Tampa Electric 10-K 13 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 08, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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, 2016	Dec. 31, 2015
Property, plant and equipment
Utility plant in service, at original costs	$ 10,018.7	$ 9,440
Construction work in progress	891.5	771.1
Accumulated depreciation	(2,826.1)	(2,676.8)
Utility plant in service, net	7,192.6	6,763.2
Other property	10.7	9.7
Total property, plant and equipment, net	7,203.3	6,772.9
Current assets
Cash and cash equivalents	9.5	9.1
Receivables, less allowance for uncollectibles of $1.2 and $1.5 at December 31, 2016 and 2015, respectively	205.6	227.9
Due from affiliates	6.9	63.6
Inventories, at average cost
Current derivative assets	15.1	0
Regulatory assets	28.1	44.3
Prepayments and other current assets	21.4	21.5
Total current assets	449.3	545.1
Deferred debits
Regulatory assets	392.6	373.8
Other	37.4	16.8
Total deferred debits	430	390.6
Total assets	8,082.6	7,708.6
Capitalization
Common stock	2,455.4	2,305.4
Accumulated other comprehensive loss	(2.8)	(3.6)
Retained earnings	311.2	313.7
Total capital	2,763.8	2,615.5
Long-term debt, less amount due within one year	2,162.9	2,161.7
Total capital	4,926.7	4,777.2
Current liabilities
Long-term debt due within one year	0	83.3
Notes payable	170	61
Accounts payable	262.1	205.7
Due to affiliates	25.2	16.9
Customer deposits	146	176.3
Regulatory liabilities	154.2	83.2
Derivative liabilities	0	24.1
Accrued interest	16.2	16.9
Accrued taxes	12.2	12.2
Other	10.3	10.2
Total current liabilities	796.2	689.8
Deferred credits
Deferred income taxes	1,406.6	1,308.8
Investment tax credits	11.4	10.5
Regulatory liabilities	590.6	603.5
Deferred credits and other liabilities	351.1	318.8
Total deferred credits	2,359.7	2,241.6
Commitments and Contingencies (see Note 9)
Total liabilities and capital	8,082.6	7,708.6
Fuel [Member]
Inventories, at average cost
Utility inventories	77	105.6
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	85.7	73.1
Electric [Member]
Property, plant and equipment
Utility plant in service, at original costs	7,623.7	7,270.3
Gas [Member]
Property, plant and equipment
Utility plant in service, at original costs	$ 1,503.5	$ 1,398.6

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Allowance for uncollectibles	$ 1.2	$ 1.5

Consolidated Statements of Inco

Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Electric	$ 1,963.6	$ 2,017.7	$ 2,020.5
Gas	432.2	401.5	398.5
Total revenues	2,395.8	2,419.2	2,419
Expenses
Fuel	561.4	638.6	692.3
Purchased power	104.1	78.9	71.4
Cost of natural gas sold	158.5	135.5	137
Other	537.9	528.9	518.4
Depreciation and amortization	328.3	313.5	302.6
Taxes, other than income	193.1	192	189.8
Total expenses	1,883.3	1,887.4	1,911.5
Income from operations	512.5	531.8	507.5
Other income
Allowance for other funds used during construction	24.1	17.2	10.5
Other income, net	7.1	2.4	4.8
Total other income	31.2	19.6	15.3
Interest charges
Interest expense	117.3	117.9	111.7
Allowance for borrowed funds used during construction	(11.5)	(8.3)	(5.1)
Total interest charges	105.8	109.6	106.6
Income before provision for income taxes	437.9	441.8	416.2
Provision for income taxes	152.2	165.5	155.9
Net income	285.7	276.3	260.3
Other comprehensive income, net of tax
Gain on cash flow hedges	0.8	3.5	0.7
Total other comprehensive income, net of tax	0.8	3.5	0.7
Comprehensive income	$ 286.5	$ 279.8	$ 261

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net income	$ 285.7	$ 276.3	$ 260.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	328.3	313.5	302.6
Deferred income taxes and investment tax credits	87.7	118.9	92.2
Allowance for other funds used during construction	(24.1)	(17.2)	(10.5)
Deferred recovery clauses	54.4	26.5	(16.2)
Receivables, less allowance for uncollectibles	17.7	(3)	0.4
Inventories	16	(21.3)	13.1
Prepayments and other deposits	(0.1)	(4)	1.5
Taxes accrued	67.5	(17.2)	11.8
Interest accrued	(0.7)	(0.1)	0.6
Accounts payable	63.1	(26.8)	5.9
Other	(64.9)	(37.7)	(14.5)
Cash flows from operating activities	830.6	607.9	647.2
Cash flows from investing activities
Capital expenditures	(726.8)	(686.6)	(671)
Net proceeds from sale of assets	9.1	0	0
Cash flows used in investing activities	(717.7)	(686.6)	(671)
Cash flows from financing activities
Common stock	150	175	100
Proceeds from long-term debt issuance	0	251.1	296.3
Repayment of long-term debt	(83.3)	(83.3)	(83.3)
Net change in short-term debt	109	3	(26)
Dividends	(288.2)	(268.4)	(262.6)
Cash flows from/(used in) financing activities	(112.5)	77.4	24.4
Net increase (decrease) in cash and cash equivalents	0.4	(1.3)	0.6
Cash and cash equivalents at beginning of the year	9.1	10.4	9.8
Cash and cash equivalents at end of the year	9.5	9.1	10.4
Supplemental disclosure of cash paid (received)
Interest	102.9	106.2	102.5
Income taxes	(3)	63.7	52.6
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (8.9)	$ 6.9	$ 14.3

Consolidated Statements of Reta

Consolidated Statements of Retained Earnings - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Of Partners Capital [Abstract]
Beginning Balance	$ 313.7	$ 305.8	$ 308.1
Add: Net income	285.7	276.3	260.3
Retained Earning, Gross	599.4	582.1	568.4
Deduct: Cash dividends on capital stock—common	288.2	268.4	262.6
Ending Balance	$ 311.2	$ 313.7	$ 305.8

Consolidated Statements of Capi

Consolidated Statements of Capitalization - Capital Stock (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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	$ 2,455.4	$ 2,305.4
Cash Dividends Paid	$ 288.2	$ 268.4

Consolidated Statements of Cap8

Consolidated Statements of Capitalization - Capital Stock (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Preferred stock - par value	$ 100
Preferred stock, no par value
Equity contributions made by TECO Energy	$ 150	$ 175
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
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

Consolidated Statements of Cap9

Consolidated Statements of Capitalization - Long-Term Debt (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt, total	$ 2,182.6	$ 2,265.9
Unamortized debt discount, net	(3)	(2.8)
Debt issuance costs	(16.7)	(18.1)
Long-term debt, carrying amount	2,162.9	2,245
Less amount due within one year	0	83.3
Total long-term debt	2,162.9	2,161.7
Long-term debt, fair value	2,345.3	2,433.3
Level 1 [Member]
Debt Instrument [Line Items]
Long-term debt, fair value	57.9
Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,920.9	2,004.2
Long-term debt, carrying amount	$ 1,920.9
Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2,018
Long-term debt, total	$ 54.2	54.2
Tampa Electric [Member] | 6.25% Notes [Member]
Debt Instrument [Line Items]
Due	2,016
Long-term debt, total	$ 0	83.3
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	$ 231.7	231.7
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	261.7	261.7
Long-term debt, carrying amount	$ 261.7
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	$ 46.7	46.7
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 Ca10

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) (Detail)	Dec. 31, 2016
Tampa Electric [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Stated interest rate	5.65%
Tampa Electric [Member] | 6.25% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.25%
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 Ca11

Consolidated Statements of Capitalization - Long-term Debt Maturities (Detail) $ in Millions	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Total long-term debt maturities	$ 2,162.9
Long Term Debt Maturities
Debt Instrument [Line Items]
2,017	0
2,018	304.2
2,019	0
2,020	0
2,021	278.4
Thereafter	1,600
Total long-term debt maturities	2,182.6
Tampa Electric [Member]
Debt Instrument [Line Items]
2,017	0
2,018	254.2
2,019	0
2,020	0
2,021	231.7
Thereafter	1,435
Total long-term debt maturities	1,920.9
PGS [Member]
Debt Instrument [Line Items]
2,017	0
2,018	50
2,019	0
2,020	0
2,021	46.7
Thereafter	165
Total long-term debt maturities	$ 261.7

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. 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, 2016 December 31, 2015 Electric generation 15-56 years $ 4,101.8 $ 4,046.5 Electric transmission 28-77 years 836.8 711.2 Electric distribution 14-56 years 2,331.4 2,221.3 Gas transmission and distribution 16-77 years 1,429.1 1,326.1 General plant and other 3-43 years 438.8 373.5 Total cost 9,137.9 8,678.6 Less accumulated depreciation (2,826.1 ) (2,676.8 ) Construction work in progress 891.5 771.1 Total property, plant and equipment, net $ 7,203.3 $ 6,772.9 Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.7% and 3.7% for 2016, 2015 and 2014, 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, 2016, 2015 and 2014 was $303.6 million, $306.0 million and $295.8 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 2016, 2015 and 2014, the rate was 6.46%. Total AFUDC for the years ended December 31, 2016, 2015 and 2014 was $35.6 million, $25.5 million and $15.6 million, respectively. The increase is a result of the construction of the Polk Power Station conversion project. 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 market, 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 current 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. 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. 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-TECO Energy affiliates at a cost of $104.1 million, $78.9 million and $71.4 million, for the years ended December 31, 2016, 2015 and 2014, 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 on a dollar-for-dollar basis incurred 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 $116.9 million, $116.9 million and $113.9 million for the years ended December 31, 2016, 2015 and 2014, 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, 2016 and 2015 ranged from 2.69% to 4.00% and 2.92% 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 in any period. See Note 2

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2016
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 were adopted by TEC are described as follows: Interest – Imputation of Interest In April 2015, the FASB issued Accounting Standard Update (ASU) 2015-03, Interest – Imputation of Interest Interest: Imputation of Interest Derivatives and Hedging - Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. 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 to have minimal 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 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. Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows Restricted Cash on the Statement of Cash Flows In November 2016, the FASB issued ASU 2016-18, Restricted Cash on the Statement of Cash Flows Clarifying the Definition of a Business In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business

Regulatory

Regulatory	12 Months Ended
	Dec. 31, 2016
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. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, 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. Base Rates-Tampa Electric Tampa Electric’s results for the past three years reflect the results of a Stipulation and Settlement Agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement. This agreement provided for the following revenue increases: $57.5 million effective November 1, 2013, an additional $7.5 million effective November 1, 2014, an additional $5.0 million effective November 1, 2015, and an additional $110.0 million effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) 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 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. Storm Damage Cost Recovery-Tampa Electric Tampa Electric’s storm reserve was $56.1 million at both December 31, 2016 and 2015. Prior to the above-mentioned stipulation and settlement agreement, Tampa Electric was accruing $8.0 million annually to an FPSC-approved self-insured storm damage reserve. Effective November 1, 2013, Tampa Electric ceased accruing for this storm damage 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 $56.1 million, the level of the reserve as of October 31, 2013. As a result of several named storms including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric has incurred $8.6 million of storm costs in 2016. On January 31, 2017, Tampa Electric petitioned the FPSC to seek full recovery of those costs as a surcharge to customers during the five-month period ended December 31, 2017. Base Rates-PGS PGS’s base rates were established in May 2009 and reflect an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. 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 $16.1 million in 2016, 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 new 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 Regulatory Assets and Liabilities Tampa Electric and PGS apply the 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 damage or the future removal of property. All regulatory assets are recovered through the regulatory process. Details of the regulatory assets and liabilities as of December 31, 2016 and 2015 are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2016 2015 Regulatory assets: Regulatory tax asset (1) $ 85.6 $ 74.6 Cost-recovery clauses - deferred balances (2) 8.4 5.2 Cost-recovery clauses - offsets to derivative liabilities (2) 0.0 26.2 Environmental remediation (3) 36.9 54.0 Postretirement benefits (4) 272.0 238.3 Deferred bond refinancing costs (5) 5.7 6.5 Competitive rate adjustment (2) 2.7 2.6 Other 9.4 10.7 Total regulatory assets 420.7 418.1 Less: Current portion 28.1 44.3 Long-term regulatory assets $ 392.6 $ 373.8 Regulatory liabilities: Regulatory tax liability $ 6.2 $ 5.7 Cost-recovery clauses (2) 111.8 54.2 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve—cost of removal (6) 546.4 570.0 Other 24.3 0.7 Total regulatory liabilities 744.8 686.7 Less: Current portion 154.2 83.2 Long-term regulatory liabilities $ 590.6 $ 603.5 (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. (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. (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) This asset represents the past costs associated with refinancing debt. It 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 amortized over the term of the related debt instruments. (6) 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 represent 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, 2016
Income Tax Disclosure [Abstract]
Income Taxes	4. Income Taxes 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 2016, 2015 and 2014, 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, 2016 2015 2014 Current income taxes Federal $ 52.7 $ 38.2 $ 54.8 State 11.8 8.4 8.9 Deferred income taxes Federal 75.7 102.9 79.0 State 11.0 14.5 13.5 Investment tax credits, net of amortization 1.0 1.5 (0.3 ) Total income tax expense $ 152.2 $ 165.5 $ 155.9 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, 2016 2015 2014 Income before provision for income taxes $ 437.9 $ 441.8 $ 416.2 Federal statutory income tax rates 35 % 35 % 35 % Income taxes, at statutory income tax rate 153.3 154.6 145.7 Increase (decrease) due to State income tax, net of federal income tax 14.8 14.8 14.5 AFUDC-equity (8.4 ) (6.0 ) (3.7 ) Tax credits (6.8 ) 0.0 0.0 Other (0.7 ) 2.1 (0.6 ) Total income tax expense on consolidated statements of income $ 152.2 $ 165.5 $ 155.9 Income tax expense as a percent of income from continuing operations, before income taxes 34.8 % 37.5 % 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, 2016 2015 Deferred tax liabilities (1) Property related $ 1,549.1 $ 1,431.9 Pension and postretirement benefits 105.0 92.0 Pension 69.2 71.1 Total deferred tax liabilities 1,723.3 1,595.0 Deferred tax assets (1) Loss and credit carryforwards (2) 91.3 80.0 Medical benefits 46.9 47.7 Insurance reserves 27.3 27.6 Pension and postretirement benefits 105.0 92.0 Capitalized energy conservation assistance costs 22.9 21.4 Other 23.3 17.5 Total deferred tax assets 316.7 286.2 Total deferred tax liability, net $ 1,406.6 $ 1,308.8 (1) Certain property related assets and liabilities have been netted. (2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $6.8 million. At December 31, 2016, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $202.8 million and $272.6 million, respectively, expiring between 2033 and 2036. TEC has unused general business credits of $10.0 million, expiring between 2028 and 2036. 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) 2016 2015 2014 Balance at January 1, $ 0.0 $ 0.0 $ 0.0 Increases due to tax positions related to current year 6.8 0.0 0.0 Balance at December 31 $ 6.8 $ 0.0 $ 0.0 As of December 31, 2016 and 2015, TEC’s uncertain tax positions were $6.8 million and zero, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. The increase was due to an uncertain tax position related to federal R&D tax credits. TEC believes that the total unrecognized tax benefits will decrease within the next twelve months due to the expected audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. As of December 31, 2016, if recognized, $6.8 million of the unrecognized tax benefits 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 2016, 2015 and 2014, TEC did not recognize any pretax charges (benefits) for interest. Additionally, TEC did not have any accrued interest at December 31, 2016, 2015 and 2014. No amounts have been recorded for penalties. Years 2015 and the short tax year ending June 30, 2016 are 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. The U.S. federal statute of limitations remains open for the year 2013 and onward. 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, 2016
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. The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits. 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. This amount was trued up in 2013. 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 2018, 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) 2016 2015 2016 2015 Change in benefit obligation Net benefit obligation at beginning of year $ 732.9 $ 728.9 $ 172.3 $ 174.3 Service cost 18.8 20.9 1.8 1.9 Interest cost 30.8 30.3 7.4 7.0 Plan participants’ contributions 0.0 0.0 2.6 2.1 Plan amendments 1.2 0.0 0.0 0.0 Plan curtailment 1.3 0.0 0.0 0.0 Plan settlement (2.1 ) 0.0 0.0 0.0 Benefits paid (69.5 ) (53.0 ) (13.9 ) (13.4 ) Actuarial loss (gain) 56.3 5.8 5.0 0.4 Net benefit obligation at end of year $ 769.7 $ 732.9 $ 175.2 $ 172.3 Change in plan assets Fair value of plan assets at beginning of year $ 625.4 $ 648.0 $ 0.0 $ 0.0 Actual return on plan assets 55.3 (25.5 ) 0.0 0.0 Employer contributions 37.4 55.0 (2.6 ) (2.1 ) Employer direct benefit payments 2.9 0.9 13.9 13.4 Plan participants’ contributions 0.0 0.0 2.6 2.1 Plan settlement (2.1 ) 0.0 0.0 0.0 Benefits paid (68.7 ) (53.0 ) (13.9 ) (13.4 ) Direct benefit payments (0.8 ) 0.0 0.0 0.0 Fair value of plan assets at end of year (1) $ 649.4 $ 625.4 $ 0.0 $ 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) 2016 2015 2016 2015 Benefit obligation (PBO/APBO) $ 769.7 $ 732.9 $ 175.2 $ 172.3 Less: Fair value of plan assets 649.4 625.4 0.0 0.0 Funded status at end of year $ (120.3 ) $ (107.5 ) $ (175.2 ) $ (172.3 ) (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 $723.9 million at December 31, 2016 and $686.9 million at December 31, 2015. 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) 2016 2015 2016 2015 Accrued benefit costs and other current liabilities $ (0.7 ) $ (0.6 ) $ (9.5 ) $ (9.2 ) Deferred credits and other liabilities (80.0 ) (69.3 ) (138.8 ) (142.3 ) $ (80.7 ) $ (69.9 ) $ (148.3 ) $ (151.5 ) 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) 2016 2015 2016 2015 Net actuarial loss (gain) $ 236.1 $ 208.2 $ 50.5 $ 47.2 Prior service cost (credit) 0.7 0.0 (15.1 ) (17.0 ) Amount recognized $ 236.8 $ 208.2 $ 35.4 $ 30.2 Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2016 2015 2016 2015 Discount rate 4.11 % 4.688 % 4.28 % 4.667 % Rate of compensation increase-weighted average 2.57 % 3.87 % 2.48 % 2.50 % Healthcare cost trend rate Immediate rate n/a n/a 6.83 % 7.05 % 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 $ 4.9 $ (4.2 ) The discount rate assumption used to determine the December 31, 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) 2016 2015 2014 2016 2015 2014 (millions) Service cost $ 18.8 $ 20.9 $ 18.3 $ 1.8 $ 1.9 $ 2.4 Interest cost 30.8 30.3 32.0 7.4 7.0 10.4 Expected return on plan assets (45.8 ) (43.3 ) (41.8 ) 0.0 0.0 0.0 Amortization, settlement, or curtailment of: Actuarial loss 16.4 15.1 13.5 0.2 0.0 0.2 Prior service (benefit) cost 0.3 (0.2 ) (0.4 ) (2.4 ) (2.4 ) (0.2 ) Curtailment loss (gain) 1.3 0.0 3.9 0.0 0.0 (0.2 ) Special termination benefit 0.0 0.0 0.2 0.0 0.0 0.0 Settlement loss 0.6 0.0 0.0 0.0 0.0 0.0 Net periodic benefit cost $ 22.4 $ 22.8 $ 25.7 $ 7.0 $ 6.5 $ 12.6 New prior service cost $ 1.3 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ (23.2 ) Net loss (gain) arising during the year 46.8 74.5 44.1 5.0 0.4 (10.1 ) Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service (benefit) cost (0.3 ) 0.2 0.4 2.4 2.5 0.3 Amortization or settlement of actuarial gain (loss) (17.1 ) (15.1 ) (13.5 ) (0.2 ) 0.0 (0.2 ) Total recognized in OCI and regulatory assets $ 30.7 $ 59.6 $ 31.0 $ 7.2 $ 2.9 $ (33.2 ) Total recognized in net periodic benefit cost, OCI and regulatory assets $ 53.1 $ 82.4 $ 56.7 $ 14.2 $ 9.4 $ (20.6 ) (1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan. TEC’s portion of the net periodic benefit costs for pension benefits was $13.3 million, $13.5 million and $14.8 million for 2016, 2015 and 2014, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $6.4 million, $5.7 million and $10.4 million for 2016, 2015 and 2014, 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 $12.7 million. There will be an estimated $1.8 million prior service credit that will be amortized from regulatory assets into net periodic benefit cost in 2017 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 $1.0 million for pension benefits and $0.4 million for other postretirement plan benefits for the six months ended December 31, 2016. Additionally, a curtailment loss for the SERP of $1.3 million was recognized by TECO Energy in 2016 as a result of retirements due to the Merger. TEC was not impacted by the curtailment loss. Assumptions used to determine net periodic benefit cost for years ended December 31: Pension Benefits Other Benefits 2016 2015 2014 (1) 2016 2015 2014 Discount rate 4.688 % 4.258 % 5.118%/4.277%/4.331% 4.667%/3.85% 4.206 % 5.096 % Expected long-term return on plan assets 7.00 % 7.00 % 7.25%/7.00%/7.00% N/A N/A N/A Rate of compensation increase 2.59 % 3.87 % 3.73 % 2.50 % 3.86 % 3.71 % Healthcare cost trend rate Initial rate n/a n/a n/a 7.05 % 7.00 % 7.25 % 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 2025 2025 (1) TECO Energy performed a valuation as of January 1, 2014. TECO Energy remeasured its Retirement Plan on September 2, 2014 for the acquisition of NMGC and on October 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs. The discount rate assumption used to determine the benefit cost from the Merger date to December 31, 2016 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 January 1, 2016 through June 30, 2016 and the 2015 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructed hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculated all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selected the portfolio with the highest yield and uses that yield as the recommended discount rate. The change in the discount rate approach was a result of the Merger and done to align methodologies with Emera. The change in discount rate resulting from the different methodology used to select a discount rate did not have a material impact on TEC’s financial statements and provides consistency with Emera’s method for selecting a discount rate. The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended December 31, 2016, TECO Energy’s pension plan’s assets increased approximately 9.2%. 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 the following effect on TEC’s expense: (millions) 1% Increase 1% Decrease Effect on net periodic benefit cost $ 0.2 $ (0.2 ) 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 2016 Target Allocation Actual Asset Category 2016 2015 Equity securities 52%-58% 56 % 53 % Fixed income securities 42%-48% 44 % 47 % 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, 2016 and 2015. Pension Plan Investments TECO Energy At Fair Value as of December 31, 2016 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 2.1 $ 0.0 $ 0.0 $ 0.0 $ 2.1 Accounts receivable 27.4 0.0 0.0 0.0 27.4 Accounts payable (58.9 ) 0.0 0.0 0.0 (58.9 ) Cash collateral 1.0 0.0 0.0 0.0 1.0 Short-term investment funds (STIFs) 11.6 0.0 0.0 0.0 11.6 Common stocks 44.0 0.0 0.0 0.0 44.0 Real estate investment trusts (REITs) 3.4 0.0 0.0 0.0 3.4 Mutual funds 181.1 0.0 0.0 0.0 181.1 Municipal bonds 0.0 2.6 0.0 0.0 2.6 Government bonds 0.0 32.2 0.0 0.0 32.2 Corporate bonds 0.0 39.2 0.0 0.0 39.2 Asset backed securities (ABS) 0.0 0.3 0.0 0.0 0.3 Mortgage-backed securities (MBS) 0.0 8.4 0.0 0.0 8.4 Collateralized mortgage obligations (CMOs) 0.0 1.3 0.0 0.0 1.3 Swaps 0.0 1.0 0.0 0.0 1.0 Purchase options (swaptions) 0.0 1.7 0.0 0.0 1.7 Written options (swaptions) 0.0 (2.0 ) 0.0 0.0 (2.0 ) Miscellaneous (open position) 0.0 0.1 0.0 0.0 0.1 Investments not utilizing the practical expedient 211.7 84.8 0.0 0.0 296.5 Mutual fund (1) 0.0 0.0 0.0 82.7 82.7 Common and collective trusts (1) 0.0 0.0 0.0 270.2 270.2 Total investments $ 211.7 $ 84.8 0.0 $ 352.9 $ 649.4 (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, 2015 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 1.9 $ 0.0 $ 0.0 $ 0.0 $ 1.9 Accounts receivable 14.3 0.0 0.0 0.0 14.3 Accounts payable (27.2 ) 0.0 0.0 0.0 (27.2 ) Money markets 0.0 0.2 0.0 0.0 0.2 Discounted notes 0.0 0.7 0.0 0.0 0.7 STIFs 12.4 (2) 0.0 0.0 0.0 12.4 Common stocks 90.9 0.0 0.0 0.0 90.9 ADRs 5.7 0.0 0.0 0.0 5.7 REITs 4.8 0.0 0.0 0.0 4.8 Mutual funds 175.6 (2) 0.0 0.0 0.0 175.6 Municipal bonds 0.0 5.0 0.0 0.0 5.0 Government bonds 0.0 56.2 0.0 0.0 56.2 Corporate bonds 0.0 32.2 0.0 0.0 32.2 ABS 0.0 0.3 0.0 0.0 0.3 MBS, net short sales 0.0 8.7 0.0 0.0 8.7 CMOs 0.0 1.5 0.0 0.0 1.5 Purchased options (swaptions) 0.0 1.1 0.0 0.0 1.1 Miscellaneous 0.0 0.1 0.0 0.0 0.1 Long futures 0.0 (0.9 ) 0.0 0.0 (0.9 ) Written options (swaptions) 0.0 (1.0 ) 0.0 0.0 (1.0 ) Investments not utilizing the practical expedient 278.4 104.1 0.0 0.0 382.5 Common and collective trusts (1) 0.0 0.0 0.0 171.6 (2) 171.6 Mutual fund (1) 0.0 0.0 0.0 71.3 71.3 Total investments $ 278.4 $ 104.1 $ 0.0 $ 242.9 $ 625.4 (1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet. (2) STIFs and mutual funds were presented in the prior year as using NAV as a practical expedient in the determination of fair value. Common and collective trust investments of $53.7 million were presented in the prior year in the level 2 column. The presentation has been updated based on additional information that became available in 2016. 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. • 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 funds honor subscription and redemption activity regularly. • 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 unqualified SERP had $40.8 million and $43.5 million of assets as of December 31, 2016 and 2015, respectively. Since the plan is unqualified, 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 unqualified 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, 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 119.5% of the Pension Protection Act funded target as of January 1, 2016 and is estimated at 118.0% of the Pension Protection Act funded target as of January 1, 2017. 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 2016 and 2015, which met the minimum funding requirements for both 2016 and 2015. TEC’s portion of the contribution in 2016 was $30.9 million and in 2015 was $43.9 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC’s portion of the contributions to the SERP in 2016 and 2015 were zero and $14.9 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, including 2016. 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 2017. 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 2017, TEC expects to make a contribution of about $9.5 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) 2017 $ 78.3 $ 11.0 2018 51.8 11.2 2019 55.6 11.5 2020 56.1 11.6 2021 58.7 11.7 2022-2026 312.4 58.9 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, 2015, 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. During the period from April 2013 to December 2014, employer matching contributions were 67% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions with an additional incentive match of up to 40% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended December 31, 2016, 2015 and 2014, TEC’s portion of expense totaled $8.3 million, $7.5 million and $10.2 million for 2016

Short-Term Debt

Short-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Short-Term Debt	6. Short-Term Debt Credit Facilities December 31, 2016 December 31, 2015 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 325.0 $ 40.0 $ 0.5 $ 325.0 $ 0.0 $ 0.5 3-year accounts receivable facility (3) 150.0 130.0 0.0 150.0 61.0 0.0 Total $ 475.0 $ 170.0 $ 0.5 $ 475.0 $ 61.0 $ 0.5 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures December 17, 2018. (3) This 3-year facility matures March 23, 2018. At December 31, 2016, 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, 2016 and 2015 was 1.49% and 0.89%, respectively. Tampa Electric Company Accounts Receivable Facility On March 24, 2015, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from April 14, 2015 to March 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of March 24, 2015 and (b) a Loan and Servicing Agreement dated as of March 24, 2015, among TEC and certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Pursuant to the Loan Agreement, TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2016. 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, at TEC’s option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin. In addition, under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of December 31, 2016, TEC was in compliance with the requirements of the Loan Agreement. Amendment of Tampa Electric Company Credit Facility On December 17, 2013, TEC amended its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from October 25, 2016 to December 17, 2018 (subject to further extension with the consent of each lender)

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
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. Issuance of Tampa Electric Company 4.35% Notes due 2044 On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the TEC 2014 Notes). TEC may redeem all or any part of the TEC 2014 Notes at its option at any time and from time to time before November 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 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, 2043, TEC may at its option redeem the TEC 2014 Notes, in whole or in part, at 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption. Purchase in Lieu of Redemption of Revenue Refunding Bonds At December 31, 2016, $232.6 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, $51.6 million term-rate refunding bonds due 2025, $75.0 million term-rate bonds due 2030, and $86.0 million term-rate refunding bonds due 2034.

Merger with Emera Inc.

Merger with Emera Inc.	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Merger with Emera Inc.	8. Merger with Emera Inc. 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, 2016
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 its 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. TEC believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. PGS Legal Proceeding In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, a suit was filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries. The suit against PGS remains pending. No trial date is currently set. TEC is unable at this time to estimate the possible loss or range of loss with respect to this matter. While the outcome of such proceeding is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on TEC’s results of operations, financial condition or cash flows. PGS Compliance Matter In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’s implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed. As a result of this report, the OPC filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On February 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On April 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016. 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, 2016, TEC has estimated its ultimate financial liability to be $31.6 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 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, 2016, 2015 and 2014, totaled $1.8 million, $3.8 million and $4.1 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, 2016: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2017 $ 10.7 $ 7.0 $ 68.8 $ 398.5 $ 485.0 2018 10.1 3.5 11.1 231.0 255.7 2019 0.0 2.1 11.8 186.2 200.1 2020 0.0 2.1 6.8 162.9 171.8 2021 0.0 2.2 6.9 132.3 141.4 Thereafter 0.0 37.8 24.4 1,156.6 1,218.8 Total future minimum payments $ 20.8 $ 54.7 $ 129.8 $ 2,267.5 $ 2,472.8 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, 2016, TEC was in compliance with all required financial covenants.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Natural gas sales $ 0.1 $ 0.8 $ 0.3 Services received from affiliates $ 65.8 $ 69.4 $ 22.5 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 using cost-causative allocation methods. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of total operating revenues, total operating assets and net income as the basis of allocation. Amounts due from or to affiliates at December 31, (millions) 2016 2015 Accounts receivable (1) $ 6.9 $ 2.3 Accounts payable (1) 18.0 15.9 Taxes receivable (2) 0.0 61.3 Taxes payable (2) 7.2 1.0 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2) At December 31, 2016, taxes payable were due to EUSHI. At December 31, 2015, taxes receivable were due from TECO Energy. See Note 4

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
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 736,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 374,000 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 2016 Revenues - external $ 1,963.6 $ 432.2 $ 0.0 $ 2,395.8 Sales to affiliates 0.9 7.1 (8.0 ) 0.0 Total revenues 1,964.5 439.3 (8.0 ) 2,395.8 Depreciation and amortization 268.4 59.9 0.0 328.3 Total interest charges 91.1 14.7 0.0 105.8 Provision for income taxes 129.8 22.4 0.0 152.2 Net income 250.8 34.9 0.0 285.7 Total assets 7,356.9 1,191.3 (465.6 ) (2) 8,082.6 Capital expenditures 594.3 132.5 0.0 726.8 2015 Revenues - external $ 2,017.7 $ 401.5 $ 0.0 $ 2,419.2 Sales to affiliates 0.6 6.0 (6.6 ) 0.0 Total revenues 2,018.3 407.5 (6.6 ) 2,419.2 Depreciation and amortization 256.7 56.8 0.0 313.5 Total interest charges 95.1 14.5 0.0 109.6 Provision for income taxes 143.6 21.9 0.0 165.5 Net income 241.0 35.3 0.0 276.3 Total assets (1) 7,003.8 1,136.1 (431.3 ) (2) 7,708.6 Capital expenditures 592.6 94.0 0.0 686.6 2014 Revenues - external $ 2,020.5 $ 398.5 $ 0.0 $ 2,419.0 Sales to affiliates 0.5 1.1 (1.6 ) 0.0 Total revenues 2,021.0 399.6 (1.6 ) 2,419.0 Depreciation and amortization 248.6 54.0 0.0 302.6 Total interest charges 92.8 13.8 0.0 106.6 Provision for income taxes 133.2 22.7 0.0 155.9 Net income 224.5 35.8 0.0 260.3 Total assets (1) 6,565.4 1,082.8 (373.9 ) (2) 7,274.3 Capital expenditures 582.1 88.9 0.0 671.0 (1) Certain prior year amounts have been reclassified to conform to current year presentation. These reclassifications relate to deferred tax assets (see note 2 below) and debt issuance costs required by newly issued accounting guidance (see Note 2 (2) 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, 2016
Other Comprehensive Income [Abstract]
Other Comprehensive Income	12. Other Comprehensive Income TEC reported the following OCI for the years ended December 31, 2016, 2015 and 2014, 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 2016 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.3 (0.5 ) 0.8 Gain on cash flow hedges 1.3 (0.5 ) 0.8 Total other comprehensive income $ 1.3 $ (0.5 ) $ 0.8 2015 Unrealized gain on cash flow hedges $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 1.4 (0.7 ) 0.7 Gain on cash flow hedges 5.7 (2.2 ) 3.5 Total other comprehensive income $ 5.7 $ (2.2 ) $ 3.5 2014 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.1 (0.4 ) 0.7 Gain on cash flow hedges 1.1 (0.4 ) 0.7 Total other comprehensive income $ 1.1 $ (0.4 ) $ 0.7 Accumulated Other Comprehensive Loss (millions) As of December 31, 2016 2015 Net unrealized losses from cash flow hedges (1) $ (2.8 ) $ (3.6 ) Total accumulated other comprehensive loss $ (2.8 ) $ (3.6 ) (1) Net of tax benefit of $1.8 million and $2.3 million as of December 31, 2016 and 2015, respectively.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2016
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. The stipulation agreement calls for the FPSC to oversee one or more workshops beginning in early 2017 to seek a cost-effective way to insure against rising gas prices. 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. The derivatives that are designated as cash flow hedges at December 31, 2016 and 2015 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 $16.6 million and zero derivative assets as of December 31, 2016 and 2015, respectively. Derivative liabilities totaled zero and $26.2 million as of December 31, 2016 and 2015, 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. All of the derivative asset and liabilities at December 31, 2016 and 2015 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, 2016, net pretax gains of $15.1 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, 2016 and 2015 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, 2016, 2015 and 2014, 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, 2016, 2015 and 2014 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, 2016, are expected to settle during the 2017 and 2018 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2017 0.0 26.0 2018 0.0 6.8 Total 0.0 32.8 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, 2016, 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, 2016
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 such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, 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. Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance: (A) Market approach : Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; (B) Cost approach Amount that would be required to replace the service capacity of an asset (replacement cost); and (C) Income approach Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). 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, 2016 and 2015. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’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. Recurring Derivative Fair Value Measures As of December 31, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0.0 $ 16.6 $ 0.0 $ 16.6 As of December 31, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.2 $ 0.0 $ 26.2 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, 2016 and 2015, 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, 2016 and 2015, the carrying value of TEC’s short-term debt was not materially different from the fair 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 and 7

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Variable Interest Entities	15. Variable Interest Entities 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 117 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 $62.0 million, $33.6 million and $25.7 million, under these PPAs for the three years ended December 31, 2016, 2015 and 2014, 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. In the normal course of business, 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, 2016
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 liability must be revalued each period 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) 2016 2015 Beginning balance $ 6.0 $ 5.3 Additional liabilities (1) 36.4 0.9 Revisions to estimated cash flows 2.6 (0.5 ) Other (2) (0.1 ) 0.3 Ending balance $ 44.9 $ 6.0 (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.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Event	17. Subsequent Event On February 7, 2017, the FPSC approved a settlement agreement between PGS and OPC agreeing to new depreciation rates that reduce annual depreciation expense, accelerate the amortization of the regulatory asset associated with environmental remediation costs, 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%. See Note 3

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts and Reserves	12 Months Ended
	Dec. 31, 2016
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, 2016, 2015 and 2014 (millions) Balance at Additions Balance at Beginning Charged to Other Payments & End of of Period Income Charges Deductions (1) Period Allowance for Uncollectible Accounts: 2016 $ 1.5 $ 2.7 $ 0.0 $ 3.0 $ 1.2 2015 $ 1.4 $ 2.7 $ 0.0 $ 2.6 $ 1.5 2014 $ 2.0 $ 2.7 $ 0.0 $ 3.3 $ 1.4 (1) Write-off of individual bad debt accounts

Significant Accounting Polici30

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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. As a result of the Merger, the Merger Sub Company merged with and into TECO Energy with TECO Energy continuing as the surviving corporation and becoming a wholly owned indirect subsidiary of Emera. 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, 2016 December 31, 2015 Electric generation 15-56 years $ 4,101.8 $ 4,046.5 Electric transmission 28-77 years 836.8 711.2 Electric distribution 14-56 years 2,331.4 2,221.3 Gas transmission and distribution 16-77 years 1,429.1 1,326.1 General plant and other 3-43 years 438.8 373.5 Total cost 9,137.9 8,678.6 Less accumulated depreciation (2,826.1 ) (2,676.8 ) Construction work in progress 891.5 771.1 Total property, plant and equipment, net $ 7,203.3 $ 6,772.9
Depreciation	Depreciation The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.7% and 3.7% for 2016, 2015 and 2014, 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, 2016, 2015 and 2014 was $303.6 million, $306.0 million and $295.8 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 2016, 2015 and 2014, the rate was 6.46%. Total AFUDC for the years ended December 31, 2016, 2015 and 2014 was $35.6 million, $25.5 million and $15.6 million, respectively. The increase is a result of the construction of the Polk Power Station conversion project.
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 market, 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 current 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.
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.
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-TECO Energy affiliates at a cost of $104.1 million, $78.9 million and $71.4 million, for the years ended December 31, 2016, 2015 and 2014, 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 on a dollar-for-dollar basis incurred 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 $116.9 million, $116.9 million and $113.9 million for the years ended December 31, 2016, 2015 and 2014, 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, 2016 and 2015 ranged from 2.69% to 4.00% and 2.92% 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 in any period. See Note 2

Significant Accounting Polici31

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of Property, Plant and Equipment	Property, plant and equipment consisted of the following assets: (millions) Estimated Useful Lives December 31, 2016 December 31, 2015 Electric generation 15-56 years $ 4,101.8 $ 4,046.5 Electric transmission 28-77 years 836.8 711.2 Electric distribution 14-56 years 2,331.4 2,221.3 Gas transmission and distribution 16-77 years 1,429.1 1,326.1 General plant and other 3-43 years 438.8 373.5 Total cost 9,137.9 8,678.6 Less accumulated depreciation (2,826.1 ) (2,676.8 ) Construction work in progress 891.5 771.1 Total property, plant and equipment, net $ 7,203.3 $ 6,772.9

Regulatory (Tables)

Regulatory (Tables)	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities as of December 31, 2016 and 2015 are presented in the following table: Regulatory Assets and Liabilities December 31, December 31, (millions) 2016 2015 Regulatory assets: Regulatory tax asset (1) $ 85.6 $ 74.6 Cost-recovery clauses - deferred balances (2) 8.4 5.2 Cost-recovery clauses - offsets to derivative liabilities (2) 0.0 26.2 Environmental remediation (3) 36.9 54.0 Postretirement benefits (4) 272.0 238.3 Deferred bond refinancing costs (5) 5.7 6.5 Competitive rate adjustment (2) 2.7 2.6 Other 9.4 10.7 Total regulatory assets 420.7 418.1 Less: Current portion 28.1 44.3 Long-term regulatory assets $ 392.6 $ 373.8 Regulatory liabilities: Regulatory tax liability $ 6.2 $ 5.7 Cost-recovery clauses (2) 111.8 54.2 Transmission and delivery storm reserve 56.1 56.1 Accumulated reserve—cost of removal (6) 546.4 570.0 Other 24.3 0.7 Total regulatory liabilities 744.8 686.7 Less: Current portion 154.2 83.2 Long-term regulatory liabilities $ 590.6 $ 603.5 (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. (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. (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) This asset represents the past costs associated with refinancing debt. It 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 amortized over the term of the related debt instruments. (6) 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 represent 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, 2016
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	Income tax expense consists of the following components: (millions) For the year ended December 31, 2016 2015 2014 Current income taxes Federal $ 52.7 $ 38.2 $ 54.8 State 11.8 8.4 8.9 Deferred income taxes Federal 75.7 102.9 79.0 State 11.0 14.5 13.5 Investment tax credits, net of amortization 1.0 1.5 (0.3 ) Total income tax expense $ 152.2 $ 165.5 $ 155.9
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, 2016 2015 2014 Income before provision for income taxes $ 437.9 $ 441.8 $ 416.2 Federal statutory income tax rates 35 % 35 % 35 % Income taxes, at statutory income tax rate 153.3 154.6 145.7 Increase (decrease) due to State income tax, net of federal income tax 14.8 14.8 14.5 AFUDC-equity (8.4 ) (6.0 ) (3.7 ) Tax credits (6.8 ) 0.0 0.0 Other (0.7 ) 2.1 (0.6 ) Total income tax expense on consolidated statements of income $ 152.2 $ 165.5 $ 155.9 Income tax expense as a percent of income from continuing operations, before income taxes 34.8 % 37.5 % 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, 2016 2015 Deferred tax liabilities (1) Property related $ 1,549.1 $ 1,431.9 Pension and postretirement benefits 105.0 92.0 Pension 69.2 71.1 Total deferred tax liabilities 1,723.3 1,595.0 Deferred tax assets (1) Loss and credit carryforwards (2) 91.3 80.0 Medical benefits 46.9 47.7 Insurance reserves 27.3 27.6 Pension and postretirement benefits 105.0 92.0 Capitalized energy conservation assistance costs 22.9 21.4 Other 23.3 17.5 Total deferred tax assets 316.7 286.2 Total deferred tax liability, net $ 1,406.6 $ 1,308.8 (1) Certain property related assets and liabilities have been netted. (2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $6.8 million.
Schedule of Unrecognized Tax Benefits	The following table provides details of the change in unrecognized tax benefits as follows: (millions) 2016 2015 2014 Balance at January 1, $ 0.0 $ 0.0 $ 0.0 Increases due to tax positions related to current year 6.8 0.0 0.0 Balance at December 31 $ 6.8 $ 0.0 $ 0.0

Employee Postretirement Benef34

Employee Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2016 2015 Accrued benefit costs and other current liabilities $ (0.7 ) $ (0.6 ) $ (9.5 ) $ (9.2 ) Deferred credits and other liabilities (80.0 ) (69.3 ) (138.8 ) (142.3 ) $ (80.7 ) $ (69.9 ) $ (148.3 ) $ (151.5 )
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) 2016 2015 2016 2015 Net actuarial loss (gain) $ 236.1 $ 208.2 $ 50.5 $ 47.2 Prior service cost (credit) 0.7 0.0 (15.1 ) (17.0 ) Amount recognized $ 236.8 $ 208.2 $ 35.4 $ 30.2
Benefit Obligations [Member]
Schedule of Assumptions Used to Determine Benefit	Assumptions used to determine benefit obligations at December 31: Pension Benefits Other Benefits 2016 2015 2016 2015 Discount rate 4.11 % 4.688 % 4.28 % 4.667 % Rate of compensation increase-weighted average 2.57 % 3.87 % 2.48 % 2.50 % Healthcare cost trend rate Immediate rate n/a n/a 6.83 % 7.05 % 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 $ 4.9 $ (4.2 )
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 2016 2015 2014 (1) 2016 2015 2014 Discount rate 4.688 % 4.258 % 5.118%/4.277%/4.331% 4.667%/3.85% 4.206 % 5.096 % Expected long-term return on plan assets 7.00 % 7.00 % 7.25%/7.00%/7.00% N/A N/A N/A Rate of compensation increase 2.59 % 3.87 % 3.73 % 2.50 % 3.86 % 3.71 % Healthcare cost trend rate Initial rate n/a n/a n/a 7.05 % 7.00 % 7.25 % 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 2025 2025 (1) TECO Energy performed a valuation as of January 1, 2014. TECO Energy remeasured its Retirement Plan on September 2, 2014 for the acquisition of NMGC and on October 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs.
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 the following effect on TEC’s expense: (millions) 1% Increase 1% Decrease Effect on net periodic benefit cost $ 0.2 $ (0.2 )
TECO Energy [Member]
Schedule of Change in Plan Assets	Change in plan assets Fair value of plan assets at beginning of year $ 625.4 $ 648.0 $ 0.0 $ 0.0 Actual return on plan assets 55.3 (25.5 ) 0.0 0.0 Employer contributions 37.4 55.0 (2.6 ) (2.1 ) Employer direct benefit payments 2.9 0.9 13.9 13.4 Plan participants’ contributions 0.0 0.0 2.6 2.1 Plan settlement (2.1 ) 0.0 0.0 0.0 Benefits paid (68.7 ) (53.0 ) (13.9 ) (13.4 ) Direct benefit payments (0.8 ) 0.0 0.0 0.0 Fair value of plan assets at end of year (1) $ 649.4 $ 625.4 $ 0.0 $ 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) 2016 2015 2014 2016 2015 2014 (millions) Service cost $ 18.8 $ 20.9 $ 18.3 $ 1.8 $ 1.9 $ 2.4 Interest cost 30.8 30.3 32.0 7.4 7.0 10.4 Expected return on plan assets (45.8 ) (43.3 ) (41.8 ) 0.0 0.0 0.0 Amortization, settlement, or curtailment of: Actuarial loss 16.4 15.1 13.5 0.2 0.0 0.2 Prior service (benefit) cost 0.3 (0.2 ) (0.4 ) (2.4 ) (2.4 ) (0.2 ) Curtailment loss (gain) 1.3 0.0 3.9 0.0 0.0 (0.2 ) Special termination benefit 0.0 0.0 0.2 0.0 0.0 0.0 Settlement loss 0.6 0.0 0.0 0.0 0.0 0.0 Net periodic benefit cost $ 22.4 $ 22.8 $ 25.7 $ 7.0 $ 6.5 $ 12.6 1. Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan
Schedule of Amounts Recognized in OCI and Regulatory Assets	New prior service cost $ 1.3 $ 0.0 $ 0.0 $ 0.0 $ 0.0 $ (23.2 ) Net loss (gain) arising during the year 46.8 74.5 44.1 5.0 0.4 (10.1 ) Amounts recognized as component of net periodic benefit cost: Amortization or curtailment recognition of prior service (benefit) cost (0.3 ) 0.2 0.4 2.4 2.5 0.3 Amortization or settlement of actuarial gain (loss) (17.1 ) (15.1 ) (13.5 ) (0.2 ) 0.0 (0.2 ) Total recognized in OCI and regulatory assets $ 30.7 $ 59.6 $ 31.0 $ 7.2 $ 2.9 $ (33.2 ) Total recognized in net periodic benefit cost, OCI and regulatory assets $ 53.1 $ 82.4 $ 56.7 $ 14.2 $ 9.4 $ (20.6 ) (1) Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.
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 2016 Target Allocation Actual Asset Category 2016 2015 Equity securities 52%-58% 56 % 53 % Fixed income securities 42%-48% 44 % 47 % 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, 2016 and 2015. Pension Plan Investments TECO Energy At Fair Value as of December 31, 2016 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 2.1 $ 0.0 $ 0.0 $ 0.0 $ 2.1 Accounts receivable 27.4 0.0 0.0 0.0 27.4 Accounts payable (58.9 ) 0.0 0.0 0.0 (58.9 ) Cash collateral 1.0 0.0 0.0 0.0 1.0 Short-term investment funds (STIFs) 11.6 0.0 0.0 0.0 11.6 Common stocks 44.0 0.0 0.0 0.0 44.0 Real estate investment trusts (REITs) 3.4 0.0 0.0 0.0 3.4 Mutual funds 181.1 0.0 0.0 0.0 181.1 Municipal bonds 0.0 2.6 0.0 0.0 2.6 Government bonds 0.0 32.2 0.0 0.0 32.2 Corporate bonds 0.0 39.2 0.0 0.0 39.2 Asset backed securities (ABS) 0.0 0.3 0.0 0.0 0.3 Mortgage-backed securities (MBS) 0.0 8.4 0.0 0.0 8.4 Collateralized mortgage obligations (CMOs) 0.0 1.3 0.0 0.0 1.3 Swaps 0.0 1.0 0.0 0.0 1.0 Purchase options (swaptions) 0.0 1.7 0.0 0.0 1.7 Written options (swaptions) 0.0 (2.0 ) 0.0 0.0 (2.0 ) Miscellaneous (open position) 0.0 0.1 0.0 0.0 0.1 Investments not utilizing the practical expedient 211.7 84.8 0.0 0.0 296.5 Mutual fund (1) 0.0 0.0 0.0 82.7 82.7 Common and collective trusts (1) 0.0 0.0 0.0 270.2 270.2 Total investments $ 211.7 $ 84.8 0.0 $ 352.9 $ 649.4 (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, 2015 (millions) Level 1 Level 2 Level 3 NAV (1) Total Cash $ 1.9 $ 0.0 $ 0.0 $ 0.0 $ 1.9 Accounts receivable 14.3 0.0 0.0 0.0 14.3 Accounts payable (27.2 ) 0.0 0.0 0.0 (27.2 ) Money markets 0.0 0.2 0.0 0.0 0.2 Discounted notes 0.0 0.7 0.0 0.0 0.7 STIFs 12.4 (2) 0.0 0.0 0.0 12.4 Common stocks 90.9 0.0 0.0 0.0 90.9 ADRs 5.7 0.0 0.0 0.0 5.7 REITs 4.8 0.0 0.0 0.0 4.8 Mutual funds 175.6 (2) 0.0 0.0 0.0 175.6 Municipal bonds 0.0 5.0 0.0 0.0 5.0 Government bonds 0.0 56.2 0.0 0.0 56.2 Corporate bonds 0.0 32.2 0.0 0.0 32.2 ABS 0.0 0.3 0.0 0.0 0.3 MBS, net short sales 0.0 8.7 0.0 0.0 8.7 CMOs 0.0 1.5 0.0 0.0 1.5 Purchased options (swaptions) 0.0 1.1 0.0 0.0 1.1 Miscellaneous 0.0 0.1 0.0 0.0 0.1 Long futures 0.0 (0.9 ) 0.0 0.0 (0.9 ) Written options (swaptions) 0.0 (1.0 ) 0.0 0.0 (1.0 ) Investments not utilizing the practical expedient 278.4 104.1 0.0 0.0 382.5 Common and collective trusts (1) 0.0 0.0 0.0 171.6 (2) 171.6 Mutual fund (1) 0.0 0.0 0.0 71.3 71.3 Total investments $ 278.4 $ 104.1 $ 0.0 $ 242.9 $ 625.4 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. • 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 funds honor subscription and redemption activity regularly. • 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) 2017 $ 78.3 $ 11.0 2018 51.8 11.2 2019 55.6 11.5 2020 56.1 11.6 2021 58.7 11.7 2022-2026 312.4 58.9
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) 2016 2015 2016 2015 Change in benefit obligation Net benefit obligation at beginning of year $ 732.9 $ 728.9 $ 172.3 $ 174.3 Service cost 18.8 20.9 1.8 1.9 Interest cost 30.8 30.3 7.4 7.0 Plan participants’ contributions 0.0 0.0 2.6 2.1 Plan amendments 1.2 0.0 0.0 0.0 Plan curtailment 1.3 0.0 0.0 0.0 Plan settlement (2.1 ) 0.0 0.0 0.0 Benefits paid (69.5 ) (53.0 ) (13.9 ) (13.4 ) Actuarial loss (gain) 56.3 5.8 5.0 0.4 Net benefit obligation at end of year $ 769.7 $ 732.9 $ 175.2 $ 172.3 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) 2016 2015 2016 2015 Benefit obligation (PBO/APBO) $ 769.7 $ 732.9 $ 175.2 $ 172.3 Less: Fair value of plan assets 649.4 625.4 0.0 0.0 Funded status at end of year $ (120.3 ) $ (107.5 ) $ (175.2 ) $ (172.3 ) (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, 2016
Debt Disclosure [Abstract]
Short-Term Debt Credit Facilities	Credit Facilities December 31, 2016 December 31, 2015 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding 5-year facility (2) $ 325.0 $ 40.0 $ 0.5 $ 325.0 $ 0.0 $ 0.5 3-year accounts receivable facility (3) 150.0 130.0 0.0 150.0 61.0 0.0 Total $ 475.0 $ 170.0 $ 0.5 $ 475.0 $ 61.0 $ 0.5 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures December 17, 2018. (3) This 3-year facility matures March 23, 2018.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2017 $ 10.7 $ 7.0 $ 68.8 $ 398.5 $ 485.0 2018 10.1 3.5 11.1 231.0 255.7 2019 0.0 2.1 11.8 186.2 200.1 2020 0.0 2.1 6.8 162.9 171.8 2021 0.0 2.2 6.9 132.3 141.4 Thereafter 0.0 37.8 24.4 1,156.6 1,218.8 Total future minimum payments $ 20.8 $ 54.7 $ 129.8 $ 2,267.5 $ 2,472.8

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	A summary of activities between TEC and its affiliates follows: Net transactions with affiliates: (millions) 2016 2015 2014 Natural gas sales $ 0.1 $ 0.8 $ 0.3 Services received from affiliates $ 65.8 $ 69.4 $ 22.5 Amounts due from or to affiliates at December 31, (millions) 2016 2015 Accounts receivable (1) $ 6.9 $ 2.3 Accounts payable (1) 18.0 15.9 Taxes receivable (2) 0.0 61.3 Taxes payable (2) 7.2 1.0 (1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest. (2) At December 31, 2016, taxes payable were due to EUSHI. At December 31, 2015, taxes receivable were due from TECO Energy. See Note 4

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
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 736,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 374,000 residential, commercial, industrial and electric power generation customers in the State of Florida. Tampa (millions) Electric PGS Eliminations TEC 2016 Revenues - external $ 1,963.6 $ 432.2 $ 0.0 $ 2,395.8 Sales to affiliates 0.9 7.1 (8.0 ) 0.0 Total revenues 1,964.5 439.3 (8.0 ) 2,395.8 Depreciation and amortization 268.4 59.9 0.0 328.3 Total interest charges 91.1 14.7 0.0 105.8 Provision for income taxes 129.8 22.4 0.0 152.2 Net income 250.8 34.9 0.0 285.7 Total assets 7,356.9 1,191.3 (465.6 ) (2) 8,082.6 Capital expenditures 594.3 132.5 0.0 726.8 2015 Revenues - external $ 2,017.7 $ 401.5 $ 0.0 $ 2,419.2 Sales to affiliates 0.6 6.0 (6.6 ) 0.0 Total revenues 2,018.3 407.5 (6.6 ) 2,419.2 Depreciation and amortization 256.7 56.8 0.0 313.5 Total interest charges 95.1 14.5 0.0 109.6 Provision for income taxes 143.6 21.9 0.0 165.5 Net income 241.0 35.3 0.0 276.3 Total assets (1) 7,003.8 1,136.1 (431.3 ) (2) 7,708.6 Capital expenditures 592.6 94.0 0.0 686.6 2014 Revenues - external $ 2,020.5 $ 398.5 $ 0.0 $ 2,419.0 Sales to affiliates 0.5 1.1 (1.6 ) 0.0 Total revenues 2,021.0 399.6 (1.6 ) 2,419.0 Depreciation and amortization 248.6 54.0 0.0 302.6 Total interest charges 92.8 13.8 0.0 106.6 Provision for income taxes 133.2 22.7 0.0 155.9 Net income 224.5 35.8 0.0 260.3 Total assets (1) 6,565.4 1,082.8 (373.9 ) (2) 7,274.3 Capital expenditures 582.1 88.9 0.0 671.0 (1) Certain prior year amounts have been reclassified to conform to current year presentation. These reclassifications relate to deferred tax assets (see note 2 below) and debt issuance costs required by newly issued accounting guidance (see Note 2 (2) 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, 2016
Other Comprehensive Income [Abstract]
Other Comprehensive Income	TEC reported the following OCI for the years ended December 31, 2016, 2015 and 2014, 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 2016 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.3 (0.5 ) 0.8 Gain on cash flow hedges 1.3 (0.5 ) 0.8 Total other comprehensive income $ 1.3 $ (0.5 ) $ 0.8 2015 Unrealized gain on cash flow hedges $ 4.3 $ (1.5 ) $ 2.8 Reclassification from AOCI to net income 1.4 (0.7 ) 0.7 Gain on cash flow hedges 5.7 (2.2 ) 3.5 Total other comprehensive income $ 5.7 $ (2.2 ) $ 3.5 2014 Unrealized gain on cash flow hedges $ 0.0 $ 0.0 $ 0.0 Reclassification from AOCI to net income 1.1 (0.4 ) 0.7 Gain on cash flow hedges 1.1 (0.4 ) 0.7 Total other comprehensive income $ 1.1 $ (0.4 ) $ 0.7
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss (millions) As of December 31, 2016 2015 Net unrealized losses from cash flow hedges (1) $ (2.8 ) $ (3.6 ) Total accumulated other comprehensive loss $ (2.8 ) $ (3.6 ) (1) Net of tax benefit of $1.8 million and $2.3 million as of December 31, 2016 and 2015, respectively.

Accounting for Derivative Ins40

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016, are expected to settle during the 2017 and 2018 fiscal years: Natural Gas Contracts (millions) (MMBTUs) Year Physical Financial 2017 0.0 26.0 2018 0.0 6.8 Total 0.0 32.8

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Recurring Fair Value Measurements	Recurring Derivative Fair Value Measures As of December 31, 2016 (millions) Level 1 Level 2 Level 3 Total Assets Natural gas swaps $ 0.0 $ 16.6 $ 0.0 $ 16.6 As of December 31, 2015 (millions) Level 1 Level 2 Level 3 Total Liabilities Natural gas swaps $ 0.0 $ 26.2 $ 0.0 $ 26.2

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	Reconciliation of beginning and ending carrying amount of asset retirement obligations: December 31, (millions) 2016 2015 Beginning balance $ 6.0 $ 5.3 Additional liabilities (1) 36.4 0.9 Revisions to estimated cash flows 2.6 (0.5 ) Other (2) (0.1 ) 0.3 Ending balance $ 44.9 $ 6.0 (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.

Significant Accounting Polici43

Significant Accounting Policies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)Segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of operating segments | Segment	2
Percentage of original cost of depreciable property	3.50%	3.70%	3.70%
Depreciation expense	$ 303.6	$ 306	$ 295.8
Allowance for funds used during construction rate	6.46%	6.46%	6.46%
Allowance for funds used during construction	$ 35.6	$ 25.5	$ 15.6
Unbilled revenues	53.6	53.7
Purchased power	104.1	78.9	71.4
Franchise fees and gross receipts taxes	$ 116.9	$ 116.9	$ 113.9
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	2.69%	2.92%
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	$ 16.1

Significant Accounting Polici44

Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Total cost	$ 9,137.9	$ 8,678.6
Less accumulated depreciation	(2,826.1)	(2,676.8)
Construction work in progress	891.5	771.1
Total property, plant and equipment, net	7,203.3	6,772.9
Electric Generation [Member]
Property Plant And Equipment [Line Items]
Total cost	4,101.8	4,046.5
Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	1,429.1	1,326.1
General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 438.8	373.5
Minimum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	15 years
Minimum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	16 years
Minimum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	3 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	$ 836.8	711.2
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	$ 2,331.4	$ 2,221.3
Electric Distribution [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	14 years
Electric Distribution [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	56 years

New Accounting Pronouncements -

New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost	$ 16.7	$ 18.1
Accounting Standard Update (ASU) 2015-03 [Member] | Long-term Debt, Less Amount Due Within One Year [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Debt issuance cost		$ 18.1

Regulatory - Additional Informa

Regulatory - Additional Information (Detail) - USD ($)	Jun. 28, 2016	May 31, 2009	Dec. 31, 2016	Dec. 31, 2013	Dec. 31, 2015
Public Utilities General Disclosures [Line Items]
Percentage of ROE			10.25%
Return on equity range			Range of plus or minus 1%
Potential increase in ROE			10.50%
Amortization period of Regulatory Asset			12 years
Allowed equity in the capital structure		54.70%		54.00%
Annual accrual storm damage reserve				$ 8,000,000
Storm damage reserve			$ 56,100,000		$ 56,100,000
Storm damage cost recovery period			12-month period or longer
Storm costs incurred			$ 8,600,000
Regulatory assets			420,700,000		$ 418,100,000
Minimum [Member]
Public Utilities General Disclosures [Line Items]
Return on equity		9.75%
Maximum [Member]
Public Utilities General Disclosures [Line Items]
Return on equity		11.75%
PGS [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE		10.75%
Reduction in annual depreciation expense			$ 16,100,000
Settlement agreement date			Apr. 18, 2016
PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Reduction in annual depreciation expense			$ 16,100,000
Decrease bottom return on equity	9.25%
Date new bottom of return on equity range will remain in effect			Dec. 31, 2020
Settlement agreement date			February 7, 2017
Regulatory assets			$ 32,000,000
Regulatory asset amortization beginning period			2,016
Regulatory asset amortization ending period			2,020
Amortization expenses			$ 16,000,000
PGS and OPC [Member] | Minimum [Member]
Public Utilities General Disclosures [Line Items]
Amortization period of Regulatory Asset			2 years
Litigation settlement, amount			$ 21,000,000
November 1, 2013 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge			57,500,000
November 1, 2014 [Member]
Public Utilities General Disclosures [Line Items]
Additional Revenue generated from increase in service charge			7,500,000
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 upper range limit			11.25%
ROE lower range limit			9.25%
Condition Two [Member]
Public Utilities General Disclosures [Line Items]
ROE upper range limit			11.50%
ROE lower range limit			9.50%
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, 2016	Dec. 31, 2015
Regulatory assets:
Regulatory assets	$ 420.7	$ 418.1
Less: Current portion	28.1	44.3
Long-term regulatory assets	392.6	373.8
Regulatory liabilities:
Regulatory liabilities	744.8	686.7
Less: Current portion	154.2	83.2
Long-term regulatory liabilities	590.6	603.5
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	85.6	74.6
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	8.4	5.2
Cost-Recovery Clauses - Offsets to Derivative Liabilities [Member]
Regulatory assets:
Regulatory assets	0	26.2
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	36.9	54
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	272	238.3
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	5.7	6.5
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.7	2.6
Other [Member]
Regulatory assets:
Regulatory assets	9.4	10.7
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	6.2	5.7
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	111.8	54.2
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	546.4	570
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 24.3	$ 0.7

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Provision for income taxes	$ 152,200,000	$ 165,500,000	$ 155,900,000
Federal statutory tax rate	35.00%	35.00%	35.00%
Deferred tax assets expiration date	2033 and 2036
General business credit	$ 10,000,000
Deferred tax general business credits expiration date	2028 and 2036
Uncertain tax positions	$ 6,800,000	$ 0	$ 0	$ 0
Pretax 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	$ 202,800,000
Florida [Member]
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward	$ 272,600,000

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current income taxes, Federal	$ 52.7	$ 38.2	$ 54.8
Current income taxes, State	11.8	8.4	8.9
Deferred income taxes, Federal	75.7	102.9	79
Deferred income taxes, State	11	14.5	13.5
Investment tax credits, net of amortization	1	1.5	(0.3)
Total income tax expense	$ 152.2	$ 165.5	$ 155.9

Income Taxes - Schedule of In50

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income before provision for income taxes	$ 437.9	$ 441.8	$ 416.2
Federal statutory income tax rates	35.00%	35.00%	35.00%
Income taxes, at statutory income tax rate	$ 153.3	$ 154.6	$ 145.7
State income tax, net of federal income tax	14.8	14.8	14.5
AFUDC-equity	(8.4)	(6)	(3.7)
Tax credits	(6.8)	0	0
Other	(0.7)	2.1	(0.6)
Total income tax expense	$ 152.2	$ 165.5	$ 155.9
Income tax expense as a percent of income from continuing operations, before income taxes	34.80%	37.50%	37.50%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Deferred tax liabilities
Property related	$ 1,549.1	$ 1,431.9
Pension and postretirement benefits	105	92
Pension	69.2	71.1
Total deferred tax liabilities	1,723.3	1,595
Deferred tax assets
Loss and credit carryforwards	91.3	80
Medical benefits	46.9	47.7
Insurance reserves	27.3	27.6
Pension and postretirement benefits	105	92
Capitalized energy conservation assistance costs	22.9	21.4
Other	23.3	17.5
Total deferred tax assets	316.7	286.2
Total deferred tax liability, net	$ 1,406.6	$ 1,308.8

Income Taxes - Schedule of De52

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Unrecognized tax benefits	$ 6.8	$ 0	$ 0	$ 0

Income Taxes - Schedule of Unre

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Beginning Balance	$ 0	$ 0	$ 0
Increases due to tax positions related to current year	6.8	0	0
Ending Balance	$ 6.8	$ 0	$ 0

Employee Postretirement Benef54

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended			21 Months Ended	24 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2014	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%
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	118.00%	118.00%	119.50%			118.00%
Employer contributions		$ 30.9	$ 43.9
Employer contributions in next fiscal year		$ 36.3
Description of defined contribution plan		Effective January 1, 2015, 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. During the period from April 2013 to December 2014, employer matching contributions were 67% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions with an additional incentive match of up to 40% of eligible participant contributions based on the achievement of certain operating company financial goals
Defined contribution plan cost recognized		$ 8.3	7.5	$ 10.2
Employer matching contribution percentage of eligible participant contribution					67.00%	70.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer					35.00%	30.00%
Pre Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution		60.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer		40.00%
Unqualified SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, assets	$ 40.8	$ 40.8	43.5			$ 40.8
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		13.3	13.5	14.8
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year		12.7
Increase in net periodic benefit cost	1
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		6.4	5.7	10.4
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year		1.8
Increase in net periodic benefit cost	0.4
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions		0	14.9
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation of defined benefit pension plans	723.9	$ 723.9	686.9			723.9
Percentage of defined benefit plan's assets increased		9.20%
Defined contribution plan, maximum employer match percentage		6.00%
TECO Energy [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	0.5	$ 0.5				0.5
TECO Energy [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	$ 29.5	29.5				$ 29.5
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		22.4	22.8	25.7
Curtailment loss		1.3	0	3.9
Employer contributions		37.4	55
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost		7	6.5	12.6
Curtailment loss		0	0	$ (0.2)
Employer contributions		(2.6)	$ (2.1)
Employer contributions in next fiscal year		9.5
TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit plans service benefit that will be amortized from regulatory assets in next fiscal year		$ 0

Employee Postretirement Benef55

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - TECO Energy [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	$ 732.9	$ 728.9
Service cost	18.8	20.9	$ 18.3
Interest cost	30.8	30.3	32
Plan participants’ contributions	0	0
Plan amendments	1.2	0
Plan curtailment	1.3	0
Plan settlement	(2.1)	0
Benefits paid	(69.5)	(53)
Actuarial loss (gain)	56.3	5.8
Net benefit obligation at end of year	769.7	732.9	728.9
Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	172.3	174.3
Service cost	1.8	1.9	2.4
Interest cost	7.4	7	10.4
Plan participants’ contributions	2.6	2.1
Plan amendments	0	0
Plan curtailment	0	0
Plan settlement	0	0
Benefits paid	(13.9)	(13.4)
Actuarial loss (gain)	5	0.4
Net benefit obligation at end of year	$ 175.2	$ 172.3	$ 174.3

Employee Postretirement Benef56

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Change in plan assets
Employer contributions	$ 30.9	$ 43.9
TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year	625.4
Fair value of plan assets at end of year	649.4	625.4
TECO Energy [Member] | Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	625.4	648
Actual return on plan assets	55.3	(25.5)
Employer contributions	37.4	55
Employer direct benefit payments	2.9	0.9
Plan participants’ contributions	0	0
Plan settlement	(2.1)	0
Benefits paid	(68.7)	(53)
Direct benefit payments	(0.8)	0
Fair value of plan assets at end of year	649.4	625.4
TECO Energy [Member] | Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	(2.6)	(2.1)
Employer direct benefit payments	13.9	13.4
Plan participants’ contributions	2.6	2.1
Plan settlement	0	0
Benefits paid	(13.9)	(13.4)
Direct benefit payments	0	0
Fair value of plan assets at end of year	$ 0	$ 0

Employee Postretirement Benef57

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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 Benef58

Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 649.4	$ 625.4
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	769.7	732.9	$ 728.9
Fair value of plan assets	649.4	625.4	648
Funded status at end of year	(120.3)	(107.5)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	175.2	172.3	174.3
Fair value of plan assets	0	0	$ 0
Other Postretirement Benefits [Member] | Florida [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	175.2	172.3
Fair value of plan assets	0	0
Funded status at end of year	$ (175.2)	$ (172.3)

Employee Postretirement Benef59

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	$ (0.7)	$ (0.6)
Deferred credits and other liabilities	(80)	(69.3)
Net amount recognized at end of year	(80.7)	(69.9)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	(9.5)	(9.2)
Deferred credits and other liabilities	(138.8)	(142.3)
Net amount recognized at end of year	$ (148.3)	$ (151.5)

Employee Postretirement Benef60

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 236.1	$ 208.2
Prior service cost (credit)	0.7	0
Amount recognized	236.8	208.2
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	50.5	47.2
Prior service cost (credit)	(15.1)	(17)
Amount recognized	$ 35.4	$ 30.2

Employee Postretirement Benef61

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)	2 Months Ended		6 Months Ended		8 Months Ended	12 Months Ended
	Dec. 31, 2014	Oct. 30, 2014	Dec. 31, 2016	Jun. 30, 2016	Sep. 01, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.11%			4.11%	4.688%
Rate of compensation increase-weighted average			2.57%			2.57%	3.87%
Discount rate	4.331%	4.277%			5.118%	4.688%	4.258%
Expected long-term return on plan assets	7.00%	7.00%			7.25%	7.00%	7.00%
Rate of compensation increase						2.59%	3.87%	3.73%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.28%			4.28%	4.667%
Rate of compensation increase-weighted average			2.48%			2.48%	2.50%
Healthcare cost trend rate
Immediate rate			6.83%			6.83%	7.05%
Ultimate rate			4.50%			4.50%	4.50%
Year rate reaches ultimate			2,038			2,038	2,038
Other Postretirement Benefits [Member] | Net Periodic Benefit Cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			3.85%	4.667%			4.206%	5.096%
Rate of compensation increase						2.50%	3.86%	3.71%
Healthcare cost trend rate
Immediate rate						7.05%	7.00%	7.25%
Ultimate rate						4.50%	4.50%	4.50%
Year rate reaches ultimate	2,025		2,038			2,038	2,025	2,025

Employee Postretirement Benef62

Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on net periodic benefit cost - Increase	$ 0.2
Effect on net periodic benefit cost - Decrease	(0.2)
Assumed One-percentage-point Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on PBO - Increase	4.9
Effect on PBO - Decrease	$ (4.2)

Employee Postretirement Benef63

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Amortization, settlement, or curtailment of:
Net periodic benefit cost	$ 13.3	$ 13.5	$ 14.8
Other Postretirement Benefits [Member]
Amortization, settlement, or curtailment of:
Net periodic benefit cost	6.4	5.7	10.4
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	18.8	20.9	18.3
Interest cost	30.8	30.3	32
Expected return on plan assets	(45.8)	(43.3)	(41.8)
Amortization, settlement, or curtailment of:
Actuarial loss	16.4	15.1	13.5
Prior service (benefit) cost	0.3	(0.2)	(0.4)
Curtailment loss (gain)	1.3	0	3.9
Special termination benefit	0	0	0.2
Settlement loss	0.6	0	0
Net periodic benefit cost	22.4	22.8	25.7
New prior service cost	1.3	0	0
Net loss (gain) arising during the year	46.8	74.5	44.1
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	(0.3)	0.2	0.4
Amortization or settlement of actuarial gain (loss)	(17.1)	(15.1)	(13.5)
Total recognized in OCI and regulatory assets	30.7	59.6	31
Total recognized in net periodic benefit cost, OCI and regulatory assets	53.1	82.4	56.7
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1.8	1.9	2.4
Interest cost	7.4	7	10.4
Expected return on plan assets	0	0	0
Amortization, settlement, or curtailment of:
Actuarial loss	0.2	0	0.2
Prior service (benefit) cost	(2.4)	(2.4)	(0.2)
Curtailment loss (gain)	0	0	(0.2)
Special termination benefit	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	7	6.5	12.6
New prior service cost	0	0	(23.2)
Net loss (gain) arising during the year	5	0.4	(10.1)
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	2.4	2.5	0.3
Amortization or settlement of actuarial gain (loss)	(0.2)	0	(0.2)
Total recognized in OCI and regulatory assets	7.2	2.9	(33.2)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$ 14.2	$ 9.4	$ (20.6)

Employee Postretirement benef64

Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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	56.00%	53.00%
Actual Asset Allocation [Member] | Fixed Income Securities [Member]
Asset Category
Actual Allocation, End of Year	44.00%	47.00%
Target Allocation [Member]
Asset Category
Target Allocation	100.00%
Target Allocation [Member] | Equity Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	52.00%
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	58.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	42.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	48.00%

Employee Postretirement Benef65

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 649.4	$ 625.4
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2.1	1.9
Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	11.6	12.4
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	90.9
Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3.4	4.8
Mortgage-Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8.4	8.7
Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	181.1	175.6
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2.6	5
Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32.2	56.2
Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	39.2	32.2
Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	296.5	382.5
Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.3	0.3
Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.3	1.5
Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	270.2	171.6
Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	82.7	71.3
Money markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.2
Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.7
ADRs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		5.7
Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	352.9	242.9
NAV [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
NAV [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	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] | Asset Backed Securities (ABS) [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	270.2	171.6
NAV [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	82.7	71.3
NAV [Member] | Money markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
NAV [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
NAV [Member] | ADRs [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
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	27.4	14.3
Accounts Receivable [Member] | NAV [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	211.7	278.4
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2.1	1.9
Level 1 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Level 1 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	11.6	12.4
Level 1 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44	90.9
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3.4	4.8
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	181.1	175.6
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	211.7	278.4
Level 1 [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
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] | Money markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 1 [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 1 [Member] | ADRs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		5.7
Level 1 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 1 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	27.4	14.3
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84.8	104.1
Level 2 [Member] | Cash [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] | 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	8.4	8.7
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	2.6	5
Level 2 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	32.2	56.2
Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	39.2	32.2
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84.8	104.1
Level 2 [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.3	0.3
Level 2 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.3	1.5
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] | Money markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.2
Level 2 [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0.7
Level 2 [Member] | ADRs [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	1
Level 2 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
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] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	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] | Asset Backed Securities (ABS) [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] | Money markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 3 [Member] | Discounted Notes [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 3 [Member] | ADRs [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
Level 3 [Member] | Accounts Receivable [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	(58.9)	(27.2)
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	(58.9)	(27.2)
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	1.7	1.1
Purchase Options (swaptions) [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Purchase Options (swaptions) [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Purchase Options (swaptions) [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1.7	1.1
Purchase Options (swaptions) [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Written Options (Swaptions) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(2)	(1)
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)	(1)
Written Options (Swaptions) [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		(0.9)
Long Futures [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Long Futures [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Long Futures [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		(0.9)
Long Futures [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Miscellaneous (open position) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.1	0.1
Miscellaneous (open position) [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous (open position) [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Miscellaneous (open position) [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0.1	0.1
Miscellaneous (open position) [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0

Employee Postretirement Benef66

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Parenthetical) (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 649.4	$ 625.4
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84.8	104.1
Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	270.2	171.6
Common and Collective Trusts [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	0
Previously Reported [Member] | Common and Collective Trusts [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 53.7

Employee Postretirement Benef67

Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions	Dec. 31, 2016USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2017	$ 78.3
Expected Benefit Payments - 2018	51.8
Expected Benefit Payments - 2019	55.6
Expected Benefit Payments - 2020	56.1
Expected Benefit Payments - 2021	58.7
Expected Benefit Payments - 2022 - 2026	312.4
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2017	11
Expected Benefit Payments - 2018	11.2
Expected Benefit Payments - 2019	11.5
Expected Benefit Payments - 2020	11.6
Expected Benefit Payments - 2021	11.7
Expected Benefit Payments - 2022 - 2026	$ 58.9

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities (Detail) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Mar. 24, 2015	Dec. 17, 2013
Line Of Credit Facility [Line Items]
Credit Facilities	$ 475,000,000	$ 475,000,000		$ 200,000,000
Borrowings Outstanding	170,000,000	61,000,000
Letters of Credit Outstanding	500,000	500,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000	325,000,000
Borrowings Outstanding	40,000,000	0
Letters of Credit Outstanding	500,000	500,000
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	130,000,000	61,000,000
Letters of Credit Outstanding	$ 0	$ 0

Short-Term Debt - Credit Faci69

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	Mar. 24, 2015	Dec. 31, 2016	Dec. 31, 2015
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Dec. 17, 2018	Dec. 17, 2018
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

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Dec. 31, 2016	Mar. 24, 2015	Dec. 17, 2013	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2014
Line Of Credit Facility [Line Items]
Weighted-average interest rate	1.49%			1.49%	0.89%
Line of credit facility maximum borrowing capacity	$ 475,000,000		$ 200,000,000	$ 475,000,000	$ 475,000,000
Interest rate description				TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%;
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			$ 325,000,000
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity	$ 150,000,000	$ 150,000,000		$ 150,000,000	$ 150,000,000
Credit facility amendment date		Mar. 24, 2015
Credit facility maturity date		Mar. 23, 2018		Mar. 23, 2018	Mar. 23, 2018
Loan agreement program and liquidity fees	0.65%
Basis spread on federal funds rate		0.50%
Interest rate description				Pursuant to the Loan Agreement, TEC will pay program and liquidity fees, which total 65 basis points as of December 31, 2016. 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, at TEC’s option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin
Before Amendment and Restatement | 3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Apr. 14, 2015
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			Oct. 25, 2016
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			Dec. 17, 2018

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	May 20, 2015	May 15, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Purchase in lieu of redemption			$ 83.3	$ 83.3	$ 83.3
Held Bonds [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption			232.6
4.35% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year		2,044
Aggregate principal amount issued		$ 300
Stated interest rate		4.35%
Debt instrument maturity date		Jan. 1, 2044
Redeemable principal amount percentage		100.00%
Basis spread on federal funds rate		0.15%
Redeemable principal amount percentage		100.00%
Debt instrument, start date of redemption		Nov. 15, 2043
Debt instrument, offering date		May 15, 2014
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
Purchase in lieu of redemption, due year			2,020
Term Rate Refunding Bonds Due 2025 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption			$ 51.6
Purchase in lieu of redemption, due year			2,025
Term Rate Refunding Bonds Due 2030 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption			$ 75
Purchase in lieu of redemption, due year			2,030
Term Rate Refunding Bonds Due 2034 [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption			$ 86
Purchase in lieu of redemption, due year			2,034

Merger with Emera Inc. - Additi

Merger with Emera Inc. - Additional Information (Detail) - Emera Inc. [Member] - USD ($) $ / shares in Units, $ in Billions	Jul. 02, 2016	Jul. 01, 2016
Business Acquisition [Line Items]
Amount of cash offered for each acquiree common stock share outstanding		$ 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) - USD ($) $ in Millions	Apr. 18, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long Term Commitments [Line Items]
Total rental expense and lease		$ 1.8	$ 3.8	$ 4.1
PGS [Member]
Long Term Commitments [Line Items]
Total potential penalties		$ 3.9
Settlement agreement date		Apr. 18, 2016
Civil penalty amount	$ 1
Customer refunds	$ 2
Ultimate financial liability to superfund sites and former MGP sites		$ 31.6
FPSC [Member]
Long Term Commitments [Line Items]
Settlement agreement date		May 5, 2016

Commitments and Contingencies74

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2017	$ 10.7
Future Minimum Purchased Power Payments Due, 2018	10.1
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, Thereafter	0
Total future minimum purchased power payments due	20.8
Future Minimum Operating Leases Payments Due, 2017	7
Future Minimum Operating Leases Payments Due, 2018	3.5
Future Minimum Operating Leases Payments Due, 2019	2.1
Future Minimum Operating Leases Payments Due, 2020	2.1
Future Minimum Operating Leases Payments Due, 2021	2.2
Future Minimum Operating Leases Payments Due, Thereafter	37.8
Total future minimum operating leases payments due	54.7
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2017	68.8
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	11.1
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2019	11.8
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2020	6.8
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2021	6.9
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	24.4
Total future minimum long-term service agreements/capital projects payments due	129.8
Future Minimum Clause Recoverable Commitments Payments Due, 2017	398.5
Future Minimum Clause Recoverable Commitments Payments Due, 2018	231
Future Minimum Clause Recoverable Commitments Payments Due, 2019	186.2
Future Minimum Clause Recoverable Commitments Payments Due, 2020	162.9
Future Minimum Clause Recoverable Commitments Payments Due, 2021	132.3
Future Minimum Clause Recoverable Commitments Payments Due, Thereafter	1,156.6
Total future minimum clause recoverable commitments payments due	2,267.5
Future Minimum Payments Due, 2017	485
Future Minimum Payments Due, 2018	255.7
Future Minimum Payments Due, 2019	200.1
Future Minimum Payments Due, 2020	171.8
Future Minimum Payments Due, 2021	141.4
Future Minimum Payments Due, Thereafter	1,218.8
Total future minimum payments	$ 2,472.8

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Natural gas sales	$ 0.1	$ 0.8	$ 0.3
Services received from affiliates	65.8	69.4	$ 22.5
Accounts receivable	6.9	2.3
Accounts payable	18	15.9
Taxes receivable	0	61.3
Taxes payable	$ 7.2	$ 1

Segment Information - Additiona

Segment Information - Additional Information (Detail)	Dec. 31, 2016Customer
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	736,000
PGS [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	374,000

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 2,395.8	$ 2,419.2	$ 2,419
Depreciation and amortization	328.3	313.5	302.6
Total interest charges	105.8	109.6	106.6
Provision for income taxes	152.2	165.5	155.9
Net income	285.7	276.3	260.3
Total assets	8,082.6	7,708.6	7,274.3
Capital expenditures	726.8	686.6	671
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,395.8	2,419.2	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	(8)	(6.6)	(1.6)
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	(465.6)	(431.3)	(373.9)
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	(8)	(6.6)	(1.6)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	1,964.5	2,018.3	2,021
Depreciation and amortization	268.4	256.7	248.6
Total interest charges	91.1	95.1	92.8
Provision for income taxes	129.8	143.6	133.2
Net income	250.8	241	224.5
Total assets	7,356.9	7,003.8	6,565.4
Capital expenditures	594.3	592.6	582.1
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	1,963.6	2,017.7	2,020.5
Tampa Electric [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.9	0.6	0.5
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	439.3	407.5	399.6
Depreciation and amortization	59.9	56.8	54
Total interest charges	14.7	14.5	13.8
Provision for income taxes	22.4	21.9	22.7
Net income	34.9	35.3	35.8
Total assets	1,191.3	1,136.1	1,082.8
Capital expenditures	132.5	94	88.9
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	432.2	401.5	398.5
PGS [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	$ 7.1	$ 6	$ 1.1

Other Comprehensive Income - Ac

Other Comprehensive Income - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Comprehensive Income Loss [Line Items]
Total other comprehensive income, Gross		$ 1.3	$ 5.7	$ 1.1
Total other comprehensive income, Tax		(0.5)	(2.2)	(0.4)
Total other comprehensive income, net of tax		0.8	3.5	0.7
Net unrealized losses from cash flow hedges	[1]	(2.8)	(3.6)
Total accumulated other comprehensive loss		(2.8)	(3.6)
Accumulated Gain on Cash Flow Hedges [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross		0	4.3	0
Reclassification from AOCI to net income, Gross		1.3	1.4	1.1
Total other comprehensive income, Gross		1.3	5.7	1.1
Unrealized gain on cash flow hedges, Tax		0	(1.5)	0
Reclassification from AOCI to net income, Tax		(0.5)	(0.7)	(0.4)
Total other comprehensive income, Tax		(0.5)	(2.2)	(0.4)
Unrealized gain on cash flow hedges, Net		0	2.8	0
Reclassification from AOCI to net income, Net		0.8	0.7	0.7
Total other comprehensive income, net of tax		$ 0.8	$ 3.5	$ 0.7
[1]	Net of tax benefit of $1.8 million and $2.3 million as of December 31, 2016 and 2015, respectively.

Other Comprehensive Income - 79

Other Comprehensive Income - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income [Abstract]
Net unrealized losses from cash flow hedges, tax benefit	$ 1.8	$ 2.3

Accounting for Derivative Ins80

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative assets	$ 16,600,000	$ 0
Derivative liabilities	0	26,200,000
Cash collateral posted with or received from any counterparties	0	$ 0
Net pretax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months	$ 15,100,000
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Nov. 30, 2018

Accounting for Derivative Ins81

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Dec. 31, 2016MMBTU
Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	32,800,000
Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contract Expected to be Settled in Year 2017 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	26,000,000
Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contract Expected to be Settled in Year 2018 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,800,000

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	$ 16.6	$ 0
Natural gas derivative liabilities	0	26.2
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 assets	16.6
Natural gas derivative liabilities		26.2
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 assets	0
Natural gas derivative liabilities		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 assets	16.6
Natural gas derivative liabilities		26.2
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas derivative assets	0	0
Natural gas derivative liabilities	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 assets	$ 0
Natural gas derivative liabilities		$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 16.6	$ 0
Derivative liabilities	0	26.2
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, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 104.1	$ 78.9	$ 71.4
Tampa Electric Company [Member] | Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 62	$ 33.6	$ 25.7
Minimum [Member] | Tampa Electric Company [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range | MW	117
Maximum [Member] | Tampa Electric Company [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, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 6	$ 5.3
Additional liabilities	36.4	0.9
Revisions to estimated cash flows	2.6	(0.5)
Other	(0.1)	0.3
Ending balance	$ 44.9	$ 6

Subsequent Event- Additional In

Subsequent Event- Additional Information (Detail) - PGS and OPC [Member]	Feb. 07, 2017	Jun. 28, 2016
Subsequent Event [Line Items]
Decrease bottom return on equity		9.25%
Subsequent Event [Member]
Subsequent Event [Line Items]
Decrease bottom return on equity	9.25%

Schedule II - Valuation and Q87

Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - Allowance for Uncollectible Accounts - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		$ 1.5	$ 1.4	$ 2
Charged to Income		2.7	2.7	2.7
Other Charges		0	0	0
Payments & Deductions	[1]	3	2.6	3.3
Balance at End of Period		$ 1.2	$ 1.5	$ 1.4
[1]	Write-off of individual bad debt accounts