Tampa Electric 10-Q 10 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 07, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
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 Common Stock, Shares Outstanding		10

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Property, plant and equipment
Utility plant, at original costs	$ 10,878	$ 10,427
Construction work in progress	524	263
Accumulated depreciation	(3,108)	(2,994)
Utility plant, net	7,770	7,433
Other property	12	11
Total property, plant and equipment, net	7,782	7,444
Current assets
Cash and cash equivalents	15	13
Receivables, less allowance for uncollectibles of $1 at June 30, 2018 and December 31, 2017	251	257
Due from affiliates	17	5
Inventories, at average cost
Regulatory assets	45	77
Prepayments and other current assets	15	13
Total current assets	488	515
Deferred debits
Regulatory assets	347	356
Other	47	49
Total deferred debits	394	405
Total assets	8,664	8,364
Capitalization
Common stock	2,860	2,645
Accumulated other comprehensive loss	(1)	(2)
Retained earnings	323	335
Total capital	3,182	2,978
Long-term debt	2,205	1,860
Total capitalization	5,387	4,838
Current liabilities
Long-term debt due within one year	0	304
Notes payable	375	305
Accounts payable	218	233
Due to affiliates	15	21
Customer deposits	131	131
Regulatory liabilities	61	58
Accrued interest	14	14
Accrued taxes	50	12
Other	17	44
Total current liabilities	881	1,122
Long-term liabilities
Deferred income taxes	855	825
Regulatory liabilities	1,205	1,227
Deferred credits and other liabilities	336	352
Total long-term liabilities	2,396	2,404
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	8,664	8,364
Fuel [Member]
Inventories, at average cost
Utility inventories	48	60
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	97	90
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	8,682	8,555
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 1,672	$ 1,609

Consolidated Condensed Balance3

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

Consolidated Condensed Statemen

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues
Electric	$ 509	$ 542	$ 970	$ 984
Gas	110	102	246	213
Total revenues	619	644	1,216	1,197
Expenses
Fuel	133	165	255	296
Purchased power	14	8	27	15
Operations and maintenance	162	131	319	259
Depreciation and amortization	89	88	182	173
Taxes, other than income	51	49	103	98
Total expenses	488	476	980	912
Income from operations	131	168	236	285
Other income
Allowance for equity funds used during construction	1	0	1	1
Other income, net	2	2	4	4
Total other income	3	2	5	5
Interest charges
Interest on long-term debt	27	28	54	56
Other interest	3	2	6	4
Allowance for borrowed funds used during construction	(1)	0	(1)	(1)
Total interest charges	29	30	59	59
Income before provision for income taxes	105	140	182	231
Provision for income taxes	20	54	34	89
Net income	85	86	148	142
Other comprehensive income, net of tax
Gain on cash flow hedges	1	0	1	1
Total other comprehensive income, net of tax	1	0	1	1
Comprehensive income	86	86	149	143
Cost of Natural Gas Sold [Member]
Expenses
Cost of goods and services sold	$ 39	$ 35	$ 94	$ 71

Consolidated Condensed Stateme5

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities
Net income	$ 148	$ 142
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	182	173
Deferred income taxes and investment tax credits	14	87
Deferred recovery clauses	(25)	(52)
Receivables, less allowance for uncollectibles	2	(23)
Inventories	5	(16)
Taxes accrued	28	27
Accounts payable	(37)	(88)
Regulatory assets and liabilities	54	(6)
Other	(25)	(16)
Cash flows from operating activities	346	228
Cash flows used in investing activities
Capital expenditures	(510)	(299)
Cash flows used in investing activities	(510)	(299)
Cash flows from financing activities
Equity contributions from TECO Energy	215	58
Proceeds from long-term debt issuance	345	0
Repayment of long-term debt	(304)	0
Net increase in short-term debt	70	128
Dividends to TECO Energy	(160)	(109)
Other financing activities	0	(1)
Cash flows from financing activities	166	76
Net increase in cash and cash equivalents	2	5
Cash and cash equivalents at beginning of period	13	10
Cash and cash equivalents at end of period	15	15
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ 18	$ (24)

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 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 June 30, 2018 and December 31, 2017, and the results of operations and cash flows for the periods ended June 30, 2018 and 2017. The results of operations for the three and six months ended June 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, line losses and inter-period changes to customer classes. 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 $249 million and $229 million as of June 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 June 30, 2018 and December 31, 2017, unbilled revenues of $80 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 $28 million and $29 million for the three months ended June 30, 2018 and 2017, respectively, and $57 million and $54 million for the six months ended June 30, 2018 and 2017, respectively.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 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 Accounting Standard Update (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 or TEC’s Condensed Consolidated Income Statement for the three and six months 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 which 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 expects to make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 which permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. TEC expects to make this election. 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 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. Significant updates to systems are not expected. TEC continues to monitor FASB amendments to ASC Topic 842 .

Regulatory

Regulatory	6 Months Ended
	Jun. 30, 2018
Regulated Operations [Abstract]
Regulatory	3. Regulatory Tampa Electric Base Rates - 2017 Agreement On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaced the 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 beginning in 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 requirements. A decision by the FPSC on the second SoBRA is anticipated to occur in October 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 reduced in the second quarter of 2018 to reflect partial 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 storm costs in excess of the reserve and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below. Tampa Electric 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. The PGS settlement 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, which is subject to negotiations with the FPSC. PGS filed testimony supporting the calculation of the tax benefits on May 31, 2018. A hearing on the tax reform impact has been scheduled for late August 2018. 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) June 30, 2018 December 31, 2017 Regulatory assets: Regulatory tax asset (1) $ 44 $ 45 Cost-recovery clauses - deferred balances (2) 22 13 Environmental remediation (3) 29 33 Postretirement benefits (4) 263 272 Storm reserve (5) 9 47 Other 25 23 Total regulatory assets 392 433 Less: Current portion 45 77 Long-term regulatory assets $ 347 $ 356 Regulatory liabilities: Regulatory tax liability (6) $ 719 $ 730 Tax reform and storm agreement (7) 13 0 Cost-recovery clauses (2) 17 32 Accumulated reserve - cost of removal (8) 512 518 Other 5 5 Total regulatory liabilities 1,266 1,285 Less: Current portion 61 58 Long-term regulatory liabilities $ 1,205 $ 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 above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered over a 12-month period. (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 in December 2017. The liability related to the revaluation of the deferred income tax balances has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 TEC Consolidated Condensed Financial Statements (7) This regulatory liability represents the offset to tax reform benefits in the first quarter of 2018 due to Tampa Electric’s settlement agreement allowing the netting of the recovery of storm costs with tax reform benefits. Beginning on April 1, 2018, the amount is being amortized over the remainder of 2018. See Tampa Electric Tax Reform and Storm Settlement 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.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 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 analyze 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 six months ended June 30, 2018 and 2017 were 18.68% and 38.53%, 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 six months ended June 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 June 30, 2018, 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 June 30, 2018, that, if recognized, would reduce TEC’s effective tax rate.

Employee Postretirement Benefit

Employee Postretirement Benefits	6 Months Ended
	Jun. 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 June 30, 2018 2017 2018 2017 Components of net periodic benefit cost Service cost $ 6 $ 5 $ 0 $ 0 Interest cost 7 9 2 2 Expected return on assets (12 ) (12 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 1 1 Actuarial (gain) loss 4 4 (1 ) (1 ) Settlement cost 2 (2) 0 0 0 Net periodic benefit cost $ 7 $ 6 $ 2 $ 2 Six months ended June 30, Components of net periodic benefit cost Service cost $ 11 $ 10 $ 1 $ 1 Interest cost 14 16 4 4 Expected return on assets (24 ) (24 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 0 Actuarial (gain) loss 9 8 (1 ) (1 ) Settlement cost 2 (2) 7 (1) 0 0 Net periodic benefit cost $ 12 $ 17 $ 4 $ 4 (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 June 30, 2018 and 2017, respectively, was $6 million and $4 million for pension benefits, and $2 million and $2 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the six months ended June 30, 2018 and 2017, respectively, was $9 million and $7 million for pension benefits, and $4 million and $3 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 $25 million to its qualified pension plan in the six months ended June 30, 2018 and 2017, respectively. TEC’s portion of these contributions was $8 million and $20 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 six months ended June 30, 2018, TEC reclassified $4 million and $8 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses from regulatory assets to net income, compared with $3 million and $5 million for the three and six months ended June 30, 2017, respectively.

Short-Term Debt

Short-Term Debt	6 Months Ended
	Jun. 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: June 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 $ 0 $ 1 $ 325 $ 5 $ 1 3-year accounts receivable facility (3) 150 75 0 150 0 0 1-year term facility (4) 300 300 0 300 300 0 Total $ 775 $ 375 $ 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 matures on November 1, 2018. At June 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 June 30, 2018 and December 31, 2017 was 2.7% 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). TEC will pay program and liquidity fees, which total 70 basis points at June 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 June 30, 2018, TEC was in compliance with the requirements of the Loan Agreement.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At June 30, 2018, TEC’s long-term debt had a carrying amount of $2,205 million and an estimated fair market value of $2,073 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 June 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 Issuance of Tampa Electric Company 4.3% Notes due 2048 On June 7, 2018, TEC completed an offering of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048 (the TEC 2018 Notes). Until December 15, 2047, TEC may redeem all or any part of the TEC 2018 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2018 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2018 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 TEC 2018 Notes, in whole or in part, at 100% of the principal amount of the TEC 2018 Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 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 June 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. 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 June 30, 2018: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2018 $ 17 $ 2 $ 308 $ 248 $ 575 2019 0 2 173 230 405 2020 0 2 52 178 232 2021 0 2 26 144 172 2022 0 2 8 136 146 Thereafter 0 36 0 1,122 1,158 Total future minimum payments $ 17 $ 46 $ 567 $ 2,058 $ 2,688 Financial Covenants TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable banking agreements and has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2018, TEC was in compliance with all required financial covenants.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
Segment Information	9. Segment Information (millions) Tampa Tampa Electric Three months ended June 30, Electric PGS Eliminations Company 2018 Revenues - external $ 509 $ 110 $ 0 $ 619 Intracompany sales 1 5 (6 ) 0 Total revenues 510 115 (6 ) 619 Total interest charges 25 4 0 29 Net income $ 74 $ 11 $ 0 $ 85 2017 Revenues - external $ 542 $ 102 $ 0 $ 644 Intracompany sales 0 2 (2 ) 0 Total revenues 542 104 (2 ) 644 Total interest charges 26 4 0 30 Net income $ 76 $ 10 $ 0 $ 86 Six months ended June 30, 2018 Revenues - external $ 970 $ 246 $ 0 $ 1,216 Intracompany sales 1 11 (12 ) 0 Total revenues 971 257 (12 ) 1,216 Total interest charges 51 8 0 59 Net income $ 121 $ 27 $ 0 $ 148 2017 Revenues - external $ 984 $ 213 $ 0 $ 1,197 Intracompany sales 1 3 (4 ) 0 Total revenues 985 216 (4 ) 1,197 Total interest charges 52 7 0 59 Net income $ 119 $ 23 $ 0 $ 142 Total assets at June 30, 2018 $ 7,853 $ 1,319 $ (508 ) (1) $ 8,664 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	6 Months Ended
	Jun. 30, 2018
Revenues [Abstract]
Revenue	10. Revenue The following disaggregates TEC’s revenue by major source for the three and six months ended June 30, 2018: (millions) Tampa Tampa Electric Three months ended June 30, 2018 Electric PGS Eliminations Company Electric revenue Residential $ 241 $ 0 $ 0 $ 241 Commercial 140 0 0 140 Industrial 40 0 0 40 Regulatory deferrals and unbilled revenue 24 0 0 24 Other (1) 65 0 (1 ) 64 Total electric revenue 510 0 (1 ) 509 Gas revenue Residential 0 35 0 35 Commercial 0 37 0 37 Industrial (2) 0 6 0 6 Other (3) 0 37 (5 ) 32 Total gas revenue 0 115 (5 ) 110 Total revenue $ 510 $ 115 $ (6 ) $ 619 Six months ended June 30, 2018 Electric revenue Residential $ 471 $ 0 $ 0 $ 471 Commercial 272 0 0 272 Industrial 78 0 0 78 Regulatory deferrals and unbilled revenue 23 0 0 23 Other (1) 127 0 (1 ) 126 Total electric revenue 971 0 (1 ) 970 Gas revenue Residential 0 91 0 91 Commercial 0 81 0 81 Industrial (2) 0 11 0 11 Other (3) 0 74 (11 ) 63 Total gas revenue 0 257 (11 ) 246 Total revenue $ 971 $ 257 $ (12 ) $ 1,216 (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 June 30, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $140 million. As allowed by the practical expedient in 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	6 Months Ended
	Jun. 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. 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 June 30, 2018, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected. The derivatives at June 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 June 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 Balance Sheets. There was no collateral posted with or received from any counterparties at June 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 Balance Sheets as current regulatory assets and liabilities. Based on the fair value of the instruments at June 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 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 June 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	6 Months Ended
	Jun. 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 June 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 June 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

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 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 June 30, 2018 and December 31, 2017, and the results of operations and cash flows for the periods ended June 30, 2018 and 2017. The results of operations for the three and six months ended June 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, line losses and inter-period changes to customer classes. 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 $249 million and $229 million as of June 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 June 30, 2018 and December 31, 2017, unbilled revenues of $80 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 $28 million and $29 million for the three months ended June 30, 2018 and 2017, respectively, and $57 million and $54 million for the six months ended June 30, 2018 and 2017, respectively.

Regulatory (Tables)

Regulatory (Tables)	6 Months Ended
	Jun. 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) June 30, 2018 December 31, 2017 Regulatory assets: Regulatory tax asset (1) $ 44 $ 45 Cost-recovery clauses - deferred balances (2) 22 13 Environmental remediation (3) 29 33 Postretirement benefits (4) 263 272 Storm reserve (5) 9 47 Other 25 23 Total regulatory assets 392 433 Less: Current portion 45 77 Long-term regulatory assets $ 347 $ 356 Regulatory liabilities: Regulatory tax liability (6) $ 719 $ 730 Tax reform and storm agreement (7) 13 0 Cost-recovery clauses (2) 17 32 Accumulated reserve - cost of removal (8) 512 518 Other 5 5 Total regulatory liabilities 1,266 1,285 Less: Current portion 61 58 Long-term regulatory liabilities $ 1,205 $ 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 above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The asset will be recovered over a 12-month period. (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 in December 2017. The liability related to the revaluation of the deferred income tax balances has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. See Note 4 TEC Consolidated Condensed Financial Statements (7) This regulatory liability represents the offset to tax reform benefits in the first quarter of 2018 due to Tampa Electric’s settlement agreement allowing the netting of the recovery of storm costs with tax reform benefits. Beginning on April 1, 2018, the amount is being amortized over the remainder of 2018. See Tampa Electric Tax Reform and Storm Settlement 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.

Employee Postretirement Benef20

Employee Postretirement Benefits (Tables)	6 Months Ended
	Jun. 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 June 30, 2018 2017 2018 2017 Components of net periodic benefit cost Service cost $ 6 $ 5 $ 0 $ 0 Interest cost 7 9 2 2 Expected return on assets (12 ) (12 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 1 1 Actuarial (gain) loss 4 4 (1 ) (1 ) Settlement cost 2 (2) 0 0 0 Net periodic benefit cost $ 7 $ 6 $ 2 $ 2 Six months ended June 30, Components of net periodic benefit cost Service cost $ 11 $ 10 $ 1 $ 1 Interest cost 14 16 4 4 Expected return on assets (24 ) (24 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 0 Actuarial (gain) loss 9 8 (1 ) (1 ) Settlement cost 2 (2) 7 (1) 0 0 Net periodic benefit cost $ 12 $ 17 $ 4 $ 4 (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)	6 Months Ended
	Jun. 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: June 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 $ 0 $ 1 $ 325 $ 5 $ 1 3-year accounts receivable facility (3) 150 75 0 150 0 0 1-year term facility (4) 300 300 0 300 300 0 Total $ 775 $ 375 $ 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 matures on November 1, 2018.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 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 June 30, 2018: Long-term Service Purchased Operating Agreements/Capital Clause Recoverable (millions) Power Leases Projects Commitments Total Year ended December 31: 2018 $ 17 $ 2 $ 308 $ 248 $ 575 2019 0 2 173 230 405 2020 0 2 52 178 232 2021 0 2 26 144 172 2022 0 2 8 136 146 Thereafter 0 36 0 1,122 1,158 Total future minimum payments $ 17 $ 46 $ 567 $ 2,058 $ 2,688

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
Schedule of Segment Information	(millions) Tampa Tampa Electric Three months ended June 30, Electric PGS Eliminations Company 2018 Revenues - external $ 509 $ 110 $ 0 $ 619 Intracompany sales 1 5 (6 ) 0 Total revenues 510 115 (6 ) 619 Total interest charges 25 4 0 29 Net income $ 74 $ 11 $ 0 $ 85 2017 Revenues - external $ 542 $ 102 $ 0 $ 644 Intracompany sales 0 2 (2 ) 0 Total revenues 542 104 (2 ) 644 Total interest charges 26 4 0 30 Net income $ 76 $ 10 $ 0 $ 86 Six months ended June 30, 2018 Revenues - external $ 970 $ 246 $ 0 $ 1,216 Intracompany sales 1 11 (12 ) 0 Total revenues 971 257 (12 ) 1,216 Total interest charges 51 8 0 59 Net income $ 121 $ 27 $ 0 $ 148 2017 Revenues - external $ 984 $ 213 $ 0 $ 1,197 Intracompany sales 1 3 (4 ) 0 Total revenues 985 216 (4 ) 1,197 Total interest charges 52 7 0 59 Net income $ 119 $ 23 $ 0 $ 142 Total assets at June 30, 2018 $ 7,853 $ 1,319 $ (508 ) (1) $ 8,664 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)	6 Months Ended
	Jun. 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 six months ended June 30, 2018: (millions) Tampa Tampa Electric Three months ended June 30, 2018 Electric PGS Eliminations Company Electric revenue Residential $ 241 $ 0 $ 0 $ 241 Commercial 140 0 0 140 Industrial 40 0 0 40 Regulatory deferrals and unbilled revenue 24 0 0 24 Other (1) 65 0 (1 ) 64 Total electric revenue 510 0 (1 ) 509 Gas revenue Residential 0 35 0 35 Commercial 0 37 0 37 Industrial (2) 0 6 0 6 Other (3) 0 37 (5 ) 32 Total gas revenue 0 115 (5 ) 110 Total revenue $ 510 $ 115 $ (6 ) $ 619 Six months ended June 30, 2018 Electric revenue Residential $ 471 $ 0 $ 0 $ 471 Commercial 272 0 0 272 Industrial 78 0 0 78 Regulatory deferrals and unbilled revenue 23 0 0 23 Other (1) 127 0 (1 ) 126 Total electric revenue 971 0 (1 ) 970 Gas revenue Residential 0 91 0 91 Commercial 0 81 0 81 Industrial (2) 0 11 0 11 Other (3) 0 74 (11 ) 63 Total gas revenue 0 257 (11 ) 246 Total revenue $ 971 $ 257 $ (12 ) $ 1,216 (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 Accoun25

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Accounting Policies [Abstract]
Receivables from contracts with customers	$ 249		$ 249		$ 229
Unbilled revenues	80		80		$ 66
Franchise fees and gross receipts taxes	$ 28	$ 29	$ 57	$ 54

Regulatory - Additional Informa

Regulatory - Additional Information (Detail) $ in Millions	Jun. 29, 2018USD ($)MW	Dec. 12, 2017USD ($)MW	Sep. 27, 2017USD ($)$ / kWacMW	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 31, 2013USD ($)
Public Utilities General Disclosures [Line Items]
Storm damage reserve									$ 56
Regulatory assets				$ 392			$ 392	$ 433
Reduction in O&M expense for amortization				5
Tax reform expense (benefits)					$ 102
Regulatory liabilities				1,266			$ 1,266	1,285
PGS [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement, approval date							Feb. 7, 2017
Regulatory liabilities				5			$ 5
Tax Reform and Storm Settlement [Member]
Public Utilities General Disclosures [Line Items]
O&M expense and regulatory liability					$ 19
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				9			$ 9	$ 47
Tax Reform and Storm Settlement [Member]
Public Utilities General Disclosures [Line Items]
O&M expense and regulatory asset				$ 35

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Regulatory assets:
Regulatory assets	$ 392	$ 433
Less: Current portion	45	77
Long-term regulatory assets	347	356
Regulatory liabilities:
Regulatory liabilities	1,266	1,285
Less: Current portion	61	58
Long-term regulatory liabilities	1,205	1,227
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	44	45
Cost-Recovery Clauses - Deferred Balances [Member]
Regulatory assets:
Regulatory assets	22	13
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	29	33
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	263	272
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	9	47
Other [Member]
Regulatory assets:
Regulatory assets	25	23
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	719	730
Tax Reform and Storm Agreement [Member]
Regulatory liabilities:
Regulatory liabilities	13	0
Cost Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	17	32
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	512	518
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 5	$ 5

Regulatory - Schedule of Regu28

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Minimum [Member] | Storm Reserve [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory asset recovery period	12 months	12 months

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	Sep. 27, 2017	Jun. 30, 2018	Jun. 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
Tampa Electric [Member]
Income Taxes [Line Items]
Effective tax rate		18.68%	38.53%

Employee Postretirement Benef30

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018		Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 6		$ 4	$ 9		$ 7
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	2		2	4		3
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	6		5	11		10
Interest cost	7		9	14		16
Expected return on assets	(12)		(12)	(24)		(24)
Amortization of:
Prior service (benefit) cost	0		0	0		0
Actuarial (gain) loss	4		4	9		8
Settlement cost	2	[1]	0	2	[1]	7	[2]
Net periodic benefit cost	7		6	12		17
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0		0	1		1
Interest cost	2		2	4		4
Expected return on assets	0		0	0		0
Amortization of:
Prior service (benefit) cost	1		1	0		0
Actuarial (gain) loss	(1)		(1)	(1)		(1)
Settlement cost	0		0	0		0
Net periodic benefit cost	$ 2		$ 2	$ 4		$ 4
[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 Benef31

Employee Postretirement Benefits - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 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	$ 8,000,000	$ 5,000,000
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	6,000,000	4,000,000	$ 9,000,000	7,000,000
Employer contributions			8,000,000	20,000,000
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	7,000,000	6,000,000	$ 12,000,000	17,000,000
Discount rate			3.63%
Employer contributions			$ 10,000,000	25,000,000
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	2,000,000	4,000,000	3,000,000
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 2,000,000	$ 2,000,000	$ 4,000,000	$ 4,000,000
Discount rate			3.70%

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities and Related Borrowings (Detail) - USD ($)	Jun. 30, 2018	Mar. 23, 2018	Dec. 31, 2017
Line Of Credit Facility [Line Items]
Credit Facilities	$ 775,000,000		$ 775,000,000
Borrowings Outstanding	375,000,000		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	0		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	75,000,000		0
Letters of Credit Outstanding	0		0
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000		300,000,000
Borrowings Outstanding	300,000,000		300,000,000
Letters of Credit Outstanding	$ 0		$ 0

Short-Term Debt - Credit Faci33

Short-Term Debt - Credit Facilities and Related Borrowings (Parenthetical) (Detail)	Mar. 23, 2018	Jun. 30, 2018	Dec. 31, 2017
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Mar. 22, 2022	Mar. 22, 2022
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2021	Mar. 22, 2021	Mar. 22, 2021
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Nov. 1, 2018	Nov. 1, 2018

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail) - USD ($)	Mar. 23, 2018	Jun. 30, 2018	Dec. 31, 2017
Line Of Credit Facility [Line Items]
Weighted-average interest rate		2.70%	2.10%
Line of credit facility maximum borrowing capacity		$ 775,000,000	$ 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		TEC will pay program and liquidity fees, which total 70 basis points at June 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	Jun. 07, 2018	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt		$ 2,205	$ 2,164
Estimated fair value		2,073	2,412
4.3% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2,048
4.3% Notes [Member] | The TEC 2018 Notes
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
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	Jun. 30, 2018USD ($)
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 28

Commitments and Contingencies37

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Jun. 30, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2018	$ 17
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	17
Future Minimum Operating Leases Payments Due, 2018	2
Future Minimum Operating Leases Payments Due, 2019	2
Future Minimum Operating Leases Payments Due, 2020	2
Future Minimum Operating Leases Payments Due, 2021	2
Future Minimum Operating Leases Payments Due, 2022	2
Future Minimum Operating Leases Payments Due, Thereafter	36
Total future minimum operating leases payments due	46
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2018	308
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2019	173
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2020	52
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2021	26
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, 2022	8
Future Minimum Long-term Service Agreements/Capital Projects Payments Due, Thereafter	0
Total future minimum long-term service agreements/capital projects payments due	567
Future Minimum Clause Recoverable Commitments Payments Due, 2018	248
Future Minimum Clause Recoverable Commitments Payments Due, 2019	230
Future Minimum Clause Recoverable Commitments Payments Due, 2020	178
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	2,058
Future Minimum Payments Due, 2018	575
Future Minimum Payments Due, 2019	405
Future Minimum Payments Due, 2020	232
Future Minimum Payments Due, 2021	172
Future Minimum Payments Due, 2022	146
Future Minimum Payments Due, Thereafter	1,158
Total future minimum payments	$ 2,688

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Total revenues	$ 619	$ 644	$ 1,216	$ 1,197
Total interest charges	29	30	59	59
Net income	85	86	148	142
Total assets	8,664		8,664		$ 8,364
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	619	644	1,216	1,197
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(6)	(2)	(12)	(4)
Total interest charges	0	0	0	0
Net income	0	0	0	0
Total assets	(508)		(508)		(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	(6)	(2)	(12)	(4)
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Total revenues	510		971
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	510	542	971	985
Total interest charges	25	26	51	52
Net income	74	76	121	119
Total assets	7,853		7,853		7,635
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	509	542	970	984
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	1	0	1	1
PGS [Member]
Segment Reporting Information [Line Items]
Total revenues	115		257
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	115	104	257	216
Total interest charges	4	4	8	7
Net income	11	10	27	23
Total assets	1,319		1,319		$ 1,284
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	110	102	246	213
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 5	$ 2	$ 11	$ 3

Revenue - Summary of Disaggrega

Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 509	$ 542	$ 970	$ 984
Total gas revenue	110	102	246	213
Total revenues	619	$ 644	1,216	$ 1,197
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	241		471
Total gas revenue	35		91
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	140		272
Total gas revenue	37		81
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	40		78
Total gas revenue	6		11
Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	24		23
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	64		126
Total gas revenue	32		63
Tampa Electric [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	510		971
Total gas revenue	0		0
Total revenues	510		971
Tampa Electric [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	241		471
Total gas revenue	0		0
Tampa Electric [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	140		272
Total gas revenue	0		0
Tampa Electric [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	40		78
Total gas revenue	0		0
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	24		23
Tampa Electric [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	65		127
Total gas revenue	0		0
PGS [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	115		257
Total revenues	115		257
PGS [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	35		91
PGS [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	37		81
PGS [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0		0
Total gas revenue	6		11
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	37		74
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)		(1)
Total gas revenue	(5)		(11)
Total revenues	(6)		(12)
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)		(1)
Total gas revenue	$ (5)		$ (11)

Revenue - Additional Informatio

Revenue - Additional Information (Details) $ in Millions	Jun. 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 Ins41

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail)	1 Months Ended	6 Months Ended
	Sep. 30, 2017	Jun. 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		2

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($)	Jun. 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