferred tax assets expiration date | 2032 and 2037 | ||||
General business credit | $ 286,000,000 | ||||
Deferred tax general business credits expiration date | 2027 and 2041 | ||||
Investment tax credits | $ 264,000,000 | ||||
Investment tax credit expiration date | 2034 and 2041 | ||||
Uncertain tax positions | $ 6,000,000 | 9,000,000 | 9,000,000 | $ 8,000,000 | |
Unrecognized tax benefits decreased | 0 | 2,000,000 | |||
Pre-tax charges (benefits) | 0 | 0 | 0 | ||
Interest accrued | 0 | 0 | 0 | ||
Penalties | $ 0 | 0 | $ 0 | ||
Statutes of limitations | 3 years | ||||
Income tax examination period | 1 year | ||||
Federal [Member] | |||||
Income Taxes [Line Items] | |||||
Federal and Florida net operating losses (NOL's) carryforward | $ 312,000,000 | ||||
Federal [Member] | R&D Tax Credits [Member] | |||||
Income Taxes [Line Items] | |||||
Uncertain tax positions | 6,000,000 | 9,000,000 | |||
Unrecognized tax benefits decreased | $ 5,000,000 | $ 2,000,000 | |||
Florida [Member] | |||||
Income Taxes [Line Items] | |||||
Federal statutory tax rate | 4.46% | 3.53% | |||
Regulatory liability due to obligation to transfer tax rate reduction expense benefit | $ 4,000,000 | ||||
Federal and Florida net operating losses (NOL's) carryforward | $ 83,000,000 |
Income Taxes - Schedule of Inco
Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Current income taxes, Federal | $ 48 | $ 35 | $ 56 |
Current income taxes, State | 4 | (7) | 6 |
Deferred income taxes, Federal | 24 | 32 | 7 |
Deferred income taxes, State | 13 | 29 | 13 |
Investment tax credits amortization | (9) | (7) | (5) |
Total income tax expense | $ 80 | $ 82 | $ 77 |
Income Taxes - Schedule of In_2
Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Income before provision for income taxes | $ 526 | $ 506 | $ 447 |
Federal statutory income tax rates | 21.00% | 21.00% | 21.00% |
Income taxes, at statutory income tax rate | $ 110 | $ 106 | $ 94 |
State income tax, net of federal income tax | 13 | 17 | 15 |
Excess deferred tax amortization | (26) | (26) | (25) |
ITC amortization | (9) | (7) | (5) |
AFUDC-equity | (9) | (6) | (2) |
Tax credits | (3) | (8) | (1) |
Other | 4 | 6 | 1 |
Total income tax expense | $ 80 | $ 82 | $ 77 |
Income tax expense as a percent of income before income taxes | 15.20% | 16.20% | 17.20% |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred tax liabilities | ||
Property related | $ 1,210 | $ 1,121 |
Pension and postretirement benefits | 98 | 116 |
Total deferred tax liabilities | 1,308 | 1,237 |
Deferred tax assets | ||
Loss and credit carryforwards | 340 | 301 |
Medical benefits | 26 | 27 |
Insurance reserves | 15 | 16 |
Pension and postretirement benefits | 46 | 66 |
Capitalized energy conservation assistance costs | 20 | 18 |
Other | 3 | 26 |
Total deferred tax assets | 450 | 454 |
Total deferred tax liability, net | $ 858 | $ 783 |
Income Taxes - Schedule of De_2
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Income Tax Disclosure [Abstract] | ||||
Unrecognized tax benefits | $ 6 | $ 9 | $ 9 | $ 8 |
Income Taxes - Schedule of Unre
Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Beginning Balance | $ 9 | $ 9 | $ 8 |
Decreases due to tax positions related to prior year | 0 | (2) | 0 |
Increases due to tax positions related to prior year | 1 | 1 | 1 |
Increases due to tax positions related to current year | 1 | 1 | 0 |
Decreases due to settlements with tax authorities | (5) | 0 | 0 |
Ending Balance | $ 6 | $ 9 | $ 9 |
Employee Postretirement Benef_3
Employee Postretirement Benefits - Additional Information (Detail) - USD ($) | Jan. 02, 2017 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | ||||||
Redemption frequency description | The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days. | |||||
Percentage of qualified pension plan's actuarial value of assets | 133.60% | 122.19% | ||||
Employer contributions | $ 17,000,000 | $ 16,000,000 | ||||
Employer contributions in next fiscal year | $ 15,000,000 | |||||
Employer matching contribution percentage of eligible participant contribution | 75.00% | 70.00% | ||||
Description of defined contribution plan | Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals. | |||||
Defined contribution plan cost recognized | $ 22,000,000 | 21,000,000 | $ 11,000,000 | |||
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer | 25.00% | |||||
Non-qualified SERP [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined benefit plan, assets | $ 10,000,000 | 10,000,000 | ||||
Unfunded [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Commitments | 0 | |||||
Pension Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Net periodic benefit cost | 10,000,000 | 12,000,000 | 12,000,000 | |||
Defined benefit plan, assets | 78,000,000 | 0 | ||||
Other Postretirement Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Net periodic benefit cost | 11,000,000 | 7,000,000 | 7,000,000 | |||
Defined benefit plan, assets | 0 | 0 | ||||
SERP [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Employer contributions | 0 | 0 | 0 | |||
Benefits paid | 1,000,000 | 1,000,000 | 5,000,000 | |||
Expected payment in next twelve months | 1,000,000 | |||||
Non Elective Employer Contribution [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined contribution plan cost recognized | 10,000,000 | 9,000,000 | 1,000,000 | |||
TECO Energy [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Accumulated benefit obligation of defined benefit pension plans | $ 819,000,000 | 876,000,000 | ||||
Percentage of defined benefit plan's actual earned returns | 9.00% | |||||
Defined contribution plan, employer match percentage | 6.00% | |||||
Employer matching contribution percentage of eligible participant contribution | 75.00% | |||||
TECO Energy [Member] | Pension Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Net periodic benefit cost | $ 12,000,000 | 16,000,000 | 17,000,000 | |||
Settlement charge | 0 | 0 | (1,000,000) | |||
Commitments | 850,000,000 | 919,000,000 | 843,000,000 | |||
Employer contributions | 21,000,000 | 19,000,000 | ||||
TECO Energy [Member] | Other Postretirement Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Net periodic benefit cost | 9,000,000 | 6,000,000 | 7,000,000 | |||
Settlement charge | 0 | 0 | 0 | |||
Commitments | [1] | 200,000,000 | 212,000,000 | $ 180,000,000 | ||
Employer contributions | [1] | 0 | $ 0 | |||
Employer contributions in next fiscal year | 12,000,000 | |||||
TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Other postretirement benefit plans service benefit to be amortized from regulatory assets in next fiscal year | $ 0 | |||||
International Brotherhood of Electrical Workers [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Percentage of employees represented | 24.00% | |||||
[1] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement Benef_4
Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - TECO Energy [Member] - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||||
Pension Benefits [Member] | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | $ 919 | $ 843 | ||||
Service cost | 19 | 20 | $ 20 | |||
Interest cost | 21 | 26 | 31 | |||
Plan participants’ contributions | 0 | 0 | ||||
Benefits paid | (77) | (54) | ||||
Actuarial (gain) loss | (32) | 84 | ||||
Benefit obligation at end of year | 850 | 919 | 843 | |||
Other Postretirement Benefits [Member] | ||||||
Change in benefit obligation | ||||||
Benefit obligation at beginning of year | [1] | 212 | 180 | |||
Service cost | 2 | [1] | 2 | [1] | 1 | |
Interest cost | 5 | [1] | 6 | [1] | 7 | |
Plan participants’ contributions | [1] | 4 | 4 | |||
Benefits paid | [1] | (17) | (17) | |||
Actuarial (gain) loss | [1] | (6) | 37 | |||
Benefit obligation at end of year | [1] | $ 200 | $ 212 | $ 180 | ||
[1] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement Benef_5
Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | |||
Change in plan assets | ||||
Employer contributions | $ 17 | $ 16 | ||
TECO Energy [Member] | ||||
Change in plan assets | ||||
Fair value of plan assets at beginning of year | 903 | |||
Fair value of plan assets at end of year | 924 | 903 | ||
TECO Energy [Member] | Pension Benefits [Member] | ||||
Change in plan assets | ||||
Fair value of plan assets at beginning of year | 903 | [1] | 796 | |
Actual return on plan assets | 76 | 142 | ||
Employer contributions | 21 | 19 | ||
Employer direct benefit payments | 1 | 1 | ||
Plan participants’ contributions | 0 | 0 | ||
Benefits paid | (76) | (54) | ||
Direct benefit payments | (1) | (1) | ||
Fair value of plan assets at end of year | [1] | 924 | 903 | |
TECO Energy [Member] | Other Postretirement Benefits [Member] | ||||
Change in plan assets | ||||
Fair value of plan assets at beginning of year | [2] | 0 | [1] | 0 |
Actual return on plan assets | [2] | 0 | 0 | |
Employer contributions | [2] | 0 | 0 | |
Employer direct benefit payments | [2] | 13 | 13 | |
Plan participants’ contributions | [2] | 4 | 4 | |
Benefits paid | [2] | 0 | 0 | |
Direct benefit payments | [2] | (17) | (17) | |
Fair value of plan assets at end of year | [1],[2] | $ 0 | $ 0 | |
[1] | The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years . | |||
[2] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement Benef_6
Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member] | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses | 5 years | 5 years |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses | 5 years | 5 years |
Employee Postretirement Benef_7
Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | $ 924 | $ 903 | ||||
Pension Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Benefit obligation (PBO/APBO) | 850 | 919 | $ 843 | |||
Fair value of plan assets | 924 | [1] | 903 | [1] | 796 | |
Funded status at end of year | 74 | (16) | ||||
Other Postretirement Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Benefit obligation (PBO/APBO) | [2] | 200 | 212 | 180 | ||
Fair value of plan assets | [2] | 0 | [1] | 0 | [1] | $ 0 |
Funded status at end of year | [2] | $ (200) | ||||
Other Postretirement Benefits [Member] | Florida [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Benefit obligation (PBO/APBO) | [2] | 212 | ||||
Fair value of plan assets | [2] | 0 | ||||
Funded status at end of year | [2] | $ (212) | ||||
[1] | The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years . | |||||
[2] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement Benef_8
Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Noncurrent assets | $ 78 | $ 0 |
Accrued benefit costs and other current liabilities | (3) | (1) |
Deferred credits and other liabilities | (12) | (15) |
Net amount recognized at end of year | 63 | (16) |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Noncurrent assets | 0 | 0 |
Accrued benefit costs and other current liabilities | (12) | (12) |
Deferred credits and other liabilities | (175) | (186) |
Net amount recognized at end of year | $ (187) | $ (198) |
Employee Postretirement Benef_9
Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial loss (gain) | $ 150 | $ 221 |
Amount recognized | 150 | 221 |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial loss (gain) | 79 | 88 |
Amount recognized | $ 79 | $ 88 |
Employee Postretirement Bene_10
Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail) | Jan. 01, 2019 | [1] | Oct. 31, 2019 | [1] | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Pension Benefits [Member] | |||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||
Discount rate | 2.77% | 2.37% | |||||
Rate of compensation increase | 3.05% | 3.07% | |||||
Discount rate | 2.37% | 3.21% | 4.33% | ||||
Expected long-term return on plan assets | 7.35% | 7.00% | 6.70% | 7.00% | |||
Rate of compensation increase | 3.08% | 3.79% | 3.75% | ||||
Other Postretirement Benefits [Member] | |||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||
Discount rate | 2.84% | 2.47% | |||||
Rate of compensation increase | 3.04% | 3.07% | |||||
Discount rate | 2.47% | 3.32% | 4.38% | ||||
Rate of compensation increase | 3.07% | 3.79% | 3.75% | ||||
Healthcare cost trend rate | |||||||
Ultimate rate | 4.50% | 4.50% | 4.50% | ||||
Year rate reaches ultimate trend rate | 2038 | 2038 | 2038 | ||||
Other Postretirement Benefits [Member] | Immediate Rate [Member] | |||||||
Healthcare cost trend rate | |||||||
Immediate rate | 5.61% | 5.74% | |||||
Other Postretirement Benefits [Member] | Initial Rate [Member] | |||||||
Healthcare cost trend rate | |||||||
Immediate rate | 5.74% | 6.03% | 6.31% | ||||
Other Postretirement Benefits [Member] | Ultimate Trend Rate Per Actuary [Member] | |||||||
Healthcare cost trend rate | |||||||
Ultimate rate | 4.00% | ||||||
Year rate reaches ultimate trend rate | 2045 | ||||||
[1] | The expected return on assets was 7.35 % as of January 1, 2019 and 7.00 % as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment. |
Employee Postretirement Bene_11
Employee Postretirement Benefits - Schedule of Amounts Recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets (Detail) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |||
Pension Benefits [Member] | |||||
Amortization of: | |||||
Net periodic benefit cost | $ 10 | $ 12 | $ 12 | ||
Other Postretirement Benefits [Member] | |||||
Amortization of: | |||||
Net periodic benefit cost | 11 | 7 | 7 | ||
TECO Energy [Member] | Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 19 | 20 | 20 | ||
Interest cost | 21 | 26 | 31 | ||
Expected return on plan assets | (52) | (50) | (51) | ||
Amortization of: | |||||
Actuarial loss | 24 | 20 | 16 | ||
Prior service (benefit) cost | 0 | 0 | 0 | ||
Settlement loss | 0 | 0 | 1 | ||
Net periodic benefit cost | 12 | 16 | 17 | ||
Net loss (gain) arising during the year (includes curtailment gain) | (56) | (8) | (17) | ||
Amounts recognized as component of net periodic benefit cost: | |||||
Amortization or curtailment recognition of prior service credit | 0 | 0 | 0 | ||
Amortization or settlement of actuarial loss | (23) | (20) | (17) | ||
Total recognized in OCI and regulatory assets | (79) | (28) | (34) | ||
Total recognized in net periodic benefit cost, OCI and regulatory assets | (67) | (12) | (17) | ||
TECO Energy [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 2 | [1] | 2 | [1] | 1 |
Interest cost | 5 | [1] | 6 | [1] | 7 |
Expected return on plan assets | 0 | 0 | 0 | ||
Amortization of: | |||||
Actuarial loss | 4 | 1 | 1 | ||
Prior service (benefit) cost | (2) | (3) | (2) | ||
Settlement loss | 0 | 0 | 0 | ||
Net periodic benefit cost | 9 | 6 | 7 | ||
Net loss (gain) arising during the year (includes curtailment gain) | (5) | 38 | 9 | ||
Amounts recognized as component of net periodic benefit cost: | |||||
Amortization or curtailment recognition of prior service credit | 2 | 2 | 2 | ||
Amortization or settlement of actuarial loss | (4) | (1) | (1) | ||
Total recognized in OCI and regulatory assets | (7) | 39 | 10 | ||
Total recognized in net periodic benefit cost, OCI and regulatory assets | $ 2 | $ 45 | $ 17 | ||
[1] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement Bene_12
Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Parenthetical) (Detail) | Jan. 01, 2019 | Oct. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Pension Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Expected long-term return on plan assets | 7.35% | [1] | 7.00% | [1] | 6.70% | 7.00% |
[1] | The expected return on assets was 7.35 % as of January 1, 2019 and 7.00 % as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment. |
Employee Postretirement bene_13
Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member] | Dec. 31, 2021 | Dec. 31, 2020 |
Actual Asset Allocation [Member] | ||
Asset Category | ||
Actual Allocation, End of Year | 100.00% | 100.00% |
Actual Asset Allocation [Member] | Equity Securities [Member] | ||
Asset Category | ||
Actual Allocation, End of Year | 59.00% | 60.00% |
Actual Asset Allocation [Member] | Fixed Income Securities [Member] | ||
Asset Category | ||
Actual Allocation, End of Year | 41.00% | 40.00% |
Target Allocation [Member] | ||
Asset Category | ||
Target Allocation | 100.00% | 100.00% |
Target Allocation [Member] | Equity Securities [Member] | Minimum [Member] | ||
Asset Category | ||
Target Allocation | 50.00% | 50.00% |
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member] | ||
Asset Category | ||
Target Allocation | 70.00% | 70.00% |
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member] | ||
Asset Category | ||
Target Allocation | 30.00% | 30.00% |
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member] | ||
Asset Category | ||
Target Allocation | 50.00% | 50.00% |
Employee Postretirement Bene_14
Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | ||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 924 | $ 903 | ||
Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 4 | 9 | ||
Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 31 | 35 | ||
Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 46 | 66 | ||
Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (1) | (2) | ||
Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 6 | 8 | ||
Short Sales [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (2) | (4) | ||
Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 68 | 69 | ||
Municipal Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 81 | 90 | ||
Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 78 | 79 | ||
Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 251 | 276 | ||
Collateralized Mortgage Obligations (CMOs) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Common and Collective Trusts [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 592 | [1] | 553 | [2] |
Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 81 | [1] | 74 | [2] |
Mortgage Backed Securities (MBS) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
NAV [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 673 | 627 | ||
NAV [Member] | Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Short Sales [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Municipal Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Collateralized Mortgage Obligations (CMOs) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Common and Collective Trusts [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 592 | [1] | 553 | [2] |
NAV [Member] | Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 81 | [1] | 74 | [2] |
NAV [Member] | Mortgage Backed Securities (MBS) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
NAV [Member] | Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 90 | 107 | ||
Level 1 [Member] | Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 4 | 9 | ||
Level 1 [Member] | Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 31 | 35 | ||
Level 1 [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 46 | 66 | ||
Level 1 [Member] | Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (1) | (2) | ||
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 6 | 8 | ||
Level 1 [Member] | Short Sales [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 68 | 69 | ||
Level 1 [Member] | Municipal Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 90 | 107 | ||
Level 1 [Member] | Collateralized Mortgage Obligations (CMOs) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | Common and Collective Trusts [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [1] | 0 | [2] |
Level 1 [Member] | Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [1] | 0 | [2] |
Level 1 [Member] | Mortgage Backed Securities (MBS) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 1 [Member] | Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 161 | 169 | ||
Level 2 [Member] | Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | Short Sales [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (2) | (4) | ||
Level 2 [Member] | Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 2 [Member] | Municipal Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Level 2 [Member] | Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 81 | 90 | ||
Level 2 [Member] | Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 78 | 79 | ||
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 161 | 169 | ||
Level 2 [Member] | Collateralized Mortgage Obligations (CMOs) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Level 2 [Member] | Common and Collective Trusts [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [1] | 0 | [2] |
Level 2 [Member] | Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [1] | 0 | [2] |
Level 2 [Member] | Mortgage Backed Securities (MBS) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Level 2 [Member] | Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Short Sales [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Municipal Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Collateralized Mortgage Obligations (CMOs) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Common and Collective Trusts [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [1] | 0 | [2] |
Level 3 [Member] | Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [1] | 0 | [2] |
Level 3 [Member] | Mortgage Backed Securities (MBS) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Level 3 [Member] | Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Accounts Receivable [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 4 | 10 | ||
Accounts Receivable [Member] | NAV [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Accounts Receivable [Member] | Level 1 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 4 | 10 | ||
Accounts Receivable [Member] | Level 2 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Accounts Receivable [Member] | Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Accounts Payable [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (70) | (88) | ||
Accounts Payable [Member] | NAV [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Accounts Payable [Member] | Level 1 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (70) | (88) | ||
Accounts Payable [Member] | Level 2 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Accounts Payable [Member] | Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 0 | $ 0 | ||
[1] | In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet of TECO Energy. | |||
[2] | In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet of TECO Energy. |
Employee Postretirement Bene_15
Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions | Dec. 31, 2021USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected Benefit Payments - 2022 | $ 69 |
Expected Benefit Payments - 2023 | 72 |
Expected Benefit Payments - 2024 | 69 |
Expected Benefit Payments - 2025 | 68 |
Expected Benefit Payments - 2026 | 66 |
Expected Benefit Payments - 2027-2031 | 302 |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected Benefit Payments - 2022 | 13 |
Expected Benefit Payments - 2023 | 14 |
Expected Benefit Payments - 2024 | 14 |
Expected Benefit Payments - 2025 | 14 |
Expected Benefit Payments - 2026 | 13 |
Expected Benefit Payments - 2027-2031 | $ 61 |
Short-Term Debt - Credit Facili
Short-Term Debt - Credit Facilities (Detail) - USD ($) | Dec. 31, 2021 | Dec. 31, 2020 | Oct. 30, 2020 | Jul. 14, 2020 |
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | $ 1,300,000,000 | $ 1,250,000,000 | ||
Borrowings Outstanding | 745,000,000 | 775,000,000 | ||
Letters of Credit Outstanding | 1,000,000 | 1,000,000 | ||
Credit Facilities [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 500,000,000 | |||
Commercial Paper [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 245,000,000 | |||
5-year Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | 800,000,000 | 800,000,000 | ||
Borrowings Outstanding | 345,000,000 | |||
Letters of Credit Outstanding | 1,000,000 | 1,000,000 | ||
5-year Facility [Member] | Credit Facilities [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 0 | |||
5-year Facility [Member] | Commercial Paper [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 245,000,000 | |||
3-year Accounts Receivable Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | 0 | 150,000,000 | $ 150,000,000 | $ 150,000,000 |
Borrowings Outstanding | 130,000,000 | |||
Letters of Credit Outstanding | 0 | 0 | ||
3-year Accounts Receivable Facility [Member] | Credit Facilities [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 0 | |||
3-year Accounts Receivable Facility [Member] | Commercial Paper [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 0 | |||
1-year Term Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | 500,000,000 | 300,000,000 | ||
Borrowings Outstanding | 300,000,000 | |||
Letters of Credit Outstanding | 0 | $ 0 | ||
1-year Term Facility [Member] | Credit Facilities [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | 500,000,000 | |||
1-year Term Facility [Member] | Commercial Paper [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Borrowings Outstanding | $ 0 |
Short-Term Debt - Credit Faci_2
Short-Term Debt - Credit Facilities (Parenthetical) (Detail) - USD ($) | Dec. 17, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | May 25, 2021 |
5-year Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit facility maturity date | Dec. 17, 2026 | Dec. 17, 2026 | ||
3-year Accounts Receivable Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit facility maturity date | Mar. 22, 2021 | Mar. 22, 2021 | ||
1-year Term Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit facility maturity date | Dec. 16, 2022 | Mar. 23, 2021 | Mar. 23, 2021 | |
Maximum [Member] | Commercial Paper Program [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Commercial paper issued | $ 800,000,000 | $ 800,000,000 |
Short-Term Debt - Additional In
Short-Term Debt - Additional Information (Detail) - USD ($) | Dec. 17, 2021 | Jan. 29, 2021 | Dec. 18, 2020 | Oct. 30, 2020 | Jul. 14, 2020 | Feb. 06, 2020 | Dec. 31, 2021 | Dec. 31, 2020 | May 25, 2021 |
Line Of Credit Facility [Line Items] | |||||||||
Commitment fees, percentage | 0.125% | ||||||||
Weighted-average interest rate | 0.58% | 0.89% | |||||||
Line of credit facility maximum borrowing capacity | $ 1,300,000,000 | $ 1,250,000,000 | |||||||
Lenders commitment amount | $ 800,000,000 | ||||||||
Increase of credit facility | $ 100,000,000 | $ 100,000,000 | |||||||
Commercial Paper Program [Member] | |||||||||
Line Of Credit Facility [Line Items] | |||||||||
Debt instrument, restrictive covenants | The maturities of the Notes will vary, but may not exceed 270 days from the date of issue. | ||||||||
3-year Accounts Receivable Facility [Member] | |||||||||
Line Of Credit Facility [Line Items] | |||||||||
Credit facility amendment date | Oct. 30, 2020 | Jul. 14, 2020 | |||||||
Line of credit facility maximum borrowing capacity | $ 150,000,000 | $ 150,000,000 | $ 0 | $ 150,000,000 | |||||
Credit facility maturity date | Mar. 22, 2021 | Mar. 22, 2021 | |||||||
364-day Credit Agreement [Member] | |||||||||
Line Of Credit Facility [Line Items] | |||||||||
Line of credit facility maximum borrowing capacity | $ 500,000,000 | $ 300,000,000 | |||||||
Credit facility maturity period | 364 days | 364 days | |||||||
Credit Facility extended maturity date | Apr. 29, 2021 | ||||||||
Credit facility maturity date | Dec. 16, 2022 | Mar. 23, 2021 | |||||||
Minimum [Member] | Amended And Restated Credit Agreement [Member] | |||||||||
Line Of Credit Facility [Line Items] | |||||||||
Debt instrument maturity date | Mar. 22, 2023 | Mar. 22, 2022 | |||||||
Maximum [Member] | Amended And Restated Credit Agreement [Member] | |||||||||
Line Of Credit Facility [Line Items] | |||||||||
Debt instrument maturity date | Dec. 17, 2026 | Mar. 22, 2023 | |||||||
Maximum [Member] | Commercial Paper Program [Member] | |||||||||
Line Of Credit Facility [Line Items] | |||||||||
Commercial paper issued | $ 800,000,000 | $ 800,000,000 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) $ in Millions | Mar. 18, 2021USD ($) |
2.40% Notes [Member] | |
Debt Instrument [Line Items] | |
Debt instrument, maturity year | 2031 |
Aggregate principal amount issued | $ 400 |
Stated interest rate | 2.40% |
Debt instrument maturity date | Mar. 15, 2031 |
Redeemable principal amount percentage | 100.00% |
Basis spread on federal funds rate | 0.15% |
Redeemable principal amount percentage | 100.00% |
Debt instrument, start date of redemption | Dec. 15, 2030 |
Debt instrument, offering date | Mar. 18, 2021 |
3.45% Notes [Member] | |
Debt Instrument [Line Items] | |
Debt instrument, maturity year | 2051 |
Aggregate principal amount issued | $ 400 |
Stated interest rate | 3.45% |
Debt instrument maturity date | Mar. 15, 2051 |
Redeemable principal amount percentage | 100.00% |
Basis spread on federal funds rate | 0.20% |
Redeemable principal amount percentage | 100.00% |
Debt instrument, start date of redemption | Sep. 15, 2050 |
Debt instrument, offering date | Mar. 18, 2021 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
PGS [Member] | ||
Long Term Commitments [Line Items] | ||
Ultimate financial liability to superfund sites and former MGP sites | $ 14 | $ 17 |
Commitments and Contingencies_2
Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions | Dec. 31, 2021USD ($) |
Other Commitments [Line Items] | |
2022 | $ 822 |
2023 | 360 |
2024 | 246 |
2025 | 221 |
2026 | 218 |
Thereafter | 1,971 |
Total future minimum payments | 3,838 |
Purchased Power [Member] | |
Other Commitments [Line Items] | |
2022 | 2 |
2023 | 0 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 0 |
Total future minimum payments | 2 |
Transportation [Member] | |
Other Commitments [Line Items] | |
2022 | 244 |
2023 | 224 |
2024 | 215 |
2025 | 200 |
2026 | 197 |
Thereafter | 1,871 |
Total future minimum payments | 2,951 |
Capital Projects [Member] | |
Other Commitments [Line Items] | |
2022 | 202 |
2023 | 63 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 0 |
Total future minimum payments | 265 |
Fuel and Gas Supply [Member] | |
Other Commitments [Line Items] | |
2022 | 349 |
2023 | 27 |
2024 | 0 |
2025 | 0 |
2026 | 0 |
Thereafter | 0 |
Total future minimum payments | 376 |
Long-term Service Agreements [Member] | |
Other Commitments [Line Items] | |
2022 | 20 |
2023 | 42 |
2024 | 27 |
2025 | 19 |
2026 | 20 |
Thereafter | 52 |
Total future minimum payments | 180 |
Operating Leases [Member] | |
Other Commitments [Line Items] | |
2022 | 3 |
2023 | 3 |
2024 | 3 |
2025 | 2 |
2026 | 1 |
Thereafter | 48 |
Total future minimum payments | 60 |
Demand Side Management [Member] | |
Other Commitments [Line Items] | |
2022 | 2 |
2023 | 1 |
2024 | 1 |
2025 | 0 |
2026 | 0 |
Thereafter | 0 |
Total future minimum payments | $ 4 |
Commitments and Contingencies_3
Commitments and Contingencies - Schedule of Long-term Commitments (Parenthetical) (Detail) $ in Millions | Dec. 31, 2021USD ($) |
Other Commitments [Line Items] | |
Total future minimum payments | $ 3,838 |
Gas Transportation [Member] | PGS and SeaCoast [Member] | |
Other Commitments [Line Items] | |
Total future minimum payments | $ 112 |
Revenue - Summary of Disaggrega
Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | $ 2,170 | $ 1,845 | $ 1,961 |
Total gas revenue | 525 | 427 | 443 |
Total revenue | 2,695 | 2,272 | 2,404 |
Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 1,156 | 1,018 | 1,046 |
Total gas revenue | 212 | 158 | 154 |
Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 602 | 506 | 562 |
Total gas revenue | 191 | 135 | 146 |
Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 172 | 133 | 156 |
Total gas revenue | 25 | 23 | 21 |
Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (8) | (25) | (49) |
Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 248 | 213 | 246 |
Total gas revenue | 97 | 111 | 122 |
Eliminations [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (4) | (4) | (4) |
Total gas revenue | (3) | (6) | (18) |
Total revenue | (7) | (10) | (22) |
Eliminations [Member] | Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 0 | 0 | 0 |
Eliminations [Member] | Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 0 | 0 | 0 |
Eliminations [Member] | Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 0 | 0 | 0 |
Eliminations [Member] | Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Eliminations [Member] | Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (4) | (4) | (4) |
Total gas revenue | (3) | (6) | (18) |
Tampa Electric [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 2,174 | 1,849 | 1,965 |
Total gas revenue | 0 | 0 | 0 |
Total revenue | 2,174 | 1,849 | 1,965 |
Tampa Electric [Member] | Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 1,156 | 1,018 | 1,046 |
Total gas revenue | 0 | 0 | 0 |
Tampa Electric [Member] | Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 602 | 506 | 562 |
Total gas revenue | 0 | 0 | 0 |
Tampa Electric [Member] | Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 172 | 133 | 156 |
Total gas revenue | 0 | 0 | 0 |
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (8) | (25) | (49) |
Tampa Electric [Member] | Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 252 | 217 | 250 |
Total gas revenue | 0 | 0 | 0 |
PGS [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 528 | 433 | 461 |
Total revenue | 528 | 433 | 461 |
PGS [Member] | Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 212 | 158 | 154 |
PGS [Member] | Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 191 | 135 | 146 |
PGS [Member] | Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | 25 | 23 | 21 |
PGS [Member] | Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
PGS [Member] | Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | 0 | 0 |
Total gas revenue | $ 100 | $ 117 | $ 140 |
Revenue - Additional Informatio
Revenue - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Disaggregation Of Revenue [Line Items] | ||
Remaining performance obligations, transaction price | $ 135 | $ 135 |
Remaining performance obligations, expected year of revenue recognition | 2041 | |
Gas Transportation [Member] | PGS and SeaCoast [Member] | ||
Disaggregation Of Revenue [Line Items] | ||
Remaining performance obligations, transaction price | $ 112 | |
Remaining performance obligations, expected year of revenue recognition | 2040 |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Related Party Transaction [Line Items] | |||
Natural gas sales to/(from) affiliates | $ (236) | $ (139) | $ (111) |
Services received from affiliates | 7 | 6 | 65 |
Dividends to TECO Energy | 450 | 408 | 373 |
Equity contributions from TECO Energy | 580 | 505 | 395 |
Affiliate [Member] | |||
Related Party Transaction [Line Items] | |||
Accounts receivable excluding asset management agreements | 4 | 7 | |
Accounts payable | 35 | 27 | |
Taxes payable | 9 | 19 | |
Emera Energy Services Inc [Member] | |||
Related Party Transaction [Line Items] | |||
Accounts receivable related to asset management agreements to Emera Energy Services Inc. | 4 | 4 | |
TECO Energy [Member] | |||
Related Party Transaction [Line Items] | |||
Dividends to TECO Energy | 450 | 408 | 373 |
Equity contributions from TECO Energy | $ 580 | $ 505 | $ 395 |
Segment Information - Additiona
Segment Information - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2021SegmentCustomer | |
Segment Reporting Information [Line Items] | |
Number of operating segments | Segment | 2 |
Tampa Electric [Member] | |
Segment Reporting Information [Line Items] | |
Number of retail electric utility service customers in West Central Florida | 810,600 |
PGS [Member] | Minimum [Member] | |
Segment Reporting Information [Line Items] | |
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution | 445,300 |
Segment Information - Schedule
Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Segment Reporting Information [Line Items] | |||
Total revenues | $ 2,695 | $ 2,272 | $ 2,404 |
Depreciation and amortization | 430 | 384 | 377 |
Total interest charges | 130 | 130 | 134 |
Provision for income taxes | 80 | 82 | 77 |
Net income | 446 | 424 | 370 |
Total assets | 12,196 | 11,048 | 10,007 |
Capital expenditures | 1,397 | 1,361 | 1,283 |
Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,695 | 2,272 | 2,404 |
Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | 0 | 0 | 0 |
Eliminations [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | (7) | (10) | (22) |
Depreciation and amortization | 0 | 0 | 0 |
Total interest charges | 0 | 0 | 0 |
Provision for income taxes | 0 | 0 | 0 |
Net income | 0 | 0 | 0 |
Total assets | (663) | (653) | (593) |
Capital expenditures | 0 | 0 | 0 |
Eliminations [Member] | Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 0 | 0 | 0 |
Eliminations [Member] | Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | (7) | (10) | (22) |
Tampa Electric [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,174 | 1,849 | 1,965 |
Tampa Electric [Member] | Operating Segments [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,174 | 1,849 | 1,965 |
Depreciation and amortization | 374 | 339 | 336 |
Total interest charges | 110 | 113 | 117 |
Provision for income taxes | 57 | 66 | 59 |
Net income | 369 | 372 | 316 |
Total assets | 10,650 | 9,800 | 9,007 |
Capital expenditures | 1,081 | 1,028 | 1,055 |
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,170 | 1,845 | 1,961 |
Tampa Electric [Member] | Operating Segments [Member] | Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | 4 | 4 | 4 |
PGS [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 528 | 433 | 461 |
PGS [Member] | Operating Segments [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 528 | 433 | 461 |
Depreciation and amortization | 56 | 45 | 41 |
Total interest charges | 20 | 17 | 17 |
Provision for income taxes | 23 | 16 | 18 |
Net income | 77 | 52 | 54 |
Total assets | 2,209 | 1,901 | 1,593 |
Capital expenditures | 316 | 333 | 228 |
PGS [Member] | Operating Segments [Member] | Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 525 | 427 | 443 |
PGS [Member] | Operating Segments [Member] | Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | $ 3 | $ 6 | $ 18 |
Asset Retirement Obligations -
Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Beginning balance | $ 39 | $ 49 |
Additional liabilities | 0 | 8 |
Liabilities settled | (9) | (19) |
Other | 1 | 1 |
Ending balance | $ 31 | $ 39 |
Leases - Additional Information
Leases - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating Leased Assets [Line Items] | |||
Operating lease, description | TEC has operating leases for buildings, land, telecommunication services and rail cars. | ||
Operating lease, existence of option to extend | true | ||
Operating lease options to extend | options to extend the leases for up to an additional 65 years. | ||
Operating lease expense | $ 5 | $ 4 | $ 4 |
Option to purchase assets related to CNG stations | Customers have the option to purchase the assets related to the CNG stations at any time after year five of the agreements, which was in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. | ||
Maximum [Member] | |||
Operating Leased Assets [Line Items] | |||
Operating lease renewal term | 64 years | ||
Minimum [Member] | |||
Operating Leased Assets [Line Items] | |||
Operating lease renewal term | 1 year |
Leases - Summary of Lease Asset
Leases - Summary of Lease Assets and Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Schedule Of Assets And Liabilities Lessee [Line Items] | ||
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other Assets Noncurrent | Other Assets Noncurrent |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other Liabilities Current | Other Liabilities Current |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Deferred Credits And Other Liabilities Noncurrent | Deferred Credits And Other Liabilities Noncurrent |
Total lease liabilities | $ 25 | $ 27 |
Other Deferred Debits [Member] | ||
Schedule Of Assets And Liabilities Lessee [Line Items] | ||
Right-of-use asset | 24 | 26 |
Other Current Liabilities [Member] | ||
Schedule Of Assets And Liabilities Lessee [Line Items] | ||
Current | 2 | 2 |
Deferred Credits and Other Liabilities [Member] | ||
Schedule Of Assets And Liabilities Lessee [Line Items] | ||
Long-term | $ 23 | $ 25 |
Leases - Future Minimum Lease P
Leases - Future Minimum Lease Payments (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Leases [Abstract] | ||
Minimum lease payments, 2022 | $ 3 | |
Minimum lease payments, 2023 | 3 | |
Minimum lease payments, 2024 | 3 | |
Minimum lease payments, 2025 | 2 | |
Minimum lease payments, 2026 | 1 | |
Minimum lease payments, Thereafter | 47 | |
Minimum lease payments, Total | 59 | |
Imputed interest, Total | (34) | |
Total lease liabilities | $ 25 | $ 27 |
Leases - Additional Informati_2
Leases - Additional Information Related to Leases (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Leases [Abstract] | ||
Operating cash flows for operating leases (millions) | $ 4 | $ 5 |
Weighted average remaining lease term (years) | 44 years | 43 years |
Weighted average discount rate - operating leases | 4.40% | 4.30% |
Leases - Net Investment in Dire
Leases - Net Investment in Direct Finance Leases (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Leases [Abstract] | ||
Total minimum lease payments to be received | $ 29 | $ 31 |
Less amounts representing estimated executory costs | (11) | (12) |
Minimum lease payments receivable | 18 | 19 |
Less unearned finance lease income | (9) | (10) |
Net investment in direct finance and sales-type leases | 9 | 9 |
Principal due within one year (included in "Receivables") | (2) | (2) |
Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits") | $ 7 | $ 7 |
Leases - Future Minimum Direct
Leases - Future Minimum Direct Finance Lease Payments to be Received (Detail) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Leases [Abstract] | ||
Minimum lease payments to be received, 2022 | $ 2 | |
Minimum lease payments to be received, 2023 | 2 | |
Minimum lease payments to be received, 2024 | 2 | |
Minimum lease payments to be received, 2025 | 2 | |
Minimum lease payments to be received, 2026 | 2 | |
Minimum lease payments to be received, Thereafter | 19 | |
Minimum lease payments to be received, Total | 29 | $ 31 |
Executory costs, Total | (11) | |
Minimum lease payments receivable | $ 18 | $ 19 |
Accounting for Derivative Instr
Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Natural Gas Contracts [Member] | ||
Derivative [Line Items] | ||
Maximum length of time hedging in future cash flow | Nov. 30, 2018 | |
Natural Gas Storage and Transportation [Member] | ||
Derivative [Line Items] | ||
Derivative assets | $ 0 | $ 0 |
Derivative liabilities | $ 0 | $ 0 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) - Performance Share Unit Plan [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
PSU/RSU performance cycles | 3 years | ||
Number of trading days | 50 days | ||
Compensation cost recognized | $ 3 | $ 8 | $ 8 |
Tax benefits related to compensation cost | 1 | 2 | 2 |
Cash payment associated with PSU | 10 | 9 | $ 0 |
Unrecognized compensation cost | $ 3 | $ 5 | |
Weighted-average period expected to be recognized | 2 years |
Stock-Based Compensation - Summ
Stock-Based Compensation - Summary of Activity Related to Employee PSUs (Detail) - Performance Share Unit Plan [Member] $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended |
Dec. 31, 2021CAD ($)$ / sharesshares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Number of Units, Outstanding as of December 31, 2020 | shares | 390 |
Number of Units, Granted including DRIP | shares | 91 |
Number of Units, Exercised | shares | (175) |
Number of Units, Forfeited | shares | (26) |
Number of Units, Transferred | shares | (5) |
Number of Units, Outstanding as of December 31, 2020 | shares | 285 |
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2020 | $ / shares | $ 46.87 |
Weighted Average Grant Date Fair Value, Granted including DRIP | $ / shares | 52.25 |
Weighted Average Grant Date Fair Value, Exercised | $ / shares | 48.12 |
Weighted Average Grant Date Fair Value, Forfeited | $ / shares | 47.82 |
Weighted Average Grant Date Fair Value, Transferred | $ / shares | 47.18 |
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2020 | $ / shares | $ 47.74 |
Aggregate Intrinsic Value, Outstanding as of December 31, 2020 | $ | $ 21 |
Aggregate Intrinsic Value, Granted including DRIP | $ | 5 |
Aggregate Intrinsic Value, Exercised | $ | 10 |
Aggregate Intrinsic Value, Forfeited | $ | 1 |
Aggregate Intrinsic Value, Transferred | $ | 0 |
Aggregate Intrinsic Value, Outstanding as of December 31, 2020 | $ | $ 18 |
Long-Term PPAs - Additional Inf
Long-Term PPAs - Additional Information (Detail) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($)MW | |
Long Term Contract For Purchase Of Electric Power [Line Items] | |||
Purchased power | $ 106 | $ 83 | $ 49 |
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member] | |||
Long Term Contract For Purchase Of Electric Power [Line Items] | |||
Purchased power | $ 46 | $ 36 | $ 25 |
Maximum [Member] | |||
Long Term Contract For Purchase Of Electric Power [Line Items] | |||
PPAs range | MW | 515 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - Allowance for Credit Losses - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Valuation And Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of Period | $ 7 | $ 2 | $ 2 | |
Charged to Income | 8 | 9 | 5 | |
Other Charges | 0 | 0 | 0 | |
Payments & Deductions | [1] | 8 | 4 | 5 |
Balance at End of Period | $ 7 | $ 7 | $ 2 | |
[1] | Write-off of individual bad debt accounts |