Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 12, 2019 | Jun. 30, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | ck0000096271 | ||
Entity Registrant Name | TAMPA ELECTRIC COMPANY | ||
Entity Central Index Key | 96,271 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 10 | ||
Entity Public Float | $ 0 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Property, plant and equipment | ||
Utility plant, at original costs | $ 11,438 | $ 10,427 |
Accumulated depreciation | (3,214) | (2,994) |
Utility plant, net | 8,224 | 7,433 |
Other property | 12 | 11 |
Total property, plant and equipment, net | 8,236 | 7,444 |
Current assets | ||
Cash and cash equivalents | 15 | 13 |
Receivables, less allowance for uncollectibles of $2 and $1 at December 31, 2018 and 2017, respectively | 258 | 257 |
Due from affiliates | 4 | 5 |
Inventories, at average cost | ||
Regulatory assets | 88 | 77 |
Prepayments and other current assets | 6 | 13 |
Total current assets | 517 | 515 |
Deferred debits | ||
Regulatory assets | 370 | 356 |
Other | 32 | 49 |
Total deferred debits | 402 | 405 |
Total assets | 9,155 | 8,364 |
Capitalization | ||
Common stock | 2,990 | 2,645 |
Accumulated other comprehensive loss | (1) | (2) |
Retained earnings | 314 | 335 |
Total capital | 3,303 | 2,978 |
Long-term debt, less amount due within one year | 2,575 | 1,860 |
Total capital | 5,878 | 4,838 |
Current liabilities | ||
Long-term debt due within one year | 0 | 304 |
Notes payable | 221 | 305 |
Accounts payable | 251 | 233 |
Due to affiliates | 24 | 21 |
Customer deposits | 132 | 131 |
Regulatory liabilities | 44 | 58 |
Accrued interest | 16 | 14 |
Accrued taxes | 13 | 12 |
Other | 84 | 44 |
Total current liabilities | 785 | 1,122 |
Long-term liabilities | ||
Deferred income taxes | 799 | 825 |
Regulatory liabilities | 1,266 | 1,227 |
Deferred credits and other liabilities | 427 | 352 |
Total deferred credits | 2,492 | 2,404 |
Commitments and Contingencies (see Note 8) | ||
Total liabilities and capital | 9,155 | 8,364 |
Fuel [Member] | ||
Inventories, at average cost | ||
Utility inventories | 46 | 60 |
Materials and Supplies [Member] | ||
Inventories, at average cost | ||
Utility inventories | 100 | 90 |
Electric [Member] | ||
Property, plant and equipment | ||
Utility plant, at original costs | 9,645 | 8,794 |
Gas [Member] | ||
Property, plant and equipment | ||
Utility plant, at original costs | $ 1,793 | $ 1,633 |
Consolidated Condensed Balance
Consolidated Condensed Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Statement Of Financial Position [Abstract] | ||
Allowance for uncollectibles | $ 2 | $ 1 |
Consolidated Statements of Inco
Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues | |||
Electric | $ 2,063 | $ 2,052 | $ 1,964 |
Gas | 461 | 418 | 432 |
Total revenues | 2,524 | 2,470 | 2,396 |
Expenses | |||
Fuel | 551 | 588 | 561 |
Purchased power | 59 | 46 | 104 |
Cost of natural gas sold | $ 180 | $ 153 | $ 159 |
Type of Cost, Good or Service [Extensible List] | us-gaap:OilAndGasMember | us-gaap:OilAndGasMember | us-gaap:OilAndGasMember |
Operations & maintenance | $ 632 | $ 513 | $ 538 |
Depreciation and amortization | 372 | 350 | 328 |
Taxes, other than income | 208 | 198 | 193 |
Total expenses | 2,002 | 1,848 | 1,883 |
Income from operations | 522 | 622 | 513 |
Other income | |||
Allowance for other funds used during construction | 10 | 2 | 24 |
Other income, net | 8 | 8 | 7 |
Total other income | 18 | 10 | 31 |
Interest charges | |||
Interest expense | 123 | 120 | 117 |
Allowance for borrowed funds used during construction | (5) | (1) | (11) |
Total interest charges | 118 | 119 | 106 |
Income before provision for income taxes | 422 | 513 | 438 |
Provision for income taxes | 81 | 197 | 152 |
Net income | 341 | 316 | 286 |
Other comprehensive income, net of tax | |||
Gain on cash flow hedges | 1 | 1 | 1 |
Total other comprehensive income, net of tax | 1 | 1 | 1 |
Comprehensive income | $ 342 | $ 317 | $ 287 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities | |||
Net income | $ 341 | $ 316 | $ 286 |
Adjustments to reconcile net income to net cash from operating activities: | |||
Depreciation and amortization | 372 | 350 | 328 |
Deferred income taxes and investment tax credits | (1) | 192 | 87 |
Allowance for equity funds used during construction | (10) | (2) | (24) |
Deferred recovery clauses | (55) | (83) | 54 |
Receivables, less allowance for uncollectibles | (2) | (43) | 18 |
Inventories | 4 | 13 | 16 |
Taxes accrued | 6 | (9) | 68 |
Accounts payable | 11 | (16) | 63 |
Regulatory assets and liabilities | 98 | (100) | (11) |
Other | 38 | (6) | (54) |
Cash flows from operating activities | 802 | 612 | 831 |
Cash flows used in investing activities | |||
Capital expenditures | (1,109) | (640) | (727) |
Net proceeds from sale of assets | 1 | 0 | 9 |
Cash flows used in investing activities | (1,108) | (640) | (718) |
Cash flows from or used in financing activities | |||
Equity contributions from TECO Energy | 345 | 190 | |
Proceeds from long-term debt issuance | 714 | 0 | 0 |
Repayment of long-term debt | (304) | 0 | (83) |
Net change in short-term debt (maturities of 90 days or less) | 216 | (165) | 109 |
Proceeds from other short-term debt (maturities over 90 days) | 0 | 300 | 0 |
Repayment of other short-term debt (maturities over 90 days) | (300) | 0 | 0 |
Dividends to TECO Energy | (362) | (292) | |
Other financing activities | (1) | (2) | 1 |
Cash flows from/(used in) financing activities | 308 | 31 | (112) |
Net increase in cash and cash equivalents | 2 | 3 | 1 |
Cash and cash equivalents at beginning of the year | 13 | 10 | 9 |
Cash and cash equivalents at end of the year | 15 | 13 | 10 |
Supplemental disclosure of cash paid (received): | |||
Interest | 112 | 115 | 103 |
Income taxes | 77 | 13 | (3) |
Supplemental disclosure of non-cash activities | |||
Change in accrued capital expenditures | 40 | (16) | (9) |
TECO Energy [Member] | |||
Cash flows from or used in financing activities | |||
Equity contributions from TECO Energy | 345 | 190 | 150 |
Dividends to TECO Energy | $ (362) | $ (292) | $ (289) |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Parenthetical) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Statement Of Cash Flows [Abstract] | |
Change in deferred taxes as result of tax reform offset to regulatory liability | $ 755 |
Consolidated Statements of Reta
Consolidated Statements of Retained Earnings - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Statement Of Partners Capital [Abstract] | |||
Beginning Balance | $ 335 | $ 311 | $ 314 |
Add: Net income | 341 | 316 | 286 |
Retained Earning, Gross | 676 | 627 | 600 |
Deduct: Cash dividends on capital stock—common | 362 | 292 | 289 |
Ending Balance | $ 314 | $ 335 | $ 311 |
Consolidated Statements of Capi
Consolidated Statements of Capitalization - Capital Stock - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Regulated Operations [Abstract] | ||
Common equity, shares authorized | 25,000,000 | 25,000,000 |
Capital Stock Outstanding December 31, Shares | 10 | 10 |
Capital Stock Outstanding December 31, Amount | $ 2,990 | $ 2,645 |
Cash Dividends Paid | $ 362 | $ 292 |
Consolidated Statements of Ca_3
Consolidated Statements of Capitalization - Capital Stock (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Preferred stock - par value | $ 100 | |
Preferred stock, no par value | ||
Equity contributions made by TECO Energy | $ 345 | $ 190 |
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 | |
Preference Stock No Par Value | ||
Preferred stock, shares authorized | 2,500,000 | |
Preferred stock, shares outstanding | 0 |
Consolidated Statements of Ca_4
Consolidated Statements of Capitalization - Long-Term Debt - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | ||
Long-term debt, total | $ 2,604 | $ 2,183 |
Unamortized debt discount, net | (7) | (3) |
Debt issuance costs | (22) | (16) |
Long-term debt, carrying amount | 2,575 | 2,164 |
Less amount due within one year | 0 | 304 |
Total long-term debt | 2,575 | 1,860 |
Long-term debt, fair value | 2,686 | 2,412 |
Level 1 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, fair value | 0 | 55 |
Tampa Electric [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, total | 2,292 | 1,921 |
Long-term debt, carrying amount | $ 2,292 | |
Tampa Electric [Member] | 5.65% Refunding bonds [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,018 | |
Long-term debt, total | $ 0 | 54 |
Tampa Electric [Member] | 6.10% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,018 | |
Long-term debt, total | $ 0 | 200 |
Tampa Electric [Member] | 5.40% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,021 | |
Long-term debt, total | $ 232 | 232 |
Tampa Electric [Member] | 2.60% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,022 | |
Long-term debt, total | $ 225 | 225 |
Tampa Electric [Member] | 6.55% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,036 | |
Long-term debt, total | $ 250 | 250 |
Tampa Electric [Member] | 6.15% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,037 | |
Long-term debt, total | $ 190 | 190 |
Tampa Electric [Member] | 4.10% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,042 | |
Long-term debt, total | $ 250 | 250 |
Tampa Electric [Member] | 4.35% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,044 | |
Long-term debt, total | $ 290 | 290 |
Tampa Electric [Member] | 4.20% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,045 | |
Long-term debt, total | $ 230 | 230 |
Tampa Electric [Member] | 4.30% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,048 | |
Long-term debt, total | $ 275 | 0 |
Tampa Electric [Member] | 4.45% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,049 | |
Long-term debt, total | $ 350 | 0 |
PGS [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, total | 312 | 262 |
Long-term debt, carrying amount | $ 312 | |
PGS [Member] | 6.10% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,018 | |
Long-term debt, total | $ 0 | 50 |
PGS [Member] | 5.40% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,021 | |
Long-term debt, total | $ 47 | 47 |
PGS [Member] | 2.60% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,022 | |
Long-term debt, total | $ 25 | 25 |
PGS [Member] | 6.15% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,037 | |
Long-term debt, total | $ 60 | 60 |
PGS [Member] | 4.10% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,042 | |
Long-term debt, total | $ 50 | 50 |
PGS [Member] | 4.35% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,044 | |
Long-term debt, total | $ 10 | 10 |
PGS [Member] | 4.20% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,045 | |
Long-term debt, total | $ 20 | 20 |
PGS [Member] | 4.30% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,048 | |
Long-term debt, total | $ 75 | 0 |
PGS [Member] | 4.45% Notes [Member] | ||
Debt Instrument [Line Items] | ||
Due | 2,049 | |
Long-term debt, total | $ 25 | $ 0 |
Consolidated Statements of Ca_5
Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) | Dec. 31, 2018 |
Tampa Electric [Member] | 5.65% Refunding bonds [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 5.65% |
Tampa Electric [Member] | 6.10% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 6.10% |
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] | 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% |
PGS [Member] | 6.10% Notes [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate | 6.10% |
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] | 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% |
Consolidated Statements of Ca_6
Consolidated Statements of Capitalization - Long-term Debt Maturities $ in Millions | Dec. 31, 2018USD ($) |
Debt Instrument [Line Items] | |
Total long-term debt maturities | $ 2,575 |
Long Term Debt Maturities | |
Debt Instrument [Line Items] | |
2,019 | 0 |
2,020 | 0 |
2,021 | 279 |
2,022 | 250 |
2,023 | 0 |
Thereafter | 2,075 |
Total long-term debt maturities | 2,604 |
Tampa Electric [Member] | |
Debt Instrument [Line Items] | |
2,019 | 0 |
2,020 | 0 |
2,021 | 232 |
2,022 | 225 |
2,023 | 0 |
Thereafter | 1,835 |
Total long-term debt maturities | 2,292 |
PGS [Member] | |
Debt Instrument [Line Items] | |
2,019 | 0 |
2,020 | 0 |
2,021 | 47 |
2,022 | 25 |
2,023 | 0 |
Thereafter | 240 |
Total long-term debt maturities | $ 312 |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | 1. Description of Business TEC has two operating segments. Its Tampa Electric 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. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned indirect subsidiary of Emera. Therefore, TEC became an indirect, wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. 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, 2018 December 31, 2017 Electric generation 21-56 years $ 5,038 $ 4,766 Electric transmission 28-77 years 880 859 Electric distribution 14-56 years 2,568 2,437 Gas transmission and distribution 16-77 years 1,678 1,534 General plant and other 8-43 years 613 579 Total cost 10,777 10,175 Less accumulated depreciation (3,214 ) (2,994 ) Construction work in progress 673 263 Total property, plant and equipment, net $ 8,236 $ 7,444 Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.7% and 3.5% for 2018, 2017 and 2016, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2018, 2017 and 2016 was $345 million, $332 million and $304 million, respectively. See Note 3 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 FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2018, 2017 and 2016, the rate was 6.46%. Total AFUDC for the years ended December 31, 2018, 2017 and 2016 was $15 million, $2 million and $36 million, respectively. The increase in 2018 is a result of the construction of solar projects and the repowering of Big Bend Unit 1 with natural gas combined-cycle technology. The decrease in 2017 is a result of the Polk Power Station conversion project, which was completed in January 2017 Inventory TEC values materials, supplies and fossil fuel inventory (natural gas, coal, petcoke 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, unless evidence indicates that the weighted-average cost will be recovered with a normal profit upon sale in the ordinary course of business. 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 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. As of December 31, 2018 and 2017, ITCs were $74 million and $22 million, respectively. The increase is due to solar projects placed in service in 2018. 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. TEC’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, weather 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. TEC’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 and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity 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 billed. Receivables and Allowance for Uncollectible Accounts Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $226 million and $229 million as of December 31, 2018 and 2017, respectively. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of fuel prices, customer deposits and general economic conditions. Accounts are 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 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 $120 million, $113 million and $117 million for the years ended December 31, 2018, 2017 and 2016, respectively. Deferred Credits and Other Liabilities Other deferred credits primarily include accrued postretirement and pension liabilities (see Note 5 Note 8 Note 12 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, 2018 and 2017 ranged from 4.00% to 4.01% and 2.74% to 4.00%, respectively. Cash Flows Related to Derivatives and Hedging Activities 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. See Note 13 Reclassifications Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TEC’s net income or financial position in any period. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Changes And Error Corrections [Abstract] | |
New Accounting Pronouncements | 2. New Accounting Pronouncements Change in Accounting Policy Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Revenue from Contracts with Customers On January 1, 2018, TEC adopted ASU 2014-09, Revenue from Contracts with Customers TEC adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to TEC’s opening retained earnings as of the adoption date. The impact of the adoption of the new standard was immaterial to TEC’s net income and is expected to be immaterial on an ongoing basis. Recognition and Measurement of Financial Assets and Financial Liabilities On January 1, 2018, TEC adopted ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities Clarifying the Definition of a Business In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business Future Accounting Pronouncements Leases In February 2016, the FASB issued ASU 2016-02, Leases In January 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. TEC will make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. TEC will make this election. Additionally, TEC will elect the options that allow it to not reassess whether any expired or existing contracts contain leases, carry forward existing lease classification, use hindsight to determine the lease term for existing leases and not separate lease components from non-lease components for all lessee and lessor arrangements. Over the past several years, TEC developed and executed a project plan which included holding training sessions with key stakeholders throughout the organization, gathering detailed information on existing lease arrangements, evaluating implementation alternatives and calculating the lease asset and liability balances associated with individual contractual arrangements. TEC has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. Updates to systems are not required as a result of implementation of this standard. The adoption of this standard will affect TEC’s financial position by increasing assets and liabilities related to operating leases by approximately $20 million, with no impact to TEC’s Consolidated Statements of Income. There will be no significant changes to TEC’s accounting for lessor arrangements as a result of the adoption of the standard. TEC is in the process of assessing the disclosure requirements and continues to monitor FASB amendments to ASC Topic 842. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach. TEC is currently evaluating the impact of adoption of this standard on its consolidated financial statements. Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, Cloud Computing In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. |
Regulatory
Regulatory | 12 Months Ended |
Dec. 31, 2018 | |
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 cost of providing service, plus a reasonable return on invested capital. Tampa Electric Base Rates-2013 Agreement Tampa Electric’s results for 2017 and 2016 reflect the stipulation and settlement agreement entered into on September 6, 2013, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. This agreement provided for an additional $110 million in base revenue effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. 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 provided that Tampa Electric could not file for additional base rate increases to be effective sooner than January 1, 2018, 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 is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software. Tampa Electric Base Rates-2017 Agreement On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaced the existing 2013 base rate settlement agreement described above and extended it another four years through 2021. The FPSC approved the agreement on November 6, 2017. The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. It includes the following potential revenue adjustments for the SoBRAs: $31 million for 150 MWs effective September 1, 2018, $51 million for 250 MWs effective January 1, 2019, $31 million for 150 MWs effective January 1, 2020, and an additional $10 million for 50 MWs effective on January 1, 2021. In order for each tranche of SoBRAs to take effect, Tampa Electric must show they are cost-effective and each individual project has a cost cap of $1,500/kWac. Additionally, in order to receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC during construction. On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018 requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018 and TEC began receiving these revenues in January 2019. The agreement further maintains Tampa Electric’s allowed regulatory ROE and allowed equity in the capital structure and extends the rate freeze date from January 1, 2018 to December 31, 2021, subject to the same ROE thresholds. The agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law. Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. 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. 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. At December 31, 2017, the amount of costs charged to the storm reserve regulatory liability exceeded the balance in the storm reserve by $47 million, which was recorded as a regulatory asset on the balance sheet as allowed by an FPSC order. This regulatory asset amount was eliminated in 2018 to reflect the effective recovery as discussed in Tampa Electric Tax Reform and Storm Settlement below. 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. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below. Tampa Electric Tax Reform and Storm Settlement On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addressed both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) PGS Base Rates and Impact of Tax Reform PGS’s base rates were established in May 2009 and reflect an allowed ROE range of 9.75% to 11.75% with base rates set at the middle of the range of 10.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital. On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. On December 15, 2016, PGS and OPC filed a settlement with the FPSC (which was approved by the FPSC on February 7, 2017) agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, 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 decrease the bottom of the ROE range from 9.75% to 9.25%. The settlement agreement provided that the bottom of the range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020, the top of the range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. No change in customer rates resulted from this agreement. As part of the settlement, PGS and OPC agreed The 2017 PGS settlement agreement did not contain a provision for tax reform. In 2018, the FPSC approved a settlement agreement filed authorizing the utility to accelerate the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability in 2018 up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS recorded amortization expense and a regulatory asset reduction of $11 million in 2018. In accordance with the settlement agreement, PGS will reduce its base rates by $12 million for the impact of tax reform and reduce depreciation rates by $10 million beginning in January 2019. PGS is permitted to initiate a general base rate proceeding in 2020 if it forecasts that ROE will fall below its allowed range. Regulatory Assets and Liabilities Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. 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 or the advance recovery of expenditures for approved costs. Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2018 2017 Regulatory assets: Regulatory tax asset (1) $ 56 $ 45 Cost-recovery clauses (2) 55 13 Environmental remediation (3) 23 33 Postretirement benefits (4) 295 272 Storm reserve (5) 3 47 Other 26 23 Total regulatory assets 458 433 Less: Current portion 88 77 Long-term regulatory assets $ 370 $ 356 Regulatory liabilities: Regulatory tax liability (6) $ 715 $ 730 Cost-recovery clauses (2) 17 32 Storm reserve (7) 56 0 Accumulated reserve—cost of removal (8) 513 518 Other 9 5 Total regulatory liabilities 1,310 1,285 Less: Current portion 44 58 Long-term regulatory liabilities $ 1,266 $ 1,227 (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 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 the next year. (3) 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. (4) 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. (5) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding (6) 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 income tax rate. The liability related to the revaluation of the deferred income tax balances will be amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and a settlement agreement for tax reform benefits approved by the FPSC. See Note 4 TEC Consolidated Financial Statements (7) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory liability is being replenished to the FPSC-allowed storm reserve balance of $56 million. (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. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 4. Income Taxes On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of tax reform proposals affecting businesses, effective January 1, 2018 which provide a corporate federal tax rate reduction from 35% to 21%, 100% asset expensing, limitation of interest deduction, the repeal of section 199 domestic production deduction and the preservation of the existing normalization rules. The Act also provides that regulated electric and gas companies are exempt from the 100% asset expensing and interest expense deduction limitation. In accordance with U.S. accounting standards, TEC is required to revalue its deferred income tax assets and liabilities based on the new 21% federal tax rate. Additionally, under FPSC rules TEC is required to adjust deferred income tax assets and liabilities for changes in tax rates with a corresponding regulatory liability for the excess deferred taxes generated by the tax rate differential. See Note 3 At December 31, 2017, TEC provisionally revalued all deferred tax assets and liabilities, $194 million and $1,019 million, respectively, based on the rates at which they are expected to reverse in the future, which is 21% for federal tax purposes. At December 31, 2017, as a result of tax reform, Tampa Electric recorded a change in net deferred taxes with an offset to a regulatory tax liability in the amount of $755 million, subject to refund to customers over time as required by order of the FPSC. Provisional amounts primarily related to the uncertainty of the application of 100% asset expensing rules after September 27, 2017, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. On August 3, 2018, the U.S Department of Treasury in conjunction with the IRS issued proposed regulations clarifying the immediate expensing depreciation provisions enacted by the Act related to whether regulated utility property acquired after September 27, 2017 and placed in service by December 31, 2017 qualifies for 100% expensing. At December 31, 2018, the amounts recorded are no longer provisional, however, TEC does not expect any material impact resulting from the proposed regulations. Income Tax Expense Effective July 1, 2016 and due to the Merger with Emera, TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. Prior to the Merger, TEC was included in the filing of a consolidated federal income tax return with TECO Energy 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 2018, 2017 and 2016, TEC recorded net tax provisions of $81 million, $197 million and $152 million, respectively. Income tax expense consists of the following components: Income Tax Expense (Benefit) (millions) For the year ended December 31, 2018 2017 2016 Current income taxes Federal $ 72 $ (1 ) $ 53 State 10 6 12 Deferred income taxes Federal (13 ) 170 76 State 13 23 11 Investment tax credits amortization (1 ) (1 ) 0 Total income tax expense $ 81 $ 197 $ 152 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, 2018 2017 2016 Income before provision for income taxes $ 422 $ 513 $ 438 Federal statutory income tax rates 21 % 35 % 35 % Income taxes, at statutory income tax rate 89 180 153 Increase (decrease) due to State income tax, net of federal income tax 19 19 15 Excess deferred tax amortization (24 ) 0 0 AFUDC-equity (2 ) (1 ) (8 ) Tax credits (2 ) (3 ) (7 ) Other 1 2 (1 ) Total income tax expense on consolidated statements of income $ 81 $ 197 $ 152 Income tax expense as a percent of income from continuing operations, before income taxes 19.2 % 38.4 % 34.8 % 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, 2018 2017 Deferred tax liabilities (1) Property related $ 969 $ 919 Pension and postretirement benefits 105 100 Total deferred tax liabilities 1,074 1,019 Deferred tax assets (1) Loss and credit carryforwards (2) 146 91 Medical benefits 24 24 Insurance reserves 17 (5 ) Pension and postretirement benefits 63 57 Capitalized energy conservation assistance costs 16 13 Other 9 14 Total deferred tax assets 275 194 Total deferred tax liability, net $ 799 $ 825 (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 $8 million. At December 31, 2018, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $340 million and $274 million, respectively, expiring between 2033 and 2037. TEC has unused general business credits of $78 million, expiring between 2028 and 2038. As a result of the Merger with Emera, TECO Energy’s 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) 2018 2017 2016 Balance at January 1, $ 8 $ 7 $ 0 Increases due to tax positions related to current year 0 1 7 Balance at December 31 $ 8 $ 8 $ 7 As of December 31, 2018 and 2017, TEC’s uncertain tax positions for federal R&D tax credits were $8 million 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 2018, 2017 and 2016, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest at December 31, 2018, 2017 and 2016. No amounts have been recorded for penalties. The IRS concluded its examination of TECO Energy’s 2015 consolidated federal income tax return in March 2017 with no changes required. The U.S. federal statute of limitations remains open for the year 2015 and forward. The short tax year ending June 30, 2016 is currently under examination by the IRS under its Compliance Assurance Program (CAP). Prior to July 1, 2016, TEC was included in a consolidated U.S. federal income tax return with TECO Energy and subsidiaries. Due to the Merger with Emera, TECO Energy was only able to participate in the CAP through its short tax year ending June 30, 2016. 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, 2018 | |
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. 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. 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) 2018 2017 2018 2017 Change in benefit obligation Net benefit obligation at beginning of year $ 812 $ 770 $ 193 $ 175 Service cost 21 20 2 2 Interest cost 29 31 7 7 Plan participants’ contributions 0 0 4 3 Plan curtailment 0 (1 ) 0 0 Plan settlement (7 ) (26 ) 0 0 Benefits paid (55 ) (51 ) (19 ) (16 ) Actuarial loss (gain) (50 ) 69 (14 ) 22 Net benefit obligation at end of year $ 750 $ 812 $ 173 $ 193 Change in plan assets Fair value of plan assets at beginning of year $ 766 $ 649 $ 0 $ 0 Actual return on plan assets (63 ) 122 0 0 Employer contributions 10 46 0 0 Employer direct benefit payments 8 27 15 13 Plan participants’ contributions 0 0 4 3 Plan settlement (7 ) (26 ) 0 0 Benefits paid (54 ) (51 ) (19 ) (16 ) Direct benefit payments (1 ) (1 ) 0 0 Fair value of plan assets at end of year (1) $ 659 $ 766 $ 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. At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with benefit obligations in excess of plan assets was as follows: TECO Energy Pension Benefits Other Benefits (1) Funded Status (millions) 2018 2017 2018 2017 Benefit obligation (PBO/APBO) $ 750 $ 812 $ 173 $ 193 Less: Fair value of plan assets 659 766 0 0 Funded status at end of year $ (91 ) $ (46 ) $ (173 ) $ (193 ) (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 $705 million at December 31, 2018 and $762 million at December 31, 2017. 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) 2018 2017 2018 2017 Accrued benefit costs and other current liabilities $ (5 ) $ (7 ) $ (10 ) $ (10 ) Deferred credits and other liabilities (68 ) (30 ) (137 ) (154 ) $ (73 ) $ (37 ) $ (147 ) $ (164 ) 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) 2018 2017 2018 2017 Net actuarial loss (gain) $ 251 $ 215 $ 45 $ 70 Prior service cost (credit) 0 1 0 (13 ) Amount recognized $ 251 $ 216 $ 45 $ 57 Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2018 2017 2018 2017 Discount rate 4.33 % 3.62 % 4.38 % 3.70 % Rate of compensation increase-weighted average 3.75 % 3.32 % 3.75 % 3.31 % Healthcare cost trend rate Immediate rate n/a n/a 6.31 % 6.58 % Ultimate rate n/a n/a 4.50 % 4.50 % Year rate reaches ultimate n/a n/a 2038 2038 A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation: (millions) 1% Increase 1 % Decrease Effect on PBO $ 5 $ (4 ) The discount rate assumption used to determine the December 31, 2018 and 2017 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) 2018 2017 2016 2018 2017 2016 (millions) Service cost $ 21 $ 20 $ 19 $ 2 $ 2 $ 2 Interest cost 29 31 31 7 7 7 Expected return on plan assets (49 ) (48 ) (46 ) 0 0 0 Amortization of: Actuarial loss 19 17 16 1 0 0 Prior service (benefit) cost 0 0 0 (2 ) (2 ) (2 ) Curtailment loss (gain) 0 0 1 0 0 0 Settlement loss 2 (3 ) 7 (2 ) 1 0 0 0 Net periodic benefit cost $ 22 $ 27 $ 22 $ 8 $ 7 $ 7 New prior service cost $ 0 $ 0 $ 1 $ 0 $ 0 $ 0 Net loss (gain) arising during the year 62 (5 ) 47 (14 ) 22 5 Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service (benefit) cost 0 0 0 2 2 2 Amortization or settlement of actuarial gain (loss) (20 ) (24 ) (17 ) (1 ) 0 0 Total recognized in OCI and regulatory assets $ 42 $ (29 ) $ 31 $ (13 ) $ 24 $ 7 Total recognized in net periodic benefit cost, OCI and regulatory assets $ 64 $ (2 ) $ 53 $ (5 ) $ 31 $ 14 (1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan (2) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements. (3) 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 $16 million, $14 million and $13 million for 2018, 2017 and 2016, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $8 million, $6 million and $6 million for 2018, 2017 and 2016, 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”. The estimated net loss for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year is $12 million. There are no prior service credits to be amortized from regulatory assets into net periodic benefit cost in 2019 for the other postretirement benefit plan. TEC’s postretirement benefit plans were not explicitly impacted by the Merger. However, as a result of the Merger, TECO Energy remeasured its postretirement benefits plans on the Merger effective date, July 1, 2016. As a result of the remeasurements, TEC’s net periodic benefit cost increased by $1 million for pension benefits for the six months ended December 31, 2016. Additionally, a curtailment loss for the SERP of $1 million was recognized by TECO Energy in 2016 as a result of retirements due to the Merger. In addition, TECO Energy recognized a settlement charge related to the SERP of $7 million in 2017 due to retirements that have occurred as a result of the Merger. TEC was not impacted by the curtailment loss or settlement charge. TEC recognized a settlement charge in 2018 relating to the retirement of an executive in the SERP plan. TEC expects to recognize a settlement charge of approximately $1 million in 2019 related to the retirement of a SERP participant. TEC expects to recognize settlement charges of approximately $1 million in 2019 related to the retirement of Restoration plan participants. Assumptions used to determine net periodic benefit cost for years ended December 31: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Discount rate 3.62 % 4.11 % 4.69 % 3.70 % 4.28 % 4.67%/3.85% Expected long-term return on plan assets 6.85 % 7.00 % 7.00 % N/A N/A N/A Rate of compensation increase 3.32 % 2.57 % 2.59 % 3.31 % 2.48 % 2.50 % Healthcare cost trend rate Initial rate n/a n/a n/a 6.58 % 6.83 % 7.05 % Ultimate rate n/a n/a n/a 4.50 % 4.50 % 4.50 % Year rate reaches ultimate n/a n/a n/a 2038 2038 2038 The discount rate assumption used to determine the benefit cost for 2018, 2017 and from the Merger date to December 31, 2016 was based on the same technique that was used to determine the December 31, 2018 and 2017 benefit obligation as discussed above. The discount rate assumption used to determine the January 1, 2016 through June 30, 2016 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructed hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculated all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selected the portfolio with the highest yield and used that yield as the recommended discount rate. The change in the discount rate approach was a result of the Merger and done to align methodologies with Emera. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate. 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, 2018, TECO Energy’s pension plan’s actual earned losses were approximately 8%. 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. A one-percentage-point change in assumed health care cost trend rates would have a less than $1 million effect on net periodic benefit cost. 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 2018 Target Allocation Actual Asset Category 2018 2017 Equity securities 47%-53% 46 % 51 % Fixed income securities 47%-53% 54 % 49 % Total 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. The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). 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, 2018 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ (3 ) $ 0 $ 0 $ 0 $ (3 ) Accounts receivable 10 0 0 0 10 Accounts payable (51 ) 0 0 0 (51 ) Short-term investment funds (STIFs) 17 0 0 0 17 Common stocks 32 0 0 0 32 Real estate investment trusts (REITs) 3 0 0 0 3 Mutual funds 97 0 0 0 97 Municipal bonds 0 1 0 0 1 Government bonds 0 59 0 0 59 Corporate bonds 0 55 0 0 55 Collateralized mortgage obligations (CMOs) 0 1 0 0 1 Long Futures 6 0 0 0 6 Swaps 0 3 0 0 3 Purchase options (swaptions) 0 1 0 0 1 Written options (swaptions) 0 (1 ) 0 0 (1 ) Investments not utilizing the practical expedient 111 119 0 0 230 Common and collective trusts (1) 0 0 0 330 330 Mutual fund (1) 0 0 0 99 99 Total investments $ 111 $ 119 $ 0 $ 429 $ 659 (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. TECO Energy At Fair Value as of December 31, 2017 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 3 $ 0 $ 0 $ 0 $ 3 Accounts receivable 14 0 0 0 14 Accounts payable (43 ) 0 0 0 (43 ) STIFs 14 0 0 0 14 Common stocks 44 0 0 0 44 REITs 4 0 0 0 4 Mutual funds 196 0 0 0 196 Municipal bonds 0 2 0 0 2 Government bonds 0 55 0 0 55 Corporate bonds 0 45 0 0 45 MBS 0 (1 ) 0 0 (1 ) CMOs 0 1 0 0 1 Swaps 0 4 0 0 4 Purchase options (swaptions) 0 1 0 0 1 Written options (swaptions) 0 (2 ) 0 0 (2 ) Investments not utilizing the practical expedient 232 105 0 0 337 Common and collective trusts (1) 0 0 0 326 326 Mutual fund (1) 0 0 0 103 103 Total investments $ 232 $ 105 $ 0 $ 429 $ 766 (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. 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-ended 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. • Options are valued using the bid-ask spread and the last price. • 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-ended 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 a closed-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, 2018. • 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, 2018. • Discounted notes are valued at amortized cost. • 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 $14 million and $17 million of assets as of December 31, 2018 and 2017, respectively. Since the plan is non-qualified, its assets are included in the “Deferred charges and other assets” line item in TEC’s 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, 2018 and 2017. 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 112.5% of the Pension Protection Act funded target as of January 1, 2018 and is estimated at 110.6% of the Pension Protection Act funded target as of January 1, 2019. 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 2018, 2017 and 2016, which met the minimum funding requirements for 2018, 2017 and 2016. TEC’s portion of the contribution in 2018 was $8 million and in 2017 was $36 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2019 contribution to be $15 million. TEC estimates its portion of annual contributions from 2020 to 2023 will range from $14 million to $17 million per year based on current assumptions. The amounts TECO Energy expects to contribute are in excess of the minimum funding required under ERISA guidelines. TEC’s portion of the contributions to the SERP in 2018, 2017 and 2016 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2019. TEC made SERP payments of approximately $7 million from the trust in 2018 and expects to make a SERP payment of approximately $5 million from the trust in 2019. 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 2019, TEC expects to make a contribution of about $10 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) 2019 $ 57 $ 12 2020 55 12 2021 59 12 2022 60 12 2023 60 12 2024-2028 333 59 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 up to 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. During the period of January 2015 to December 2016, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended December 31, 2018, 2017 and 2016, TEC’s portion of expense totaled $11 million, $11 million and $8 million, respectively, related to the matching contributions made to this plan. |
Short-Term Debt
Short-Term Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Short-Term Debt | 6. Short-Term Debt Credit Facilities December 31, 2018 December 31, 2017 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 325 $ 131 $ 1 $ 325 $ 5 $ 1 3-year accounts receivable facility (3) 150 90 0 150 0 0 1-year term facility (4) 0 0 0 300 300 0 Total $ 475 $ 221 $ 1 $ 775 $ 305 $ 1 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures March 22, 2022. (3) This 3-year facility matures March 22, 2021. (4) This 1-year facility was repaid on October 11, 2018. At December 31, 2018, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2018 and 2017 was 3.14% and 2.07%, respectively. Tampa Electric Company Accounts Receivable Facility On March 23, 2018, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a Second Amended Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). Throughout the term of the facility, TEC will pay program and liquidity fees, which total 70 basis points at December 31, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin. In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of December 31, 2018, TEC was in compliance with the requirements of the Loan Agreement. Tampa Electric Company Credit Facility On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); provides 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 $175 million in the aggregate; includes a $50 million letter of credit facility; and made other technical changes. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2018 | |
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 4.3% Notes due 2048 On June 7, 2018, TEC completed a sale of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048. Until December 15, 2047, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), 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, 2047, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption. Tampa Electric Company 4.45% Notes due 2049 On October 4, 2018, TEC completed a sale of $375 million aggregate principal amount of 4.45% unsecured notes due June 15, 2049. Until December 15, 2048, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), 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, 2048, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption. Purchase in Lieu of Redemption of Revenue Refunding Bonds At December 31, 2018 and 2017, $233 million of tax-exempt bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric to provide an opportunity to evaluate refinancing alternatives including $20 million variable-rate bonds due 2020, $52 million term-rate refunding bonds due 2025, $75 million term-rate bonds due 2030, and $86 million term-rate refunding bonds due 2034. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
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 Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas 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, 2018, TEC has estimated its ultimate financial liability to be $28 million, 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 long-term leases (primarily for land, building space, vehicles and office equipment), long-term service agreements and capital projects, including Tampa Electric’s solar projects (see Note 3 ) and the modernization of the Big Bend power station Capital Fuel and Gas Long-term Service Operating Demand Side (millions) Transportation Projects Supply Agreements Leases Management Total Year ended December 31: 2019 $ 194 $ 298 $ 257 $ 7 $ 2 $ 5 $ 763 2020 175 89 106 6 2 1 379 2021 141 33 3 6 2 0 185 2022 133 8 3 7 2 0 153 2023 108 2 1 11 2 0 124 Thereafter 1,013 6 0 78 34 0 1,131 Total future minimum payments $ 1,764 $ 436 $ 370 $ 115 $ 44 $ 6 $ 2,735 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, 2018 and 2017, TEC was in compliance with all required financial covenants. |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2018 | |
Revenues [Abstract] | |
Revenue | 9. Revenue The following disaggregates TEC’s revenue by major source: (millions) Tampa Tampa Electric For the year ended December 31, 2018 Electric PGS Eliminations Company Electric revenue Residential $ 1,067 $ 0 $ 0 $ 1,067 Commercial 582 0 0 582 Industrial 161 0 0 161 Regulatory deferrals and unbilled revenue (2 ) 0 0 (2 ) Other (1) 258 0 (3 ) 255 Total electric revenue 2,066 0 (3 ) 2,063 Gas revenue Residential 0 157 0 157 Commercial 0 151 0 151 Industrial (2) 0 21 0 21 Other (3) 0 159 (27 ) 132 Total gas revenue 0 488 (27 ) 461 Total revenue $ 2,066 $ 488 $ (30 ) $ 2,524 (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 primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $135 million. 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 2033. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2018 | |
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) 2018 2017 2016 Natural gas sales to/(from) affiliates $ (38 ) $ (4 ) $ 0 Services received from affiliates 65 67 66 Dividends to TECO Energy 362 292 289 Equity contributions from TECO Energy 345 190 150 Services received from affiliates primarily include shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary. Through TSI, TECO Energy provided TEC with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or allocated to TEC based on FPSC-approved cost-causative allocation methods or the Modified Massachusetts Formula. Amounts due from or to affiliates at December 31, (millions) 2018 2017 Accounts receivable (1) $ 3 $ 2 Accounts payable (1) 20 19 Taxes receivable (2) 1 3 Taxes payable (2) 4 2 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2 ) Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2018 | |
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. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 764,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 392,000 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 2018 Revenues - external $ 2,063 $ 461 $ 0 $ 2,524 Sales to affiliates 3 27 (30 ) 0 Total revenues 2,066 488 (30 ) 2,524 Depreciation and amortization 312 60 0 372 Total interest charges 102 16 0 118 Provision for income taxes 65 16 0 81 Net income 294 47 0 341 Total assets 8,235 1,407 (487 ) (1) 9,155 Capital expenditures 940 169 0 1,109 2017 Revenues - external $ 2,052 $ 418 $ 0 $ 2,470 Sales to affiliates 2 20 (22 ) 0 Total revenues 2,054 438 (22 ) 2,470 Depreciation and amortization 300 50 0 350 Total interest charges 104 15 0 119 Provision for income taxes 171 26 0 197 Net income 273 43 0 316 Total assets 7,635 1,284 (555 ) (1) 8,364 Capital expenditures 518 122 0 640 2016 Revenues - external $ 1,964 $ 432 $ 0 $ 2,396 Sales to affiliates 1 7 (8 ) 0 Total revenues 1,965 439 (8 ) 2,396 Depreciation and amortization 268 60 0 328 Total interest charges 91 15 0 106 Provision for income taxes 130 22 0 152 Net income 251 35 0 286 Total assets 7,357 1,191 (465 ) (1) 8,083 Capital expenditures 594 133 0 727 (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, 2018 | |
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, 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) 2018 2017 Beginning balance $ 47 $ 45 Additional liabilities (1) 18 1 Liabilities settled 0 (1 ) Revisions to estimated cash flows (3 ) 0 Other (2) 2 2 Ending balance $ 64 $ 47 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The increase in the ARO in 2018 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units, due to the closure of a CCR management facility in 2018. Tampa Electric submitted a petition to the FPSC in December 2018 for recovery of the costs associated with this ongoing project and the petition is currently under review. (2) Includes accretion recorded as a deferred regulatory asset. |
Accounting for Derivative Instr
Accounting for Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Accounting for Derivative Instruments and Hedging Activities | 13. Accounting for Derivative Instruments and Hedging Activities From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes: • To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and • To optimize the utilization of Tampa Electric’s physical natural gas storage capacity and PGS’s firm transportation capacity on interstate pipelines. TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers and to optimize the utilization of its physical natural gas storage capacity and firm transportation capacity on interstate pipelines. The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies. On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which replaces the 2013 base rate settlement agreement and includes a provision for a five-year moratorium on hedging of natural gas purchases ending on December 31, 2022 (see Note 3 TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements and to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage capacity for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income (see Note 3 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, 2018, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected. TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation. It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of December 31, 2018, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated. TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination. TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 14. 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, 2018 and 2017, 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 Consolidated Statements of Capitalization |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2018 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Variable Interest Entities | 15. Variable Interest Entities A VIE is an entity that a company has a controlling financial interest in, and that controlling interest is determined through means other than a majority voting interest. The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Tampa Electric entered into PPAs with wholesale energy providers in Florida, which expired in December 2018. These agreements ranged in size from 121 MW to 250 MW of available capacity, were with similar entities and contained similar provisions. In the first quarter of 2019, Tampa Electric entered into a PPA with a wholesale energy provider in Florida with up to 360 MW of available capacity. 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 is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $15 million, $16 million and $62 million under these PPAs for the three years ended December 31, 2018, 2017 and 2016, respectively. TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. Excluding the payments for energy under these contracts, TEC’s involvement with these VIEs does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-Based Compensation | 16. Stock-Based Compensation Performance Share Unit Plan Emera has a performance share unit (PSU) plan, and TEC employees started participating in the plan in 2017. The PSU liability is marked-to-market at the end of each period based on the common share price in CAD at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA. Under the PSU plan, 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 a given calculation date. Dividend equivalents are awarded and are paid in the form of additional PSUs, also referred to as the Dividend Reinvestment Plan (DRIP). 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 will be calculated and approved by the Emera Management Resources and Compensation Committee early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of termination, disability or death. 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, 2017 133 $ 45.11 $ 6 Granted including DRIP 130 47.98 6 Exercised (4 ) 38.85 (1 ) Forfeited (1 ) 45.41 0 Outstanding as of December 31, 2018 258 $ 46.68 $ 11 Compensation cost recognized for the PSU plan for the years ended December 31, 2018 and 2017 was $4 million and $2 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2018 and 2017 |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts and Reserves | 12 Months Ended |
Dec. 31, 2018 | |
Valuation And Qualifying Accounts [Abstract] | |
Schedule II - Valuation and Qualifying Accounts and Reserves | TAMPA ELECTRIC COMPANY VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 2018, 2017 and 2016 (millions) Balance at Additions Balance at Beginning Charged to Other Payments & End of of Period Income Charges Deductions (1) Period Allowance for Uncollectible Accounts: 2018 $ 1 $ 7 $ 0 $ 6 $ 2 2017 $ 1 $ 5 $ 0 $ 5 $ 1 2016 $ 1 $ 3 $ 0 $ 3 $ 1 (1) Write-off of individual bad debt accounts |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
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. On July 1, 2016, TECO Energy and Emera completed the Merger contemplated by the Merger Agreement entered into on September 4, 2015, and TECO Energy became a wholly owned indirect subsidiary of Emera. Therefore, TEC became an indirect, wholly owned subsidiary of Emera as of July 1, 2016. The acquisition method of accounting was not pushed down to TECO Energy or its subsidiaries, including TEC. |
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, 2018 December 31, 2017 Electric generation 21-56 years $ 5,038 $ 4,766 Electric transmission 28-77 years 880 859 Electric distribution 14-56 years 2,568 2,437 Gas transmission and distribution 16-77 years 1,678 1,534 General plant and other 8-43 years 613 579 Total cost 10,777 10,175 Less accumulated depreciation (3,214 ) (2,994 ) Construction work in progress 673 263 Total property, plant and equipment, net $ 8,236 $ 7,444 |
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%, 3.7% and 3.5% for 2018, 2017 and 2016, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2018, 2017 and 2016 was $345 million, $332 million and $304 million, respectively. See Note 3 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 FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2018, 2017 and 2016, the rate was 6.46%. Total AFUDC for the years ended December 31, 2018, 2017 and 2016 was $15 million, $2 million and $36 million, respectively. The increase in 2018 is a result of the construction of solar projects and the repowering of Big Bend Unit 1 with natural gas combined-cycle technology. The decrease in 2017 is a result of the Polk Power Station conversion project, which was completed in January 2017 |
Inventory | Inventory TEC values materials, supplies and fossil fuel inventory (natural gas, coal, petcoke 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, unless evidence indicates that the weighted-average cost will be recovered with a normal profit upon sale in the ordinary course of business. |
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 |
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. As of December 31, 2018 and 2017, ITCs were $74 million and $22 million, respectively. The increase is due to solar projects placed in service in 2018. |
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. TEC’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, weather 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. TEC’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 and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity 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 billed. |
Receivables and Allowance for Uncollectible Accounts | Receivables and Allowance for Uncollectible Accounts Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $226 million and $229 million as of December 31, 2018 and 2017, respectively. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of fuel prices, customer deposits and general economic conditions. Accounts are 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 |
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 $120 million, $113 million and $117 million for the years ended December 31, 2018, 2017 and 2016, respectively. |
Deferred Credits and Other Liabilities | Deferred Credits and Other Liabilities Other deferred credits primarily include accrued postretirement and pension liabilities (see Note 5 Note 8 Note 12 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, 2018 and 2017 ranged from 4.00% to 4.01% and 2.74% to 4.00%, respectively. |
Cash Flows Related to Derivatives and Hedging Activities | Cash Flows Related to Derivatives and Hedging Activities 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. See Note 13 |
Reclassifications | Reclassifications Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TEC’s net income or financial position in any period. |
Significant Accounting Polici_3
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of Property, Plant and Equipment | Property, plant and equipment consisted of the following assets: (millions) Estimated Useful Lives December 31, 2018 December 31, 2017 Electric generation 21-56 years $ 5,038 $ 4,766 Electric transmission 28-77 years 880 859 Electric distribution 14-56 years 2,568 2,437 Gas transmission and distribution 16-77 years 1,678 1,534 General plant and other 8-43 years 613 579 Total cost 10,777 10,175 Less accumulated depreciation (3,214 ) (2,994 ) Construction work in progress 673 263 Total property, plant and equipment, net $ 8,236 $ 7,444 |
Regulatory (Tables)
Regulatory (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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) 2018 2017 Regulatory assets: Regulatory tax asset (1) $ 56 $ 45 Cost-recovery clauses (2) 55 13 Environmental remediation (3) 23 33 Postretirement benefits (4) 295 272 Storm reserve (5) 3 47 Other 26 23 Total regulatory assets 458 433 Less: Current portion 88 77 Long-term regulatory assets $ 370 $ 356 Regulatory liabilities: Regulatory tax liability (6) $ 715 $ 730 Cost-recovery clauses (2) 17 32 Storm reserve (7) 56 0 Accumulated reserve—cost of removal (8) 513 518 Other 9 5 Total regulatory liabilities 1,310 1,285 Less: Current portion 44 58 Long-term regulatory liabilities $ 1,266 $ 1,227 (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 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 the next year. (3) 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. (4) 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. (5) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding (6) 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 income tax rate. The liability related to the revaluation of the deferred income tax balances will be amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and a settlement agreement for tax reform benefits approved by the FPSC. See Note 4 TEC Consolidated Financial Statements (7) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory liability is being replenished to the FPSC-allowed storm reserve balance of $56 million. (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. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income Tax Expense | Income tax expense consists of the following components: (millions) For the year ended December 31, 2018 2017 2016 Current income taxes Federal $ 72 $ (1 ) $ 53 State 10 6 12 Deferred income taxes Federal (13 ) 170 76 State 13 23 11 Investment tax credits amortization (1 ) (1 ) 0 Total income tax expense $ 81 $ 197 $ 152 |
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, 2018 2017 2016 Income before provision for income taxes $ 422 $ 513 $ 438 Federal statutory income tax rates 21 % 35 % 35 % Income taxes, at statutory income tax rate 89 180 153 Increase (decrease) due to State income tax, net of federal income tax 19 19 15 Excess deferred tax amortization (24 ) 0 0 AFUDC-equity (2 ) (1 ) (8 ) Tax credits (2 ) (3 ) (7 ) Other 1 2 (1 ) Total income tax expense on consolidated statements of income $ 81 $ 197 $ 152 Income tax expense as a percent of income from continuing operations, before income taxes 19.2 % 38.4 % 34.8 % |
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, 2018 2017 Deferred tax liabilities (1) Property related $ 969 $ 919 Pension and postretirement benefits 105 100 Total deferred tax liabilities 1,074 1,019 Deferred tax assets (1) Loss and credit carryforwards (2) 146 91 Medical benefits 24 24 Insurance reserves 17 (5 ) Pension and postretirement benefits 63 57 Capitalized energy conservation assistance costs 16 13 Other 9 14 Total deferred tax assets 275 194 Total deferred tax liability, net $ 799 $ 825 (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 $8 million. |
Schedule of Unrecognized Tax Benefits | The following table provides details of the change in unrecognized tax benefits as follows: (millions) 2018 2017 2016 Balance at January 1, $ 8 $ 7 $ 0 Increases due to tax positions related to current year 0 1 7 Balance at December 31 $ 8 $ 8 $ 7 |
Employee Postretirement Benef_2
Employee Postretirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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) 2018 2017 2018 2017 Accrued benefit costs and other current liabilities $ (5 ) $ (7 ) $ (10 ) $ (10 ) Deferred credits and other liabilities (68 ) (30 ) (137 ) (154 ) $ (73 ) $ (37 ) $ (147 ) $ (164 ) |
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) 2018 2017 2018 2017 Net actuarial loss (gain) $ 251 $ 215 $ 45 $ 70 Prior service cost (credit) 0 1 0 (13 ) Amount recognized $ 251 $ 216 $ 45 $ 57 |
Benefit Obligations [Member] | |
Schedule of Assumptions Used to Determine Benefit | Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2018 2017 2018 2017 Discount rate 4.33 % 3.62 % 4.38 % 3.70 % Rate of compensation increase-weighted average 3.75 % 3.32 % 3.75 % 3.31 % Healthcare cost trend rate Immediate rate n/a n/a 6.31 % 6.58 % Ultimate rate n/a n/a 4.50 % 4.50 % Year rate reaches ultimate n/a n/a 2038 2038 |
Schedule of One-Percentage-Point Change in Assumed Health Care Cost | A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation: (millions) 1% Increase 1 % Decrease Effect on PBO $ 5 $ (4 ) |
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 2018 2017 2016 2018 2017 2016 Discount rate 3.62 % 4.11 % 4.69 % 3.70 % 4.28 % 4.67%/3.85% Expected long-term return on plan assets 6.85 % 7.00 % 7.00 % N/A N/A N/A Rate of compensation increase 3.32 % 2.57 % 2.59 % 3.31 % 2.48 % 2.50 % Healthcare cost trend rate Initial rate n/a n/a n/a 6.58 % 6.83 % 7.05 % Ultimate rate n/a n/a n/a 4.50 % 4.50 % 4.50 % Year rate reaches ultimate n/a n/a n/a 2038 2038 2038 |
Effect on Expenses [Member] | |
Schedule of One-Percentage-Point Change in Assumed Health Care Cost | A one-percentage-point change in assumed health care cost trend rates would have a less than $1 million effect on net periodic benefit cost. |
TECO Energy [Member] | |
Schedule of Change in Plan Assets | Change in plan assets Fair value of plan assets at beginning of year $ 766 $ 649 $ 0 $ 0 Actual return on plan assets (63 ) 122 0 0 Employer contributions 10 46 0 0 Employer direct benefit payments 8 27 15 13 Plan participants’ contributions 0 0 4 3 Plan settlement (7 ) (26 ) 0 0 Benefits paid (54 ) (51 ) (19 ) (16 ) Direct benefit payments (1 ) (1 ) 0 0 Fair value of plan assets at end of year (1) $ 659 $ 766 $ 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) 2018 2017 2016 2018 2017 2016 (millions) Service cost $ 21 $ 20 $ 19 $ 2 $ 2 $ 2 Interest cost 29 31 31 7 7 7 Expected return on plan assets (49 ) (48 ) (46 ) 0 0 0 Amortization of: Actuarial loss 19 17 16 1 0 0 Prior service (benefit) cost 0 0 0 (2 ) (2 ) (2 ) Curtailment loss (gain) 0 0 1 0 0 0 Settlement loss 2 (3 ) 7 (2 ) 1 0 0 0 Net periodic benefit cost $ 22 $ 27 $ 22 $ 8 $ 7 $ 7 |
Schedule of Amounts Recognized in OCI and Regulatory Assets | New prior service cost $ 0 $ 0 $ 1 $ 0 $ 0 $ 0 Net loss (gain) arising during the year 62 (5 ) 47 (14 ) 22 5 Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service (benefit) cost 0 0 0 2 2 2 Amortization or settlement of actuarial gain (loss) (20 ) (24 ) (17 ) (1 ) 0 0 Total recognized in OCI and regulatory assets $ 42 $ (29 ) $ 31 $ (13 ) $ 24 $ 7 Total recognized in net periodic benefit cost, OCI and regulatory assets $ 64 $ (2 ) $ 53 $ (5 ) $ 31 $ 14 (1) Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan (2) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements. (3) 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 2018 Target Allocation Actual Asset Category 2018 2017 Equity securities 47%-53% 46 % 51 % Fixed income securities 47%-53% 54 % 49 % Total 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, 2018 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ (3 ) $ 0 $ 0 $ 0 $ (3 ) Accounts receivable 10 0 0 0 10 Accounts payable (51 ) 0 0 0 (51 ) Short-term investment funds (STIFs) 17 0 0 0 17 Common stocks 32 0 0 0 32 Real estate investment trusts (REITs) 3 0 0 0 3 Mutual funds 97 0 0 0 97 Municipal bonds 0 1 0 0 1 Government bonds 0 59 0 0 59 Corporate bonds 0 55 0 0 55 Collateralized mortgage obligations (CMOs) 0 1 0 0 1 Long Futures 6 0 0 0 6 Swaps 0 3 0 0 3 Purchase options (swaptions) 0 1 0 0 1 Written options (swaptions) 0 (1 ) 0 0 (1 ) Investments not utilizing the practical expedient 111 119 0 0 230 Common and collective trusts (1) 0 0 0 330 330 Mutual fund (1) 0 0 0 99 99 Total investments $ 111 $ 119 $ 0 $ 429 $ 659 (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. TECO Energy At Fair Value as of December 31, 2017 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 3 $ 0 $ 0 $ 0 $ 3 Accounts receivable 14 0 0 0 14 Accounts payable (43 ) 0 0 0 (43 ) STIFs 14 0 0 0 14 Common stocks 44 0 0 0 44 REITs 4 0 0 0 4 Mutual funds 196 0 0 0 196 Municipal bonds 0 2 0 0 2 Government bonds 0 55 0 0 55 Corporate bonds 0 45 0 0 45 MBS 0 (1 ) 0 0 (1 ) CMOs 0 1 0 0 1 Swaps 0 4 0 0 4 Purchase options (swaptions) 0 1 0 0 1 Written options (swaptions) 0 (2 ) 0 0 (2 ) Investments not utilizing the practical expedient 232 105 0 0 337 Common and collective trusts (1) 0 0 0 326 326 Mutual fund (1) 0 0 0 103 103 Total investments $ 232 $ 105 $ 0 $ 429 $ 766 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-ended 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. • Options are valued using the bid-ask spread and the last price. • 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-ended 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 a closed-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, 2018. • 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, 2018. • Discounted notes are valued at amortized cost. • 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) 2019 $ 57 $ 12 2020 55 12 2021 59 12 2022 60 12 2023 60 12 2024-2028 333 59 |
TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member] | |
Schedule of Change in Benefit Obligation | TECO Energy Pension Benefits Other Benefits (2) Obligations and Funded Status (millions) 2018 2017 2018 2017 Change in benefit obligation Net benefit obligation at beginning of year $ 812 $ 770 $ 193 $ 175 Service cost 21 20 2 2 Interest cost 29 31 7 7 Plan participants’ contributions 0 0 4 3 Plan curtailment 0 (1 ) 0 0 Plan settlement (7 ) (26 ) 0 0 Benefits paid (55 ) (51 ) (19 ) (16 ) Actuarial loss (gain) (50 ) 69 (14 ) 22 Net benefit obligation at end of year $ 750 $ 812 $ 173 $ 193 |
Schedule of Funded status | At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with benefit obligations in excess of plan assets was as follows: TECO Energy Pension Benefits Other Benefits (1) Funded Status (millions) 2018 2017 2018 2017 Benefit obligation (PBO/APBO) $ 750 $ 812 $ 173 $ 193 Less: Fair value of plan assets 659 766 0 0 Funded status at end of year $ (91 ) $ (46 ) $ (173 ) $ (193 ) (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, 2018 | |
Debt Disclosure [Abstract] | |
Short-Term Debt Credit Facilities | Credit Facilities December 31, 2018 December 31, 2017 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 325 $ 131 $ 1 $ 325 $ 5 $ 1 3-year accounts receivable facility (3) 150 90 0 150 0 0 1-year term facility (4) 0 0 0 300 300 0 Total $ 475 $ 221 $ 1 $ 775 $ 305 $ 1 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures March 22, 2022. (3) This 3-year facility matures March 22, 2021. (4) This 1-year facility was repaid on October 11, 2018. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018: Capital Fuel and Gas Long-term Service Operating Demand Side (millions) Transportation Projects Supply Agreements Leases Management Total Year ended December 31: 2019 $ 194 $ 298 $ 257 $ 7 $ 2 $ 5 $ 763 2020 175 89 106 6 2 1 379 2021 141 33 3 6 2 0 185 2022 133 8 3 7 2 0 153 2023 108 2 1 11 2 0 124 Thereafter 1,013 6 0 78 34 0 1,131 Total future minimum payments $ 1,764 $ 436 $ 370 $ 115 $ 44 $ 6 $ 2,735 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 Electric PGS Eliminations Company Electric revenue Residential $ 1,067 $ 0 $ 0 $ 1,067 Commercial 582 0 0 582 Industrial 161 0 0 161 Regulatory deferrals and unbilled revenue (2 ) 0 0 (2 ) Other (1) 258 0 (3 ) 255 Total electric revenue 2,066 0 (3 ) 2,063 Gas revenue Residential 0 157 0 157 Commercial 0 151 0 151 Industrial (2) 0 21 0 21 Other (3) 0 159 (27 ) 132 Total gas revenue 0 488 (27 ) 461 Total revenue $ 2,066 $ 488 $ (30 ) $ 2,524 (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. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2018 2017 2016 Natural gas sales to/(from) affiliates $ (38 ) $ (4 ) $ 0 Services received from affiliates 65 67 66 Dividends to TECO Energy 362 292 289 Equity contributions from TECO Energy 345 190 150 Amounts due from or to affiliates at December 31, (millions) 2018 2017 Accounts receivable (1) $ 3 $ 2 Accounts payable (1) 20 19 Taxes receivable (2) 1 3 Taxes payable (2) 4 2 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2 ) Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Schedule of 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. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 764,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 392,000 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 2018 Revenues - external $ 2,063 $ 461 $ 0 $ 2,524 Sales to affiliates 3 27 (30 ) 0 Total revenues 2,066 488 (30 ) 2,524 Depreciation and amortization 312 60 0 372 Total interest charges 102 16 0 118 Provision for income taxes 65 16 0 81 Net income 294 47 0 341 Total assets 8,235 1,407 (487 ) (1) 9,155 Capital expenditures 940 169 0 1,109 2017 Revenues - external $ 2,052 $ 418 $ 0 $ 2,470 Sales to affiliates 2 20 (22 ) 0 Total revenues 2,054 438 (22 ) 2,470 Depreciation and amortization 300 50 0 350 Total interest charges 104 15 0 119 Provision for income taxes 171 26 0 197 Net income 273 43 0 316 Total assets 7,635 1,284 (555 ) (1) 8,364 Capital expenditures 518 122 0 640 2016 Revenues - external $ 1,964 $ 432 $ 0 $ 2,396 Sales to affiliates 1 7 (8 ) 0 Total revenues 1,965 439 (8 ) 2,396 Depreciation and amortization 268 60 0 328 Total interest charges 91 15 0 106 Provision for income taxes 130 22 0 152 Net income 251 35 0 286 Total assets 7,357 1,191 (465 ) (1) 8,083 Capital expenditures 594 133 0 727 (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, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | Reconciliation of beginning and ending carrying amount of asset retirement obligations: December 31, (millions) 2018 2017 Beginning balance $ 47 $ 45 Additional liabilities (1) 18 1 Liabilities settled 0 (1 ) Revisions to estimated cash flows (3 ) 0 Other (2) 2 2 Ending balance $ 64 $ 47 (1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The increase in the ARO in 2018 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units, due to the closure of a CCR management facility in 2018. Tampa Electric submitted a petition to the FPSC in December 2018 for recovery of the costs associated with this ongoing project and the petition is currently under review. (2) Includes accretion recorded as a deferred regulatory asset. |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2017 133 $ 45.11 $ 6 Granted including DRIP 130 47.98 6 Exercised (4 ) 38.85 (1 ) Forfeited (1 ) 45.41 0 Outstanding as of December 31, 2018 258 $ 46.68 $ 11 |
Significant Accounting Polici_4
Significant Accounting Policies - Additional Information (Detail) $ in Millions | Jan. 01, 2019USD ($) | Dec. 31, 2018USD ($)Segment | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 12, 2017USD ($) |
Summary Of Significant Accounting Policies [Line Items] | |||||
Number of operating segments | Segment | 2 | ||||
Percentage of original cost of depreciable property | 3.50% | 3.70% | 3.50% | ||
Depreciation expense | $ 345 | $ 332 | $ 304 | ||
Allowance for funds used during construction rate | 6.46% | 6.46% | 6.46% | ||
Allowance for funds used during construction | $ 15 | $ 2 | $ 36 | ||
Investment tax credits | 74 | $ 22 | |||
Receivables from contracts with customers | 226 | 229 | |||
Unbilled revenues | 67 | 66 | |||
Franchise fees and gross receipts taxes | $ 120 | $ 113 | 117 | ||
Minimum [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Discount rates used in estimating other self-insurance liabilities | 4.00% | 2.74% | |||
Maximum [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Discount rates used in estimating other self-insurance liabilities | 4.01% | 4.00% | |||
PGS [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Reduction in annual depreciation expense | $ 16 | ||||
PGS [Member] | Subsequent Event [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Reduction in annual depreciation expense | $ 10 |
Significant Accounting Polici_5
Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Property Plant And Equipment [Line Items] | ||
Total cost | $ 10,777 | $ 10,175 |
Less accumulated depreciation | (3,214) | (2,994) |
Construction work in progress | 673 | 263 |
Total property, plant and equipment, net | 8,236 | 7,444 |
Electric Generation [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | 5,038 | 4,766 |
Gas Transmission and Distribution [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | 1,678 | 1,534 |
General Plant and Other [Member] | ||
Property Plant And Equipment [Line Items] | ||
Total cost | $ 613 | 579 |
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 | $ 880 | 859 |
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 | $ 2,568 | $ 2,437 |
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 |
New Accounting Pronouncements -
New Accounting Pronouncements - Additional Information (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
ASU 2016-02 [Member] | |
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | |
Increase in assets and liabilities related to operating leases | $ 20 |
Regulatory - Additional Informa
Regulatory - Additional Information (Detail) | Aug. 20, 2018USD ($) | Jun. 29, 2018USD ($)MW | Dec. 28, 2017USD ($) | Dec. 12, 2017USD ($)MW | Sep. 27, 2017USD ($)$ / kWacMW | Dec. 15, 2016USD ($) | Jun. 28, 2016 | Sep. 06, 2013 | May 31, 2009 | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Mar. 31, 2018USD ($) | 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% | ||||||||||||||||
Storm restoration costs | $ 10,000,000 | ||||||||||||||||
Regulatory assets | $ 458,000,000 | $ 433,000,000 | |||||||||||||||
Regulatory liability | 1,310,000,000 | 1,285,000,000 | |||||||||||||||
Reduction in regulatory asset for amortization | (98,000,000) | 100,000,000 | $ 11,000,000 | ||||||||||||||
PGS [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Percentage of ROE | 10.75% | 10.75% | |||||||||||||||
Allowed equity in the capital structure | 54.70% | ||||||||||||||||
Reduction in regulatory asset for amortization | (11,000,000) | ||||||||||||||||
PGS [Member] | Scenario Forecast [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Reduction in annual depreciation expense | $ 10,000,000 | ||||||||||||||||
Reduction in annual base rates | $ 12,000,000 | ||||||||||||||||
PGS and OPC [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Regulatory assets | $ 32,000,000 | ||||||||||||||||
Reduction in annual depreciation expense | $ 16,000,000 | ||||||||||||||||
Date new bottom of return on equity range will remain in effect | Dec. 31, 2020 | ||||||||||||||||
Amortization expenses | 5,000,000 | $ 16,000,000 | |||||||||||||||
Regulatory asset amortization beginning period | 2,016 | ||||||||||||||||
Regulatory asset amortization ending period | 2,020 | ||||||||||||||||
Storm Reserve [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Regulatory liability | $ 56,000,000 | 0 | |||||||||||||||
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] | O&M Expenses [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Storm restoration costs | 3,000,000 | ||||||||||||||||
Hurricane Irma [Member] | Capital Expenditures [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Storm restoration costs | $ 9,000,000 | ||||||||||||||||
Minimum [Member] | PGS [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Percentage of ROE | 9.75% | ||||||||||||||||
Minimum [Member] | PGS and OPC [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Amortization period of Regulatory Asset | 2 years | ||||||||||||||||
Decrease bottom return on equity | 9.25% | ||||||||||||||||
Amortization expenses | $ 21,000,000 | ||||||||||||||||
Maximum [Member] | PGS [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Percentage of ROE | 11.75% | 11.75% | |||||||||||||||
Maximum [Member] | PGS and OPC [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Decrease bottom return on equity | 9.75% | ||||||||||||||||
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 | ||||||||||||||||
Cost savings benefit percentage for projects below cost cap | 75.00% | ||||||||||||||||
Solar generation capacity investments | $ 850,000,000 | ||||||||||||||||
Impact of tax reform through reduction in base revenue days | 120 days | ||||||||||||||||
Investments in gas reserves | $ 0 | ||||||||||||||||
Solar Project Cost Recovery [Member] | Minimum [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar project investment term | 2,017 | ||||||||||||||||
Extended agreement base rate freeze date | Jan. 1, 2018 | ||||||||||||||||
Solar Project Cost Recovery [Member] | Maximum [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar project investment term | 2,021 | ||||||||||||||||
Extended agreement base rate freeze date | Dec. 31, 2021 | ||||||||||||||||
Solar Project Cost Recovery [Member] | Effective September 1, 2018 [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar base rate adjustments | $ 31,000,000 | ||||||||||||||||
Solar energy capacity | MW | 145 | 150 | |||||||||||||||
Estimated annual revenue requirements | $ 24,000,000 | ||||||||||||||||
Solar Project Cost Recovery [Member] | Effective January 1, 2019 [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar base rate adjustments | $ 51,000,000 | ||||||||||||||||
Solar energy capacity | MW | 260 | 250 | |||||||||||||||
Estimated annual revenue requirements | $ 46,000,000 | ||||||||||||||||
Solar Project Cost Recovery [Member] | Effective January 1, 2020 [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar base rate adjustments | $ 31,000,000 | ||||||||||||||||
Solar energy capacity | MW | 150 | ||||||||||||||||
Solar Project Cost Recovery [Member] | Effective January 1, 2021 [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar base rate adjustments | $ 10,000,000 | ||||||||||||||||
Solar energy capacity | MW | 50 | ||||||||||||||||
Solar Project Cost Recovery [Member] | First Two Tranches [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Solar energy capacity | MW | 400 | ||||||||||||||||
Maximum cost to be constructed to build last tranche | $ / kWac | 1,475 | ||||||||||||||||
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 | $ 3,000,000 | $ 47,000,000 | |||||||||||||||
Regulatory liability | 56,000,000 | ||||||||||||||||
January 16, 2017 [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Additional base Revenue generated from increase in service charge | $ 110,000,000 | ||||||||||||||||
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% | ||||||||||||||||
Tax Reform and Storm Settlement Two [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
O&M expense | $ 47,000,000 | ||||||||||||||||
Reduction in regulatory asset | 47,000,000 | ||||||||||||||||
Tax Reform and Storm Settlement Three [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
O&M expense | $ 56,000,000 | ||||||||||||||||
Regulatory liability | $ 56,000,000 | ||||||||||||||||
Tax Reform and Storm Settlement [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Annually approved lowering base rates, Amount | $ 103,000,000 | ||||||||||||||||
Computer Software [Member] | |||||||||||||||||
Public Utilities General Disclosures [Line Items] | |||||||||||||||||
Amortization period of Regulatory Asset | 15 years |
Regulatory - Schedule of Regula
Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Regulatory assets: | ||
Regulatory assets | $ 458 | $ 433 |
Less: Current portion | 88 | 77 |
Long-term regulatory assets | 370 | 356 |
Regulatory liabilities: | ||
Regulatory liabilities | 1,310 | 1,285 |
Less: Current portion | 44 | 58 |
Long-term regulatory liabilities | 1,266 | 1,227 |
Regulatory Tax Asset [Member] | ||
Regulatory assets: | ||
Regulatory assets | 56 | 45 |
Cost-Recovery Clauses [Member] | ||
Regulatory assets: | ||
Regulatory assets | 55 | 13 |
Environmental Remediation [Member] | ||
Regulatory assets: | ||
Regulatory assets | 23 | 33 |
Postretirement Benefit [Member] | ||
Regulatory assets: | ||
Regulatory assets | 295 | 272 |
Storm Reserve [Member] | ||
Regulatory assets: | ||
Regulatory assets | 3 | 47 |
Regulatory liabilities: | ||
Regulatory liabilities | 56 | |
Other [Member] | ||
Regulatory assets: | ||
Regulatory assets | 26 | 23 |
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 715 | 730 |
Cost-Recovery Clauses [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 17 | 32 |
Storm Reserve [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 56 | 0 |
Accumulated Reserve - Cost of Removal [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | 513 | 518 |
Other [Member] | ||
Regulatory liabilities: | ||
Regulatory liabilities | $ 9 | $ 5 |
Regulatory - Schedule of Regu_2
Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liability | $ 1,310 | $ 1,285 |
Storm Reserve [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liability | $ 56 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) | Sep. 27, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Income Taxes [Line Items] | |||||
Federal statutory tax rate | 21.00% | 35.00% | 35.00% | ||
Asset expensing | 100.00% | ||||
Deferred tax assets | $ 275,000,000 | $ 194,000,000 | |||
Deferred tax liabilities | 1,074,000,000 | 1,019,000,000 | |||
Change in net deferred taxes offset to regulatory tax liability | $ 755,000,000 | ||||
Asset expensing, uncertainty provisional percentage | 100.00% | 100.00% | |||
Provision for income taxes | $ 81,000,000 | $ 197,000,000 | $ 152,000,000 | ||
Deferred tax assets expiration date | 2033 and 2037 | ||||
General business credit | $ 78,000,000 | ||||
Deferred tax general business credits expiration date | 2028 and 2038 | ||||
Uncertain tax positions | $ 8,000,000 | 8,000,000 | 7,000,000 | $ 0 | |
Pre-tax charges (benefits) | 0 | 0 | 0 | ||
Interest accrued | 0 | 0 | $ 0 | ||
Penalties | $ 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 | $ 340,000,000 | ||||
Federal [Member] | R&D Tax Credits [Member] | |||||
Income Taxes [Line Items] | |||||
Uncertain tax positions | 8,000,000 | $ 8,000,000 | |||
Florida [Member] | |||||
Income Taxes [Line Items] | |||||
Federal and Florida net operating losses (NOL's) carryforward | $ 274,000,000 |
Income Taxes - Schedule of Inco
Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Current income taxes, Federal | $ 72 | $ (1) | $ 53 |
Current income taxes, State | 10 | 6 | 12 |
Deferred income taxes, Federal | (13) | 170 | 76 |
Deferred income taxes, State | 13 | 23 | 11 |
Investment tax credits amortization | (1) | (1) | 0 |
Total income tax expense | $ 81 | $ 197 | $ 152 |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Income before provision for income taxes | $ 422 | $ 513 | $ 438 |
Federal statutory income tax rates | 21.00% | 35.00% | 35.00% |
Income taxes, at statutory income tax rate | $ 89 | $ 180 | $ 153 |
State income tax, net of federal income tax | 19 | 19 | 15 |
Excess deferred tax amortization | (24) | 0 | 0 |
AFUDC-equity | (2) | (1) | (8) |
Tax credits | (2) | (3) | (7) |
Other | 1 | 2 | (1) |
Total income tax expense | $ 81 | $ 197 | $ 152 |
Income tax expense as a percent of income from continuing operations, before income taxes | 19.20% | 38.40% | 34.80% |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax liabilities | ||
Property related | $ 969 | $ 919 |
Pension and postretirement benefits | 105 | 100 |
Total deferred tax liabilities | 1,074 | 1,019 |
Deferred tax assets | ||
Loss and credit carryforwards | 146 | 91 |
Medical benefits | 24 | 24 |
Insurance reserves | 17 | (5) |
Pension and postretirement benefits | 63 | 57 |
Capitalized energy conservation assistance costs | 16 | 13 |
Other | 9 | 14 |
Total deferred tax assets | 275 | 194 |
Total deferred tax liability, net | $ 799 | $ 825 |
Income Taxes - Schedule of De_2
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Income Tax Disclosure [Abstract] | ||||
Unrecognized tax benefits | $ 8 | $ 8 | $ 7 | $ 0 |
Income Taxes - Schedule of Unre
Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Beginning Balance | $ 8 | $ 7 | $ 0 |
Increases due to tax positions related to current year | 0 | 1 | 7 |
Ending Balance | $ 8 | $ 8 | $ 7 |
Employee Postretirement Benef_3
Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - TECO Energy [Member] - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||
Pension Benefits [Member] | ||||||
Change in benefit obligation | ||||||
Net benefit obligation at beginning of year | $ 812 | $ 770 | ||||
Service cost | 21 | 20 | $ 19 | |||
Interest cost | 29 | 31 | 31 | |||
Plan participants’ contributions | 0 | 0 | ||||
Plan curtailment | 0 | (1) | ||||
Plan settlement | (7) | (26) | ||||
Benefits paid | (55) | (51) | ||||
Actuarial loss (gain) | (50) | 69 | ||||
Net benefit obligation at end of year | 750 | 812 | 770 | |||
Other Postretirement Benefits [Member] | ||||||
Change in benefit obligation | ||||||
Net benefit obligation at beginning of year | [1] | 193 | 175 | |||
Service cost | 2 | [1] | 2 | [1] | 2 | |
Interest cost | 7 | [1] | 7 | [1] | 7 | |
Plan participants’ contributions | [1] | 4 | 3 | |||
Plan curtailment | [1] | 0 | 0 | |||
Plan settlement | [1] | 0 | 0 | |||
Benefits paid | [1] | (19) | (16) | |||
Actuarial loss (gain) | [1] | (14) | 22 | |||
Net benefit obligation at end of year | [1] | $ 173 | $ 193 | $ 175 | ||
[1] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement Benef_4
Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | |||
Change in plan assets | ||||
Employer contributions | $ 8 | $ 36 | ||
TECO Energy [Member] | ||||
Change in plan assets | ||||
Fair value of plan assets at beginning of year | 766 | |||
Fair value of plan assets at end of year | 659 | 766 | ||
TECO Energy [Member] | Pension Benefits [Member] | ||||
Change in plan assets | ||||
Fair value of plan assets at beginning of year | 766 | [1] | 649 | |
Actual return on plan assets | (63) | 122 | ||
Employer contributions | 10 | 46 | ||
Employer direct benefit payments | 8 | 27 | ||
Plan participants’ contributions | 0 | 0 | ||
Plan settlement | (7) | (26) | ||
Benefits paid | (54) | (51) | ||
Direct benefit payments | (1) | (1) | ||
Fair value of plan assets at end of year | [1] | 659 | 766 | |
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] | 15 | 13 | |
Plan participants’ contributions | [2] | 4 | 3 | |
Plan settlement | [2] | 0 | 0 | |
Benefits paid | [2] | (19) | (16) | |
Direct benefit payments | [2] | 0 | 0 | |
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_5
Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member] | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
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_6
Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | $ 659 | $ 766 | ||||
Pension Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Benefit obligation (PBO/APBO) | 750 | 812 | $ 770 | |||
Fair value of plan assets | 659 | [1] | 766 | [1] | 649 | |
Funded status at end of year | (91) | (46) | ||||
Other Postretirement Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Benefit obligation (PBO/APBO) | [2] | 173 | 193 | 175 | ||
Fair value of plan assets | [2] | 0 | [1] | 0 | [1] | $ 0 |
Other Postretirement Benefits [Member] | Florida [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Benefit obligation (PBO/APBO) | [2] | 173 | 193 | |||
Fair value of plan assets | [2] | 0 | 0 | |||
Funded status at end of year | [2] | $ (173) | $ (193) | |||
[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_7
Employee Postretirement Benefits - Additional Information (Detail) - USD ($) | Jan. 02, 2017 | Dec. 31, 2016 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | 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 | 110.60% | 112.50% | ||||||
Employer contributions | $ 8,000,000 | $ 36,000,000 | ||||||
Employer contributions in next fiscal year | $ 15,000,000 | |||||||
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. During the period of January 2015 to December 2016, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. | |||||||
Defined contribution plan cost recognized | $ 11,000,000 | 11,000,000 | $ 8,000,000 | |||||
Employer matching contribution percentage of eligible participant contribution | 75.00% | 70.00% | 70.00% | |||||
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer | 25.00% | 30.00% | ||||||
Non-qualified SERP [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Defined benefit plan, assets | $ 14,000,000 | 17,000,000 | ||||||
Unfunded [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Commitments | 0 | |||||||
Maximum [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Effect on net periodic benefit cost | 1,000,000 | |||||||
Pension Benefits [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Net periodic benefit cost | 16,000,000 | 14,000,000 | $ 13,000,000 | |||||
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year | 12,000,000 | |||||||
Increase in net periodic benefit cost | $ 1,000,000 | |||||||
Other Postretirement Benefits [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Net periodic benefit cost | 8,000,000 | 6,000,000 | 6,000,000 | |||||
Other postretirement benefit plans service benefit to be amortized from regulatory assets in next fiscal year | 0 | |||||||
SERP [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Employer contributions | 0 | 0 | 0 | |||||
Benefits paid | 7,000,000 | |||||||
Expected payment in next twelve months | 5,000,000 | |||||||
SERP [Member] | Scenario Forecast [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Expected settlement charge | $ 1,000,000 | |||||||
Restoration Plan [Member] | Scenario Forecast [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Expected settlement charge | $ 1,000,000 | |||||||
TECO Energy [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Accumulated benefit obligation of defined benefit pension plans | $ 705,000,000 | 762,000,000 | ||||||
Percentage of defined benefit plan's actual earned losses | 8.00% | |||||||
Defined contribution plan, maximum employer match percentage | 6.00% | |||||||
TECO Energy [Member] | Maximum [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Estimated annual contributions | $ 17,000,000 | |||||||
TECO Energy [Member] | Minimum [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Estimated annual contributions | 14,000,000 | |||||||
TECO Energy [Member] | Pension Benefits [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Net periodic benefit cost | 22,000,000 | 27,000,000 | 22,000,000 | |||||
Curtailment loss | 0 | 0 | 1,000,000 | |||||
Settlement charge | (2,000,000) | (7,000,000) | (1,000,000) | |||||
Commitments | 770,000,000 | 750,000,000 | 812,000,000 | 770,000,000 | $ 770,000,000 | |||
Employer contributions | 10,000,000 | 46,000,000 | ||||||
TECO Energy [Member] | Other Postretirement Benefits [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Net periodic benefit cost | 8,000,000 | 7,000,000 | 7,000,000 | |||||
Curtailment loss | 0 | 0 | 0 | |||||
Settlement charge | 0 | 0 | 0 | |||||
Commitments | [1] | $ 175,000,000 | 173,000,000 | 193,000,000 | $ 175,000,000 | $ 175,000,000 | ||
Employer contributions | [1] | 0 | 0 | |||||
Employer contributions in next fiscal year | 10,000,000 | |||||||
TECO Energy [Member] | SERP [Member] | ||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||
Settlement charge | $ 7,000,000 | |||||||
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 | |||||||
[1] | 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, 2018 | Dec. 31, 2017 |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit costs and other current liabilities | $ (5) | $ (7) |
Deferred credits and other liabilities | (68) | (30) |
Net amount recognized at end of year | (73) | (37) |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Accrued benefit costs and other current liabilities | (10) | (10) |
Deferred credits and other liabilities | (137) | (154) |
Net amount recognized at end of year | $ (147) | $ (164) |
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, 2018 | Dec. 31, 2017 |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial loss (gain) | $ 251 | $ 215 |
Prior service cost (credit) | 0 | 1 |
Amount recognized | 251 | 216 |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net actuarial loss (gain) | 45 | 70 |
Prior service cost (credit) | 0 | (13) |
Amount recognized | $ 45 | $ 57 |
Employee Postretirement Bene_10
Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.33% | 3.62% | |
Rate of compensation increase-weighted average | 3.75% | 3.32% | |
Discount rate | 3.62% | 4.11% | 4.69% |
Expected long-term return on plan assets | 6.85% | 7.00% | 7.00% |
Rate of compensation increase | 3.32% | 2.57% | 2.59% |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.38% | 3.70% | |
Rate of compensation increase-weighted average | 3.75% | 3.31% | |
Discount rate | 3.70% | 4.28% | |
Rate of compensation increase | 3.31% | 2.48% | 2.50% |
Healthcare cost trend rate | |||
Ultimate rate | 4.50% | 4.50% | 4.50% |
Year rate reaches ultimate | 2,038 | 2,038 | 2,038 |
Other Postretirement Benefits [Member] | Maximum [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.667% | ||
Other Postretirement Benefits [Member] | Minimum [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 3.85% | ||
Other Postretirement Benefits [Member] | Immediate Rate [Member] | |||
Healthcare cost trend rate | |||
Immediate rate | 6.31% | 6.58% | |
Other Postretirement Benefits [Member] | Initial Rate [Member] | |||
Healthcare cost trend rate | |||
Immediate rate | 6.58% | 6.83% | 7.05% |
Employee Postretirement Bene_11
Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) - Assumed One-percentage-point Change [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |
Effect on PBO - Increase | $ 5 |
Effect on PBO - Decrease | $ (4) |
Employee Postretirement Bene_12
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Pension Benefits [Member] | |||||
Amortization of: | |||||
Net periodic benefit cost | $ 16 | $ 14 | $ 13 | ||
Other Postretirement Benefits [Member] | |||||
Amortization of: | |||||
Net periodic benefit cost | 8 | 6 | 6 | ||
TECO Energy [Member] | Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 21 | 20 | 19 | ||
Interest cost | 29 | 31 | 31 | ||
Expected return on plan assets | (49) | (48) | (46) | ||
Amortization of: | |||||
Actuarial loss | 19 | 17 | 16 | ||
Prior service (benefit) cost | 0 | 0 | 0 | ||
Curtailment loss (gain) | 0 | 0 | 1 | ||
Settlement loss | 2 | 7 | 1 | ||
Net periodic benefit cost | 22 | 27 | 22 | ||
New prior service cost | 0 | 0 | 1 | ||
Net loss (gain) arising during the year | 62 | (5) | 47 | ||
Amounts recognized as component of net periodic benefit cost: | |||||
Amortization or curtailment recognition of prior service (benefit) cost | 0 | 0 | 0 | ||
Amortization or settlement of actuarial gain (loss) | (20) | (24) | (17) | ||
Total recognized in OCI and regulatory assets | 42 | (29) | 31 | ||
Total recognized in net periodic benefit cost, OCI and regulatory assets | 64 | (2) | 53 | ||
TECO Energy [Member] | Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 2 | [1] | 2 | [1] | 2 |
Interest cost | 7 | [1] | 7 | [1] | 7 |
Expected return on plan assets | 0 | 0 | 0 | ||
Amortization of: | |||||
Actuarial loss | 1 | 0 | 0 | ||
Prior service (benefit) cost | (2) | (2) | (2) | ||
Curtailment loss (gain) | 0 | 0 | 0 | ||
Settlement loss | 0 | 0 | 0 | ||
Net periodic benefit cost | 8 | 7 | 7 | ||
New prior service cost | 0 | 0 | 0 | ||
Net loss (gain) arising during the year | (14) | 22 | 5 | ||
Amounts recognized as component of net periodic benefit cost: | |||||
Amortization or curtailment recognition of prior service (benefit) cost | 2 | 2 | 2 | ||
Amortization or settlement of actuarial gain (loss) | (1) | 0 | 0 | ||
Total recognized in OCI and regulatory assets | (13) | 24 | 7 | ||
Total recognized in net periodic benefit cost, OCI and regulatory assets | $ (5) | $ 31 | $ 14 | ||
[1] | Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. |
Employee Postretirement bene_13
Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member] | Dec. 31, 2018 | Dec. 31, 2017 |
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 | 46.00% | 51.00% |
Actual Asset Allocation [Member] | Fixed Income Securities [Member] | ||
Asset Category | ||
Actual Allocation, End of Year | 54.00% | 49.00% |
Target Allocation [Member] | ||
Asset Category | ||
2018 Target Allocation | 100.00% | |
Target Allocation [Member] | Equity Securities [Member] | Minimum [Member] | ||
Asset Category | ||
2018 Target Allocation | 47.00% | |
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member] | ||
Asset Category | ||
2018 Target Allocation | 53.00% | |
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member] | ||
Asset Category | ||
2018 Target Allocation | 47.00% | |
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member] | ||
Asset Category | ||
2018 Target Allocation | 53.00% |
Employee Postretirement Bene_14
Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | ||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | $ 659 | $ 766 | ||
Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (3) | 3 | ||
Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 17 | 14 | ||
Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 32 | 44 | ||
Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 6 | |||
Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 3 | 4 | ||
Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 97 | 196 | ||
Municipal Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 2 | ||
Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 59 | 55 | ||
Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 55 | 45 | ||
Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 230 | 337 | ||
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 | 330 | [1] | 326 | [2] |
Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 99 | [1] | 103 | [2] |
MBS [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (1) | |||
Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 3 | 4 | ||
NAV [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 429 | 429 | ||
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 | |||
NAV [Member] | Real Estate Investment Trust (REIT) [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 | 330 | [1] | 326 | [2] |
NAV [Member] | Mutual fund [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 99 | [1] | 103 | [2] |
NAV [Member] | MBS [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 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 | 111 | 232 | ||
Level 1 [Member] | Cash [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (3) | 3 | ||
Level 1 [Member] | Short Term Investment Fund (STIF) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 17 | 14 | ||
Level 1 [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 32 | 44 | ||
Level 1 [Member] | Long Futures [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 6 | |||
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 3 | 4 | ||
Level 1 [Member] | Mutual Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 97 | 196 | ||
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 | 111 | 232 | ||
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] | MBS [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 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 | 119 | 105 | ||
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 | |||
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] | 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 | 2 | ||
Level 2 [Member] | Government Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 59 | 55 | ||
Level 2 [Member] | Corporate Bonds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 55 | 45 | ||
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 119 | 105 | ||
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] | MBS [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (1) | |||
Level 2 [Member] | Swaps [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 3 | 4 | ||
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 | |||
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] | 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] | MBS [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 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 | 10 | 14 | ||
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 | 10 | 14 | ||
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 | (51) | (43) | ||
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 | (51) | (43) | ||
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 | ||
Purchase Options (swaptions) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Purchase Options (swaptions) [Member] | NAV [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Purchase Options (swaptions) [Member] | Level 1 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Purchase Options (swaptions) [Member] | Level 2 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1 | 1 | ||
Purchase Options (swaptions) [Member] | Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Written Options (Swaptions) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (1) | (2) | ||
Written Options (Swaptions) [Member] | NAV [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Written Options (Swaptions) [Member] | Level 1 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Written Options (Swaptions) [Member] | Level 2 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | (1) | (2) | ||
Written Options (Swaptions) [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. | |||
[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. |
Employee Postretirement Bene_15
Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions | Dec. 31, 2018USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected Benefit Payments - 2019 | $ 57 |
Expected Benefit Payments - 2020 | 55 |
Expected Benefit Payments - 2021 | 59 |
Expected Benefit Payments - 2022 | 60 |
Expected Benefit Payments - 2023 | 60 |
Expected Benefit Payments - 2024 - 2028 | 333 |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected Benefit Payments - 2019 | 12 |
Expected Benefit Payments - 2020 | 12 |
Expected Benefit Payments - 2021 | 12 |
Expected Benefit Payments - 2022 | 12 |
Expected Benefit Payments - 2023 | 12 |
Expected Benefit Payments - 2024 - 2028 | $ 59 |
Short-Term Debt - Credit Facili
Short-Term Debt - Credit Facilities (Detail) - USD ($) | Dec. 31, 2018 | Mar. 23, 2018 | Dec. 31, 2017 | Mar. 22, 2017 |
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | $ 475,000,000 | $ 775,000,000 | $ 50,000,000 | |
Borrowings Outstanding | 221,000,000 | 305,000,000 | ||
Letters of Credit Outstanding | 1,000,000 | 1,000,000 | ||
5-year Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | 325,000,000 | 325,000,000 | ||
Borrowings Outstanding | 131,000,000 | 5,000,000 | ||
Letters of Credit Outstanding | 1,000,000 | 1,000,000 | ||
3-year Accounts Receivable Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | 150,000,000 | $ 150,000,000 | 150,000,000 | |
Borrowings Outstanding | 90,000,000 | 0 | ||
Letters of Credit Outstanding | 0 | 0 | ||
1-year Term Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Credit Facilities | 0 | 300,000,000 | ||
Borrowings Outstanding | 0 | 300,000,000 | ||
Letters of Credit Outstanding | $ 0 | $ 0 |
Short-Term Debt - Credit Faci_2
Short-Term Debt - Credit Facilities (Parenthetical) (Detail) | Mar. 23, 2018 | Dec. 31, 2018 | Dec. 31, 2017 |
5-year Facility [Member] | |||
Line Of Credit Facility [Line Items] | |||
Credit facility maturity date | Mar. 22, 2022 | Mar. 22, 2022 | |
3-year Accounts Receivable Facility [Member] | |||
Line Of Credit Facility [Line Items] | |||
Credit facility maturity date | Mar. 22, 2021 | Mar. 22, 2021 | Mar. 22, 2021 |
1-year Term Facility [Member] | |||
Line Of Credit Facility [Line Items] | |||
Credit facility maturity date | Oct. 11, 2018 | Oct. 11, 2018 |
Short-Term Debt - Additional In
Short-Term Debt - Additional Information (Detail) - USD ($) | Mar. 23, 2018 | Mar. 22, 2017 | Dec. 31, 2018 | Dec. 31, 2017 |
Line Of Credit Facility [Line Items] | ||||
Weighted-average interest rate | 3.14% | 2.07% | ||
Line of credit facility maximum borrowing capacity | $ 50,000,000 | $ 475,000,000 | $ 775,000,000 | |
Increase of credit facility | 175,000,000 | |||
Amended And Restated Credit Agreement [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Line of credit facility maximum borrowing capacity | $ 325,000,000 | |||
3-year Accounts Receivable Facility [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Line of credit facility maximum borrowing capacity | $ 150,000,000 | $ 150,000,000 | $ 150,000,000 | |
Credit facility amendment date | Mar. 23, 2018 | |||
Credit facility maturity date | Mar. 22, 2021 | Mar. 22, 2021 | Mar. 22, 2021 | |
Loan agreement program and liquidity fees | 0.70% | |||
Interest rate description | TEC will pay program and liquidity fees, which total 70 basis points at December 31, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin | |||
Minimum [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Commitment fees, percentage | 0.125% | |||
Minimum [Member] | Amended And Restated Credit Agreement [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Debt instrument maturity date | Dec. 17, 2018 | |||
Maximum [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Commitment fees, percentage | 0.35% | |||
Maximum [Member] | Amended And Restated Credit Agreement [Member] | ||||
Line Of Credit Facility [Line Items] | ||||
Debt instrument maturity date | Mar. 22, 2022 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions | Oct. 04, 2018 | Jun. 07, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | |||||
Purchase in lieu of redemption | $ 304 | $ 0 | $ 83 | ||
Held Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Purchase in lieu of redemption | 233 | 233 | |||
4.3% Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, maturity year | 2,048 | ||||
4.3% Notes [Member] | Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount issued | $ 350 | ||||
Stated interest rate | 4.30% | ||||
Debt instrument maturity date | Jun. 15, 2048 | ||||
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 | Dec. 15, 2047 | ||||
Debt instrument, offering date | Jun. 7, 2018 | ||||
4.45% Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, maturity year | 2,049 | ||||
4.45% Notes [Member] | Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount issued | $ 375 | ||||
Stated interest rate | 4.45% | ||||
Debt instrument maturity date | Jun. 15, 2049 | ||||
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 | Dec. 15, 2048 | ||||
Debt instrument, offering date | Oct. 4, 2018 | ||||
Variable Rate Bonds Due 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Purchase in lieu of redemption | $ 20 | $ 20 | |||
Purchase in lieu of redemption, due year | 2,020 | 2,020 | |||
Term Rate Refunding Bonds Due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Purchase in lieu of redemption | $ 52 | $ 52 | |||
Purchase in lieu of redemption, due year | 2,025 | 2,025 | |||
Term Rate Refunding Bonds Due 2030 [Member] | |||||
Debt Instrument [Line Items] | |||||
Purchase in lieu of redemption | $ 75 | $ 75 | |||
Purchase in lieu of redemption, due year | 2,030 | 2,030 | |||
Term Rate Refunding Bonds Due 2034 [Member] | |||||
Debt Instrument [Line Items] | |||||
Purchase in lieu of redemption | $ 86 | $ 86 | |||
Purchase in lieu of redemption, due year | 2,034 | 2,034 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Long Term Commitments [Line Items] | |||
Total rental expense and lease | $ 2 | $ 2 | $ 2 |
PGS [Member] | |||
Long Term Commitments [Line Items] | |||
Ultimate financial liability to superfund sites and former MGP sites | $ 28 |
Commitments and Contingencies_2
Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions | Dec. 31, 2018USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
Future Minimum Transportation Payments Due, 2019 | $ 194 |
Future Minimum Transportation Payments Due, 2020 | 175 |
Future Minimum Transportation Payments Due, 2021 | 141 |
Future Minimum Transportation Payments Due, 2022 | 133 |
Future Minimum Transportation Payments Due, 2023 | 108 |
Future Minimum Transportation Payments Due, Thereafter | 1,013 |
Total future minimum transportation payments due | 1,764 |
Future Minimum Capital Projects Payments Due, 2019 | 298 |
Future Minimum Capital Projects Payments Due, 2020 | 89 |
Future Minimum Capital Projects Payments Due, 2021 | 33 |
Future Minimum Capital Projects Payments Due, 2022 | 8 |
Future Minimum Capital Projects Payments Due, 2023 | 2 |
Future Minimum Capital Projects Payments Due, Thereafter | 6 |
Total future minimum capital projects payments due | 436 |
Future Minimum Fuel and Gas Supply Payments Due, 2019 | 257 |
Future Minimum Fuel and Gas Supply Payments Due, 2020 | 106 |
Future Minimum Fuel and Gas Supply Payments Due, 2021 | 3 |
Future Minimum Fuel and Gas Supply Payments Due, 2022 | 3 |
Future Minimum Fuel and Gas Supply Payments Due, 2023 | 1 |
Future Minimum Fuel and Gas Supply Payments Due, Thereafter | 0 |
Total future minimum fuel and gas supply payments due | 370 |
Future Minimum Long-term Service Agreements Payments Due, 2019 | 7 |
Future Minimum Long-term Service Agreements Payments Due, 2020 | 6 |
Future Minimum Long-term Service Agreements Payments Due, 2021 | 6 |
Future Minimum Long-term Service Agreements Payments Due, 2022 | 7 |
Future Minimum Long-term Service Agreements Payments Due, 2023 | 11 |
Future Minimum Long-term Service Agreements Payments Due, Thereafter | 78 |
Total future minimum long-term service agreements payments due | 115 |
Future Minimum Operating Leases Payments Due, 2019 | 2 |
Future Minimum Operating Leases Payments Due, 2020 | 2 |
Future Minimum Operating Leases Payments Due, 2021 | 2 |
Future Minimum Operating Leases Payments Due, 2022 | 2 |
Future Minimum Operating Leases Payments Due, 2023 | 2 |
Future Minimum Operating Leases Payments Due, Thereafter | 34 |
Total future minimum operating leases payments due | 44 |
Future Minimum Demand Side Management Payments Due, 2019 | 5 |
Future Minimum Demand Side Management Payments Due, 2020 | 1 |
Future Minimum Demand Side Management Payments Due, 2021 | 0 |
Future Minimum Demand Side Management Payments Due, 2022 | 0 |
Future Minimum Demand Side Management Payments Due, 2023 | 0 |
Future Minimum Demand Side Management Payments Due, Thereafter | 0 |
Total future minimum demand side management payments due | 6 |
Future Minimum Payments Due, 2019 | 763 |
Future Minimum Payments Due, 2020 | 379 |
Future Minimum Payments Due, 2021 | 185 |
Future Minimum Payments Due, 2022 | 153 |
Future Minimum Payments Due, 2023 | 124 |
Future Minimum Payments Due, Thereafter | 1,131 |
Total future minimum payments | $ 2,735 |
Revenue - Summary of Disaggrega
Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | $ 2,063 | $ 2,052 | $ 1,964 |
Total gas revenue | 461 | 418 | 432 |
Total revenue | 2,524 | $ 2,470 | $ 2,396 |
Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 1,067 | ||
Total gas revenue | 157 | ||
Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 582 | ||
Total gas revenue | 151 | ||
Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 161 | ||
Total gas revenue | 21 | ||
Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (2) | ||
Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 255 | ||
Total gas revenue | 132 | ||
Tampa Electric [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 2,066 | ||
Total gas revenue | 0 | ||
Total revenue | 2,066 | ||
Tampa Electric [Member] | Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 1,067 | ||
Total gas revenue | 0 | ||
Tampa Electric [Member] | Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 582 | ||
Total gas revenue | 0 | ||
Tampa Electric [Member] | Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 161 | ||
Total gas revenue | 0 | ||
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (2) | ||
Tampa Electric [Member] | Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 258 | ||
Total gas revenue | 0 | ||
PGS [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 488 | ||
Total revenue | 488 | ||
PGS [Member] | Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 157 | ||
PGS [Member] | Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 151 | ||
PGS [Member] | Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 21 | ||
PGS [Member] | Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
PGS [Member] | Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 159 | ||
Eliminations [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (3) | ||
Total gas revenue | (27) | ||
Total revenue | (30) | ||
Eliminations [Member] | Residential [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 0 | ||
Eliminations [Member] | Commercial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 0 | ||
Eliminations [Member] | Industrial [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Total gas revenue | 0 | ||
Eliminations [Member] | Regulatory Deferrals and Unbilled Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | 0 | ||
Eliminations [Member] | Other [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Total electric revenue | (3) | ||
Total gas revenue | $ (27) |
Revenue - Additional Informatio
Revenue - Additional Information (Details) $ in Millions | Dec. 31, 2018USD ($) |
Regulated Operating Revenue [Abstract] | |
Remaining performance obligations, transaction price | $ 135 |
Remaining performance obligations, expected year of revenue recognition | 2,033 |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |||
Natural gas sales to/(from) affiliates | $ (38) | $ (4) | $ 0 |
Services received from affiliates | 65 | 67 | 66 |
Dividends to TECO Energy | 362 | 292 | |
Equity contributions from TECO Energy | 345 | 190 | |
Accounts receivable | 3 | 2 | |
Accounts payable | 20 | 19 | |
Taxes receivable | 1 | 3 | |
Taxes payable | 4 | 2 | |
TECO Energy [Member] | |||
Related Party Transaction [Line Items] | |||
Dividends to TECO Energy | 362 | 292 | 289 |
Equity contributions from TECO Energy | $ 345 | $ 190 | $ 150 |
Segment Information - Additiona
Segment Information - Additional Information (Detail) | Dec. 31, 2018Customer |
Tampa Electric [Member] | |
Segment Reporting Information [Line Items] | |
Number of retail electric utility service customers in West Central Florida | 764,000 |
PGS [Member] | Minimum [Member] | |
Segment Reporting Information [Line Items] | |
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution | 392,000 |
Segment Information - Schedule
Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||
Total revenues | $ 2,524 | $ 2,470 | $ 2,396 |
Depreciation and amortization | 372 | 350 | 328 |
Total interest charges | 118 | 119 | 106 |
Provision for income taxes | 81 | 197 | 152 |
Net income | 341 | 316 | 286 |
Total assets | 9,155 | 8,364 | 8,083 |
Capital expenditures | 1,109 | 640 | 727 |
Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,524 | 2,470 | 2,396 |
Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | 0 | 0 | 0 |
Eliminations [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | (30) | (22) | (8) |
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 | (487) | (555) | (465) |
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 | (30) | (22) | (8) |
Tampa Electric [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,066 | ||
Tampa Electric [Member] | Operating Segments [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,066 | 2,054 | 1,965 |
Depreciation and amortization | 312 | 300 | 268 |
Total interest charges | 102 | 104 | 91 |
Provision for income taxes | 65 | 171 | 130 |
Net income | 294 | 273 | 251 |
Total assets | 8,235 | 7,635 | 7,357 |
Capital expenditures | 940 | 518 | 594 |
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 2,063 | 2,052 | 1,964 |
Tampa Electric [Member] | Operating Segments [Member] | Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | 3 | 2 | 1 |
PGS [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 488 | ||
PGS [Member] | Operating Segments [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 488 | 438 | 439 |
Depreciation and amortization | 60 | 50 | 60 |
Total interest charges | 16 | 15 | 15 |
Provision for income taxes | 16 | 26 | 22 |
Net income | 47 | 43 | 35 |
Total assets | 1,407 | 1,284 | 1,191 |
Capital expenditures | 169 | 122 | 133 |
PGS [Member] | Operating Segments [Member] | Revenues - External [Member] | |||
Segment Reporting Information [Line Items] | |||
Total revenues | 461 | 418 | 432 |
PGS [Member] | Operating Segments [Member] | Sales to Affiliates [Member] | |||
Segment Reporting Information [Line Items] | |||
Sales to affiliates | $ 27 | $ 20 | $ 7 |
Asset Retirement Obligations -
Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Beginning balance | $ 47 | $ 45 |
Additional liabilities | 18 | 1 |
Liabilities settled | 0 | (1) |
Revisions to estimated cash flows | (3) | 0 |
Other | 2 | 2 |
Ending balance | $ 64 | $ 47 |
Accounting for Derivative Ins_2
Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($) | Nov. 06, 2017 | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative [Line Items] | |||
Derivative assets | $ 0 | ||
Derivative liabilities | $ 0 | $ 1,000,000 | |
Natural Gas Contracts [Member] | |||
Derivative [Line Items] | |||
Maximum length of time hedging in future cash flow | Nov. 30, 2018 | ||
Natural Gas [Member] | |||
Derivative [Line Items] | |||
Financial hedging moratorium period | 5 years |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Detail) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | $ 0 | |
Derivative liabilities | 0 | $ 1,000,000 |
Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | 0 | 0 |
Derivative liabilities | $ 0 | $ 0 |
Variable Interest Entities - Ad
Variable Interest Entities - Additional Information (Detail) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2019MW | Dec. 31, 2018USD ($)MW | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Long Term Contract For Purchase Of Electric Power [Line Items] | ||||
Purchased power | $ | $ 59 | $ 46 | $ 104 | |
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member] | ||||
Long Term Contract For Purchase Of Electric Power [Line Items] | ||||
Purchased power | $ | $ 15 | $ 16 | $ 62 | |
Minimum [Member] | ||||
Long Term Contract For Purchase Of Electric Power [Line Items] | ||||
Multiple PPAs range | 121 | |||
Maximum [Member] | ||||
Long Term Contract For Purchase Of Electric Power [Line Items] | ||||
Multiple PPAs range | 250 | |||
Maximum [Member] | Scenario Forecast [Member] | ||||
Long Term Contract For Purchase Of Electric Power [Line Items] | ||||
Multiple PPAs range | 360 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) - Performance Share Unit Plan [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
PSUs performance cycles | 3 years | |
Number of trading days | 50 days | |
Compensation cost recognized | $ 4 | $ 2 |
Tax benefits related to compensation cost | 1 | 1 |
Unrecognized compensation cost | $ 6 | $ 4 |
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, 2018CAD ($)$ / sharesshares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Number of Units, Outstanding as of December 31, 2017 | shares | 133 |
Number of Units, Granted including DRIP | shares | 130 |
Number of Units, Exercised | shares | (4) |
Number of Units, Forfeited | shares | (1) |
Number of Units, Outstanding as of December 31, 2018 | shares | 258 |
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2017 | $ / shares | $ 45.11 |
Weighted Average Grant Date Fair Value, Granted including DRIP | $ / shares | 47.98 |
Weighted Average Grant Date Fair Value, Exercised | $ / shares | 38.85 |
Weighted Average Grant Date Fair Value, Forfeited | $ / shares | 45.41 |
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2018 | $ / shares | $ 46.68 |
Aggregate Intrinsic Value, Outstanding as of December 31, 2017 | $ | $ 6 |
Aggregate Intrinsic Value, Granted including DRIP | $ | 6 |
Aggregate Intrinsic Value, Exercised | $ | (1) |
Aggregate Intrinsic Value, Forfeited | $ | 0 |
Aggregate Intrinsic Value, Outstanding as of December 31, 2018 | $ | $ 11 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - Allowance for Uncollectible Accounts - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Valuation And Qualifying Accounts Disclosure [Line Items] | ||||
Balance at Beginning of Period | $ 1 | $ 1 | $ 1 | |
Charged to Income | 7 | 5 | 3 | |
Other Charges | 0 | 0 | 0 | |
Payments & Deductions | [1] | 6 | 5 | 3 |
Balance at End of Period | $ 2 | $ 1 | $ 1 | |
[1] | Write-off of individual bad debt accounts |