Tampa Electric 10-K 12 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 08, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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 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, 2017	Dec. 31, 2016
Property, plant and equipment
Utility plant in service, at original costs	$ 10,427	$ 10,019
Construction work in progress	263	892
Accumulated depreciation	(2,994)	(2,826)
Utility plant in service, net	7,433	7,193
Other property	11	10
Total property, plant and equipment, net	7,444	7,203
Current assets
Cash and cash equivalents	13	10
Receivables, less allowance for uncollectibles of $1 at December 31, 2017 and 2016	257	206
Due from affiliates	5	7
Inventories, at average cost
Current derivative assets	0	15
Regulatory assets	77	28
Prepayments and other current assets	13	21
Total current assets	515	450
Deferred debits
Regulatory assets	356	393
Other	49	37
Total deferred debits	405	430
Total assets	8,364	8,083
Capitalization
Common stock	2,645	2,456
Accumulated other comprehensive loss	(2)	(3)
Retained earnings	335	311
Total capital	2,978	2,764
Long-term debt, less amount due within one year	1,860	2,163
Total capital	4,838	4,927
Current liabilities
Long-term debt due within one year	304	0
Notes payable	305	170
Accounts payable	233	262
Due to affiliates	21	25
Customer deposits	131	146
Regulatory liabilities	58	154
Accrued interest	14	16
Accrued taxes	12	12
Other	44	11
Total current liabilities	1,122	796
Long-term liabilities
Deferred income taxes	825	1,407
Regulatory liabilities	1,227	591
Deferred credits and other liabilities	352	362
Total deferred credits	2,404	2,360
Commitments and Contingencies (see Note 9)
Total liabilities and capital	8,364	8,083
Fuel [Member]
Inventories, at average cost
Utility inventories	60	77
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	90	86
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	8,555	7,624
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,609	$ 1,503

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Allowance for uncollectibles	$ 1	$ 1

Consolidated Statements of Inco

Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Electric	$ 2,052	$ 1,964	$ 2,018
Gas	418	432	401
Total revenues	2,470	2,396	2,419
Expenses
Fuel	588	561	639
Purchased power	46	104	79
Cost of natural gas sold	153	159	135
Operations & maintenance	513	538	529
Depreciation and amortization	350	328	313
Taxes, other than income	198	193	192
Total expenses	1,848	1,883	1,887
Income from operations	622	513	532
Other income
Allowance for other funds used during construction	2	24	17
Other income, net	8	7	3
Total other income	10	31	20
Interest charges
Interest expense	120	117	118
Allowance for borrowed funds used during construction	(1)	(11)	(8)
Total interest charges	119	106	110
Income before provision for income taxes	513	438	442
Provision for income taxes	197	152	166
Net income	316	286	276
Other comprehensive income, net of tax
Gain on cash flow hedges	1	1	4
Total other comprehensive income, net of tax	1	1	4
Comprehensive income	$ 317	$ 287	$ 280

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities
Net income	$ 316	$ 286	$ 276
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	350	328	313
Deferred income taxes and investment tax credits	192	87	120
Allowance for equity funds used during construction	(2)	(24)	(17)
Deferred recovery clauses	(83)	54	26
Receivables, less allowance for uncollectibles	(43)	18	(3)
Inventories	13	16	(21)
Taxes accrued	(9)	68	(17)
Accounts payable	(16)	63	(27)
Regulatory assets and liabilities	(100)	(11)	(9)
Other	(6)	(54)	(33)
Cash flows from operating activities	612	831	608
Cash flows from investing activities
Capital expenditures	(640)	(727)	(687)
Net proceeds from sale of assets	0	9	0
Cash flows used in investing activities	(640)	(718)	(687)
Cash flows from financing activities
Equity contributions from TECO Energy	190	150
Proceeds from long-term debt issuance	0	0	251
Repayment of long-term debt	0	(83)	(83)
Net change in short-term debt (maturities of 90 days or less)	(165)	109	3
Proceeds from other short-term debt (maturities over 90 days)	300	0	0
Dividends to TECO Energy	(292)	(289)
Other financing activities	(2)	1	0
Cash flows from/(used in) financing activities	31	(112)	78
Net increase (decrease) in cash and cash equivalents	3	1	(1)
Cash and cash equivalents at beginning of the year	10	9	10
Cash and cash equivalents at end of the year	13	10	9
Supplemental disclosure of cash paid (received):
Interest	115	103	106
Income taxes	13	(3)	64
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	(16)	(9)	7
TECO Energy [Member]
Cash flows from financing activities
Equity contributions from TECO Energy	190	150	175
Dividends to TECO Energy	$ (292)	$ (289)	$ (268)

Consolidated Statements of Cas6

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement Of Partners Capital [Abstract]
Beginning Balance	$ 311	$ 314	$ 306
Add: Net income	316	286	276
Retained Earning, Gross	627	600	582
Deduct: Cash dividends on capital stock—common	292	289	268
Ending Balance	$ 335	$ 311	$ 314

Consolidated Statements of Capi

Consolidated Statements of Capitalization - Capital Stock - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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	$ 2,645	$ 2,456
Cash Dividends Paid	$ 292	$ 289

Consolidated Statements of Cap9

Consolidated Statements of Capitalization - Capital Stock (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Preferred stock - par value | $ / shares	$ 100
Preferred stock, no par value | $ / shares
Equity contributions made by TECO Energy | $	$ 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 [Member]
Preferred stock, no par value | $ / shares
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

Consolidated Statements of Ca10

Consolidated Statements of Capitalization - Long-Term Debt - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt, total	$ 2,183	$ 2,183
Unamortized debt discount, net	(3)	(3)
Debt issuance costs	(16)	(17)
Long-term debt, carrying amount	2,164	2,163
Less amount due within one year	304	0
Total long-term debt	1,860	2,163
Long-term debt, fair value	2,412	2,345
Level 1 [Member]
Debt Instrument [Line Items]
Long-term debt, fair value	55	58
Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,921	1,921
Long-term debt, carrying amount	$ 1,921
Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 54	54
Tampa Electric [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 200	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
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	262	262
Long-term debt, carrying amount	$ 262
PGS [Member] | 6.10% Notes [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 50	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

Consolidated Statements of Ca11

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical)	Dec. 31, 2017
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%
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%

Consolidated Statements of Ca12

Consolidated Statements of Capitalization - Long-term Debt Maturities $ in Millions	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Total long-term debt maturities	$ 2,164
Long Term Debt Maturities
Debt Instrument [Line Items]
2,018	304
2,019	0
2,020	0
2,021	279
2,022	250
Thereafter	1,350
Total long-term debt maturities	2,183
Tampa Electric [Member]
Debt Instrument [Line Items]
2,018	254
2,019	0
2,020	0
2,021	232
2,022	225
Thereafter	1,210
Total long-term debt maturities	1,921
PGS [Member]
Debt Instrument [Line Items]
2,018	50
2,019	0
2,020	0
2,021	47
2,022	25
Thereafter	140
Total long-term debt maturities	$ 262

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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. See Note 8 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. In general, when regulated depreciable property is retired or disposed, its original cost less salvage is charged to accumulated depreciation. 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, 2017 December 31, 2016 Electric generation 21-56 years $ 4,766 $ 4,102 Electric transmission 28-77 years 859 837 Electric distribution 14-56 years 2,437 2,331 Gas transmission and distribution 15-77 years 1,534 1,429 General plant and other 8-43 years 579 438 Total cost 10,175 9,137 Less accumulated depreciation (2,994 ) (2,826 ) Construction work in progress 263 892 Total property, plant and equipment, net $ 7,444 $ 7,203 Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7%, 3.5% and 3.7% for 2017, 2016 and 2015, respectively. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $332 million, $304 million and $306 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 2017, 2016 and 2015, the rate was 6.46%. Total AFUDC for the years ended December 31, 2017, 2016 and 2015 was $2 million, $36 million and $26 million, respectively. The decrease in 2017 and increase in 2016 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 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, 2017 and 2016, ITCs were $22 million and $11 million, respectively. Revenue Recognition TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer. Tampa Electric’s and PGS’s retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3 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. Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-affiliates at a cost of $46 million, $104 million and $79 million, for the years ended December 31, 2017, 2016 and 2015, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause. Receivables and Allowance for Uncollectible Accounts Receivables consist of services billed to residential, commercial, industrial and other customers. 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 natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. Accounting for Franchise Fees and Gross Receipts Taxes TEC is 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 are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $113 million, $117 million and $117 million for the years ended December 31, 2017, 2016 and 2015, respectively. Deferred Credits and Other Liabilities Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5 Note 9 Note 16 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, 2017 and 2016 ranged from 2.74% to 4.00% and 2.69% 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. 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, 2017
Accounting Changes And Error Corrections [Abstract]
New Accounting Pronouncements	2. New Accounting Pronouncements Change in Accounting Policy The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2017, are described as follows: Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows In August 2016, the FASB issued Accounting Standard Update (ASU) 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows Future Accounting Pronouncements TEC considers the applicability and impact of all ASUs issued by FASB. The following updates have been issued by FASB, but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements. Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers TEC implemented a revenue recognition project plan in 2016. In the first quarter of 2017, TEC concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In the second quarter of 2017, TEC completed an analysis of material regulated revenue streams and collectibility risk and concluded that there will be no material changes on adoption of this standard. In the third quarter of 2017, TEC completed an analysis of material unregulated revenue streams and concluded that there will be no material changes on adoption of this standard. TEC also evaluated the disclosure requirements and determined that the disaggregation of revenue information required by the new standard will not have a significant impact on TEC’s information gathering processes and procedures as the revenue information required by the standard is consistent with historical revenue information gathered by TEC for financial reporting purposes. TEC continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities Leases In February 2016, the FASB issued ASU 2016-02, Leases In January 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect an optional transition practical expedient to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. In November 2017, the FASB voted to amend ASC Topic 842 to allow companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The amendment is expected to be finalized in the first quarter of 2018. TEC is in the process of evaluating the impact of adoption of this standard on its financial statements and disclosures. In the third quarter of 2017, TEC implemented a project plan. In the fourth quarter of 2017, TEC began execution of the project plan, including training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements. This includes evaluating the available practical expedients, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements. TEC 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. Clarifying the Definition of a Business In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities,

Regulatory

Regulatory	12 Months Ended
	Dec. 31, 2017
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 the past three years 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 the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million 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 beginning on January 1, 2013. 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 petition along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the spring of 2018. 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 Prior to the September 6, 2013 stipulation and settlement agreement, Tampa Electric was accruing $8 million annually to an FPSC-approved self-insured storm reserve. Effective November 1, 2013, Tampa Electric ceased accruing for this storm reserve as a result of the 2013 rate case settlement. However, 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. As of December 31, 2016, the balance of the self-insured storm reserve was $56 million. As a result of several named storms, including Tropical Storm Colin, Tropical Storm Erika, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $10 million of storm costs in 2016. In the first quarter of 2017, Tampa Electric applied the $10 million of storm costs to the storm reserve. This resulted in a storm reserve balance of $46 million as of March 31, 2017. Tampa Electric was impacted by Hurricane Irma in the third quarter of 2017 and has currently estimated the cost of restoration to be approximately $105 million, of which $93 million was charged to the storm reserve, $4 million was charged to O&M expense, and $8 million was charged to capital expenditures. This reflects an update from the estimated cost of restoration of $70 million at September 30, 2017, primarily due to higher than expected mutual assistance and contractor costs. At December 31, 2017, the amount of $93 million charged to the storm reserve exceeded the $46 million balance by $47 million, which is currently recorded as a regulatory asset on the balance sheet. Based on an FPSC order, if the charges to the storm reserve exceed the account balance, the excess is to be carried as a regulatory asset. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs in excess of the reserve 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 Implementation Settlement On January 30, 2018, Tampa Electric filed a settlement agreement with the FPSC that addresses both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) PGS Base Rates 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. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC 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. On February 7, 2017, the FPSC approved the settlement agreement. No change in customer rates resulted from this agreement. As part of the settlement, PGS and OPC agreed The PGS settlement does not contain a provision for tax reform. On January 9, 2018, the Florida Office of Public Counsel filed a generic docket requesting the FPSC to address tax reform benefits for all utilities in Florida without an existing tax reform settlement provision, including PGS. Regulatory Assets and Liabilities Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. Areas of applicability include: revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm restoration or the future removal of property. Details of the regulatory assets and liabilities as of December 31, 2017 and 2016 are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2017 2016 Regulatory assets: Regulatory tax asset (1) $ 45 $ 86 Cost-recovery clauses - deferred balances (2) 12 8 Cost-recovery clauses - offsets to derivative liabilities (2) 1 0 Environmental remediation (3) 33 37 Postretirement benefits (4) 272 272 Storm reserve (5) 47 0 Other 23 18 Total regulatory assets 433 421 Less: Current portion 77 28 Long-term regulatory assets $ 356 $ 393 Regulatory liabilities: Regulatory tax liability (6) $ 730 $ 6 Cost-recovery clauses (2) 32 112 Cost-recovery clauses - offsets to derivative assets (2) 0 17 Storm reserve (5) 0 56 Accumulated reserve—cost of removal (7) 518 547 Other 5 7 Total regulatory liabilities 1,285 745 Less: Current portion 58 154 Long-term regulatory liabilities $ 1,227 $ 591 (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 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. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. In the case of the regulatory liability related to derivative assets, refund occurs in the year following the settlement of the derivative position. (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 the Tampa Electric Storm Restoration Cost Recovery section above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered within a 12-month period. (6) The increase in the regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 (7) 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, 2017
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 TEC has provisionally revalued all deferred tax assets and liabilities, $199 million and $1,024 million, respectively, based on the rates at which they are expected to reverse in the future, which is 21% for federal tax purposes. TEC is still analyzing certain aspects of the Act, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Provisional amounts primarily relate to the uncertainty of the application of 100% asset expensing rules after September 27, 2017. Further adjustments, if any, will be recorded by TEC during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income tax Accounting Implications of the Tax Cuts and Jobs Act 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 2017, 2016 and 2015, TEC recorded net tax provisions of $ Income tax expense consists of the following components: Income Tax Expense (Benefit) (millions) For the year ended December 31, 2017 2016 2015 Current income taxes Federal $ (1 ) $ 53 $ 38 State 6 12 8 Deferred income taxes Federal 170 76 105 State 23 11 15 Investment tax credits, net of amortization (1 ) 0 0 Total income tax expense $ 197 $ 152 $ 166 For the three years presented, the overall effective tax rate differs from the 35% U.S. federal statutory rate as presented below: Effective Income Tax Rate (millions) For the year ended December 31, 2017 2016 2015 Income before provision for income taxes $ 513 $ 438 $ 442 Federal statutory income tax rates 35 % 35 % 35 % Income taxes, at statutory income tax rate 180 153 155 Increase (decrease) due to State income tax, net of federal income tax 19 15 15 AFUDC-equity (1 ) (8 ) (6 ) Tax credits (3 ) (7 ) 0 Other 2 (1 ) 2 Total income tax expense on consolidated statements of income $ 197 $ 152 $ 166 Income tax expense as a percent of income from continuing operations, before income taxes 38.4 % 34.8 % 37.5 % 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, 2017 2016 Deferred tax liabilities (1) Property related $ 924 $ 1,549 Pension and postretirement benefits 57 105 Pension 43 69 Total deferred tax liabilities 1,024 1,723 Deferred tax assets (1) Loss and credit carryforwards (2) 91 91 Medical benefits 24 47 Insurance reserves (5 ) 27 Pension and postretirement benefits 57 105 Capitalized energy conservation assistance costs 13 23 Other 19 23 Total deferred tax assets 199 316 Total deferred tax liability, net $ 825 $ 1,407 (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. 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. At December 31, 2017, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $345 million and $273 million, respectively, expiring between 2033 and 2037. TEC has unused general business credits of $23 million, expiring between 2028 and 2037. 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) 2017 2016 2015 Balance at January 1, $ 7 $ 0 $ 0 Increases due to tax positions related to current year 1 7 0 Balance at December 31 $ 8 $ 7 $ 0 As of December 31, 2017 and 2016, TEC’s uncertain tax positions for federal R&D tax credits were $8 million and $7 million, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC believes that the total unrecognized tax benefits will decrease and be recognized within the next twelve months due to the ongoing audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. TEC had $8 million of unrecognized tax benefits at December 31, 2017, that, if recognized, would reduce TEC’s effective tax rate. TEC recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2017, 2016 and 2015, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest at December 31, 2017, 2016 and 2015. 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 2014 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 is 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, 2017
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, which is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. 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. MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. TECO Energy has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D. In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2020, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy and its affiliates do not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase the PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position. Effective January 1, 2013, TECO Energy implemented an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by TECO Energy under Medicare Part D for its post-65 retiree prescription drug plan. Effective January 1, 2015, TECO Energy changed its post-65 retiree coverage for medical benefits to a Medicare Advantage plan insured by Aetna. This will result in a lower claims cost by taking advantage of the government subsidies available for that plan. 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) 2017 2016 2017 2016 Change in benefit obligation Net benefit obligation at beginning of year $ 770 $ 733 $ 175 $ 172 Service cost 20 19 2 2 Interest cost 31 31 7 7 Plan participants’ contributions 0 0 3 3 Plan amendments 0 1 0 0 Plan curtailment (1 ) 1 0 0 Plan settlement (26 ) (2 ) 0 0 Benefits paid (51 ) (69 ) (16 ) (14 ) Actuarial loss (gain) 69 56 22 5 Net benefit obligation at end of year $ 812 $ 770 $ 193 $ 175 Change in plan assets Fair value of plan assets at beginning of year $ 649 $ 625 $ 0 $ 0 Actual return on plan assets 122 55 0 0 Employer contributions 46 38 (3 ) (3 ) Employer direct benefit payments 27 3 16 14 Plan participants’ contributions 0 0 3 3 Plan settlement (26 ) (2 ) 0 0 Benefits paid (51 ) (69 ) (16 ) (14 ) Direct benefit payments (1 ) (1 ) 0 0 Fair value of plan assets at end of year (1) $ 766 $ 649 $ 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) 2017 2016 2017 2016 Benefit obligation (PBO/APBO) $ 812 $ 770 $ 193 $ 175 Less: Fair value of plan assets 766 649 0 0 Funded status at end of year $ (46 ) $ (121 ) $ (193 ) $ (175 ) (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 $762 million at December 31, 2017 and $724 million at December 31, 2016. 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) 2017 2016 2017 2016 Accrued benefit costs and other current liabilities $ (7 ) $ (1 ) $ (10 ) $ (9 ) Deferred credits and other liabilities (30 ) (80 ) (154 ) (139 ) $ (37 ) $ (81 ) $ (164 ) $ (148 ) 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) 2017 2016 2017 2016 Net actuarial loss (gain) $ 215 $ 236 $ 70 $ 50 Prior service cost (credit) 1 1 (13 ) (15 ) Amount recognized $ 216 $ 237 $ 57 $ 35 Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2017 2016 2017 2016 Discount rate 3.62 % 4.11 % 3.70 % 4.28 % Rate of compensation increase-weighted average 3.32 % 2.57 % 3.31 % 2.48 % Healthcare cost trend rate Immediate rate n/a n/a 6.58 % 6.83 % 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 $ 7 $ (6 ) The discount rate assumption used to determine the December 31, 2017 and 2016 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. The discount rate assumption used to determine the December 31, 2015 benefit obligation 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. Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets TECO Energy Pension Benefits Other Benefits (1) 2017 2016 2015 2017 2016 2015 (millions) Service cost $ 20 $ 19 $ 21 $ 2 $ 2 $ 2 Interest cost 31 31 30 7 7 7 Expected return on plan assets (48 ) (46 ) (43 ) 0 0 0 Amortization of: Actuarial loss 17 16 15 0 0 0 Prior service (benefit) cost 0 0 0 (2 ) (2 ) (3 ) Curtailment loss (gain) 0 1 0 0 0 0 Settlement loss (2) 7 1 0 0 0 0 Net periodic benefit cost $ 27 $ 22 $ 23 $ 7 $ 7 $ 6 New prior service cost 0 1 $ 0 $ 0 $ 0 $ 0 Net loss (gain) arising during the year (5 ) 47 75 22 5 0 Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service (benefit) cost 0 0 0 2 2 3 Amortization or settlement of actuarial gain (loss) (24 ) (17 ) (15 ) 0 0 0 Total recognized in OCI and regulatory assets $ (29 ) $ 31 $ 60 $ 24 $ 7 $ 3 Total recognized in net periodic benefit cost, OCI and regulatory assets $ (2 ) $ 53 $ 83 $ 31 $ 14 $ 9 (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. TEC’s portion of the net periodic benefit costs for pension benefits was $14 million, $13 million and $14 million for 2017, 2016 and 2015, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $6 million, $6 million and $6 million for 2017, 2016 and 2015, respectively. 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 $14 million. There are no prior service credits to be amortized from regulatory assets into net periodic benefit cost in 2018 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 and $0 million for other postretirement plan 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. Assumptions used to determine net periodic benefit cost for years ended December 31: Pension Benefits Other Benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.110 % 4.688 % 4.258 % 4.280 % 4.667%/3.85% 4.206 % Expected long-term return on plan assets 7.00 % 7.00 % 7.00 % N/A N/A N/A Rate of compensation increase 2.57 % 2.59 % 3.87 % 2.48 % 2.50 % 3.86 % Healthcare cost trend rate Initial rate n/a n/a n/a 6.83 % 7.05 % 7.00 % 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 2025 The discount rate assumption used to determine the benefit cost for 2017 and from the Merger date to December 31, 2016 was based on the same technique that was used to determine the December 31, 2017 and 2016 benefit obligation as discussed above. The discount rate assumption used to determine the January 1, 2016 through June 30, 2016 and the 2015 benefit cost was based on the same technique that was used to determine the December 31, 2015 benefit obligation as discussed above. 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, 2017, TECO Energy’s pension plan’s assets increased approximately 19%. 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 2017 Target Allocation Actual Asset Category 2017 2016 Equity securities 47%-53% 51 % 56 % Fixed income securities 47%-53% 49 % 44 % 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, Inc. 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 as of December 31, 2017 and 2016. Pension Plan Investments 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 ) Short-term investment funds (STIFs) 14 0 0 0 14 Common stocks 44 0 0 0 44 Real estate investment trusts (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 Mortgage-backed securities (MBS) 0 (1 ) 0 0 (1 ) Collateralized mortgage obligations (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. TECO Energy At Fair Value as of December 31, 2016 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 2 $ 0 $ 0 $ 0 $ 2 Accounts receivable 27 0 0 0 27 Accounts payable (59 ) 0 0 0 (59 ) Cash collateral 1 0 0 0 1 STIFs 12 0 0 0 12 Common stocks 44 0 0 0 44 REITs 3 0 0 0 3 Mutual funds 181 0 0 0 181 Municipal bonds 0 3 0 0 3 Government bonds 0 32 0 0 32 Corporate bonds 0 39 0 0 39 MBS 0 9 0 0 9 CMOs 0 1 0 0 1 Swaps 0 1 0 0 1 Purchase options (swaptions) 0 2 0 0 2 Written options (swaptions) 0 (2 ) 0 0 (2 ) Investments not utilizing the practical expedient 211 85 0 0 296 Common and collective trusts (1) 0 0 0 270 270 Mutual fund (1) 0 0 0 83 83 Total investments $ 211 $ 85 $ 0 $ 353 $ 649 (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. ABS and 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. There were no unfunded commitments as of December 31, 2017. • 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 5 business days. There were no unfunded commitments as of December 31, 2017. • 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 $17 million and $41 million of assets as of December 31, 2017 and 2016, 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, 2017 and 2016. Other Postretirement Benefit Plan Assets There are no assets associated with TECO Energy’s Florida-based other postretirement benefits plan. Contributions The Pension Protection Act became effective January 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants. WRERA was signed into law on December 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements. In August 2014, HAFTA was signed into law, which modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015, the Bipartisan Budget Act of 2015 was signed into law, which extended pension funding relief of MAP-21 and HAFTA through 2022. The qualified pension plan’s actuarial value of assets, including credit balance, was 118.1% of the Pension Protection Act funded target as of January 1, 2017 and is estimated at 117.9% of the Pension Protection Act funded target as of January 1, 2018. 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 2017, 2016 and 2015, which met the minimum funding requirements for 2017, 2016 and 2015. TEC’s portion of the contribution in 2017 was $36 million and in 2016 was $31 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2018 contribution to be $37 million. TEC estimates its portion of annual contributions from 2019 to 2022 will range from $6 million to $17 million per year based on current assumptions. The amounts TECO Energy expects to make are in excess of the minimum funding required under ERISA guidelines. TEC’s portion of the contributions to the SERP in 2017, 2016 and 2015 were zero, zero and $15 million, respectively. TEC’s contribution in 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year. The fully-funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2018. 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 2018, TEC expects to make a contribution of about $10 million. 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) 2018 $ 58 $ 12 2019 56 12 2020 56 12 2021 59 12 2022 61 12 2023-2027 323 61 Defined Contribution Plan TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match 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, 2017, 2016 and 2015, TEC’s portion of expense totaled $11 million, $8 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, 2017
Debt Disclosure [Abstract]
Short-Term Debt	6. Short-Term Debt Credit Facilities December 31, 2017 December 31, 2016 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 325 $ 5 $ 1 $ 325 $ 40 $ 1 3-year accounts receivable facility (3) 150 0 0 150 130 0 1-year term facility (4) 300 300 0 0 0 0 Total $ 775 $ 305 $ 1 $ 475 $ 170 $ 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 23, 2018. (4) This 1-year facility matures on November 1, 2018. At December 31, 2017, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2017 and 2016 was 2.07% and 1.49%, respectively. Tampa Electric Company Credit Agreement On November 2, 2017, TEC entered into a 364-day, $300 million credit agreement with a consortium of banks. The credit agreement has a maturity date of November 1, 2018; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. Tampa Electric Company Accounts Receivable Facility On March 24, 2015, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to appoint a new program agent; add new lenders; and extend the scheduled termination date to March 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement and (b) a Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2017. 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 BTMU’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, 2017, TEC was in compliance with the requirements of the Loan Agreement. Amendment of 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, 2017
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. Issuance of Tampa Electric Company 4.20% Notes due 2045 On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes). Until November 15, 2044, TEC may redeem all or any part of the TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 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 November 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 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, 2017 and 2016, $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.

Merger with Emera

Merger with Emera	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Merger with Emera	8. Merger with Emera As disclosed in Note 1, Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of TECO Energy common stock was cancelled and converted automatically into the right to receive $27.55 in cash, without interest. This represents an aggregate purchase price of approximately $10.7 billion including Emera’s purchase price allocation for debt of approximately $4.2 billion (of which TEC’s portion of debt was $2.3 billion). The Merger Agreement requires Emera, among other things, (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s and TEC’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those that they received as of immediately prior to the closing.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	9. 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. Tampa Electric Legal Proceeding As a result of a tragic industrial accident at Big Bend Power Station on June 29, 2017, five workers (including one Tampa Electric employee and four contract workers) were killed and one other worker sustained serious injuries. Tampa Electric believes that any costs associated with the damages, injuries, fatalities and other losses related to the incident are substantially covered by insurance. Tampa Electric recorded any accruals for all material insured and non-insured costs and related insurance recoveries resulting from the incident. 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, 2017, TEC has estimated its ultimate financial liability to be $30 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 Condensed 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. See Note 3 Long-Term Commitments TEC has commitments for purchased power and long-term leases, primarily for land, building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015, totaled $2 million, $2 million and $4 million, respectively. TEC also has other purchase obligations for long-term service agreements and capital projects. In addition, TEC has payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at December 31, 2017: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2018 $ 10 $ 2 $ 303 $ 444 $ 759 2019 0 2 74 230 306 2020 0 2 7 177 186 2021 0 2 7 147 156 2022 0 2 7 141 150 Thereafter 0 36 18 1,029 1,083 Total future minimum payments $ 10 $ 46 $ 416 $ 2,168 $ 2,640 Financial Covenants TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2017, TEC was in compliance with all required financial covenants.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 2015 Natural gas sales to/(from) affiliates $ (4 ) $ 0 $ 1 Services received from affiliates 67 66 69 Dividends to TECO Energy 292 289 268 Equity contributions from TECO Energy 190 150 175 Services received from affiliates primarily include shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning on January 1, 2015. 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 cost-causative allocation methods or the Modified Massachusetts Formula. Amounts due from or to affiliates at December 31, (millions) 2017 2016 Accounts receivable (1) $ 2 $ 7 Accounts payable (1) 19 18 Taxes receivable (2) 3 0 Taxes payable (2) 2 7 (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, 2017
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 750,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 375,000 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 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 2015 Revenues - external $ 2,018 $ 401 $ 0 $ 2,419 Sales to affiliates 0 6 (6 ) 0 Total revenues 2,018 407 (6 ) 2,419 Depreciation and amortization 256 57 0 313 Total interest charges 95 15 0 110 Provision for income taxes 144 22 0 166 Net income 241 35 0 276 Total assets 7,004 1,136 (431 ) (1) 7,709 Capital expenditures 593 94 0 687 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2017
Other Comprehensive Income [Abstract]
Other Comprehensive Income	12. Other Comprehensive Income TEC reported the following OCI related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges: Other Comprehensive Income (millions) Gross Tax Net 2017 Unrealized gain on cash flow hedges $ 0 $ 0 $ 0 Reclassification from AOCI to net income 1 0 1 Gain on cash flow hedges 1 0 1 Total other comprehensive income $ 1 $ 0 $ 1 2016 Unrealized gain on cash flow hedges $ 0 $ 0 $ 0 Reclassification from AOCI to net income 1 0 1 Gain on cash flow hedges 1 0 1 Total other comprehensive income $ 1 $ 0 $ 1 2015 Unrealized gain on cash flow hedges $ 4 $ (1 ) $ 3 Reclassification from AOCI to net income 2 (1 ) 1 Gain on cash flow hedges 6 (2 ) 4 Total other comprehensive income $ 6 $ (2 ) $ 4 Accumulated Other Comprehensive Loss (millions) As of December 31, 2017 2016 Net unrealized losses from cash flow hedges (1) $ (2 ) $ (3 ) Total accumulated other comprehensive loss $ (2 ) $ (3 ) (1) Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2017
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 limit the exposure to interest rate fluctuations on debt securities. 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. 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. In November 2016, Tampa Electric and the other major electric IOUs in Florida signed a stipulation agreement approved by the FPSC calling for a one-year moratorium on hedging of natural gas purchases. In September 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement, which replaces the existing 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. The FPSC approved the agreement on November 6, 2017 (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, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 14 TEC applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas 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 hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (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, 2016, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected. The derivatives that are designated as cash flow hedges at December 31, 2017 and 2016 are reflected on TEC’s Consolidated Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were zero and $17 million derivative assets as of December 31, 2017 and 2016, respectively. There were $1 million and zero derivative liabilities as of December 31, 2017 and 2016, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties at December 31, 2017 and 2016. All of the derivative asset and liabilities at December 31, 2017 and 2016 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long term regulatory assets and liabilities. Based on the fair value of the instruments at December 31, 2017, net pre-tax reductions of $1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months. The December 31, 2017 and 2016 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12 For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the years ended December 31, 2017, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the years ended December 31, 2017, 2016 and 2015 is presented in Note 12 The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to November 30, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of December 31, 2017, are expected to settle during the 2018 fiscal year: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2018 0 7 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. 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, 2017, 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 the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. 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, 2017
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. The fair value of financial instruments is determined by using various market data and other valuation techniques. The following table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016. Recurring Derivative Fair Value Measures As of December 31, 2017 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0 $ 1 $ 0 $ 1 As of December 31, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0 $ 17 $ 0 $ 17 Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 13 TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At December 31, 2017 and 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented. As of December 31, 2017 and 2016, 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 Notes 5 Consolidated Statements of Capitalization

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2017
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 has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. 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 has reviewed these risks and has determined that the owners of these entities have retained 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 $16 million, $62 million and $34 million, under these PPAs for the three years ended December 31, 2017, 2016 and 2015, 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.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	16. 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. 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. Reconciliation of beginning and ending carrying amount of asset retirement obligations: December 31, (millions) 2017 2016 Beginning balance $ 45 $ 6 Additional liabilities (1) 1 36 Liabilities settled (1 ) 0 Revisions to estimated cash flows 0 3 Other (2) 2 0 Ending balance $ 47 $ 45 (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 2016 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed. (2) Includes accretion recorded as a deferred regulatory asset.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-Based Compensation	17. 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. 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 used to purchase 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 retirement, disability or death. A summary of the activity related to TEC employee PSUs for the year ended December 31, 2017 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, 2016 0 $ 0 $ 0 Granted including DRIP 144 45.40 6 Exercised (5 ) 30.57 0 Forfeited (17 ) 45.41 (1 ) Transferred 11 38.51 1 Outstanding as of December 31, 2017 133 $ 45.11 $ 6 Compensation cost recognized for the PSU plan for the year ended December 31, 2017 was $2 million. Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2017

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts and Reserves	12 Months Ended
	Dec. 31, 2017
Valuation And Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts and Reserves	SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES TAMPA ELECTRIC COMPANY VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 2017, 2016 and 2015 (millions) Balance at Additions Balance at Beginning Charged to Other Payments & End of of Period Income Charges Deductions (1) Period Allowance for Uncollectible Accounts: 2017 $ 1 $ 5 $ 0 $ 5 $ 1 2016 $ 1 $ 3 $ 0 $ 3 $ 1 2015 $ 1 $ 3 $ 0 $ 3 $ 1 (1) Write-off of individual bad debt accounts

Significant Accounting Polici31

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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. See Note 8
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. In general, when regulated depreciable property is retired or disposed, its original cost less salvage is charged to accumulated depreciation. 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, 2017 December 31, 2016 Electric generation 21-56 years $ 4,766 $ 4,102 Electric transmission 28-77 years 859 837 Electric distribution 14-56 years 2,437 2,331 Gas transmission and distribution 15-77 years 1,534 1,429 General plant and other 8-43 years 579 438 Total cost 10,175 9,137 Less accumulated depreciation (2,994 ) (2,826 ) Construction work in progress 263 892 Total property, plant and equipment, net $ 7,444 $ 7,203
Depreciation	Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7%, 3.5% and 3.7% for 2017, 2016 and 2015, respectively. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $332 million, $304 million and $306 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 2017, 2016 and 2015, the rate was 6.46%. Total AFUDC for the years ended December 31, 2017, 2016 and 2015 was $2 million, $36 million and $26 million, respectively. The decrease in 2017 and increase in 2016 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 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, 2017 and 2016, ITCs were $22 million and $11 million, respectively.
Revenue Recognition	Revenue Recognition TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer. Tampa Electric’s and PGS’s retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3
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. Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-affiliates at a cost of $46 million, $104 million and $79 million, for the years ended December 31, 2017, 2016 and 2015, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.
Receivables and Allowance for Uncollectible Accounts	Receivables and Allowance for Uncollectible Accounts Receivables consist of services billed to residential, commercial, industrial and other customers. 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 natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.
Accounting for Franchise Fees and Gross Receipts Taxes	Accounting for Franchise Fees and Gross Receipts Taxes TEC is 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 are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $113 million, $117 million and $117 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Deferred Credits and Other Liabilities	Deferred Credits and Other Liabilities Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5 Note 9 Note 16 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, 2017 and 2016 ranged from 2.74% to 4.00% and 2.69% 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.
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 Polici32

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Property, Plant and Equipment	Property, plant and equipment consisted of the following assets: (millions) Estimated Useful Lives December 31, 2017 December 31, 2016 Electric generation 21-56 years $ 4,766 $ 4,102 Electric transmission 28-77 years 859 837 Electric distribution 14-56 years 2,437 2,331 Gas transmission and distribution 15-77 years 1,534 1,429 General plant and other 8-43 years 579 438 Total cost 10,175 9,137 Less accumulated depreciation (2,994 ) (2,826 ) Construction work in progress 263 892 Total property, plant and equipment, net $ 7,444 $ 7,203

Regulatory (Tables)

Regulatory (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of December 31, 2017 and 2016 are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2017 2016 Regulatory assets: Regulatory tax asset (1) $ 45 $ 86 Cost-recovery clauses - deferred balances (2) 12 8 Cost-recovery clauses - offsets to derivative liabilities (2) 1 0 Environmental remediation (3) 33 37 Postretirement benefits (4) 272 272 Storm reserve (5) 47 0 Other 23 18 Total regulatory assets 433 421 Less: Current portion 77 28 Long-term regulatory assets $ 356 $ 393 Regulatory liabilities: Regulatory tax liability (6) $ 730 $ 6 Cost-recovery clauses (2) 32 112 Cost-recovery clauses - offsets to derivative assets (2) 0 17 Storm reserve (5) 0 56 Accumulated reserve—cost of removal (7) 518 547 Other 5 7 Total regulatory liabilities 1,285 745 Less: Current portion 58 154 Long-term regulatory liabilities $ 1,227 $ 591 (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 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. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position. In the case of the regulatory liability related to derivative assets, refund occurs in the year following the settlement of the derivative position. (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 the Tampa Electric Storm Restoration Cost Recovery section above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered within a 12-month period. (6) The increase in the regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 (7) 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, 2017
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	Income tax expense consists of the following components: (millions) For the year ended December 31, 2017 2016 2015 Current income taxes Federal $ (1 ) $ 53 $ 38 State 6 12 8 Deferred income taxes Federal 170 76 105 State 23 11 15 Investment tax credits, net of amortization (1 ) 0 0 Total income tax expense $ 197 $ 152 $ 166
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 35% U.S. federal statutory rate as presented below: (millions) For the year ended December 31, 2017 2016 2015 Income before provision for income taxes $ 513 $ 438 $ 442 Federal statutory income tax rates 35 % 35 % 35 % Income taxes, at statutory income tax rate 180 153 155 Increase (decrease) due to State income tax, net of federal income tax 19 15 15 AFUDC-equity (1 ) (8 ) (6 ) Tax credits (3 ) (7 ) 0 Other 2 (1 ) 2 Total income tax expense on consolidated statements of income $ 197 $ 152 $ 166 Income tax expense as a percent of income from continuing operations, before income taxes 38.4 % 34.8 % 37.5 %
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, 2017 2016 Deferred tax liabilities (1) Property related $ 924 $ 1,549 Pension and postretirement benefits 57 105 Pension 43 69 Total deferred tax liabilities 1,024 1,723 Deferred tax assets (1) Loss and credit carryforwards (2) 91 91 Medical benefits 24 47 Insurance reserves (5 ) 27 Pension and postretirement benefits 57 105 Capitalized energy conservation assistance costs 13 23 Other 19 23 Total deferred tax assets 199 316 Total deferred tax liability, net $ 825 $ 1,407 (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) 2017 2016 2015 Balance at January 1, $ 7 $ 0 $ 0 Increases due to tax positions related to current year 1 7 0 Balance at December 31 $ 8 $ 7 $ 0

Employee Postretirement Benef35

Employee Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 2017 2016 Accrued benefit costs and other current liabilities $ (7 ) $ (1 ) $ (10 ) $ (9 ) Deferred credits and other liabilities (30 ) (80 ) (154 ) (139 ) $ (37 ) $ (81 ) $ (164 ) $ (148 )
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) 2017 2016 2017 2016 Net actuarial loss (gain) $ 215 $ 236 $ 70 $ 50 Prior service cost (credit) 1 1 (13 ) (15 ) Amount recognized $ 216 $ 237 $ 57 $ 35
Benefit Obligations [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2017 2016 2017 2016 Discount rate 3.62 % 4.11 % 3.70 % 4.28 % Rate of compensation increase-weighted average 3.32 % 2.57 % 3.31 % 2.48 % Healthcare cost trend rate Immediate rate n/a n/a 6.58 % 6.83 % 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 $ 7 $ (6 )
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 2017 2016 2015 2017 2016 2015 Discount rate 4.110 % 4.688 % 4.258 % 4.280 % 4.667%/3.85% 4.206 % Expected long-term return on plan assets 7.00 % 7.00 % 7.00 % N/A N/A N/A Rate of compensation increase 2.57 % 2.59 % 3.87 % 2.48 % 2.50 % 3.86 % Healthcare cost trend rate Initial rate n/a n/a n/a 6.83 % 7.05 % 7.00 % 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 2025
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 $ 649 $ 625 $ 0 $ 0 Actual return on plan assets 122 55 0 0 Employer contributions 46 38 (3 ) (3 ) Employer direct benefit payments 27 3 16 14 Plan participants’ contributions 0 0 3 3 Plan settlement (26 ) (2 ) 0 0 Benefits paid (51 ) (69 ) (16 ) (14 ) Direct benefit payments (1 ) (1 ) 0 0 Fair value of plan assets at end of year (1) $ 766 $ 649 $ 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) 2017 2016 2015 2017 2016 2015 (millions) Service cost $ 20 $ 19 $ 21 $ 2 $ 2 $ 2 Interest cost 31 31 30 7 7 7 Expected return on plan assets (48 ) (46 ) (43 ) 0 0 0 Amortization of: Actuarial loss 17 16 15 0 0 0 Prior service (benefit) cost 0 0 0 (2 ) (2 ) (3 ) Curtailment loss (gain) 0 1 0 0 0 0 Settlement loss (2) 7 1 0 0 0 0 Net periodic benefit cost $ 27 $ 22 $ 23 $ 7 $ 7 $ 6
Schedule of Amounts Recognized in OCI and Regulatory Assets	New prior service cost 0 1 $ 0 $ 0 $ 0 $ 0 Net loss (gain) arising during the year (5 ) 47 75 22 5 0 Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service (benefit) cost 0 0 0 2 2 3 Amortization or settlement of actuarial gain (loss) (24 ) (17 ) (15 ) 0 0 0 Total recognized in OCI and regulatory assets $ (29 ) $ 31 $ 60 $ 24 $ 7 $ 3 Total recognized in net periodic benefit cost, OCI and regulatory assets $ (2 ) $ 53 $ 83 $ 31 $ 14 $ 9 (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.
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 2017 Target Allocation Actual Asset Category 2017 2016 Equity securities 47%-53% 51 % 56 % Fixed income securities 47%-53% 49 % 44 % 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 as of December 31, 2017 and 2016. Pension Plan Investments 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 ) Short-term investment funds (STIFs) 14 0 0 0 14 Common stocks 44 0 0 0 44 Real estate investment trusts (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 Mortgage-backed securities (MBS) 0 (1 ) 0 0 (1 ) Collateralized mortgage obligations (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. TECO Energy At Fair Value as of December 31, 2016 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 2 $ 0 $ 0 $ 0 $ 2 Accounts receivable 27 0 0 0 27 Accounts payable (59 ) 0 0 0 (59 ) Cash collateral 1 0 0 0 1 STIFs 12 0 0 0 12 Common stocks 44 0 0 0 44 REITs 3 0 0 0 3 Mutual funds 181 0 0 0 181 Municipal bonds 0 3 0 0 3 Government bonds 0 32 0 0 32 Corporate bonds 0 39 0 0 39 MBS 0 9 0 0 9 CMOs 0 1 0 0 1 Swaps 0 1 0 0 1 Purchase options (swaptions) 0 2 0 0 2 Written options (swaptions) 0 (2 ) 0 0 (2 ) Investments not utilizing the practical expedient 211 85 0 0 296 Common and collective trusts (1) 0 0 0 270 270 Mutual fund (1) 0 0 0 83 83 Total investments $ 211 $ 85 $ 0 $ 353 $ 649 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. ABS and 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. There were no unfunded commitments as of December 31, 2017. • 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 5 business days. There were no unfunded commitments as of December 31, 2017. • 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) 2018 $ 58 $ 12 2019 56 12 2020 56 12 2021 59 12 2022 61 12 2023-2027 323 61
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) 2017 2016 2017 2016 Change in benefit obligation Net benefit obligation at beginning of year $ 770 $ 733 $ 175 $ 172 Service cost 20 19 2 2 Interest cost 31 31 7 7 Plan participants’ contributions 0 0 3 3 Plan amendments 0 1 0 0 Plan curtailment (1 ) 1 0 0 Plan settlement (26 ) (2 ) 0 0 Benefits paid (51 ) (69 ) (16 ) (14 ) Actuarial loss (gain) 69 56 22 5 Net benefit obligation at end of year $ 812 $ 770 $ 193 $ 175 1. Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan
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) 2017 2016 2017 2016 Benefit obligation (PBO/APBO) $ 812 $ 770 $ 193 $ 175 Less: Fair value of plan assets 766 649 0 0 Funded status at end of year $ (46 ) $ (121 ) $ (193 ) $ (175 ) (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, 2017
Debt Disclosure [Abstract]
Short-Term Debt Credit Facilities	Credit Facilities December 31, 2017 December 31, 2016 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 325 $ 5 $ 1 $ 325 $ 40 $ 1 3-year accounts receivable facility (3) 150 0 0 150 130 0 1-year term facility (4) 300 300 0 0 0 0 Total $ 775 $ 305 $ 1 $ 475 $ 170 $ 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 23, 2018. (4) This 1-year facility matures on November 1, 2018.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Schedule of Long-term Commitments	The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at December 31, 2017: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2018 $ 10 $ 2 $ 303 $ 444 $ 759 2019 0 2 74 230 306 2020 0 2 7 177 186 2021 0 2 7 147 156 2022 0 2 7 141 150 Thereafter 0 36 18 1,029 1,083 Total future minimum payments $ 10 $ 46 $ 416 $ 2,168 $ 2,640

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2017 2016 2015 Natural gas sales to/(from) affiliates $ (4 ) $ 0 $ 1 Services received from affiliates 67 66 69 Dividends to TECO Energy 292 289 268 Equity contributions from TECO Energy 190 150 175 Amounts due from or to affiliates at December 31, (millions) 2017 2016 Accounts receivable (1) $ 2 $ 7 Accounts payable (1) 19 18 Taxes receivable (2) 3 0 Taxes payable (2) 2 7 (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, 2017
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 750,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 375,000 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 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 2015 Revenues - external $ 2,018 $ 401 $ 0 $ 2,419 Sales to affiliates 0 6 (6 ) 0 Total revenues 2,018 407 (6 ) 2,419 Depreciation and amortization 256 57 0 313 Total interest charges 95 15 0 110 Provision for income taxes 144 22 0 166 Net income 241 35 0 276 Total assets 7,004 1,136 (431 ) (1) 7,709 Capital expenditures 593 94 0 687 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2017
Other Comprehensive Income [Abstract]
Other Comprehensive Income	TEC reported the following OCI related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges: Other Comprehensive Income (millions) Gross Tax Net 2017 Unrealized gain on cash flow hedges $ 0 $ 0 $ 0 Reclassification from AOCI to net income 1 0 1 Gain on cash flow hedges 1 0 1 Total other comprehensive income $ 1 $ 0 $ 1 2016 Unrealized gain on cash flow hedges $ 0 $ 0 $ 0 Reclassification from AOCI to net income 1 0 1 Gain on cash flow hedges 1 0 1 Total other comprehensive income $ 1 $ 0 $ 1 2015 Unrealized gain on cash flow hedges $ 4 $ (1 ) $ 3 Reclassification from AOCI to net income 2 (1 ) 1 Gain on cash flow hedges 6 (2 ) 4 Total other comprehensive income $ 6 $ (2 ) $ 4
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (millions) As of December 31, 2017 2016 Net unrealized losses from cash flow hedges (1) $ (2 ) $ (3 ) Total accumulated other comprehensive loss $ (2 ) $ (3 ) (1) Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

Accounting for Derivative Ins41

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Volumes Expected to Settle	The following table presents TEC’s derivative volumes that, as of December 31, 2017, are expected to settle during the 2018 fiscal year: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2018 0 7

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Recurring Fair Value Measurements	The fair value of financial instruments is determined by using various market data and other valuation techniques. The following table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016. Recurring Derivative Fair Value Measures As of December 31, 2017 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0 $ 1 $ 0 $ 1 As of December 31, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0 $ 17 $ 0 $ 17

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	Reconciliation of beginning and ending carrying amount of asset retirement obligations: December 31, (millions) 2017 2016 Beginning balance $ 45 $ 6 Additional liabilities (1) 1 36 Liabilities settled (1 ) 0 Revisions to estimated cash flows 0 3 Other (2) 2 0 Ending balance $ 47 $ 45 (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 2016 is to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. In 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. However, additional petitions will be submitted for recovery of future project expense based on engineering studies currently being performed. (2) Includes accretion recorded as a deferred regulatory asset.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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 for the year ended December 31, 2017 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, 2016 0 $ 0 $ 0 Granted including DRIP 144 45.40 6 Exercised (5 ) 30.57 0 Forfeited (17 ) 45.41 (1 ) Transferred 11 38.51 1 Outstanding as of December 31, 2017 133 $ 45.11 $ 6

Significant Accounting Polici45

Significant Accounting Policies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of operating segments | Segment	2
Percentage of original cost of depreciable property	3.70%	3.50%	3.70%
Depreciation expense	$ 332	$ 304	$ 306
Allowance for funds used during construction rate	6.46%	6.46%	6.46%
Allowance for funds used during construction	$ 2	$ 36	$ 26
Investment tax credits	22	11
Unbilled revenues	66	54
Purchased power	46	104	79
Franchise fees and gross receipts taxes	$ 113	$ 117	$ 117
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	2.74%	2.69%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	4.00%	4.00%
PGS [Member]
Summary Of Significant Accounting Policies [Line Items]
Reduction in annual depreciation expense		$ 16

Significant Accounting Polici46

Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Total cost	$ 10,175	$ 9,137
Less accumulated depreciation	(2,994)	(2,826)
Construction work in progress	263	892
Total property, plant and equipment, net	7,444	7,203
Electric Generation [Member]
Property Plant And Equipment [Line Items]
Total cost	4,766	4,102
Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	1,534	1,429
General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 579	438
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	15 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	$ 859	837
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	$ 2,437	$ 2,331
Electric Distribution [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	14 years
Electric Distribution [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	56 years

Regulatory - Additional Informa

Regulatory - Additional Information (Detail)

Dec. 12, 2017USD ($)MW

Sep. 30, 2017USD ($)

Sep. 27, 2017USD ($)$ / kWacMW

Dec. 15, 2016USD ($)

Jun. 28, 2016

May 31, 2009

Sep. 30, 2017USD ($)

Mar. 31, 2017USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2013

Oct. 31, 2013USD ($)

Sep. 05, 2013USD ($)

Public Utilities General Disclosures [Line Items]

Percentage of ROE

10.25%

Return on equity range

Range of plus or minus 1%

Amortization period of Regulatory Asset

12 years

Allowed equity in the capital structure

54.00%

Storm costs incurred

$ 10,000,000

Storm costs applied to storm reserve

$ 10,000,000

Storm damage reserve

$ 46,000,000

$ 56,000,000

Regulatory assets

$ 433,000,000

$ 421,000,000

PGS [Member]

Public Utilities General Disclosures [Line Items]

Percentage of ROE

10.75%

10.75%

Allowed equity in the capital structure

54.70%

PGS and OPC [Member]

Public Utilities General Disclosures [Line Items]

Settlement agreement, approval date

Feb. 7, 2017

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

Hurricane Irma [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

$ 70,000,000

$ 105,000,000

Hurricane Irma [Member] | Storm Reserve [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

93,000,000

Hurricane Irma [Member] | O&M Expenses [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

4,000,000

Hurricane Irma [Member] | Capital Expenditures [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

8,000,000

Minimum [Member] | PGS [Member]

Public Utilities General Disclosures [Line Items]

Return on equity

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]

Return on equity

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 revenue requirements

$ 26,000,000

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

250

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]

Annual accrual, storm damage reserve

$ 8,000,000

Minimum cost recovery period

12 months

Replenishment reserve for recovery of cost

$ 56,000,000

Self-insured storm reserve

56,000,000

Storm Reserve [Member]

Public Utilities General Disclosures [Line Items]

Regulatory assets

$ 47,000,000

$ 47,000,000

$ 47,000,000

$ 0

November 1, 2013 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

58,000,000

November 1, 2014 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

8,000,000

November 1, 2015 [Member]

Public Utilities General Disclosures [Line Items]

Additional Revenue generated from increase in service charge

5,000,000

January 16, 2017 [Member]

Public Utilities General Disclosures [Line Items]

Additional 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%

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, 2017	Sep. 30, 2017	Dec. 31, 2016
Regulatory assets:
Regulatory assets	$ 433		$ 421
Less: Current portion	77		28
Long-term regulatory assets	356		393
Regulatory liabilities:
Regulatory liabilities	1,285		745
Less: Current portion	58		154
Long-term regulatory liabilities	1,227		591
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	45		86
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	12		8
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	1		0
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	33		37
Postretirement Benefit [Member]
Regulatory assets:
Regulatory assets	272		272
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	47	$ 47	0
Other [Member]
Regulatory assets:
Regulatory assets	23		18
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	730		6
Cost-Recovery Clauses - Offsets to Derivative Assets [Member]
Regulatory liabilities:
Regulatory liabilities	0		17
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	32		112
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	0		56
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	518		547
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 5		$ 7

Regulatory - Schedule of Regu49

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2017
Maximum [Member] | Storm Reserve [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory asset recovery period	12 months

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	Jan. 01, 2018	Sep. 27, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Federal statutory tax rate			35.00%	35.00%	35.00%
Deferred tax assets			$ 199,000,000	$ 316,000,000
Deferred tax liabilities			1,024,000,000	1,723,000,000
Asset expensing, uncertainty provisional percentage		100.00%
Provision for income taxes			197,000,000	152,000,000	$ 166,000,000
Change in net deferred taxes offset to regulatory tax liability			$ 755,000,000
Deferred tax assets expiration date			2033 and 2037
General business credit			$ 23,000,000
Deferred tax general business credits expiration date			2028 and 2037
Uncertain tax positions			$ 8,000,000	7,000,000	0	$ 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			$ 345,000,000
Federal [Member] | R&D Tax Credits [Member]
Income Taxes [Line Items]
Uncertain tax positions			8,000,000	$ 7,000,000
Florida [Member]
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward			$ 273,000,000
Subsequent Event [Member]
Income Taxes [Line Items]
Federal statutory tax rate	21.00%
Asset expensing	100.00%

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current income taxes, Federal	$ (1)	$ 53	$ 38
Current income taxes, State	6	12	8
Deferred income taxes, Federal	170	76	105
Deferred income taxes, State	23	11	15
Investment tax credits, net of amortization	(1)	0	0
Total income tax expense	$ 197	$ 152	$ 166

Income Taxes - Schedule of In52

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income before provision for income taxes	$ 513	$ 438	$ 442
Federal statutory income tax rates	35.00%	35.00%	35.00%
Income taxes, at statutory income tax rate	$ 180	$ 153	$ 155
State income tax, net of federal income tax	19	15	15
AFUDC-equity	(1)	(8)	(6)
Tax credits	(3)	(7)	0
Other	2	(1)	2
Total income tax expense	$ 197	$ 152	$ 166
Income tax expense as a percent of income from continuing operations, before income taxes	38.40%	34.80%	37.50%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred tax liabilities
Property related	$ 924	$ 1,549
Pension and postretirement benefits	57	105
Pension	43	69
Total deferred tax liabilities	1,024	1,723
Deferred tax assets
Loss and credit carryforwards	91	91
Medical benefits	24	47
Insurance reserves	(5)	27
Pension and postretirement benefits	57	105
Capitalized energy conservation assistance costs	13	23
Other	19	23
Total deferred tax assets	199	316
Total deferred tax liability, net	$ 825	$ 1,407

Income Taxes - Schedule of De54

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Unrecognized tax benefits	$ 8	$ 7	$ 0	$ 0

Income Taxes - Schedule of Unre

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Beginning Balance	$ 7	$ 0	$ 0
Increases due to tax positions related to current year	1	7	0
Ending Balance	$ 8	$ 7	$ 0

Employee Postretirement Benef56

Employee Postretirement Benefits - Additional Information (Detail) - USD ($)		Jan. 02, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Percentage of tax-free subsidy under prescription drug programs				28.00%
Amortization period of Regulatory Asset				12 years
Tax of premiums paid for retiree medical benefits plan				40.00%
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 5 business days.
Primary provisions for pension benefits				First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2013, rather than the funding target of 100%.
Percentage of qualified pension plan's actuarial value of assets			118.10%	117.90%	118.10%		118.10%
Employer contributions				$ 36,000,000	$ 31,000,000
Employer contributions in next fiscal year				$ 37,000,000
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	$ 8,000,000	$ 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			$ 41,000,000	$ 17,000,000	$ 41,000,000		$ 41,000,000
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				14,000,000	13,000,000	14,000,000
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year				14,000,000
Increase in net periodic benefit cost			1,000,000
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				6,000,000	6,000,000	6,000,000
Other postretirement benefit plans service benefit to be amortized from regulatory assets in next fiscal year				0
Increase in net periodic benefit cost			0
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				0	0	15,000,000
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation of defined benefit pension plans			724,000,000	$ 762,000,000	724,000,000		724,000,000
Percentage of defined benefit plan's assets increased				19.00%
Defined contribution plan, maximum employer match percentage				6.00%
TECO Energy [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions				$ 17,000,000
TECO Energy [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions				6,000,000
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				27,000,000	22,000,000	23,000,000
Curtailment loss				0	1,000,000	0
Settlement charge				(7,000,000)	(1,000,000)	0
Commitments			770,000,000	812,000,000	770,000,000	733,000,000	770,000,000
Employer contributions				46,000,000	38,000,000
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost				7,000,000	7,000,000	6,000,000
Curtailment loss				0	0	0
Settlement charge				0	0	0
Commitments	[1]		$ 175,000,000	193,000,000	175,000,000	$ 172,000,000	$ 175,000,000
Employer contributions	[1]			(3,000,000)	$ (3,000,000)
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 Benef57

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - TECO Energy [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year		$ 770		$ 733
Service cost		20		19		$ 21
Interest cost		31		31		30
Plan participants’ contributions		0		0
Plan amendments		0		1
Plan curtailment		(1)		1
Plan settlement		(26)		(2)
Benefits paid		(51)		(69)
Actuarial loss (gain)		69		56
Net benefit obligation at end of year		812		770		733
Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	[1]	175		172
Service cost		2	[1]	2	[1]	2
Interest cost		7	[1]	7	[1]	7
Plan participants’ contributions	[1]	3		3
Plan amendments	[1]	0		0
Plan curtailment	[1]	0		0
Plan settlement	[1]	0		0
Benefits paid	[1]	(16)		(14)
Actuarial loss (gain)	[1]	22		5
Net benefit obligation at end of year	[1]	$ 193		$ 175		$ 172
[1]	Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

Employee Postretirement Benef58

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Change in plan assets
Employer contributions		$ 36		$ 31
TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year		649
Fair value of plan assets at end of year		766		649
TECO Energy [Member] | Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year		649	[1]	625
Actual return on plan assets		122		55
Employer contributions		46		38
Employer direct benefit payments		27		3
Plan participants’ contributions		0		0
Plan settlement		(26)		(2)
Benefits paid		(51)		(69)
Direct benefit payments		(1)		(1)
Fair value of plan assets at end of year	[1]	766		649
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]	(3)		(3)
Employer direct benefit payments	[2]	16		14
Plan participants’ contributions	[2]	3		3
Plan settlement	[2]	0		0
Benefits paid	[2]	(16)		(14)
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 Benef59

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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 Benef60

Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 766		$ 649
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)		812		770		$ 733
Fair value of plan assets		766	[1]	649	[1]	625
Funded status at end of year		(46)		(121)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	[2]	193		175		172
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)		193		175
Fair value of plan assets		0		0
Funded status at end of year		$ (193)		$ (175)
[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 Benef61

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	$ (7)	$ (1)
Deferred credits and other liabilities	(30)	(80)
Net amount recognized at end of year	(37)	(81)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	(10)	(9)
Deferred credits and other liabilities	(154)	(139)
Net amount recognized at end of year	$ (164)	$ (148)

Employee Postretirement Benef62

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 215	$ 236
Prior service cost (credit)	1	1
Amount recognized	216	237
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	70	50
Prior service cost (credit)	(13)	(15)
Amount recognized	$ 57	$ 35

Employee Postretirement Benef63

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.62%	4.11%
Rate of compensation increase-weighted average	3.32%	2.57%
Discount rate	4.11%	4.688%	4.258%
Expected long-term return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	2.57%	2.59%	3.87%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.70%	4.28%
Rate of compensation increase-weighted average	3.31%	2.48%
Healthcare cost trend rate
Immediate rate	6.58%	6.83%
Ultimate rate	4.50%	4.50%
Year rate reaches ultimate	2,038	2,038
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.28%		4.206%
Rate of compensation increase	2.48%	2.50%	3.86%
Healthcare cost trend rate
Immediate rate	6.83%	7.05%	7.00%
Ultimate rate	4.50%	4.50%	4.50%
Year rate reaches ultimate	2,038	2,038	2,025
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.667%
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.85%

Employee Postretirement Benef64

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, 2017USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on PBO - Increase	$ 7
Effect on PBO - Decrease	$ (6)

Employee Postretirement Benef65

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, 2017		Dec. 31, 2016		Dec. 31, 2015
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 14		$ 13		$ 14
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	6		6		6
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	20		19		21
Interest cost	31		31		30
Expected return on plan assets	(48)		(46)		(43)
Amortization of:
Actuarial loss	17		16		15
Prior service (benefit) cost	0		0		0
Curtailment loss (gain)	0		1		0
Settlement loss (2)	7		1		0
Net periodic benefit cost	27		22		23
New prior service cost	0		1		0
Net loss (gain) arising during the year	(5)		47		75
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)	(24)		(17)		(15)
Total recognized in OCI and regulatory assets	(29)		31		60
Total recognized in net periodic benefit cost, OCI and regulatory assets	(2)		53		83
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	0		0		0
Prior service (benefit) cost	(2)		(2)		(3)
Curtailment loss (gain)	0		0		0
Settlement loss (2)	0		0		0
Net periodic benefit cost	7		7		6
New prior service cost	0		0		0
Net loss (gain) arising during the year	22		5		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	2		2		3
Amortization or settlement of actuarial gain (loss)	0		0		0
Total recognized in OCI and regulatory assets	24		7		3
Total recognized in net periodic benefit cost, OCI and regulatory assets	$ 31		$ 14		$ 9
[1]	Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

Employee Postretirement benef66

Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member]	Dec. 31, 2017	Dec. 31, 2016
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	51.00%	56.00%
Actual Asset Allocation [Member] | Fixed Income Securities [Member]
Asset Category
Actual Allocation, End of Year	49.00%	44.00%
Target Allocation [Member]
Asset Category
Target Allocation	100.00%
Target Allocation [Member] | Equity Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	47.00%
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	53.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	47.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	53.00%

Employee Postretirement Benef67

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 766	$ 649
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	2
Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	12
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	44
Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	3
Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)	9
Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	196	181
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	3
Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	55	32
Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45	39
Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	337	296
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	326	270
Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103	83
Cash Collateral [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	4	1
NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	429	353
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] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Mortgage-Backed Securities (MBS) [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	326	270
NAV [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103	83
NAV [Member] | Cash Collateral [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	232	211
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	2
Level 1 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	12
Level 1 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	44
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	3
Level 1 [Member] | Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	196	181
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	232	211
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	0
Level 1 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
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	105	85
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] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)	9
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	2	3
Level 2 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	55	32
Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	45	39
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	105	85
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	0
Level 2 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 2 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	1
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Mortgage-Backed Securities (MBS) [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	0
Level 3 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Collateral [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	14	27
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	14	27
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	(43)	(59)
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	(43)	(59)
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	2
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	2
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	(2)	(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	(2)	(2)
Written Options (Swaptions) [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0

Employee Postretirement Benef68

Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions	Dec. 31, 2017USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2018	$ 58
Expected Benefit Payments - 2019	56
Expected Benefit Payments - 2020	56
Expected Benefit Payments - 2021	59
Expected Benefit Payments - 2022	61
Expected Benefit Payments - 2023 - 2027	323
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2018	12
Expected Benefit Payments - 2019	12
Expected Benefit Payments - 2020	12
Expected Benefit Payments - 2021	12
Expected Benefit Payments - 2022	12
Expected Benefit Payments - 2023 - 2027	$ 61

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities (Detail) - USD ($)	Dec. 31, 2017	Mar. 22, 2017	Dec. 31, 2016	Mar. 24, 2015
Line Of Credit Facility [Line Items]
Credit Facilities	$ 775,000,000	$ 50,000,000	$ 475,000,000
Borrowings Outstanding	305,000,000		170,000,000
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	5,000,000		40,000,000
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	0		130,000,000
Letters of Credit Outstanding	0		0
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000		0
Borrowings Outstanding	300,000,000		0
Letters of Credit Outstanding	$ 0		$ 0

Short-Term Debt - Credit Faci70

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	Mar. 24, 2015	Dec. 31, 2017	Dec. 31, 2016
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. 23, 2018	Mar. 23, 2018	Mar. 23, 2018
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Nov. 1, 2018	Nov. 1, 2018

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Nov. 02, 2017	Mar. 22, 2017	Mar. 24, 2015	Dec. 31, 2017	Dec. 31, 2016
Line Of Credit Facility [Line Items]
Weighted-average interest rate				2.07%	1.49%
Line of credit facility maximum borrowing capacity		$ 50,000,000		$ 775,000,000	$ 475,000,000
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
364-day Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity period	364 days
Line of credit facility maximum borrowing capacity	$ 300,000,000
Credit facility maturity date	Nov. 1, 2018
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 maturity date			Mar. 23, 2018	Mar. 23, 2018	Mar. 23, 2018
Credit facility amendment date			Mar. 24, 2015
Loan agreement program and liquidity fees				0.65%
Interest rate description				TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2017. 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 BTMU’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				0.30%
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	May 20, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Purchase in lieu of redemption		$ 0	$ 83	$ 83
Held Bonds [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption		233	233
4.20% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2,045
4.20% Notes [Member] | The TEC 2015 Notes
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 250
Stated interest rate	4.20%
Debt instrument maturity date	May 15, 2045
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	Nov. 15, 2044
Debt instrument, offering date	May 20, 2015
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

Merger with Emera - Additional

Merger with Emera - Additional Information (Detail) - Emera Inc. [Member] $ / shares in Units, $ in Billions	Jul. 01, 2016USD ($)$ / shares
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding | $ / shares	$ 27.55
Aggregate purchase price	$ 10.7
Purchase price allocation for debt	4.2
Assumed debt	$ 2.3

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jun. 29, 2017Worker
Long Term Commitments [Line Items]
Total rental expense and lease | $	$ 2	$ 2	$ 4
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites | $	$ 30
Industrial Accident [Member]
Long Term Commitments [Line Items]
Number of workers killed				5
Number of workers sustained serious injuries				1
Industrial Accident [Member] | Tampa Electric Employee [Member]
Long Term Commitments [Line Items]
Number of workers killed				1
Industrial Accident [Member] | Contract Workers [Member]
Long Term Commitments [Line Items]
Number of workers killed				4

Commitments and Contingencies75

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2018	$ 10
Future Minimum Purchased Power Payments Due, 2019	0
Future Minimum Purchased Power Payments Due, 2020	0
Future Minimum Purchased Power Payments Due, 2021	0
Future Minimum Purchased Power Payments Due, 2022	0
Future Minimum Purchased Power Payments Due, Thereafter	0
Total future minimum purchased power payments due	10
Future Minimum Operating Leases Payments Due, 2018	2
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, Thereafter	36
Total future minimum operating leases payments due	46
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	303
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2019	74
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2020	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2021	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2022	7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	18
Total future minimum long-term service agreements/capital projects payments due	416
Future Minimum Clause Recoverable Commitments Payments Due, 2018	444
Future Minimum Clause Recoverable Commitments Payments Due, 2019	230
Future Minimum Clause Recoverable Commitments Payments Due, 2020	177
Future Minimum Clause Recoverable Commitments Payments Due, 2021	147
Future Minimum Clause Recoverable Commitments Payments Due, 2022	141
Future Minimum Clause Recoverable Commitments Payments Due, Thereafter	1,029
Total future minimum clause recoverable commitments payments due	2,168
Future Minimum Payments Due, 2018	759
Future Minimum Payments Due, 2019	306
Future Minimum Payments Due, 2020	186
Future Minimum Payments Due, 2021	156
Future Minimum Payments Due, 2022	150
Future Minimum Payments Due, Thereafter	1,083
Total future minimum payments	$ 2,640

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Natural gas sales to/(from) affiliates	$ (4)	$ 0	$ 1
Services received from affiliates	67	66	69
Dividends to TECO Energy	292	289
Equity contributions from TECO Energy	190	150
Accounts receivable	2	7
Accounts payable	19	18
Taxes receivable	3	0
Taxes payable	2	7
TECO Energy [Member]
Related Party Transaction [Line Items]
Dividends to TECO Energy	292	289	268
Equity contributions from TECO Energy	$ 190	$ 150	$ 175

Segment Information - Additiona

Segment Information - Additional Information (Detail)	Dec. 31, 2017Customer
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	750,000
PGS [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	375,000

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total revenues	$ 2,470	$ 2,396	$ 2,419
Depreciation and amortization	350	328	313
Total interest charges	119	106	110
Provision for income taxes	197	152	166
Net income	316	286	276
Total assets	8,364	8,083	7,709
Capital expenditures	640	727	687
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,470	2,396	2,419
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(22)	(8)	(6)
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	(555)	(465)	(431)
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	(22)	(8)	(6)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2,054	1,965	2,018
Depreciation and amortization	300	268	256
Total interest charges	104	91	95
Provision for income taxes	171	130	144
Net income	273	251	241
Total assets	7,635	7,357	7,004
Capital expenditures	518	594	593
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,052	1,964	2,018
Tampa Electric [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	2	1	0
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	438	439	407
Depreciation and amortization	50	60	57
Total interest charges	15	15	15
Provision for income taxes	26	22	22
Net income	43	35	35
Total assets	1,284	1,191	1,136
Capital expenditures	122	133	94
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	418	432	401
PGS [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	$ 20	$ 7	$ 6

Other Comprehensive Income - Ac

Other Comprehensive Income - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income, Gross		$ 1	$ 1	$ 6
Total other comprehensive income, Tax		0	0	(2)
Total other comprehensive income, net of tax		1	1	4
Net unrealized losses from cash flow hedges	[1]	(2)	(3)
Total accumulated other comprehensive loss		(2)	(3)
Accumulated Gain on Cash Flow Hedges [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0	0	4
Reclassification from AOCI to net income, Gross		1	1	2
Total other comprehensive income, Gross		1	1	6
Unrealized gain on cash flow hedges, Tax		0	0	(1)
Reclassification from AOCI to net income, Tax		0	0	(1)
Total other comprehensive income, Tax		0	0	(2)
Unrealized gain on cash flow hedges, Net		0	0	3
Reclassification from AOCI to net income, Net		1	1	1
Total other comprehensive income, net of tax		$ 1	$ 1	$ 4
[1]	Net of tax benefit of $1 million and $2 million as of December 31, 2017 and 2016, respectively.

Other Comprehensive Income - 80

Other Comprehensive Income - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Comprehensive Income [Abstract]
Net unrealized losses from cash flow hedges, tax benefit	$ 1	$ 2

Accounting for Derivative Ins81

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	1 Months Ended		12 Months Ended
	Sep. 30, 2017	Nov. 30, 2016	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative assets			$ 0	$ 17,000,000
Derivative liabilities			1,000,000	0
Cash collateral posted with or received from any counterparties			0	$ 0
Net pre-tax reductions expected to be reclassified from regulatory assets or liabilities, next 12 months			$ 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	1 year

Accounting for Derivative Ins82

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail) - Natural Gas Contract Expected to be Settled in Year 2018 [Member]	Dec. 31, 2017MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 1,000,000	$ 0
Natural gas derivative assets	0	17,000,000
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	1,000,000
Natural gas derivative assets		17,000,000
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0
Natural gas derivative assets		0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	1,000,000
Natural gas derivative assets		17,000,000
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	0	0
Natural gas derivative assets	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Derivatives [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative liabilities	$ 0
Natural gas derivative assets		$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 0	$ 17,000,000
Derivative liabilities	1,000,000	0
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	12 Months Ended
	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 46	$ 104	$ 79
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 16	$ 62	$ 34
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	121
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	250

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 45	$ 6
Additional liabilities	1	36
Liabilities settled	(1)	0
Revisions to estimated cash flows	0	3
Other	2	0
Ending balance	$ 47	$ 45

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - Performance Share Unit Plan [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
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	$ 2
Tax benefits related to compensation cost	1
Unrecognized compensation cost	$ 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] CAD / shares in Units, shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017CADCAD / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Outstanding as of December 31, 2016 | shares	0
Number of Units, Granted including DRIP | shares	144
Number of Units, Exercised | shares	(5)
Number of Units, Forfeited | shares	(17)
Number of Units, Transferred | shares	11
Number of Units, Outstanding as of December 31, 2017 | shares	133
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2016 | CAD / shares	CAD 0
Weighted Average Grant Date Fair Value, Granted including DRIP | CAD / shares	45.40
Weighted Average Grant Date Fair Value, Exercised | CAD / shares	30.57
Weighted Average Grant Date Fair Value, Forfeited | CAD / shares	45.41
Weighted Average Grant Date Fair Value, Transferred | CAD / shares	38.51
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2017 | CAD / shares	CAD 45.11
Aggregate Intrinsic Value, Outstanding as of December 31, 2016 | CAD	CAD 0
Aggregate Intrinsic Value, Granted including DRIP | CAD	6
Aggregate Intrinsic Value, Exercised | CAD	0
Aggregate Intrinsic Value, Forfeited | CAD	(1)
Aggregate Intrinsic Value, Transferred | CAD	1
Aggregate Intrinsic Value, Outstanding as of December 31, 2017 | CAD	CAD 6

Schedule II - Valuation and Q89

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		5	3	3
Other Charges		0	0	0
Payments & Deductions	[1]	5	3	3
Balance at End of Period		$ 1	$ 1	$ 1
[1]	Write-off of individual bad debt accounts