Tampa Electric 10-Q 12 Aug 19 2019 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 08, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Current Reporting Status	Yes
Entity Shell Company	false
Trading Symbol	ck0000096271
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity File Number	1-5007
Entity Address, Address Line One	TECO Plaza
Entity Address, Address Line Two	702 N. Franklin Street
Entity Address, City or Town	Tampa
Entity Address, State or Province	Florida
Entity Tax Identification Number	590475140
Entity Address, Postal Zip Code	33602
City Area Code	813
Local Phone Number	228-1111
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		10

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Property, plant and equipment
Utility plant, at original costs	$ 11,952	$ 11,438
Accumulated depreciation	(3,350)	(3,214)
Utility plant, net	8,602	8,224
Other property	13	12
Total property, plant and equipment, net	8,615	8,236
Current assets
Cash and cash equivalents	10	15
Receivables, less allowance for uncollectibles of $2 at June 30, 2019 and December 31, 2018	256	258
Due from affiliates	13	4
Inventories, at average cost
Regulatory assets	88	88
Prepayments and other current assets	12	6
Total current assets	524	517
Deferred debits
Regulatory assets	388	370
Other	45	32
Total deferred debits	433	402
Total assets	9,572	9,155
Capitalization
Common stock	3,210	2,990
Accumulated other comprehensive loss	(1)	(1)
Retained earnings	345	314
Total capital	3,554	3,303
Long-term debt	2,575	2,575
Total capitalization	6,129	5,878
Current liabilities
Notes payable	386	221
Accounts payable	205	251
Due to affiliates	20	24
Customer deposits	132	132
Regulatory liabilities	80	44
Accrued interest	15	16
Accrued taxes	51	13
Other	40	84
Total current liabilities	929	785
Long-term liabilities
Deferred income taxes	740	799
Regulatory liabilities	1,252	1,266
Investment tax credits	170	74
Deferred credits and other liabilities	352	353
Total long-term liabilities	2,514	2,492
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	9,572	9,155
Fuel [Member]
Inventories, at average cost
Utility inventories	41	46
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	104	100
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	10,064	9,645
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 1,888	$ 1,793

Consolidated Condensed Balanc_2

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Statement Of Financial Position [Abstract]
Allowance for uncollectibles	$ 2	$ 2

Consolidated Condensed Statemen

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues
Electric	$ 520	$ 509	$ 931	$ 970
Gas	107	110	235	246
Total revenues	627	619	1,166	1,216
Expenses
Fuel	139	133	246	255
Purchased power	13	14	17	27
Cost of natural gas sold	$ 38	$ 39	$ 85	$ 94
Type of Cost, Good or Service [Extensible List]	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember	us-gaap:OilAndGasMember
Operations and maintenance	$ 132	$ 162	$ 262	$ 319
Depreciation and amortization	94	89	186	182
Taxes, other than income	52	51	102	103
Total expenses	468	488	898	980
Income from operations	159	131	268	236
Other income
Allowance for equity funds used during construction	2	1	4	1
Other income, net	3	2	5	4
Total other income	5	3	9	5
Interest charges
Interest expense	34	30	68	60
Allowance for borrowed funds used during construction	(1)	(1)	(2)	(1)
Total interest charges	33	29	66	59
Income before provision for income taxes	131	105	211	182
Provision for income taxes	24	20	40	34
Net income	107	85	171	148
Other comprehensive income, net of tax
Gain on cash flow hedges	0	1	0	1
Comprehensive income	$ 107	$ 86	$ 171	$ 149

Consolidated Condensed Statem_2

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash flows from operating activities
Net income	$ 171	$ 148
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	186	182
Deferred income taxes and investment tax credits	31	14
Deferred recovery clauses	1	(25)
Inventories	1	5
Prepayments and other deposits	(6)	(2)
Taxes accrued	25	28
Accounts payable	(54)	(37)
Regulatory assets and liabilities	5	54
Other	(29)	(21)
Cash flows from operating activities	331	346
Cash flows used in investing activities
Capital expenditures	(581)	(510)
Cash flows used in investing activities	(581)	(510)
Cash flows from financing activities
Equity contributions from Parent	220	215
Proceeds from long-term debt issuance	0	345
Repayment of long-term debt	0	(304)
Net increase in short-term debt	165	70
Dividends to Parent	(140)	(160)
Cash flows from financing activities	245	166
Net increase (decrease) in cash and cash equivalents	(5)	2
Cash and cash equivalents at beginning of period	15	13
Cash and cash equivalents at end of period	10	15
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (4)	$ 18

Consolidated Condensed Statem_3

Consolidated Condensed Statements of Capital (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Beginning balance	$ 3,401	$ 3,054	$ 3,303	$ 2,978
Net income	107	85	171	148
Other comprehensive income, after tax		1		1
Equity contributions from Parent	110	105	220	215
Dividends to Parent	(64)	(63)	(140)	(160)
Ending balance	3,554	3,182	3,554	3,182
Common Stock [Member]
Beginning balance	$ 3,100	$ 2,755	$ 2,990	$ 2,645
Beginning balance	10	10	10	10
Equity contributions from Parent	$ 110	$ 105	$ 220	$ 215
Ending balance	$ 3,210	$ 2,860	$ 3,210	$ 2,860
Ending balance	10	10	10	10
Retained Earnings [Member]
Beginning balance	$ 302	$ 301	$ 314	$ 335
Net income	107	85	171	148
Dividends to Parent	(64)	(63)	(140)	(160)
Ending balance	345	323	345	323
Accumulated Other Comprehensive Loss [Member]
Beginning balance	(1)	(2)	(1)	(2)
Other comprehensive income, after tax		1		1
Ending balance	$ (1)	$ (1)	$ (1)	$ (1)

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2019
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, 2018 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, 2019 and December 31, 2018, and the results of operations and cash flows for the periods ended June 30, 2019 and June 30, 2018. The results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2019. 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. Receivables and Allowance for Uncollectible Accounts Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $254 million and $226 million as of June 30, 2019 and December 31, 2018, 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, fuel prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. As of June 30, 2019 and December 31, 2018, unbilled revenues of $75 million and $67 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-for-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 $29 million and $28 million for the three months ended June 30, 2019 and 2018, respectively, and $56 million and $57 million for the six months ended June 30, 2019 and 2018, respectively.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2019
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 2019 are described as follows: Leases On January 1, 2019, TEC adopted Accounting Standard Updates (ASU) 2016-02, Leases (Topic 842), As permitted by the optional transition method, TEC did not restate comparative financial information in its consolidated financial statements, did not reassess whether any expired or existing contracts contained leases and carried forward existing lease classifications. Additionally, TEC elected to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under the leasing guidance within ASC Topic 840. TEC elected to use hindsight to determine the lease term for existing leases and elected to not separate lease components from non-lease components for all lessee and lessor arrangements. TEC has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. There were no updates to information technology systems as a result of implementation. TEC’s adoption of this new standard resulted in right-of-use (ROU) assets and lease liabilities of $20 million as of January 1, 2019. The ROU assets and lease liabilities were measured at the present value of remaining lease payments using TEC’s incremental borrowing rate. There was no impact to opening retained earnings as of January 1, 2019 or TEC’s net income or cash flows for the three and six months ended June 30, 2019 as a result of the adoption of the standard. There were no significant impacts to TEC’s accounting for lessor arrangements. Refer to Note 11 Targeted Improvements to Accounting for Hedging Activities On January 1, 2019, TEC adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities Cloud Computing In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract 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, 2018.

Regulatory

Regulatory	6 Months Ended
	Jun. 30, 2019
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 existing 2013 base rate settlement agreement and extended it another 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. Tampa Electric plans to invest approximately $850 million during 2017 through 2021 related to 600 MW of solar projects recoverable under the SoBRAs. On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018 requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018 and TEC began receiving these revenues in January 2019. On June 28, 2019, TEC filed its third SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2020 tranche representing 149 MW and $27 million annually in estimated revenue requirements. The FPSC is expected to issue its decision regarding the third SoBRA in the fourth quarter of 2019. Tampa Electric Storm Restoration Cost Recovery and Tax Reform 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. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs and to replenish the balance in the reserve to the level that existed as of October 31, 2013. On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addressed both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs, which was approved by the FPSC on May 21, 2019. As a result, PGS Base Rates PGS’s base rates were established in 2009. In 2017, the FPSC approved an updated PGS settlement agreement that did not contain a provision for tax reform. In 2018, the FPSC approved a settlement agreement authorizing PGS to accelerate $11 million of amortization of its regulatory asset associated with the MGP environmental liability in 2018 to net it against the estimated 2018 tax reform benefits. In accordance with the 2018 settlement agreement, PGS reduced its base rates by $12 million for the impact of tax reform and reduced depreciation rates by $10 million on an annual basis beginning in January 2019. PGS is permitted to initiate a general base rate proceeding during 2020 regardless of its earned ROE at the time provided the new rates 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) June 30, 2019 December 31, 2018 Regulatory assets: Regulatory tax asset (1) $ 73 $ 56 Cost-recovery clauses (2) 61 55 Environmental remediation (3) 25 23 Postretirement benefits (4) 288 295 Storm reserve (5) 3 3 Other 26 26 Total regulatory assets 476 458 Less: Current portion 88 88 Long-term regulatory assets $ 388 $ 370 Regulatory liabilities: Regulatory tax liability (6) $ 725 $ 715 Cost-recovery clauses (2) 24 17 Accumulated reserve - cost of removal (7) 512 513 Storm reserve (8) 56 56 Other 15 9 Total regulatory liabilities 1,332 1,310 Less: Current portion 80 44 Long-term regulatory liabilities $ 1,252 $ 1,266 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. (3) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. (4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC. (5) In October 2018, Hurricane Michael impacted PGS’s Panama City division and the cost of restoration exceeded PGS’s storm reserve balance. On July 9, 2019, the FPSC approved storm cost recovery of approximately $3 million, subject to true-up and refund pending further review of costs. The costs will be recovered on a dollar-for-dollar basis during 2019. (6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC. See Note 4 TEC Consolidated Financial Statements (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (8) See “Tampa Electric Storm Restoration Cost Recovery and Tax Reform” discussion above for information regarding this reserve.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2019
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 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 reflected in common stock. TEC’s effective tax rates for the six months ended June 30, 2019 and 2018 were 19.0% and 18.7%, respectively. The June 30, 2019 effective tax rate is an estimate of the annual effective income tax rate. TEC’s effective tax rate for the six months ended June 30, 2019 and 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, 2019 and December 31, 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, 2019 and December 31, 2018, that, if recognized, would reduce TEC’s effective tax rate.

Employee Postretirement Benefit

Employee Postretirement Benefits	6 Months Ended
	Jun. 30, 2019
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, 2019 2018 2019 2018 Components of net periodic benefit cost Service cost $ 5 $ 6 $ 0 $ 0 Interest cost 8 7 1 2 Expected return on assets (14 ) (12 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 1 Actuarial (gain) loss 5 4 0 (1 ) Settlement cost 0 2 (1) 0 0 Net periodic benefit cost $ 4 $ 7 $ 1 $ 2 Six months ended June 30, Components of net periodic benefit cost Service cost $ 10 $ 11 $ 0 $ 1 Interest cost 16 14 3 4 Expected return on assets (26 ) (24 ) 0 0 Amortization of: Actuarial (gain) loss 8 9 0 (1 ) Settlement cost 1 (1) 2 (1) 0 0 Net periodic benefit cost $ 9 $ 12 $ 3 $ 4 (1) Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the prior retirements of certain executives. TEC’s portion of the net periodic benefit cost for the three months ended June 30, 2019 and 2018, respectively, was $3 million and $6 million for pension benefits, and $1 million and $2 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the six months ended June 30, 2019 and 2018, respectively, was $7 million and $9 million for pension benefits, and $3 million and $4 million for other postretirement benefits. TECO Energy assumed a long-term EROA of 7.35% and a discount rate of 4.34% for pension benefits under its qualified pension plan for 2019. For TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.38% for 2019. TECO Energy made contributions of $7 million and $10 million to its qualified pension plan in the six months ended June 30, 2019 and 2018, respectively. TEC’s portion of these contributions was $5 million and $8 million, respectively. TECO Energy expects to make contributions to the pension plan of $14 million for the remainder of 2019, and TEC estimates its portion of the remaining 2019 contributions to be $10 million. Included in the benefit cost discussed above, for the three and six months ended June 30, 2019, TEC reclassified $3 million and $6 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 $4 million and $8 million for the three and six months ended June 30, 2018, respectively.

Short-Term Debt

Short-Term Debt	6 Months Ended
	Jun. 30, 2019
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, 2019 December 31, 2018 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 $ 275 $ 1 $ 325 $ 131 $ 1 3-year accounts receivable facility (3) 150 111 0 150 90 0 Total $ 475 $ 386 $ 1 $ 475 $ 221 $ 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. At June 30, 2019, 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, 2019 and December 31, 2018 was 3.36% and 3.14%, respectively.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Long-Term Debt	7. Long-Term Debt Fair Value of Long-Term Debt At June 30, 2019, TEC’s long-term debt had a carrying amount of $2,575 million and an estimated fair market value of $2,903 million. At December 31, 2018, TEC’s total long-term debt had a carrying amount of $2,575 million and an estimated fair market value of $2,686 million. The fair value of the debt securities is determined using Level 2 measurements Note 13 Tampa Electric Company 3.625% Notes due 2050 On July 24, 2019, TEC completed a sale of $300 million aggregate principal amount of 3.625% unsecured notes due June 15, 2050. Until December 15, 2049, 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, 2049, 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	6 Months Ended
	Jun. 30, 2019
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, 2019, 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, 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, 2019: Long-term Demand Purchased Capital Fuel and Service Operating Side (millions) Power Transportation Projects Gas Supply Agreements Leases Management Total 2019 $ 23 $ 100 $ 246 $ 125 $ 3 $ 1 $ 2 $ 500 2020 0 196 86 33 6 2 1 324 2021 0 191 35 3 7 2 0 238 2022 0 184 9 3 7 2 0 205 2023 0 161 3 1 11 2 0 178 Thereafter 0 1,647 13 0 78 35 0 1,773 Total future minimum payments $ 23 $ 2,479 $ 392 $ 165 $ 112 $ 44 $ 3 $ 3,218 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 June 30, 2019, TEC was in compliance with all required financial covenants.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Segment Information	9. Segment Information (millions) Tampa Tampa Electric Three months ended June 30, Electric PGS Eliminations Company 2019 Revenues - external $ 520 $ 107 $ 0 $ 627 Intracompany sales 1 4 (5 ) 0 Total revenues 521 111 (5 ) 627 Total interest charges 29 4 0 33 Net income $ 93 $ 14 $ 0 $ 107 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 Six months ended June 30, 2019 Revenues - external $ 931 $ 235 $ 0 $ 1,166 Intracompany sales 2 8 (10 ) 0 Total revenues 933 243 (10 ) 1,166 Total interest charges 58 8 0 66 Net income $ 139 $ 32 $ 0 $ 171 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 Total assets at June 30, 2019 $ 8,674 $ 1,478 $ (580 ) (1) $ 9,572 Total assets at December 31, 2018 $ 8,235 $ 1,407 $ (487 ) (1) $ 9,155 (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, 2019
Revenues [Abstract]
Revenue	10. Revenue The following disaggregates TEC’s revenue by major source: (millions) Tampa Tampa Electric Three months ended June 30, 2019 Electric PGS Eliminations Company Electric revenue Residential $ 261 $ 0 $ 0 $ 261 Commercial 141 0 0 141 Industrial 42 0 0 42 Regulatory deferrals and unbilled revenue 17 0 0 17 Other (1) 60 0 (1 ) 59 Total electric revenue 521 0 (1 ) 520 Gas revenue Residential 0 36 0 36 Commercial 0 35 0 35 Industrial (2) 0 6 0 6 Other (3) 0 34 (4 ) 30 Total gas revenue 0 111 (4 ) 107 Total revenue $ 521 $ 111 $ (5 ) $ 627 Three months ended June 30, 2018 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 (millions) Tampa Tampa Electric Six months ended June 30, 2019 Electric PGS Eliminations Company Electric revenue Residential $ 467 $ 0 $ 0 $ 467 Commercial 261 0 0 261 Industrial 76 0 0 76 Regulatory deferrals and unbilled revenue 10 0 0 10 Other (1) 119 0 (2 ) 117 Total electric revenue 933 0 (2 ) 931 Gas revenue Residential 0 86 0 86 Commercial 0 77 0 77 Industrial (2) 0 11 0 11 Other (3) 0 69 (8 ) 61 Total gas revenue 0 243 (8 ) 235 Total revenue $ 933 $ 243 $ (10 ) $ 1,166 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 electric revenue includes sales to public authorities, off-system sales to other utilities and various other items. (2) Industrial gas revenue includes sales to power generation customers. (3) Other gas revenue includes off-system sales to other utilities and various other items. Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of June 30, 2019 and December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $131 million and $135 million, respectively. 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.

Leases

Leases	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Leases	11. Leases TEC determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating lease ROU assets and operating lease liabilities are recognized on the Consolidated Condensed Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of TEC’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operations and maintenance expenses” on the Consolidated Condensed Statements of Income. Where TEC is the lessor, a lease is a sales-type lease if certain criteria is met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. TEC has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases. Lessee TEC has operating leases for buildings, land, telecommunication services and rail cars. TEC’s leases have remaining lease terms of 2 years to 67 years, some of which include options to extend the leases for up to an additional 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised. (millions) Classification June 30, 2019 Right-of-use asset Other deferred debits $ 17 Lease liabilities Current Other current liabilities $ 1 Long-term Deferred credits and other liabilities 17 Total lease liabilities $ 18 TEC has recorded operating lease expense for the three and six months ended June 30, 2019 of $1 million and $2 million, respectively. Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at June 30, 2019: (millions) 2019 2020 2021 2022 2023 Thereafter Total Minimum lease payments $ 1 $ 2 $ 2 $ 2 $ 2 $ 35 $ 44 Less imputed interest (26 ) Total future minimum payments $ 18 Additional information related to TEC’s leases is as follows: Six months ended June 30, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions) $ 2 Weighted average remaining lease term (years) 48 Weighted average discount rate - operating leases 4.3 % Lessor TEC leases CNG stations to other companies, which are classified as direct finance leases. The net investment in direct finance leases consists of the following: (millions) June 30, 2019 Total minimum lease payments to be received $ 35 Less amounts representing estimated executory costs (13 ) Minimum lease payments receivable $ 22 Less unearned finance lease income (11 ) Net investment in direct finance leases $ 11 Principal due within one year (included in "Receivables") (1 ) Net investment in direct finance leases - long-term (included in "Other deferred debits") $ 10 The unearned income related to these direct finance leases is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Gas revenues” on the Consolidated Condensed Statements of Income. Customers have the option to purchase the assets related to the CNG stations at any time after 2021 by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. Alternatively, the customer may take possession of the CNG station asset at the end of the lease term for no cost. As of June 30, 2019, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following: (millions) 2019 2020 2021 2022 2023 Thereafter Total Minimum lease payments to be received $ 2 $ 2 $ 2 $ 2 $ 2 $ 25 $ 35 Less executory costs (13 ) Total minimum lease payments receivable $ 22

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	12. Accounting for Derivative Instruments and Hedging Activities From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes: • To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and • To optimize the utilization of Tampa Electric’s physical natural gas storage capacity and PGS’s firm transportation capacity on interstate pipelines. TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers and to optimize the utilization of its physical natural gas storage capacity and firm transportation capacity on interstate pipelines. The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies. On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which replaces the 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 (see Note 3) TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements and to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage and firm transportation 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. 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, 2019, all of TEC’s physical contracts qualify for the NPNS exception, which has been elected. TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation. It is possible that volatility in commodity prices or other circumstances 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, 2019, counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies, collateralized, or approved for credit based on their financial statements. 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, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	13. Fair Value Measurements Items Measured at Fair Value on a Recurring Basis Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: Level 1: Observable inputs, such as quoted prices in active markets; Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions. There were no Level 3 assets or liabilities for the periods presented. As of June 30, 2019 and December 31, 2018, 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	6 Months Ended
	Jun. 30, 2019
Subsequent Events [Abstract]
Subsequent Event	14. Subsequent Event Tampa Electric Company 3.625% Notes due 2050 On July 24, 2019, TEC completed a sale of $300 million aggregate principal amount of 3.625% unsecured notes due June 15, 2050. See Note 7

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2019
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, 2019 and December 31, 2018, and the results of operations and cash flows for the periods ended June 30, 2019 and June 30, 2018. The results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2019. 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.
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 $254 million and $226 million as of June 30, 2019 and December 31, 2018, 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, fuel prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. As of June 30, 2019 and December 31, 2018, unbilled revenues of $75 million and $67 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-for-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 $29 million and $28 million for the three months ended June 30, 2019 and 2018, respectively, and $56 million and $57 million for the six months ended June 30, 2019 and 2018, respectively.

Regulatory (Tables)

Regulatory (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 December 31, 2018 Regulatory assets: Regulatory tax asset (1) $ 73 $ 56 Cost-recovery clauses (2) 61 55 Environmental remediation (3) 25 23 Postretirement benefits (4) 288 295 Storm reserve (5) 3 3 Other 26 26 Total regulatory assets 476 458 Less: Current portion 88 88 Long-term regulatory assets $ 388 $ 370 Regulatory liabilities: Regulatory tax liability (6) $ 725 $ 715 Cost-recovery clauses (2) 24 17 Accumulated reserve - cost of removal (7) 512 513 Storm reserve (8) 56 56 Other 15 9 Total regulatory liabilities 1,332 1,310 Less: Current portion 80 44 Long-term regulatory liabilities $ 1,252 $ 1,266 (1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction. (2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. (3) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. (4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC. (5) In October 2018, Hurricane Michael impacted PGS’s Panama City division and the cost of restoration exceeded PGS’s storm reserve balance. On July 9, 2019, the FPSC approved storm cost recovery of approximately $3 million, subject to true-up and refund pending further review of costs. The costs will be recovered on a dollar-for-dollar basis during 2019. (6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC. See Note 4 TEC Consolidated Financial Statements (7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred. (8) See “Tampa Electric Storm Restoration Cost Recovery and Tax Reform” discussion above for information regarding this reserve.

Employee Postretirement Benef_2

Employee Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2019
TECO Energy [Member]
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, 2019 2018 2019 2018 Components of net periodic benefit cost Service cost $ 5 $ 6 $ 0 $ 0 Interest cost 8 7 1 2 Expected return on assets (14 ) (12 ) 0 0 Amortization of: Prior service (benefit) cost 0 0 0 1 Actuarial (gain) loss 5 4 0 (1 ) Settlement cost 0 2 (1) 0 0 Net periodic benefit cost $ 4 $ 7 $ 1 $ 2 Six months ended June 30, Components of net periodic benefit cost Service cost $ 10 $ 11 $ 0 $ 1 Interest cost 16 14 3 4 Expected return on assets (26 ) (24 ) 0 0 Amortization of: Actuarial (gain) loss 8 9 0 (1 ) Settlement cost 1 (1) 2 (1) 0 0 Net periodic benefit cost $ 9 $ 12 $ 3 $ 4 (1) Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the prior retirements of certain executives.

Short-Term Debt (Tables)

Short-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 December 31, 2018 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 $ 275 $ 1 $ 325 $ 131 $ 1 3-year accounts receivable facility (3) 150 111 0 150 90 0 Total $ 475 $ 386 $ 1 $ 475 $ 221 $ 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.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019: Long-term Demand Purchased Capital Fuel and Service Operating Side (millions) Power Transportation Projects Gas Supply Agreements Leases Management Total 2019 $ 23 $ 100 $ 246 $ 125 $ 3 $ 1 $ 2 $ 500 2020 0 196 86 33 6 2 1 324 2021 0 191 35 3 7 2 0 238 2022 0 184 9 3 7 2 0 205 2023 0 161 3 1 11 2 0 178 Thereafter 0 1,647 13 0 78 35 0 1,773 Total future minimum payments $ 23 $ 2,479 $ 392 $ 165 $ 112 $ 44 $ 3 $ 3,218

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Schedule of Segment Information	(millions) Tampa Tampa Electric Three months ended June 30, Electric PGS Eliminations Company 2019 Revenues - external $ 520 $ 107 $ 0 $ 627 Intracompany sales 1 4 (5 ) 0 Total revenues 521 111 (5 ) 627 Total interest charges 29 4 0 33 Net income $ 93 $ 14 $ 0 $ 107 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 Six months ended June 30, 2019 Revenues - external $ 931 $ 235 $ 0 $ 1,166 Intracompany sales 2 8 (10 ) 0 Total revenues 933 243 (10 ) 1,166 Total interest charges 58 8 0 66 Net income $ 139 $ 32 $ 0 $ 171 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 Total assets at June 30, 2019 $ 8,674 $ 1,478 $ (580 ) (1) $ 9,572 Total assets at December 31, 2018 $ 8,235 $ 1,407 $ (487 ) (1) $ 9,155 (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, 2019
Revenue Recognition [Abstract]
Summary of Disaggregates TEC Revenue by Major Source	The following disaggregates TEC’s revenue by major source: (millions) Tampa Tampa Electric Three months ended June 30, 2019 Electric PGS Eliminations Company Electric revenue Residential $ 261 $ 0 $ 0 $ 261 Commercial 141 0 0 141 Industrial 42 0 0 42 Regulatory deferrals and unbilled revenue 17 0 0 17 Other (1) 60 0 (1 ) 59 Total electric revenue 521 0 (1 ) 520 Gas revenue Residential 0 36 0 36 Commercial 0 35 0 35 Industrial (2) 0 6 0 6 Other (3) 0 34 (4 ) 30 Total gas revenue 0 111 (4 ) 107 Total revenue $ 521 $ 111 $ (5 ) $ 627 Three months ended June 30, 2018 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 (millions) Tampa Tampa Electric Six months ended June 30, 2019 Electric PGS Eliminations Company Electric revenue Residential $ 467 $ 0 $ 0 $ 467 Commercial 261 0 0 261 Industrial 76 0 0 76 Regulatory deferrals and unbilled revenue 10 0 0 10 Other (1) 119 0 (2 ) 117 Total electric revenue 933 0 (2 ) 931 Gas revenue Residential 0 86 0 86 Commercial 0 77 0 77 Industrial (2) 0 11 0 11 Other (3) 0 69 (8 ) 61 Total gas revenue 0 243 (8 ) 235 Total revenue $ 933 $ 243 $ (10 ) $ 1,166 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 electric revenue includes sales to public authorities, off-system sales to other utilities and various other items. (2) Industrial gas revenue includes sales to power generation customers. (3) Other gas revenue includes off-system sales to other utilities and various other items.

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Summary of Lease Assets and Liabilities	(millions) Classification June 30, 2019 Right-of-use asset Other deferred debits $ 17 Lease liabilities Current Other current liabilities $ 1 Long-term Deferred credits and other liabilities 17 Total lease liabilities $ 18
Future Minimum Lease Payments	Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at June 30, 2019: (millions) 2019 2020 2021 2022 2023 Thereafter Total Minimum lease payments $ 1 $ 2 $ 2 $ 2 $ 2 $ 35 $ 44 Less imputed interest (26 ) Total future minimum payments $ 18
Additional Information Related to Leases	Additional information related to TEC’s leases is as follows: Six months ended June 30, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases (millions) $ 2 Weighted average remaining lease term (years) 48 Weighted average discount rate - operating leases 4.3 %
Net Investment in Direct Finance Leases	The net investment in direct finance leases consists of the following: (millions) June 30, 2019 Total minimum lease payments to be received $ 35 Less amounts representing estimated executory costs (13 ) Minimum lease payments receivable $ 22 Less unearned finance lease income (11 ) Net investment in direct finance leases $ 11 Principal due within one year (included in "Receivables") (1 ) Net investment in direct finance leases - long-term (included in "Other deferred debits") $ 10
Future Minimum Direct Finance Lease Payments to be Received	As of June 30, 2019, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following: (millions) 2019 2020 2021 2022 2023 Thereafter Total Minimum lease payments to be received $ 2 $ 2 $ 2 $ 2 $ 2 $ 25 $ 35 Less executory costs (13 ) Total minimum lease payments receivable $ 22

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Accounting Policies [Abstract]
Receivables from contracts with customers	$ 254		$ 254		$ 226
Unbilled revenues	75		75		$ 67
Franchise fees and gross receipts taxes	$ 29	$ 28	$ 56	$ 57

New Accounting Pronouncements -

New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2019	Jan. 01, 2019
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Lease liability	$ 18
ASU 2016-02 [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Right-of-use asset		$ 20
Lease liability		$ 20

Regulatory - Additional Informa

Regulatory - Additional Information (Detail) $ in Millions

Jun. 28, 2019USD ($)MW

Apr. 09, 2019USD ($)

Aug. 20, 2018USD ($)

Jun. 29, 2018USD ($)MW

Dec. 12, 2017USD ($)MW

Sep. 27, 2017USD ($)MW

Jun. 30, 2019USD ($)

Jun. 30, 2018USD ($)

Sep. 30, 2017USD ($)

Jun. 30, 2019USD ($)

Jun. 30, 2018USD ($)

Dec. 31, 2018USD ($)

Oct. 31, 2013USD ($)

Public Utilities General Disclosures [Line Items]

Tax reform benefits

$ (24)

$ (20)

$ (40)

$ (34)

Regulatory liability

1,332

1,332

$ 1,310

Amount refundable on settlement

$ 12

Regulatory asset for amortization

(5)

$ (54)

PGS [Member]

Public Utilities General Disclosures [Line Items]

Regulatory asset for amortization

11

Reduction in annual depreciation rates

10

Reduction in annual base rates

12

Tax Reform And Storm Settlement

Public Utilities General Disclosures [Line Items]

Tax reform benefits

103

Annually approved lowering base rates, Amount

$ 103

Tax Reform and Storm Settlement Two [Member]

Public Utilities General Disclosures [Line Items]

O&M expense

$ 47

Reduction in regulatory asset

47

Tax Reform and Storm Settlement Three [Member]

Public Utilities General Disclosures [Line Items]

O&M expense

56

Regulatory liability

$ 56

$ 56

Hurricane Irma [Member]

Public Utilities General Disclosures [Line Items]

Storm restoration costs

$ 102

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

Solar generation capacity investments

$ 850

Solar energy capacity | MW

600

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

Solar Project Cost Recovery [Member] | Effective January 1, 2020 [Member]

Public Utilities General Disclosures [Line Items]

Solar energy capacity | MW

149

Estimated annual revenue requirements

$ 27

Solar Project Cost Recovery [Member] | Minimum [Member]

Public Utilities General Disclosures [Line Items]

Solar project investment term

2017

Solar Project Cost Recovery [Member] | Maximum [Member]

Public Utilities General Disclosures [Line Items]

Solar project investment term

2021

Storm Restoration Cost Recovery [Member]

Public Utilities General Disclosures [Line Items]

Minimum cost recovery period

12 months

Replenishment reserve for recovery of cost

$ 56

Regulatory - Schedule of Regula

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Regulatory assets:
Regulatory assets	$ 476	$ 458
Less: Current portion	88	88
Long-term regulatory assets	388	370
Regulatory liabilities:
Regulatory liabilities	1,332	1,310
Less: Current portion	80	44
Long-term regulatory liabilities	1,252	1,266
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	73	56
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	61	55
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	25	23
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	288	295
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	3	3
Other [Member]
Regulatory assets:
Regulatory assets	26	26
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	725	715
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	24	17
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56	56
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	512	513
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 15	$ 9

Regulatory - Schedule of Regu_2

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail) $ in Millions	Jul. 09, 2019USD ($)
Storm Reserve [Member] | Subsequent Event [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets recoverable amount	$ 3

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2018
Income Taxes [Line Items]
Federal statutory tax rate	21.00%		35.00%
Asset expensing	100.00%
Unrecognized tax benefits	$ 8			$ 8
Unrecognized tax benefit that would reduce effective tax rate	$ 8			$ 8
Tampa Electric [Member]
Income Taxes [Line Items]
Effective tax rate	19.00%	18.70%

Employee Postretirement Benef_3

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 3	$ 6	$ 7	$ 9
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	1	2	3	4
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	5	6	10	11
Interest cost	8	7	16	14
Expected return on assets	(14)	(12)	(26)	(24)
Amortization of:
Prior service (benefit) cost	0	0
Actuarial (gain) loss	5	4	8	9
Settlement cost	0	2	1	2
Net periodic benefit cost	4	7	9	12
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0	1
Interest cost	1	2	3	4
Expected return on assets	0	0	0	0
Amortization of:
Prior service (benefit) cost	0	1
Actuarial (gain) loss	0	(1)	0	(1)
Settlement cost	0	0	0	0
Net periodic benefit cost	$ 1	$ 2	$ 3	$ 4

Employee Postretirement Benef_4

Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Defined Benefit Plan Disclosure [Line Items]
Reclassification of regulatory assets to net income as part of periodic benefit cost	$ 3	$ 4	$ 6	$ 8
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA			7.35%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	3	6	$ 7	9
Employer contributions			5	8
Expected future employer contributions for remainder of 2019	10		10
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	4	7	$ 9	12
Discount rate			4.34%
Employer contributions			$ 7	10
Expected future employer contributions for remainder of 2019	14		14
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	1	2	3	4
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 1	$ 2	$ 3	$ 4
Discount rate			4.38%

Short-Term Debt - Credit Facili

Short-Term Debt - Credit Facilities and Related Borrowings (Detail) - USD ($)	Jun. 30, 2019	Dec. 31, 2018
Line Of Credit Facility [Line Items]
Credit Facilities	$ 475,000,000	$ 475,000,000
Borrowings Outstanding	386,000,000	221,000,000
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	275,000,000	131,000,000
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
Borrowings Outstanding	111,000,000	90,000,000
Letters of Credit Outstanding	$ 0	$ 0

Short-Term Debt - Credit Faci_2

Short-Term Debt - Credit Facilities and Related Borrowings (Parenthetical) (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
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

Short-Term Debt - Additional In

Short-Term Debt - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Line Of Credit Facility [Line Items]
Weighted-average interest rate	3.36%	3.14%
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	Jul. 24, 2019	Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt		$ 2,575	$ 2,575
Estimated fair value		$ 2,903	$ 2,686
Subsequent Event [Member] | 3.625% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2050
Subsequent Event [Member] | 3.625% Notes [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 300
Stated interest rate	3.625%
Debt instrument maturity date	Jun. 15, 2050
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, 2049
Debt instrument, offering date	Jul. 24, 2019

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Jun. 30, 2019USD ($)
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	Jun. 30, 2019USD ($)
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Purchased Power Payments Due, 2019	$ 23
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, 2023	0
Future Minimum Purchased Power Payments Due, Thereafter	0
Total future minimum purchased power payments due	23
Future Minimum Transportation Payments Due, 2019	100
Future Minimum Transportation Payments Due, 2020	196
Future Minimum Transportation Payments Due, 2021	191
Future Minimum Transportation Payments Due, 2022	184
Future Minimum Transportation Payments Due, 2023	161
Future Minimum Transportation Payments Due, Thereafter	1,647
Total future minimum transportation payments due	2,479
Future Minimum Capital Projects Payments Due, 2019	246
Future Minimum Capital Projects Payments Due, 2020	86
Future Minimum Capital Projects Payments Due, 2021	35
Future Minimum Capital Projects Payments Due, 2022	9
Future Minimum Capital Projects Payments Due, 2023	3
Future Minimum Capital Projects Payments Due, Thereafter	13
Total future minimum capital projects payments due	392
Future Minimum Fuel and Gas Supply Payments Due, 2019	125
Future Minimum Fuel and Gas Supply Payments Due, 2020	33
Future Minimum Fuel and Gas Supply Payments Due, 2021	3
Future Minimum Fuel and Gas Supply Payments Due, 2022	3
Future Minimum Fuel and Gas Supply Payments Due, 2023	1
Future Minimum Fuel and Gas Supply Payments Due, Thereafter	0
Total future minimum fuel and gas supply payments due	165
Future Minimum Long-term Service Agreements Payments Due, 2019	3
Future Minimum Long-term Service Agreements Payments Due, 2020	6
Future Minimum Long-term Service Agreements Payments Due, 2021	7
Future Minimum Long-term Service Agreements Payments Due, 2022	7
Future Minimum Long-term Service Agreements Payments Due, 2023	11
Future Minimum Long-term Service Agreements Payments Due, Thereafter	78
Total future minimum long-term service agreements payments due	112
Future Minimum Operating Leases Payments Due, 2019	1
Future Minimum Operating Leases Payments Due, 2020	2
Future Minimum Operating Leases Payments Due, 2021	2
Future Minimum Operating Leases Payments Due, 2022	2
Future Minimum Operating Leases Payments Due, 2023	2
Future Minimum Operating Leases Payments Due, Thereafter	35
Total future minimum operating leases payments due	44
Future Minimum Demand Side Management Payments Due, 2019	2
Future Minimum Demand Side Management Payments Due, 2020	1
Future Minimum Demand Side Management Payments Due, 2021	0
Future Minimum Demand Side Management Payments Due, 2022	0
Future Minimum Demand Side Management Payments Due, 2023	0
Future Minimum Demand Side Management Payments Due, Thereafter	0
Total future minimum demand side management payments due	3
Future Minimum Payments Due, 2019	500
Future Minimum Payments Due, 2020	324
Future Minimum Payments Due, 2021	238
Future Minimum Payments Due, 2022	205
Future Minimum Payments Due, 2023	178
Future Minimum Payments Due, Thereafter	1,773
Total future minimum payments	$ 3,218

Segment Information - Schedule

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Segment Reporting Information [Line Items]
Total revenues	$ 627	$ 619	$ 1,166	$ 1,216
Total interest charges	33	29	66	59
Net income	107	85	171	148
Total assets	9,572		9,572		$ 9,155
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	627	619	1,166	1,216
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(5)	(6)	(10)	(12)
Total interest charges	0	0	0	0
Net income	0	0	0	0
Total assets	(580)		(580)		(487)
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	(5)	(6)	(10)	(12)
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Total revenues	521	510	933	971
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	521	510	933	971
Total interest charges	29	25	58	51
Net income	93	74	139	121
Total assets	8,674		8,674		8,235
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	520	509	931	970
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	1	1	2	1
PGS [Member]
Segment Reporting Information [Line Items]
Total revenues	111	115	243	257
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	111	115	243	257
Total interest charges	4	4	8	8
Net income	14	11	32	27
Total assets	1,478		1,478		$ 1,407
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	107	110	235	246
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 4	$ 5	$ 8	$ 11

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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 520	$ 509	$ 931	$ 970
Total gas revenue	107	110	235	246
Total revenue	627	619	1,166	1,216
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	261	241	467	471
Total gas revenue	36	35	86	91
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	141	140	261	272
Total gas revenue	35	37	77	81
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	42	40	76	78
Total gas revenue	6	6	11	11
Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	17	24	10	23
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	59	64	117	126
Total gas revenue	30	32	61	63
Tampa Electric [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	521	510	933	971
Total gas revenue	0	0	0	0
Total revenue	521	510	933	971
Tampa Electric [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	261	241	467	471
Total gas revenue	0	0	0	0
Tampa Electric [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	141	140	261	272
Total gas revenue	0	0	0	0
Tampa Electric [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	42	40	76	78
Total gas revenue	0	0	0	0
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	17	24	10	23
Tampa Electric [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	60	65	119	127
Total gas revenue	0	0	0	0
PGS [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	111	115	243	257
Total revenue	111	115	243	257
PGS [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	36	35	86	91
PGS [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	35	37	77	81
PGS [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	6	6	11	11
PGS [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
PGS [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	34	37	69	74
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)	(1)	(2)	(1)
Total gas revenue	(4)	(5)	(8)	(11)
Total revenue	(5)	(6)	(10)	(12)
Eliminations [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	0	0	0	0
Eliminations [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	0	0	0	0
Eliminations [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	0	0	0	0
Eliminations [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Eliminations [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)	(1)	(2)	(1)
Total gas revenue	$ (4)	$ (5)	$ (8)	$ (11)

Revenue - Additional Informatio

Revenue - Additional Information (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Regulated Operating Revenue [Abstract]
Remaining performance obligations, transaction price	$ 131	$ 135
Remaining performance obligations, expected year of revenue recognition	2033

Leases - Additional Information

Leases - Additional Information (Detail) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019USD ($)	Jun. 30, 2019USD ($)
Operating Leased Assets [Line Items]
Operating lease, description		TEC has operating leases for buildings, land, telecommunication services and rail cars.
Operating lease, existence of option to extend		true
Operating lease options to extend		options to extend the leases for up to an additional 65 years
Operating lease expense	$ 1	$ 2
Option to purchase assets related to CNG stations		Customers have the option to purchase the assets related to the CNG stations at any time after 2021 by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return
Maximum [Member]
Operating Leased Assets [Line Items]
Operating lease renewal term	67 years	67 years
Minimum [Member]
Operating Leased Assets [Line Items]
Operating lease renewal term	2 years	2 years

Leases - Summary of Lease Asset

Leases - Summary of Lease Assets and Liabilities (Detail) $ in Millions	Jun. 30, 2019USD ($)
Schedule Of Assets And Liabilities Lessee [Line Items]
Total lease liabilities	$ 18
Other Deferred Debits [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Right-of-use asset	17
Other Current Liabilities [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Current	1
Deferred Credits and Other Liabilities [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Long-term	$ 17

Leases - Future Minimum Lease P

Leases - Future Minimum Lease Payments (Detail) $ in Millions	Jun. 30, 2019USD ($)
Leases [Abstract]
Minimum lease payments, 2019	$ 1
Minimum lease payments, 2020	2
Minimum lease payments, 2021	2
Minimum lease payments, 2022	2
Minimum lease payments, 2023	2
Minimum lease payments, Thereafter	35
Minimum lease payments, Total	44
Imputed interest, Total	(26)
Total lease liabilities	$ 18

Leases - Additional Informati_2

Leases - Additional Information Related to Leases (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)
Leases [Abstract]
Operating cash flows for operating leases (millions)	$ 2
Weighted average remaining lease term (years)	48 years
Weighted average discount rate - operating leases	4.30%

Leases - Net Investment in Dire

Leases - Net Investment in Direct Finance Leases (Detail) $ in Millions	Jun. 30, 2019USD ($)
Leases [Abstract]
Total minimum lease payments to be received	$ 35
Less amounts representing estimated executory costs	(13)
Minimum lease payments receivable	22
Less unearned finance lease income	(11)
Net investment in direct finance leases	11
Principal due within one year (included in "Receivables")	(1)
Net investment in direct finance leases - long-term (included in "Other deferred debits")	$ 10

Leases - Future Minimum Direct

Leases - Future Minimum Direct Finance Lease Payments to be Received (Detail) $ in Millions	Jun. 30, 2019USD ($)
Leases [Abstract]
Minimum lease payments to be received, 2019	$ 2
Minimum lease payments to be received, 2020	2
Minimum lease payments to be received, 2021	2
Minimum lease payments to be received, 2022	2
Minimum lease payments to be received, 2023	2
Minimum lease payments to be received, Thereafter	25
Minimum lease payments to be received, Total	35
Executory costs, Total	(13)
Minimum lease payments receivable	$ 22

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	Nov. 06, 2017	Jun. 30, 2019	Dec. 31, 2018
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow		Nov. 30, 2018
Natural Gas Storage and Transportation [Member]
Derivative [Line Items]
Derivative assets			$ 0
Derivative liabilities		$ 1,000,000	$ 0
Natural Gas [Member]
Derivative [Line Items]
Financial hedging moratorium period	5 years

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - Level 3 [Member] - Fair Value, Measurements, Recurring [Member] - USD ($)	Jun. 30, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 0	$ 0
Derivative liabilities	$ 0	$ 0

Subsequent Event - Additional I

Subsequent Event - Additional Information (Detail) - Subsequent Event [Member] - 3.625% Notes [Member] $ in Millions	Jul. 24, 2019USD ($)
Subsequent Event [Line Items]
Debt instrument, maturity year	2050
Unsecured Notes [Member]
Subsequent Event [Line Items]
Aggregate principal amount issued	$ 300
Stated interest rate	3.625%
Debt instrument maturity date	Jun. 15, 2050
Debt instrument, offering date	Jul. 24, 2019