Tampa Electric 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 07, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	ck0000096271
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	96,271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		10

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Property, plant and equipment
Utility plant, at original costs	$ 11,150	$ 10,427
Construction work in progress	528	263
Accumulated depreciation	(3,156)	(2,994)
Utility plant, net	7,994	7,433
Other property	12	11
Total property, plant and equipment, net	8,006	7,444
Current assets
Cash and cash equivalents	22	13
Receivables, less allowance for uncollectibles	304	257
Due from affiliates	3	5
Inventories, at average cost
Regulatory assets	46	77
Prepayments and other current assets	9	13
Total current assets	528	515
Deferred debits
Regulatory assets	340	356
Other	43	49
Total deferred debits	383	405
Total assets	8,917	8,364
Capitalization
Common stock	2,980	2,645
Accumulated other comprehensive loss	(1)	(2)
Retained earnings	357	335
Total capital	3,336	2,978
Long-term debt	2,505	1,860
Total capitalization	5,841	4,838
Current liabilities
Long-term debt due within one year	0	304
Notes payable	111	305
Accounts payable	222	233
Due to affiliates	15	21
Customer deposits	131	131
Regulatory liabilities	96	58
Accrued interest	37	14
Accrued taxes	70	12
Other	17	44
Total current liabilities	699	1,122
Long-term liabilities
Deferred income taxes	787	825
Regulatory liabilities	1,202	1,227
Deferred credits and other liabilities	388	352
Total long-term liabilities	2,377	2,404
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	8,917	8,364
Fuel [Member]
Inventories, at average cost
Utility inventories	44	60
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	100	90
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	8,925	8,555
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 1,697	$ 1,609

Consolidated Condensed Balanc_2

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Allowance for uncollectibles	$ 2	$ 1

Consolidated Condensed Statemen

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Electric	$ 593	$ 597	$ 1,563	$ 1,581
Gas	104	96	350	309
Total revenues	697	693	1,913	1,890
Expenses
Fuel	162	158	417	454
Purchased power	21	21	48	36
Operations and maintenance	153	127	472	386
Depreciation and amortization	97	89	279	262
Taxes, other than income	55	53	158	151
Total expenses	529	492	1,509	1,404
Income from operations	168	201	404	486
Other income
Allowance for equity funds used during construction	6	0	7	1
Other income, net	2	2	6	6
Total other income	8	2	13	7
Interest charges
Interest on long-term debt	26	27	80	83
Other interest	4	3	10	7
Allowance for borrowed funds used during construction	(3)	0	(4)	(1)
Total interest charges	27	30	86	89
Income before provision for income taxes	149	173	331	404
Provision for income taxes	31	67	65	156
Net income	118	106	266	248
Other comprehensive income, net of tax
Gain on cash flow hedges			1	1
Comprehensive income	118	106	267	249
Cost of Natural Gas Sold [Member]
Expenses
Cost of goods and services sold	$ 41	$ 44	$ 135	$ 115

Consolidated Condensed Statem_2

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities
Net income	$ 266	$ 248
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	279	262
Deferred income taxes and investment tax credits	5	151
Deferred recovery clauses	(28)	(73)
Receivables, less allowance for uncollectibles	(49)	(70)
Inventories	6	(8)
Taxes accrued	59	45
Interest accrued	23	25
Accounts payable	(41)	(20)
Regulatory assets and liabilities	80	(67)
Other	(13)	(31)
Cash flows from operating activities	587	462
Cash flows used in investing activities
Capital expenditures	(815)	(451)
Cash flows used in investing activities	(815)	(451)
Cash flows from financing activities
Equity contributions from Parent	335	98
Proceeds from long-term debt issuance	344	0
Repayment of long-term debt	(304)	0
Net increase in short-term debt	106	85
Dividends to Parent	(244)	(185)
Other financing activities	0	(1)
Cash flows from (used in) financing activities	237	(3)
Net increase in cash and cash equivalents	9	8
Cash and cash equivalents at beginning of period	13	10
Cash and cash equivalents at end of period	22	18
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	27	(25)
Reclassification of note payable from short-term to long-term	$ 300	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. Summary of Significant Accounting Policies See TEC’s Annual Report on Form 10-K for the year ended December 31, 2017 for a complete discussion of accounting policies. The significant accounting policies for TEC include: Principles of Consolidation and Basis of Presentation TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS. Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of September 30, 2018 and December 31, 2017, and the results of operations and cash flows for the periods ended September 30, 2018 and 2017. The results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2018. 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. The year-end consolidated condensed balance sheet was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. Revenue Recognition Regulated electric revenue Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWh delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather and line losses. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes. Other See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue. Receivables and Allowance for Uncollectible Accounts Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $302 million and $229 million as of September 30, 2018 and December 31, 2017, respectively. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. As of September 30, 2018 and December 31, 2017, unbilled revenues of $75 million and $66 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. Accounting for Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis 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 Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $33 million and $31 million for the three months ended September 30, 2018 and 2017, respectively, and $90 million and $86 million for the nine months ended September 30, 2018 and 2017, respectively.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
Accounting Changes And Error Corrections [Abstract]
New Accounting Pronouncements	2. New Accounting Pronouncements Change in Accounting Policy The new U.S. GAAP accounting policies that are applicable to and adopted by TEC in 2018 are described as follows: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Revenue from Contracts with Customers On January 1, 2018, TEC adopted ASU 2014-09, Revenue from Contracts with Customers TEC adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to TEC’s opening retained earnings as of the adoption date. The impact of the adoption of the new standard was immaterial to TEC’s net income and is expected to be immaterial on an ongoing basis. Recognition and Measurement of Financial Assets and Financial Liabilities On January 1, 2018, TEC adopted ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities December 15, 2017. Clarifying the Definition of a Business In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business Future Accounting Pronouncements TEC considers the applicability and impact of all ASUs issued by the FASB. The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in TEC’s Annual Report on Form 10-K for the year ended December 31, 2017, with updates noted below. Leases In February 2016, the FASB issued ASU 2016-02, Leases In January 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. TEC will make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. TEC will make this election. Additionally, TEC will elect the option that allows TEC to not reassess whether any expired or existing contracts contain leases and will carry forward existing lease classification. The standard will affect TEC’s financial position by increasing the assets and liabilities recorded relating to its operating leases. However, the ultimate impact of the new standard on TEC’s financial statements and disclosures has not yet been fully determined. In 2017, TEC developed and began execution of a project plan which included holding training sessions with key stakeholders throughout the organization and gathering detailed information on existing lease arrangements. Activities currently being executed include evaluating the remaining available implementation alternatives, calculating the lease asset and liability balances associated with individual contractual arrangements and assessing the disclosure requirements. TEC will implement additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. There will not be significant updates to systems as a result of implementation. TEC continues to monitor FASB amendments to ASC Topic 842 . Cloud Computing In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. .

Regulatory

Regulatory	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
Regulatory	3. Regulatory Tampa Electric Base Rates On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaced the 2013 base rate settlement agreement and extended it four years through December 31, 2021. The FPSC approved the agreement on November 6, 2017. The amended agreement provides for SoBRAs for TEC’s investments in solar generation. The solar investments are expected to go into service in tranches in the period from September 2018 through January 2021. In order for each tranche of SoBRAs to take effect, Tampa Electric must show that each tranche is cost-effective and each individual project has a cost cap of $1,500/kWac. Additionally, in order to receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects. The amended agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law. Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018 as the assets for the first tranche were placed in service requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018. Tampa Electric Storm Restoration Cost Recovery As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million, of which $90 million was charged to the storm reserve, $3 million was charged to O&M expense and $9 million was charged to capital expenditures. At December 31, 2017, the amount of estimated costs charged to the storm reserve regulatory liability exceeded the balance in the storm reserve by $47 million, which was recorded as a regulatory asset on the balance sheet as allowed by an FPSC order. This regulatory asset amount was eliminated in 2018 to reflect the effective recovery as discussed in Tampa Electric Tax Reform and Storm Settlement below. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated Hurricane Irma storm costs plus approximately $10 million in restoration costs from prior named storms and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below. Tampa Electric Tax Reform and Storm Settlement On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addresses both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) PGS Base Rates PGS’s base rates were established in May 2009. An updated settlement agreement was approved by the FPSC on February 7, 2017. As part of the 2017 settlement, PGS and OPC agreed that at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites would be amortized over the period 2016 through 2020, of which $21 million was amortized in 2016 and 2017. The 2017 PGS settlement agreement does not contain a provision for tax reform. The FPSC approved that tax reform benefits should be applied to customers beginning on February 6, 2018 for utilities in Florida without an existing tax reform settlement provision, including PGS. As a result, PGS deferred the estimated tax reform benefits to customers and recorded O&M expense and a regulatory tax liability of $5 million for the period February 6 to June 30, 2018. In the third quarter of 2018, the FPSC approved a settlement agreement filed between OPC, the Florida Industrial Power Users Group and PGS authorizing the utility to accelerate in 2018 the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS reversed in the third quarter of 2018 the $5 million estimated tax reform benefits deferral included in O&M expense and regulatory liability and will record amortization expense and a regulatory asset reduction of $11 million in 2018, of which $10 million was recorded during the nine months ended September 30, 2018. In January 2019, PGS will reduce its base rates by $12 million for the impact of tax reform and reduce depreciation rates by $10 million in accordance with the settlement agreement. Lastly, PGS is permitted to initiate a general base rate proceeding during 2020 provided rates established in such proceeding do not become effective before January 1, 2021. Regulatory Assets and Liabilities Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred or the advance recovery of expenditures for approved costs. Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) September 30, 2018 December 31, 2017 Regulatory assets: Regulatory tax asset (1) $ 45 $ 45 Cost-recovery clauses - deferred balances (2) 36 13 Environmental remediation (3) 23 33 Postretirement benefits (4) 259 272 Storm reserve (5) 0 47 Other 23 23 Total regulatory assets 386 433 Less: Current portion 46 77 Long-term regulatory assets $ 340 $ 356 Regulatory liabilities: Regulatory tax liability (6) $ 722 $ 730 Tax reform and storm agreement (7) 11 0 Cost-recovery clauses - deferred balances (2) 25 32 Accumulated reserve - cost of removal (8) 511 518 Storm reserve (9) 25 0 Other 4 5 Total regulatory liabilities 1,298 1,285 Less: Current portion 96 58 Long-term regulatory liabilities $ 1,202 $ 1,227 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liability, 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) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory asset was included in rate base and earned a rate of return as permitted by the FPSC. The asset was effectively recovered in 2018. (6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate recorded on December 31, 2017. The liability related to the revaluation of the deferred income tax balances will be amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and a settlement agreement for tax reform benefits approved by the FPSC. See Note 4 TEC Consolidated Condensed Financial Statements (7) This regulatory liability represents the offset to tax reform benefits due to Tampa Electric’s settlement agreement allowing the netting of the recovery of storm costs with tax reform benefits. See Tampa Electric Tax Reform and Storm Settlement discussion above for further information. (8) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (9) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory liability is being replenished to the FPSC-allowed storm reserve balance of $56 million.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	4. Income Taxes U.S. Tax Reform On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017 (the Act) was signed into legislation. The Act includes a broad range of tax reform changes affecting businesses, effective January 1, 2018 which provide a corporate federal tax rate reduction from 35% to 21%, 100% asset expensing, limitation of interest deduction, the repeal of section 199 domestic production deduction and the preservation of the existing normalization rules. The Act also provides that regulated electric and gas companies are exempt from the 100% asset expensing and interest expense deduction limitation. In accordance with U.S. GAAP, TEC was required to revalue its deferred income tax assets and liabilities based on the new 21% federal tax rate at the date of enactment. Additionally, under FPSC rules TEC was required to adjust deferred income tax assets and liabilities for changes in tax rates with a corresponding regulatory liability for the excess deferred taxes generated by the tax rate differential. See Note 3 TEC continues to monitor certain aspects of the Act, including the uncertainty of the application of 100% asset expensing rules after September 27, 2017, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by TEC during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act Income Tax Expense TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements with 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. TEC’s effective tax rates for the nine months ended September 30, 2018 and 2017 were 19.64% and 38.61%, respectively. The decrease in the effective tax rates in 2018 versus the same period in 2017 was primarily due to tax reform impacts. TEC’s effective tax rate for the nine months ended September 30, 2018 differed from the statutory rate principally due to the amortization of the regulatory tax liability resulting from tax reform. See Note 3 Unrecognized Tax Benefits As of September 30, 2018 and December 31, 2017, the amount of unrecognized tax benefits was $8 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC believes that the total unrecognized tax benefits will decrease and be recognized within the next twelve months due to the ongoing audit examination of TECO Energy’s consolidated federal income tax return for the short tax year ending June 30, 2016. TEC had $8 million of unrecognized tax benefits at September 30, 2018, that, if recognized, would reduce TEC’s effective tax rate.

Employee Postretirement Benefit

Employee Postretirement Benefits	9 Months Ended
	Sep. 30, 2018
Compensation And Retirement Disclosure [Abstract]
Employee Postretirement Benefits	5. Employee Postretirement Benefits TEC is a participant in the comprehensive retirement plans of TECO Energy. The following table presents detail related to TECO Energy’s periodic benefit cost for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP and Restoration Plan. TECO Energy Benefit Cost (millions) Pension Benefits Other Postretirement Benefits Three months ended September 30, 2018 2017 2018 2017 Components of net periodic benefit cost Service cost $ 5 $ 5 $ 0 $ 0 Interest cost 8 8 1 2 Expected return on assets (13 ) (12 ) 0 0 Amortization of: Actuarial (gain) loss 5 4 1 (1 ) Net periodic benefit cost $ 5 $ 5 $ 2 $ 1 Nine months ended September 30, Components of net periodic benefit cost Service cost $ 16 $ 15 $ 1 $ 1 Interest cost 22 24 5 6 Expected return on assets (37 ) (36 ) 0 0 Amortization of: Actuarial (gain) loss 14 12 0 (2 ) Settlement cost 2 (2) 7 (1) 0 0 Net periodic benefit cost $ 17 $ 22 $ 6 $ 5 (1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements. (2) Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the retirements of certain executives. TEC’s portion of the net periodic benefit cost for the three months ended September 30, 2018 and 2017, respectively, was $4 million and $3 million for pension benefits, and $2 million and $1 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the nine months ended September 30, 2018 and 2017, respectively, was $9 million and $10 million for pension benefits, and $6 million and $4 million for other postretirement benefits. TECO Energy assumed a long-term EROA of 6.85% and a discount rate of 3.63% for pension benefits under its qualified pension plan for 2018. For TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 3.70% for 2018. TECO Energy made contributions of $10 million and $46 million to its qualified pension plan in the nine months ended September 30, 2018 and 2017, respectively. TEC’s portion of these contributions was $8 million and $36 million, respectively. TECO Energy and TEC do not expect to make additional contributions to the pension plan for the remainder of 2018. Included in the benefit cost discussed above, for the three and nine months ended September 30, 2018, TEC reclassified $4 million and $14 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses from regulatory assets to the Consolidated Condensed Statement of Income, compared with $3 million and $8 million for the three and nine months ended September 30, 2017, respectively.

Short-Term Debt

Short-Term Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Short-Term Debt	6. Short-Term Debt Details of the credit facilities and related borrowings are presented in the following table: September 30, 2018 December 31, 2017 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325 $ 45 $ 1 $ 325 $ 5 $ 1 3-year accounts receivable facility (3) 150 66 0 150 0 0 1-year term facility (4) 0 0 0 300 300 0 Total $ 475 $ 111 $ 1 $ 775 $ 305 $ 1 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures March 22, 2022. (3) This 3-year facility matures March 22, 2021. (4) This 1-year facility of $300 million was outstanding on September 30, 2018 and was repaid on October 11, 2018 with the proceeds from the long-term debt issued on October 4, 2018. Therefore, this 1-year facility was classified as long-term debt on TEC’s balance sheet as of September 30, 2018. See Note 7 At September 30, 2018, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at September 30, 2018 and December 31, 2017 was 2.8% and 2.1%, respectively. Tampa Electric Company Accounts Receivable Facility On March 23, 2018, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a Second Amended Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). Throughout the term of the facility, TEC will pay program and liquidity fees, which total 70 basis points at September 30, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin. In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of September 30, 2018, TEC was in compliance with the requirements of the Loan Agreement.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At September 30, 2018, TEC’s long-term debt had a carrying amount of $2,505 million and an estimated fair market value of $2,601 million. At December 31, 2017, TEC’s total long-term debt had a carrying amount of $2,164 million and an estimated fair market value of $2,412 million. The fair value of debt securities determined using Level 1 measurements was zero at September 30, 2018 and $55 million at December 31, 2017. The fair value of the remaining debt securities is determined using Level 2 measurements Note 12 Tampa Electric Company 4.3% Notes due 2048 On June 7, 2018, TEC completed a sale of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048. Until December 15, 2047, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2047, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption. Tampa Electric Company 4.45% Notes due 2049 On October 4, 2018, TEC completed a sale of $375 million aggregate principal amount of 4.45% unsecured notes due June 15, 2049. Until December 15, 2048, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2048, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	8. Commitments and Contingencies Legal Contingencies From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of September 30, 2018, TEC has estimated its ultimate financial liability to be $28 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated 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 currently assessed 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, long-term leases (primarily for land, building space, vehicles, office equipment and heavy equipment), other purchase obligations, 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 September 30, 2018: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2018 $ 7 $ 1 $ 188 $ 105 $ 301 2019 0 2 226 229 457 2020 0 2 85 179 266 2021 0 2 32 144 178 2022 0 2 10 136 148 Thereafter 0 36 91 1,122 1,249 Total future minimum payments $ 7 $ 45 $ 632 $ 1,915 $ 2,599 Financial Covenants TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements and has certain restrictive covenants in specific agreements and debt instruments. At September 30, 2018, TEC was in compliance with all required financial covenants.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment Information	9. Segment Information (millions) Tampa Tampa Electric Three months ended September 30, Electric PGS Eliminations Company 2018 Revenues - external $ 593 $ 104 $ 0 $ 697 Intracompany sales 1 7 (8 ) 0 Total revenues 594 111 (8 ) 697 Total interest charges 23 4 0 27 Net income $ 109 $ 9 $ 0 $ 118 2017 Revenues - external $ 597 $ 96 $ 0 $ 693 Intracompany sales 1 14 (15 ) 0 Total revenues 598 110 (15 ) 693 Total interest charges 26 4 0 30 Net income $ 98 $ 8 $ 0 $ 106 Nine months ended September 30, 2018 Revenues - external $ 1,563 $ 350 $ 0 $ 1,913 Intracompany sales 2 18 (20 ) 0 Total revenues 1,565 368 (20 ) 1,913 Total interest charges 75 11 0 86 Net income $ 230 $ 36 $ 0 $ 266 2017 Revenues - external $ 1,581 $ 309 $ 0 $ 1,890 Intracompany sales 2 17 (19 ) 0 Total revenues 1,583 326 (19 ) 1,890 Total interest charges 78 11 0 89 Net income $ 217 $ 31 $ 0 $ 248 Total assets at September 30, 2018 $ 8,151 $ 1,348 $ (582 ) (1) $ 8,917 Total assets at December 31, 2017 $ 7,635 $ 1,284 $ (555 ) (1) $ 8,364 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

Revenue

Revenue	9 Months Ended
	Sep. 30, 2018
Revenues [Abstract]
Revenue	10. Revenue The following disaggregates TEC’s revenue by major source for the three and nine months ended September 30, 2018: (millions) Tampa Tampa Electric Three months ended September 30, 2018 Electric PGS Eliminations Company Electric revenue Residential $ 331 $ 0 $ 0 $ 331 Commercial 163 0 0 163 Industrial 43 0 0 43 Regulatory deferrals and unbilled revenue (10 ) 0 0 (10 ) Other (1) 67 0 (1 ) 66 Total electric revenue 594 0 (1 ) 593 Gas revenue Residential 0 29 0 29 Commercial 0 34 0 34 Industrial (2) 0 4 0 4 Other (3) 0 44 (7 ) 37 Total gas revenue 0 111 (7 ) 104 Total revenue $ 594 $ 111 $ (8 ) $ 697 Nine months ended September 30, 2018 Electric revenue Residential $ 802 $ 0 $ 0 $ 802 Commercial 435 0 0 435 Industrial 121 0 0 121 Regulatory deferrals and unbilled revenue 13 0 0 13 Other (1) 194 0 (2 ) 192 Total electric revenue 1,565 0 (2 ) 1,563 Gas revenue Residential 0 120 0 120 Commercial 0 115 0 115 Industrial (2) 0 15 0 15 Other (3) 0 118 (18 ) 100 Total gas revenue 0 368 (18 ) 350 Total revenue $ 1,565 $ 368 $ (20 ) $ 1,913 (1) Other includes sales to public authorities, off-system sales to other utilities and various other items. (2) Industrial includes sales to power generation customers. (3) Other includes off-system sales to other utilities and various other items. Remaining Performance Obligations Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of September 30, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $140 million. As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2033.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	11. Accounting for Derivative Instruments and Hedging Activities From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes: • To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and • To optimize the utilization of Tampa Electric’s physical natural gas storage capacity. TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers and to optimize the utilization of its physical natural gas storage capacity. 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 September 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement, which replaces the existing 2013 base rate settlement agreement and includes a provision for a five-year moratorium on hedging of natural gas purchases ending on December 31, 2022. The FPSC approved the agreement on November 6, 2017 (see Note 3 TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage capacity for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income (see Note 3 TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of September 30, 2018, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected. The derivatives at September 30, 2018 and December 31, 2017 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current assets and liabilities on a net basis as permitted by their respective master netting agreements. There were approximately zero derivative assets and liabilities as of September 30, 2018 and $1 million of derivative liabilities as of December 31, 2017. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts included in the Consolidated Condensed Balance Sheets. There was no collateral posted with or received from any counterparties at September 30, 2018 and December 31, 2017. The corresponding effect of these derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current regulatory assets and liabilities. Based on the fair value of the instruments at September 30, 2018, there are no net pre-tax reductions in fuel costs that are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months. TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation. It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of September 30, 2018, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated. TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination. TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	12. Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. The fair value of financial instruments is determined by using various market data and other valuation techniques. TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis are derivative assets and liabilities, which are classified as Level 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 11 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. As of September 30, 2018, 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 September 30, 2018 and December 31, 2017, 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 Note 7

Subsequent Event

Subsequent Event	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Event	13. Subsequent Event Tampa Electric Company 4.45% Notes due 2049 On October 4, 2018, TEC completed a sale of $375 million aggregate principal amount of 4.45% unsecured notes due June 15, 2049. See Note 7 for additional information

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Principles of Consolidation and Basis of Presentation	Principles of Consolidation and Basis of Presentation TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS. Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of September 30, 2018 and December 31, 2017, and the results of operations and cash flows for the periods ended September 30, 2018 and 2017. The results of operations for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2018. 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. The year-end consolidated condensed balance sheet was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.
Revenue Recognition	Revenue Recognition Regulated electric revenue Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWh delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather and line losses. Regulated gas revenue Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. TEC’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes. Other See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue.
Receivables and Allowance for Uncollectible Accounts	Receivables and Allowance for Uncollectible Accounts Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $302 million and $229 million as of September 30, 2018 and December 31, 2017, respectively. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. As of September 30, 2018 and December 31, 2017, unbilled revenues of $75 million and $66 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.
Accounting for Franchise Fees and Gross Receipts	Accounting for Franchise Fees and Gross Receipts Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis 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 Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $33 million and $31 million for the three months ended September 30, 2018 and 2017, respectively, and $90 million and $86 million for the nine months ended September 30, 2018 and 2017, respectively.

Regulatory (Tables)

Regulatory (Tables)	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Regulatory Liabilities	Details of the regulatory assets and liabilities are presented in the following table: Regulatory Assets and Liabilities (millions) September 30, 2018 December 31, 2017 Regulatory assets: Regulatory tax asset (1) $ 45 $ 45 Cost-recovery clauses - deferred balances (2) 36 13 Environmental remediation (3) 23 33 Postretirement benefits (4) 259 272 Storm reserve (5) 0 47 Other 23 23 Total regulatory assets 386 433 Less: Current portion 46 77 Long-term regulatory assets $ 340 $ 356 Regulatory liabilities: Regulatory tax liability (6) $ 722 $ 730 Tax reform and storm agreement (7) 11 0 Cost-recovery clauses - deferred balances (2) 25 32 Accumulated reserve - cost of removal (8) 511 518 Storm reserve (9) 25 0 Other 4 5 Total regulatory liabilities 1,298 1,285 Less: Current portion 96 58 Long-term regulatory liabilities $ 1,202 $ 1,227 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liability, 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) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory asset was included in rate base and earned a rate of return as permitted by the FPSC. The asset was effectively recovered in 2018. (6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances at the lower income tax rate recorded on December 31, 2017. The liability related to the revaluation of the deferred income tax balances will be amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and a settlement agreement for tax reform benefits approved by the FPSC. See Note 4 TEC Consolidated Condensed Financial Statements (7) This regulatory liability represents the offset to tax reform benefits due to Tampa Electric’s settlement agreement allowing the netting of the recovery of storm costs with tax reform benefits. See Tampa Electric Tax Reform and Storm Settlement discussion above for further information. (8) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (9) See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory liability is being replenished to the FPSC-allowed storm reserve balance of $56 million.

Employee Postretirement Benef_2

Employee Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2018
Compensation And Retirement Disclosure [Abstract]
Schedule of Net Periodic Benefit Cost	The following table presents detail related to TECO Energy’s periodic benefit cost for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP and Restoration Plan. TECO Energy Benefit Cost (millions) Pension Benefits Other Postretirement Benefits Three months ended September 30, 2018 2017 2018 2017 Components of net periodic benefit cost Service cost $ 5 $ 5 $ 0 $ 0 Interest cost 8 8 1 2 Expected return on assets (13 ) (12 ) 0 0 Amortization of: Actuarial (gain) loss 5 4 1 (1 ) Net periodic benefit cost $ 5 $ 5 $ 2 $ 1 Nine months ended September 30, Components of net periodic benefit cost Service cost $ 16 $ 15 $ 1 $ 1 Interest cost 22 24 5 6 Expected return on assets (37 ) (36 ) 0 0 Amortization of: Actuarial (gain) loss 14 12 0 (2 ) Settlement cost 2 (2) 7 (1) 0 0 Net periodic benefit cost $ 17 $ 22 $ 6 $ 5 (1) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements. (2) Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the retirements of certain executives.

Short-Term Debt (Tables)

Short-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Short-Term Debt Credit Facilities and Related Borrowings	Details of the credit facilities and related borrowings are presented in the following table: September 30, 2018 December 31, 2017 Letters Letters Credit Borrowings of Credit Credit Borrowings of Credit (millions) Facilities Outstanding (1) Outstanding Facilities Outstanding (1) Outstanding Tampa Electric Company: 5-year facility (2) $ 325 $ 45 $ 1 $ 325 $ 5 $ 1 3-year accounts receivable facility (3) 150 66 0 150 0 0 1-year term facility (4) 0 0 0 300 300 0 Total $ 475 $ 111 $ 1 $ 775 $ 305 $ 1 (1) Borrowings outstanding are reported as notes payable. (2) This 5-year facility matures March 22, 2022. (3) This 3-year facility matures March 22, 2021. (4) This 1-year facility of $300 million was outstanding on September 30, 2018 and was repaid on October 11, 2018 with the proceeds from the long-term debt issued on October 4, 2018. Therefore, this 1-year facility was classified as long-term debt on TEC’s balance sheet as of September 30, 2018. See Note 7

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2018 $ 7 $ 1 $ 188 $ 105 $ 301 2019 0 2 226 229 457 2020 0 2 85 179 266 2021 0 2 32 144 178 2022 0 2 10 136 148 Thereafter 0 36 91 1,122 1,249 Total future minimum payments $ 7 $ 45 $ 632 $ 1,915 $ 2,599

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Schedule of Segment Information	(millions) Tampa Tampa Electric Three months ended September 30, Electric PGS Eliminations Company 2018 Revenues - external $ 593 $ 104 $ 0 $ 697 Intracompany sales 1 7 (8 ) 0 Total revenues 594 111 (8 ) 697 Total interest charges 23 4 0 27 Net income $ 109 $ 9 $ 0 $ 118 2017 Revenues - external $ 597 $ 96 $ 0 $ 693 Intracompany sales 1 14 (15 ) 0 Total revenues 598 110 (15 ) 693 Total interest charges 26 4 0 30 Net income $ 98 $ 8 $ 0 $ 106 Nine months ended September 30, 2018 Revenues - external $ 1,563 $ 350 $ 0 $ 1,913 Intracompany sales 2 18 (20 ) 0 Total revenues 1,565 368 (20 ) 1,913 Total interest charges 75 11 0 86 Net income $ 230 $ 36 $ 0 $ 266 2017 Revenues - external $ 1,581 $ 309 $ 0 $ 1,890 Intracompany sales 2 17 (19 ) 0 Total revenues 1,583 326 (19 ) 1,890 Total interest charges 78 11 0 89 Net income $ 217 $ 31 $ 0 $ 248 Total assets at September 30, 2018 $ 8,151 $ 1,348 $ (582 ) (1) $ 8,917 Total assets at December 31, 2017 $ 7,635 $ 1,284 $ (555 ) (1) $ 8,364 (1) Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

Revenue (Tables)

Revenue (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue Recognition [Abstract]
Summary of Disaggregates TEC Revenue by Major Source	The following disaggregates TEC’s revenue by major source for the three and nine months ended September 30, 2018: (millions) Tampa Tampa Electric Three months ended September 30, 2018 Electric PGS Eliminations Company Electric revenue Residential $ 331 $ 0 $ 0 $ 331 Commercial 163 0 0 163 Industrial 43 0 0 43 Regulatory deferrals and unbilled revenue (10 ) 0 0 (10 ) Other (1) 67 0 (1 ) 66 Total electric revenue 594 0 (1 ) 593 Gas revenue Residential 0 29 0 29 Commercial 0 34 0 34 Industrial (2) 0 4 0 4 Other (3) 0 44 (7 ) 37 Total gas revenue 0 111 (7 ) 104 Total revenue $ 594 $ 111 $ (8 ) $ 697 Nine months ended September 30, 2018 Electric revenue Residential $ 802 $ 0 $ 0 $ 802 Commercial 435 0 0 435 Industrial 121 0 0 121 Regulatory deferrals and unbilled revenue 13 0 0 13 Other (1) 194 0 (2 ) 192 Total electric revenue 1,565 0 (2 ) 1,563 Gas revenue Residential 0 120 0 120 Commercial 0 115 0 115 Industrial (2) 0 15 0 15 Other (3) 0 118 (18 ) 100 Total gas revenue 0 368 (18 ) 350 Total revenue $ 1,565 $ 368 $ (20 ) $ 1,913 (1) Other includes sales to public authorities, off-system sales to other utilities and various other items. (2) Industrial includes sales to power generation customers. (3) Other includes off-system sales to other utilities and various other items.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Accounting Policies [Abstract]
Receivables from contracts with customers	$ 302		$ 302		$ 229
Unbilled revenues	75		75		$ 66
Franchise fees and gross receipts taxes	$ 33	$ 31	$ 90	$ 86

Regulatory - Additional Informa

Regulatory - Additional Information (Detail) $ in Millions

Aug. 20, 2018USD ($)

Jun. 29, 2018USD ($)MW

Dec. 28, 2017USD ($)

Dec. 12, 2017USD ($)MW

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

Feb. 07, 2017

Sep. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Sep. 30, 2017USD ($)

Sep. 30, 2018USD ($)

Sep. 30, 2018USD ($)

Sep. 30, 2017USD ($)

Dec. 31, 2019USD ($)

Jun. 30, 2018USD ($)

Dec. 31, 2017USD ($)

Oct. 31, 2013USD ($)

Public Utilities General Disclosures [Line Items]

Storm restoration costs

$ 10

Regulatory assets

$ 386

$ 386

$ 386

$ 433

Reduction in O&M expense for amortization

12

Annually approved lowering base rates, Amount

$ 103

Regulatory liabilities

1,298

1,298

1,298

1,285

Reduction in regulatory asset for amortization

$ (80)

$ 67

PGS [Member]

Public Utilities General Disclosures [Line Items]

Settlement agreement, approval date

Feb. 7, 2017

Regulatory liabilities

$ 5

Tax reform benefits

5

Reduction in regulatory asset for amortization

(11)

$ (10)

PGS [Member] | Scenario Forecast [Member]

Public Utilities General Disclosures [Line Items]

Reduction in annual depreciation rates

$ 10

Reduction in annual base rates

$ 12

PGS and OPC [Member]

Public Utilities General Disclosures [Line Items]

Regulatory assets

32

32

32

Amortization expenses

$ 21

Regulatory asset amortization beginning period

2,016

Regulatory asset amortization ending period

2,020

Tax Reform and Storm Settlement [Member]

Public Utilities General Disclosures [Line Items]

O&M expense and regulatory liability

$ 19

25

Hurricane Irma [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

$ 102

Hurricane Irma [Member] | Storm Reserve [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

90

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

Public Utilities General Disclosures [Line Items]

Storm restoration costs

3

Hurricane Irma [Member] | Capital Expenditures [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

$ 9

Solar Project Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

Settlement agreement, extended terms

four years through December 31, 2021

Settlement agreement, approval date

Nov. 6, 2017

Cost cap of project | $ / kWac

1,500

Solar generation capacity investments

$ 850

Impact of tax reform through reduction in base revenue days

120 days

Solar Project Cost Recovery [Member] | Last Tranche [Member]

Public Utilities General Disclosures [Line Items]

Solar energy capacity | MW

50

Solar Project Cost Recovery [Member] | First Two Tranches [Member]

Public Utilities General Disclosures [Line Items]

Solar energy capacity | MW

400

Maximum cost to be constructed to build last tranche | $ / kWac

1,475

Solar Project Cost Recovery [Member] | Effective September 1, 2018 [Member]

Public Utilities General Disclosures [Line Items]

Solar energy capacity | MW

145

Estimated annual revenue requirements

$ 24

Solar Project Cost Recovery [Member] | Effective January 1, 2019 [Member]

Public Utilities General Disclosures [Line Items]

Solar energy capacity | MW

260

Estimated annual revenue requirements

$ 46

Storm Restoration Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

Minimum cost recovery period

12 months

Replenishment reserve for recovery of cost

$ 56

Storm Reserve [Member]

Public Utilities General Disclosures [Line Items]

Regulatory assets

0

0

$ 0

$ 47

Regulatory liabilities

$ 56

56

$ 56

Tax Reform and Storm Settlement [Member]

Public Utilities General Disclosures [Line Items]

O&M expense and regulatory asset

$ 47

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory assets:
Regulatory assets	$ 386	$ 433
Less: Current portion	46	77
Long-term regulatory assets	340	356
Regulatory liabilities:
Regulatory liabilities	1,298	1,285
Less: Current portion	96	58
Long-term regulatory liabilities	1,202	1,227
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	45	45
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	36	13
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	23	33
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	259	272
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	0	47
Regulatory liabilities:
Regulatory liabilities	56
Other [Member]
Regulatory assets:
Regulatory assets	23	23
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	722	730
Tax Reform and Storm Agreement [Member]
Regulatory liabilities:
Regulatory liabilities	11	0
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory liabilities:
Regulatory liabilities	25	32
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	25	0
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	511	518
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 4	$ 5

Regulatory - Schedule of Regu_2

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 1,298	$ 1,285
Storm Reserve [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 56

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	Sep. 27, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Taxes [Line Items]
Federal statutory tax rate		21.00%		35.00%
Asset expensing	100.00%	100.00%
Unrecognized tax benefits		$ 8		$ 8
Unrecognized tax benefit that would reduce effective tax rate		$ 8
Tampa Electric [Member]
Income Taxes [Line Items]
Effective tax rate		19.64%	38.61%

Employee Postretirement Benef_3

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 4	$ 3	$ 9		$ 10
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	2	1	6		4
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	5	5	16		15
Interest cost	8	8	22		24
Expected return on assets	(13)	(12)	(37)		(36)
Amortization of:
Actuarial (gain) loss	5	4	14		12
Settlement cost			2	[1]	7	[2]
Net periodic benefit cost	5	5	17		22
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	1		1
Interest cost	1	2	5		6
Expected return on assets	0	0	0		0
Amortization of:
Actuarial (gain) loss	1	(1)	0		(2)
Settlement cost			0		0
Net periodic benefit cost	$ 2	$ 1	$ 6		$ 5
[1]	Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the retirements of certain executives.
[2]	Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

Employee Postretirement Benef_4

Employee Postretirement Benefits - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Reclassification of regulatory assets to net income as part of periodic benefit cost	$ 4,000,000	$ 3,000,000	$ 14,000,000	$ 8,000,000
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA			6.85%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	4,000,000	3,000,000	$ 9,000,000	10,000,000
Employer contributions			8,000,000	36,000,000
Expected future employer contributions for remainder of 2018	0		0
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	5,000,000	5,000,000	$ 17,000,000	22,000,000
Discount rate			3.63%
Employer contributions			$ 10,000,000	46,000,000
Expected future employer contributions for remainder of 2018	0		0
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	2,000,000	1,000,000	6,000,000	4,000,000
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 2,000,000	$ 1,000,000	$ 6,000,000	$ 5,000,000
Discount rate			3.70%

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities and Related Borrowings (Detail) - USD ($)	Sep. 30, 2018	Mar. 23, 2018	Dec. 31, 2017
Line Of Credit Facility [Line Items]
Credit Facilities	$ 475,000,000		$ 775,000,000
Borrowings Outstanding	111,000,000		305,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	325,000,000		325,000,000
Borrowings Outstanding	45,000,000		5,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000	$ 150,000,000	150,000,000
Borrowings Outstanding	66,000,000		0
Letters of Credit Outstanding	0		0
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	0		300,000,000
Borrowings Outstanding	0		300,000,000
Letters of Credit Outstanding	$ 0		$ 0

Short-Term Debt - Credit Faci_2

Short-Term Debt - Credit Facilities and Related Borrowings (Parenthetical) (Detail) - USD ($) $ in Millions	Mar. 23, 2018	Sep. 30, 2018	Dec. 31, 2017
Line Of Credit Facility [Line Items]
Long-term debt due within one year		$ 0	$ 304
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Mar. 22, 2022	Mar. 22, 2022
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2021	Mar. 22, 2021	Mar. 22, 2021
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Oct. 11, 2018	Oct. 11, 2018
Long-term debt due within one year		$ 300	$ 300

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Mar. 23, 2018	Sep. 30, 2018	Dec. 31, 2017
Line Of Credit Facility [Line Items]
Weighted-average interest rate		2.80%	2.10%
Line of credit facility maximum borrowing capacity		$ 475,000,000	$ 775,000,000
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity	$ 150,000,000	$ 150,000,000	$ 150,000,000
Credit facility amendment date	Mar. 23, 2018
Credit facility maturity date	Mar. 22, 2021	Mar. 22, 2021	Mar. 22, 2021
Loan agreement program and liquidity fees		0.70%
Interest rate description		Throughout the term of the facility, TEC will pay program and liquidity fees, which total 70 basis points at September 30, 2018. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin.
Minimum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.125%
Maximum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage		0.35%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Oct. 04, 2018	Jun. 07, 2018	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt			$ 2,505	$ 2,164
Estimated fair value			2,601	2,412
4.3% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year		2,048
4.3% Notes [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		$ 350
Stated interest rate		4.30%
Debt instrument maturity date		Jun. 15, 2048
Redeemable principal amount percentage		100.00%
Basis spread on federal funds rate		0.20%
Redeemable principal amount percentage		100.00%
Debt instrument, start date of redemption		Dec. 15, 2047
Debt instrument, offering date		Jun. 7, 2018
4.45% Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2,049
4.45% Notes [Member] | Unsecured Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 375
Stated interest rate	4.45%
Debt instrument maturity date	Jun. 15, 2049
Redeemable principal amount percentage	100.00%
Basis spread on federal funds rate	0.20%
Redeemable principal amount percentage	100.00%
Debt instrument, start date of redemption	Dec. 15, 2048
Debt instrument, offering date	Oct. 4, 2018
Level 1 [Member]
Debt Instrument [Line Items]
Fair value of debt securities			$ 0	$ 55

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Sep. 30, 2018USD ($)
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 28

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Sep. 30, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2018	$ 7
Future Minimum Purchased Power Payments Due, 2019	0
Future Minimum Purchased Power Payments Due, 2020	0
Future Minimum Purchased Power Payments Due, 2021	0
Future Minimum Purchased Power Payments Due, 2022	0
Future Minimum Purchased Power Payments Due, Thereafter	0
Total future minimum purchased power payments due	7
Future Minimum Operating Leases Payments Due, 2018	1
Future Minimum Operating Leases Payments Due, 2019	2
Future Minimum Operating Leases Payments Due, 2020	2
Future Minimum Operating Leases Payments Due, 2021	2
Future Minimum Operating Leases Payments Due, 2022	2
Future Minimum Operating Leases Payments Due, Thereafter	36
Total future minimum operating leases payments due	45
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	188
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2019	226
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2020	85
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2021	32
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2022	10
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	91
Total future minimum long-term service agreements/capital projects payments due	632
Future Minimum Clause Recoverable Commitments Payments Due, 2018	105
Future Minimum Clause Recoverable Commitments Payments Due, 2019	229
Future Minimum Clause Recoverable Commitments Payments Due, 2020	179
Future Minimum Clause Recoverable Commitments Payments Due, 2021	144
Future Minimum Clause Recoverable Commitments Payments Due, 2022	136
Future Minimum Clause Recoverable Commitments Payments Due, Thereafter	1,122
Total future minimum clause recoverable commitments payments due	1,915
Future Minimum Payments Due, 2018	301
Future Minimum Payments Due, 2019	457
Future Minimum Payments Due, 2020	266
Future Minimum Payments Due, 2021	178
Future Minimum Payments Due, 2022	148
Future Minimum Payments Due, Thereafter	1,249
Total future minimum payments	$ 2,599

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Total revenues	$ 697	$ 693	$ 1,913	$ 1,890
Total interest charges	27	30	86	89
Net income	118	106	266	248
Total assets	8,917		8,917		$ 8,364
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	697	693	1,913	1,890
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(8)	(15)	(20)	(19)
Total interest charges	0	0	0	0
Net income	0	0	0	0
Total assets	(582)		(582)		(555)
Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Eliminations [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	(8)	(15)	(20)	(19)
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Total revenues	594		1,565
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	594	598	1,565	1,583
Total interest charges	23	26	75	78
Net income	109	98	230	217
Total assets	8,151		8,151		7,635
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	593	597	1,563	1,581
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	1	1	2	2
PGS [Member]
Segment Reporting Information [Line Items]
Total revenues	111		368
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	111	110	368	326
Total interest charges	4	4	11	11
Net income	9	8	36	31
Total assets	1,348		1,348		$ 1,284
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	104	96	350	309
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 7	$ 14	$ 18	$ 17

Revenue - Summary of Disaggrega

Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 593	$ 597	$ 1,563	$ 1,581
Total gas revenue	104	96	350	309
Total revenues	697	$ 693	1,913	$ 1,890
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	331		802
Total gas revenue	29		120
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	163		435
Total gas revenue	34		115
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	43		121
Total gas revenue	4		15
Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(10)		13
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	66		192
Total gas revenue	37		100
Tampa Electric [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	594		1,565
Total gas revenue	0		0
Total revenues	594		1,565
Tampa Electric [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	331		802
Total gas revenue	0		0
Tampa Electric [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	163		435
Total gas revenue	0		0
Tampa Electric [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	43		121
Total gas revenue	0		0
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(10)		13
Tampa Electric [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	67		194
Total gas revenue	0		0
PGS [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	111		368
Total revenues	111		368
PGS [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	29		120
PGS [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	34		115
PGS [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	4		15
PGS [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
PGS [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	44		118
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)		(2)
Total gas revenue	(7)		(18)
Total revenues	(8)		(20)
Eliminations [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	0		0
Eliminations [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	0		0
Eliminations [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	0		0
Eliminations [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Eliminations [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)		(2)
Total gas revenue	$ (7)		$ (18)

Revenue - Additional Informatio

Revenue - Additional Information (Details) $ in Millions	Sep. 30, 2018USD ($)
Regulated Operating Revenue [Abstract]
Remaining performance obligations, transaction price	$ 140
Remaining performance obligations, expected year of revenue recognition	2,033

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail)	1 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2018USD ($)MMBTU	Dec. 31, 2017USD ($)
Derivative [Line Items]
Derivative assets		$ 0
Derivative liabilities		0	$ 1,000,000
Cash collateral posted with or received from any counterparties		0	$ 0
Net pre-tax gain (loss) expected to be reclassified from regulatory assets or liabilities, next 12 months		$ 0
Natural Gas [Member]
Derivative [Line Items]
Financial hedging moratorium period	5 years
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow		Nov. 30, 2018
Natural Gas Contracts [Member] | Financial [Member]
Derivative [Line Items]
Derivative volume | MMBTU		1

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 0
Derivative liabilities	0	$ 1,000,000
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	$ 0

Subsequent Event - Additional I

Subsequent Event - Additional Information (Detail) - Subsequent Event [Member] - 4.45% Notes [Member] $ in Millions	Oct. 04, 2018USD ($)
Subsequent Event [Line Items]
Debt instrument, maturity year	2,049
Unsecured Notes [Member]
Subsequent Event [Line Items]
Aggregate principal amount issued	$ 375
Stated interest rate	4.45%
Debt instrument maturity date	Jun. 15, 2049
Debt instrument, offering date	Oct. 4, 2018