10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No	Exact name of each registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-5007	TAMPA ELECTRIC COMPANY	59-0475140
	(a Florida corporation) TECO Plaza 702 N. Franklin Street Tampa, Florida 33602 (813) 228-1111

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class	Trading symbol(s)	Name of each exchange on which registered
None.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     YES  ☒    NO  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).     YES  ☒    NO  ☐

Indicate by check mark whether Tampa Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark whether Tampa Electric Company has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act).     YES  ☐    NO  ☒

As of November 5, 2019, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

ACRONYMS

Acronyms used in this and other filings with the U.S. Securities and Exchange Commission in 2018 and 2019 include the following:

Term	Meaning
AFUDC	allowance for funds used during construction
AFUDC-debt	debt component of allowance for funds used during construction
AFUDC-equity	equity component of allowance for funds used during construction
AMI	Advanced Metering Infrastructure
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
ASC	Accounting Standards Codification
BACT	Best Available Control Technology
CAD	Canadian dollars
CAIR	Clean Air Interstate Rule
CCRs	coal combustion residuals
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CO2	carbon dioxide
CT	combustion turbine
ECRC	environmental cost recovery clause
Emera	Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada
EPA	U.S. Environmental Protection Agency
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
EUSHI	Emera US Holdings Inc., a wholly owned subsidiary of Emera, which is the sole shareholder of TECO Energy’s common stock
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FPSC	Florida Public Service Commission
GHG	greenhouse gas(es)
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ITCs	investment tax credits
KW	kilowatt(s)
kWac	kilowatt on an alternating current basis
LNG	liquefied natural gas
MBS	mortgage-backed securities
MD&A	the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger	Merger of Merger Sub Company with and into TECO Energy, with TECO Energy as the surviving corporation
MGP	manufactured gas plant
Merger Agreement	Agreement and Plan of Merger dated September 4, 2015, by and among TECO Energy, Emera and Merger Sub Company
Merger Sub Company	Emera US Inc., a Florida corporation
MMBTU	one million British Thermal Units
MRV	market-related value
MW	megawatt(s)
MWH	megawatt-hour(s)
NAV	net asset value
Note	Note to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income

2

Term	Meaning
OPC	Office of Public Counsel
OPEB	other postemployment benefits
Parent	TECO Energy, Inc., the direct parent company of Tampa Electric Company
PBGC	Pension Benefit Guarantee Corporation
PBO	projected benefit obligation
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PRP	potentially responsible party
R&D	research and development
REIT	real estate investment trust
RFP	request for proposal
Regulatory ROE	return on common equity as determined for regulatory purposes
ROE	return on common equity
ROU	right-of-use
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SoBRAs	solar base rate adjustments
SERP	Supplemental Executive Retirement Plan
STIF	short-term investment fund
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TEC	Tampa Electric Company
TECO Energy	TECO Energy, Inc., the direct parent company of Tampa Electric Company
TSI	TECO Services, Inc.
U.S. GAAP	generally accepted accounting principles in the United States
VIE	variable interest entity

3

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	September 30,			December 31,
(millions)	2019			2018
Property, plant and equipment
Utility plant
Electric	$	10,246		$	9,645
Gas		1,945			1,793
Utility plant, at original costs		12,191			11,438
Accumulated depreciation		(3,422	)		(3,214	)
Utility plant, net		8,769			8,224
Other property		13			12
Total property, plant and equipment, net		8,782			8,236
Current assets
Cash and cash equivalents		23			15
Receivables, less allowance for uncollectibles of $2 at September 30, 2019 and December 31, 2018		264			258
Due from affiliates		12			4
Inventories, at average cost
Fuel		39			46
Materials and supplies		108			100
Regulatory assets		55			88
Prepayments and other current assets		9			6
Total current assets		510			517
Deferred debits
Regulatory assets		390			370
Other		58			32
Total deferred debits		448			402
Total assets	$	9,740		$	9,155

The accompanying notes are an integral part of the consolidated condensed financial statements.

4

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	September 30,			December 31,
(millions)	2019			2018
Capitalization
Common stock	$	3,235		$	2,990
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		365			314
Total capital		3,599			3,303
Long-term debt		2,868			2,575
Total capitalization		6,467			5,878
Current liabilities
Notes payable		136			221
Accounts payable		246			251
Due to affiliates		29			24
Customer deposits		131			132
Regulatory liabilities		83			44
Accrued interest		44			16
Accrued taxes		69			13
Other		48			84
Total current liabilities		786			785
Long-term liabilities
Deferred income taxes		740			799
Regulatory liabilities		1,228			1,266
Investment tax credits		172			74
Deferred credits and other liabilities		347			353
Total long-term liabilities		2,487			2,492
Commitments and Contingencies(see Note 8)
Total liabilities and capitalization	$	9,740		$	9,155

The accompanying notes are an integral part of the consolidated condensed financial statements.

5

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended September 30,
(millions)	2019			2018
Revenues
Electric	$	558		$	593
Gas		96			104
Total revenues		654			697
Expenses
Fuel		141			162
Purchased power		22			21
Cost of natural gas sold		30			41
Operations and maintenance		134			153
Depreciation and amortization		95			97
Taxes, other than income		53			55
Total expenses		475			529
Income from operations		179			168
Other income
Allowance for equity funds used during construction		3			6
Other income, net		2			2
Total other income		5			8
Interest charges
Interest expense		36			30
Allowance for borrowed funds used during construction		(1	)		(3	)
Total interest charges		35			27
Income before provision for income taxes		149			149
Provision for income taxes		23			31
Net income	$	126		$	118
Comprehensive income	$	126		$	118

The accompanying notes are an integral part of the consolidated condensed financial statements.

6

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Nine months ended September 30,
(millions)	2019			2018
Revenues
Electric	$	1,489		$	1,563
Gas		331			350
Total revenues		1,820			1,913
Expenses
Fuel		387			417
Purchased power		39			48
Cost of natural gas sold		115			135
Operations and maintenance		396			472
Depreciation and amortization		281			279
Taxes, other than income		155			158
Total expenses		1,373			1,509
Income from operations		447			404
Other income
Allowance for equity funds used during construction		7			7
Other income, net		7			6
Total other income		14			13
Interest charges
Interest expense		104			90
Allowance for borrowed funds used during construction		(3	)		(4	)
Total interest charges		101			86
Income before provision for income taxes		360			331
Provision for income taxes		63			65
Net income	$	297		$	266
Other comprehensive income, net of tax
Gain on cash flow hedges		0			1
Comprehensive income	$	297		$	267

The accompanying notes are an integral part of the consolidated condensed financial statements.

7

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended September 30,
(millions)	2019			2018
Cash flows from operating activities
Net income	$	297		$	266
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		281			279
Deferred income taxes and investment tax credits		17			5
Deferred recovery clauses		37			(28	)
Receivables, less allowance for uncollectibles		(15	)		(49	)
Inventories		(1	)		6
Taxes accrued		59			59
Interest accrued		28			23
Accounts payable		(18	)		(41	)
Regulatory assets and liabilities		0			80
Other		(39	)		(13	)
Cash flows from operating activities		646			587
Cash flows used in investing activities
Capital expenditures		(844	)		(815	)
Cash flows used in investing activities		(844	)		(815	)
Cash flows from financing activities
Equity contributions from Parent		245			335
Proceeds from long-term debt issuance		293			344
Repayment of long-term debt		0			(304	)
Net increase (decrease) in short-term debt		(85	)		106
Dividends to Parent		(247	)		(244	)
Cash flows from financing activities		206			237
Net increase in cash and cash equivalents		8			9
Cash and cash equivalents at beginning of period		15			13
Cash and cash equivalents at end of period	$	23		$	22
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	5		$	27
Reclassification of note payable from short-term to long-term	$	0		$	300

The accompanying notes are an integral part of the consolidated condensed financial statements.

8

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Capital

Unaudited

								Accumulated
								Other
			Common		Retained			Comprehensive			Total
(millions, except share amounts)	Shares		Stock		Earnings			Loss			Capital
Three months ended September 30, 2019
Balance, June 30, 2019		10		3,210	$	345		$	(1	)	$	3,554
Net income						126						126
Equity contributions from Parent			25									25
Dividends to Parent						(107	)					(107	)
Other						1						1
Balance, September 30, 2019		10	$	3,235	$	365		$	(1	)	$	3,599
Three months ended September 30, 2018
Balance, June 30, 2018		10		2,860	$	323		$	(1	)	$	3,182
Net income						118						118
Equity contributions from Parent			120									120
Dividends to Parent						(84	)					(84	)
Balance, September 30, 2018		10	$	2,980	$	357		$	(1	)	$	3,336
Nine months ended September 30, 2019
Balance, December 31, 2018		10		2,990	$	314		$	(1	)	$	3,303
Net income						297						297
Equity contributions from Parent			245									245
Dividends to Parent						(247	)					(247	)
Other						1						1
Balance, September 30, 2019	$	10	$	3,235	$	365		$	(1	)	$	3,599
Nine months ended September 30, 2018
Balance, December 31, 2017		10		2,645	$	335		$	(2	)	$	2,978
Net income						266						266
Other comprehensive income, after    tax									1			1
Equity contributions from Parent			335									335
Dividends to Parent						(244	)					(244	)
Balance, September 30, 2018		10	$	2,980	$	357		$	(1	)	$	3,336

The accompanying notes are an integral part of the consolidated condensed financial statements.

9

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

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 September 30, 2019 and December 31, 2018, and the results of operations and cash flows for the periods ended September 30, 2019 and September 30, 2018. The results of operations for the three and nine months ended September 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 $262 million and $226 million as of September 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 September 30, 2019 and December 31, 2018, unbilled revenues of $70 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 $32 million and $33 million for the three months ended September 30, 2019 and 2018, respectively, and $88 million and $90 million for the nine months ended September 30, 2019 and 2018, respectively.

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), including all related amendments, using the modified retrospective approach. The standard requires lessees to recognize leases on the balance sheet for all leases with a term of longer than twelve months and disclose key information about leasing arrangements.

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.

10

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 nine months ended September 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 for further detail.

Targeted Improvements to Accounting for Hedging Activities

On January 1, 2019, TEC adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. There was no impact on the consolidated condensed financial statements as a result of the adoption of this standard.

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. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. TEC early adopted the standard effective January 1, 2019 and elected to apply the guidance prospectively. There was no material impact on the consolidated condensed financial statements as a result of the adoption of this standard.

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, with updates noted below.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019 and will be applied using a modified retrospective approach. Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018. TEC will not early adopt the standard. TEC does not expect a material impact on its consolidated financial statements as a result of adoption of this standard.

11

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 up to 600 MW of cost-effective 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. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue 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 approved the tariffs on this SoBRA filing on October 17, 2019. TEC expects to file its fourth SoBRA petition for the January 1, 2021 tranche in June 2020.

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. 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) while keeping customer rates stable in 2018. Beginning on April 1, 2018, the agreement authorized Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits of $103 million. As a result, during 2018, Tampa Electric recorded O&M expense and a reduction of the storm reserve regulatory asset of $47 million and recorded O&M expense for the increase in the storm reserve regulatory liability of $56 million to reflect effective recovery of the storm costs due to the allowed netting of storm cost recovery with tax reform benefits. On August 20, 2018, the FPSC approved lowering base rates by $103 million annually beginning on January 1, 2019 as a result of lower tax expense.

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, Tampa Electric will refund $12 million to customers in January 2020, resulting in minimal impact to the Consolidated Condensed Statements of Income.

In the third quarter of 2019, Tampa Electric incurred storm restoration preparation costs for Hurricane Dorian estimated to be approximately $8 million, which was charged to the storm reserve regulatory liability.

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.

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Regulatory Assets and Liabilities

Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred or the advance recovery of expenditures for approved costs.

Details of the regulatory assets and liabilities are presented in the following table:

Regulatory Assets and Liabilities
(millions)	September 30, 2019		December 31, 2018
Regulatory assets:
Regulatory tax asset (1)	$	74	$	56
Cost-recovery clauses (2)		30		55
Environmental remediation (3)		27		23
Postretirement benefits (4)		285		295
Storm reserve (5)		2		3
Asset retirement obligation (6)		19		18
Other		8		8
Total regulatory assets		445		458
Less: Current portion		55		88
Long-term regulatory assets	$	390	$	370
Regulatory liabilities:
Regulatory tax liability (7)	$	710	$	715
Cost-recovery clauses (2)		30		17
Accumulated reserve - cost of removal (8)		507		513
Storm reserve (9)		48		56
Other		16		9
Total regulatory liabilities		1,311		1,310
Less: Current portion		83		44
Long-term regulatory liabilities	$	1,228	$	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 are being recovered on a dollar-for-dollar basis during 2019.

(6) This asset is related to costs associated with an asset retirement obligation, which is a legal obligation for the future retirement of certain tangible, long-lived assets. This regulatory asset does not earn a return because it is offset with related assets and liabilities within rate base. It is recovered and removed as the obligation is settled and removed as the activities for the retirement of the related assets have been completed.

(7) 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. This regulatory tax liability also includes TEC’s estimate for the state corporate tax rate change enacted in the third quarter of 2019. See Note 4 to the TEC Consolidated Financial Statements 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

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customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

(9) See “Tampa Electric Storm Restoration Cost Recovery” discussion above for information regarding this reserve.

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.

Change in Florida Corporate Income Tax Rate

On September 12, 2019, the state of Florida issued a corporate tax rate reduction from 5.5% to 4.458% effective January 1, 2019 through December 31, 2021. Through September 30, 2019, TEC recorded a $3 million tax benefit, of which $2 million is expected to be refunded to customers and is reflected as a regulatory liability. In addition, TEC recorded an estimated $5 million decrease to its deferred tax liability and an increase to its regulatory tax liability due to the revaluation of TEC’s state deferred income tax balances at 4.458% over the 2019-2021 period. 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 nine months ended September 30, 2019 and 2018 were 17.5% and 19.6%, respectively. The September 30, 2019 effective tax rate is an estimate of the annual effective income tax rate. TEC’s effective tax rate for the nine months ended September 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 for further information regarding the regulatory tax liability.

Unrecognized Tax Benefits

As of September 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 September 30, 2019 and December 31, 2018, that, if recognized, would reduce TEC’s effective tax rate.

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5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. The following table presents detail related to TECO Energy’s periodic benefit cost for pension and other postretirement benefits. Amounts disclosed for TECO Energy’s pension benefits include the amounts related to its qualified pension plan and non-qualified, non-contributory SERP and Restoration Plan.

TECO Energy Benefit Cost
(millions)	Pension Benefits								Other Postretirement Benefits
Three months ended September 30,	2019				2018				2019			2018
Components of net periodic benefit cost
Service cost	$	5			$	5			$	1		$	0
Interest cost		8				8				3			1
Expected return on assets		(12	)			(13	)			0			0
Amortization of:
Actuarial (gain) loss		3				5				(2	)		1
Net periodic benefit cost	$	4			$	5			$	2		$	2
Nine months ended September 30,
Components of net periodic benefit cost
Service cost	$	15			$	16			$	1		$	1
Interest cost		24				22				6			5
Expected return on assets		(38	)			(37	)			0			0
Amortization of:
Actuarial (gain) loss		11				14				(2	)		0
Settlement cost		1		(1)		2		(1)		0			0
Net periodic benefit cost	$	13			$	17			$	5		$	6

 (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 September 30, 2019 and 2018, respectively, was $2 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 nine months ended September 30, 2019 and 2018, respectively, was $9 million and $9 million for pension benefits, and $5 million and $6 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 $20 million and $10 million to its qualified pension plan in the nine months ended September 30, 2019 and 2018, respectively. TEC’s portion of these contributions was $15 million and $8 million, respectively. TECO Energy and TEC do not expect to make additional contributions to the pension plan for the remainder of 2019.

Included in the benefit cost discussed above, for the three and nine months ended September 30, 2019, $3 million and $9 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses were reclassified by TEC from regulatory assets to the Consolidated Condensed Statement of Income, compared with $4 million and $14 million for the three and nine months ended September 30, 2018, respectively.

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6. Short-Term Debt

Details of TEC’s credit facilities and related borrowings are presented in the following table:

	September 30, 2019						December 31, 2018
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	325	$	71	$	1	$	325	$	131	$	1
3-year accounts    receivable facility (3)		150		65		0		150		90		0
Total	$	475	$	136	$	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 September 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 September 30, 2019 and December 31, 2018 was 2.96% and 3.14%, respectively.

7. Long-Term Debt

Fair Value of Long-Term Debt

At September 30, 2019, TEC’s long-term debt had a carrying amount of $2,868 million and an estimated fair market value of $3,385 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(see Note 13 for information regarding the fair value hierarchy).

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.

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of September 30, 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.

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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 various purchases as disclosed below, including payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at September 30, 2019:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total
2019	$	6	$	50	$	186	$	85	$	0	$	1	$	1	$	329
2020		0		198		127		217		6		2		1		551
2021		0		210		28		49		7		3		0		297
2022		0		212		8		3		10		3		0		236
2023		0		189		1		1		13		3		0		207
Thereafter		0		2,206		0		0		86		53		0		2,345
Total future minimum payments	$	6	$	3,065	$	350	$	355	$	122	$	65	$	2	$	3,965

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements and has certain restrictive covenants in specific agreements and debt instruments. At September 30, 2019, TEC was in compliance with all required financial covenants.

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9. Segment Information

(millions)	Tampa								Tampa Electric
Three months ended September 30,	Electric		PGS		Eliminations				Company
2019
Revenues - external	$	558	$	96	$	0			$	654
Intracompany sales		1		5		(6	)			0
Total revenues		559		101		(6	)			654
Total interest charges		30		5		0				35
Net income	$	116	$	10	$	0			$	126
2018
Revenues - external	$	593	$	104	$	0			$	697
Intracompany sales		1		7		(8	)			0
Total revenues		594		111		(8	)			697
Total interest charges		23		4		0				27
Net income	$	109	$	9	$	0			$	118
Nine months ended September 30,
2019
Revenues - external	$	1,489	$	331	$	0			$	1,820
Intracompany sales		3		13		(16	)			0
Total revenues		1,492		344		(16	)			1,820
Total interest charges		88		13		0				101
Net income	$	255	$	42	$	0			$	297
2018
Revenues - external	$	1,563	$	350	$	0			$	1,913
Intracompany sales		2		18		(20	)			0
Total revenues		1,565		368		(20	)			1,913
Total interest charges		75		11		0				86
Net income	$	230	$	36	$	0			$	266
Total assets at September 30, 2019	$	8,801	$	1,531	$	(592	)	(1)	$	9,740
Total assets at December 31, 2018	$	8,235	$	1,407	$	(487	)	(1)	$	9,155

(1) Amounts primarily relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

10. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
Three months ended September 30, 2019	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	325		$	0	$	0		$	325
Commercial		160			0		0			160
Industrial		41			0		0			41
Regulatory deferrals and unbilled revenue		(31	)		0		0			(31	)
Other (1)		64			0		(1	)		63
Total electric revenue		559			0		(1	)		558
Gas revenue
Residential		0			30		0			30
Commercial		0			32		0			32
Industrial (2)		0			5		0			5
Other (3)		0			34		(5	)		29
Total gas revenue		0			101		(5	)		96
Total revenue	$	559		$	101	$	(6	)	$	654
Three months ended September 30, 2018
Electric revenue

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Residential	$	331		$	0	$	0		$	331
Commercial		163			0		0			163
Industrial		43			0		0			43
Regulatory deferrals and unbilled revenue		(10	)		0		0			(10	)
Other (1)		67			0		(1	)		66
Total electric revenue		594			0		(1	)		593
Gas revenue
Residential		0			29		0			29
Commercial		0			34		0			34
Industrial (2)		0			4		0			4
Other (3)		0			44		(7	)		37
Total gas revenue		0			111		(7	)		104
Total revenue	$	594		$	111	$	(8	)	$	697
(millions)	Tampa								Tampa Electric
Nine months ended September 30, 2019	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	792		$	0	$	0		$	792
Commercial		421			0		0			421
Industrial		117			0		0			117
Regulatory deferrals and unbilled revenue		(21	)		0		0			(21	)
Other (1)		183			0		(3	)		180
Total electric revenue		1,492			0		(3	)		1,489
Gas revenue
Residential		0			116		0			116
Commercial		0			109		0			109
Industrial (2)		0			16		0			16
Other (3)		0			103		(13	)		90
Total gas revenue		0			344		(13	)		331
Total revenue	$	1,492		$	344	$	(16	)	$	1,820
Nine months ended September 30, 2018
Electric revenue
Residential	$	802		$	0	$	0		$	802
Commercial		435			0		0			435
Industrial		121			0		0			121
Regulatory deferrals and unbilled revenue		13			0		0			13
Other (1)		194			0		(2	)		192
Total electric revenue		1,565			0		(2	)		1,563
Gas revenue
Residential		0			120		0			120
Commercial		0			115		0			115
Industrial (2)		0			15		0			15
Other (3)		0			118		(18	)		100
Total gas revenue		0			368		(18	)		350
Total revenue	$	1,565		$	368	$	(20	)	$	1,913

(1)    Other 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

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of September 30, 2019 and December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $129 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

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amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2033.

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 are 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	September 30, 2019
Right-of-use asset	Other deferred debits	$	28
Lease liabilities
Current	Other current liabilities	$	1
Long-term	Deferred credits and other liabilities		28
Total lease liabilities		$	29

TEC has recorded operating lease expense for the three and nine months ended September 30, 2019 of $1 million and $3 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 September 30, 2019: 

(millions)	2019		2020		2021		2022		2023		Thereafter		Total
Minimum lease payments	$	1	$	2	$	3	$	3	$	3	$	53	$	65
Less imputed interest														(36	)
Total future minimum payments													$	29

Additional information related to TEC’s leases is as follows: 

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Nine months ended September 30,	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	3
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions)	$	11
Weighted average remaining lease term (years)		43
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)	September 30, 2019
Total minimum lease payments to be received	$	34
Less amounts representing estimated executory costs		(13	)
Minimum lease payments receivable	$	21
Less unearned finance lease income		(11	)
Net investment in direct finance leases	$	10
Principal due within one year (included in "Receivables")		(2	)
Net investment in direct finance leases - long-term (included in "Other deferred debits")	$	8

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 year five of the agreement, which is in 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 September 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	$	1	$	2	$	2	$	2	$	2	$	25	$	34
Less executory costs														(13	)
Total minimum lease payments receivable													$	21

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 includes a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022 (see Note 3). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had $1

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million of derivative liabilitiesrelated to natural gas storage and transportation optimization as of September 30, 2019 and zero derivative assets and liabilities on its Consolidated Condensed Balance Sheets as of December 31, 2018.

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 September 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 September 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.  

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 September 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

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value of TEC’s short-term debt is determined using Level 2 measurements. See Note 7 for information regarding the fair value of long-term debt.

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Item 2. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on TEC's current expectations and assumptions, and TEC does not undertake to update that information or any other information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions or legislation by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; general economic conditions affecting customer growth and energy sales; economic conditions affecting the Florida economy; weather variations and customer energy usage patterns affecting sales and operating costs and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost; natural gas demand; and the ability of TEC to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under "Risk Factors" in TEC’s Annual Report on Form 10-K for the year ended December 31, 2018.

Earnings Summary - Unaudited

		Three months ended September 30,						Nine months ended September 30,
(millions)		2019			2018			2019			2018
Revenues
	Tampa Electric	$	559		$	594		$	1,492		$	1,565
	PGS		101			111			344			368
	Eliminations		(6	)		(8	)		(16	)		(20	)
	TEC	$	654		$	697		$	1,820		$	1,913
Net income
	Tampa Electric	$	116		$	109		$	255		$	230
	PGS		10			9			42			36
	TEC	$	126		$	118		$	297		$	266

Operating Results

Three Months Ended September 30, 2019

Third quarter 2019 net income was $126 million, compared to $118 million in the third quarter of 2018. In the third quarter of 2018, as permitted by the FPSC, TEC offset the impact of estimated 2018 tax reform benefits with a $32 million charge to O&M expense related to storm costs (see Note 3 to the TEC Consolidated Condensed Financial Statements). Beginning on January 1, 2019, as approved by the FPSC, base rates were lowered due to the impact of tax reform by an estimated $103 million annually ($27 million in the third quarter of 2019) at Tampa Electric and $12 million annually ($3 million in the third quarter of 2019) at PGS. Therefore, the decrease in revenue due to lower base rates from tax reform in 2019 was largely offset by lower O&M expense from the absence of the offsetting of tax reform benefits in 2018, resulting in minimal impact to the Consolidated Condensed Statements of Income. Excluding the impact of tax reform and 2018 storm costs, third quarter 2019 results were impacted by higher base revenue, primarily related to the in-service of solar generation projects, and lower income taxes, partially offset by higher O&M expense, higher interest expense and lower AFUDC. See below for further detail.

Nine Months Ended September 30, 2019

Year-to-date 2019 net income was $297 million, compared to $266 million in the 2018 year-to-date period. Year-to-date 2018, as permitted by the FPSC, TEC offset the impact of estimated 2018 tax reform benefits with a $80 million charge to O&M expense related to storm costs (see Note 3 to the TEC Consolidated Condensed Financial Statements). Beginning on January 1, 2019, as approved by the FPSC, base rates were lowered due to the impact of tax reform by $103 million annually ($74 million in the nine months ended September 30, 2019) at Tampa Electric and $12 million annually ($8 million in the nine months ended September 30, 2019) at PGS. Therefore, the decrease in revenue due to lower base rates from tax reform in 2019 was largely offset by lower O&M expense from the absence of the offsetting of tax reform benefits in 2018, resulting in minimal impact to the Consolidated Condensed Statements of Income. Excluding the impact of tax reform and storm costs, year-to-date 2019 results were impacted by higher base revenue, primarily related to the in-service of solar generation projects and customer growth, partially offset by higher interest expense. See below for further detail.

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Operating Company Results

Amounts included in the operating company discussions below are pre-tax, except net income and income taxes.

Electric Division

Tampa Electric’s net income for the third quarter of 2019 was $116 million, compared with $109 million for the same period in 2018. Excluding the impact of tax reform and storm costs as disclosed above, results primarily reflected higher base revenues and lower income taxes, partially offset by higher depreciation expense, higher interest expense and lower AFUDC.

Revenues, excluding the impact of tax reform as disclosed above, were $8 million lower than in the same period in 2018, driven by lower clause revenues partially offset by higher base revenues related to the in-service of solar generation projects and customer growth. Results reflect a 2% increase in number of customers at September 30, 2019 compared to September 30, 2018. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in the third quarter of 2019 were 4% above normal and 3% below the 2018 period. Total retail net energy for load, which is a calendar measurement of energy output, in the third quarter of 2019 was consistent with the same period in 2018, reflecting customer growth offset by unfavorable weather in the third quarter of 2019 compared to 2018. Base revenues are energy sales excluding revenues from clauses, gross receipts taxes and franchise fees. Clauses, gross receipts taxes and franchise fees do not have a material effect on net income as these revenues substantially represent a dollar-for-dollar recovery of clauses and other pass-through costs.

O&M expense, excluding all FPSC-approved cost-recovery clauses and the impact of regulatory agreements related to the recovery of storm costs and tax reform benefits as discussed above and in Note 4 to the TEC Consolidated Condensed Financial Statements, was $2 million higher than in the 2018 quarter. See Note 3 to the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and storm settlement agreement. Depreciation and amortization expense increased $7 million in the third quarter of 2019 from normal additions to facilities to reliably serve customers and the in-service of solar generation projects.

Tampa Electric’s 2019 net income year-to-date was $255 million, compared with $230 million for the same period in 2018. Excluding the impact of tax reform and storm costs as disclosed above, results reflected higher base revenues and lower income taxes, partially offset by higher depreciation expense and higher interest expense. 

Revenues, excluding the impact of tax reform as disclosed above, were $1 million higher than in the same year-to-date period in 2018, driven by in-service of solar generation projects and customer growth, partially offset by lower clause revenue. Total degree days in Tampa Electric's service area in the year-to-date period of 2019 were 6% above normal and 2% below the 2018 period. Total net energy for load increased 1% in the year-to-date period of 2019 compared with the same period in 2018.

In the 2019 year-to-date period, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of regulatory agreements related to the recovery of storm costs and tax reform benefits as discussed above and in Note 4 to the TEC Consolidated Condensed Financial Statements, was consistent with the 2018 year-to-date period primarily reflecting higher transmission and distribution costs as a result of line clearance costs, pole inspection activities and serving customer growth, offset by lower generation costs as a result of lower outage costs and stronger unit performance. See Note 3 to the TEC Consolidated Condensed Financial Statements for further information regarding Tampa Electric’s tax reform and storm settlement agreement. Depreciation and amortization expense increased $18 million in 2019 from normal additions to facilities to reliably serve customers and the in-service of solar generation projects.

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Tampa Electric’s regulated operatingstatistics for the threeand ninemonths ended September 30, 2019 and 2018were as follows:

(millions, except customers and total degree days)	Operating Revenues									Kilowatt-Hours Billed
Three months ended September 30,	2019			2018			% Change			2019		2018		% Change
By Customer Type
Residential (1)	$	325		$	331			(2	)		2,976		2,944		1
Commercial (1)		160			163			(2	)		1,791		1,791		0
Industrial (1)		41			43			(5	)		519		546		(5	)
Other (1)		49			49			0			513		526		(2	)
Regulatory deferrals and unbilled revenue (2)		(31	)		(10	)		210
Total retail sales of electricity		544			576			(6	)		5,799		5,807		(0	)
Off system sales of electricity		1			2			(50	)		35		53		(34	)
Other operating revenue		14			16			(13	)
Total revenues	$	559		$	594			(6	)		5,834		5,860		(0	)
Customers at September 30, (thousands)		775			760			2
Retail net energy for load (kilowatt hours)		6,095			6,095			0
Total degree days		1,744			1,806			(3	)
Nine months ended September 30,
By Customer Type
Residential (1)	$	792		$	802			(1	)		7,281		7,098		3
Commercial (1)		421			435			(3	)		4,704		4,698		0
Industrial (1)		117			121			(3	)		1,520		1,524		(0	)
Other (1)		135			139			(3	)		1,435		1,447		(1	)
Regulatory deferrals and unbilled revenue (2)		(21	)		13			(262	)
Total retail sales of electricity		1,444			1,510			(4	)		14,940		14,767		1
Off system sales of electricity		3			10			(70	)		80		258		(69	)
Other operating revenue		45			45			0
Total revenues	$	1,492		$	1,565			(5	)		15,020		15,025		(0	)
Customers at September 30, (thousands)		775			760			2
Retail net energy for load (kilowatt-hours)		15,997			15,837			1
Total degree days		3,706			3,785			(2	)

(1) Reflects a billing cycle measurement.

(2) Primarily reflects unbilled revenue, which incorporates a calendar measurement, and postings for clause recovery deferrals.

Natural Gas Division

PGS had net income of $10 million for the third quarter, compared with $9 million in the third quarter of 2018. Results reflect a 3.0% higher number of customers in the third quarter of 2019 compared to the third quarter of 2018. Excluding the impact of tax reform as disclosed above, revenues were $8 million lower than the prior year quarter primarily due to lower off-system sales, partially offset by customer growth. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses and the impact of deferring tax reform benefits in 2018, was $3 million higher than in 2018 primarily due to higher employee benefit costs.  As a result of the tax reform settlement approved by the FPSC in 2018, in the third quarter of 2018 PGS reversed $5 million of deferred tax reform related O&M expense recorded through the second quarter of 2018 and recorded $6 million of amortization expense related to the regulatory asset associated with MGP environmental remediation costs.  Depreciation and amortization decreased $9 million due to the accelerated amortization expense in 2018 and reduced depreciation rates in 2019 related to the 2018 settlement agreement (see Note 3 to the TEC Consolidated Condensed Financial Statements), which were partially offset by normal asset growth.   

PGS had net income of $42 million for the 2019 year-to-date period, compared with $36 million in the 2018 period. Excluding the impact of tax reform as disclosed above, revenues were $16 million lower than the prior year due to lower off-system sales and lower clause-related revenue. Excluding the impact of tax reform, base revenues were $1 million higher than 2018 primarily due to customer growth being partially offset by unfavorable weather in 2019. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $3 million higher than in 2018 primarily due to higher employee benefit and self-insurance

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costs. Depreciation and amortization decreased $16 million due to accelerated amortization of the regulatory asset associated with MGP environmental remediation costs in 2018 and reduced depreciation rates in 2019 related to the 2018 settlement agreement (see Note 3 to the TEC Consolidated Condensed Financial Statements), which were partially offset by normal asset growth.  Return on investment in the cast iron and bare steel replacement rider was $3 million higher in the 2019 period. 

PGS’s regulated operating statistics for the three and nine months ended September 30, 2019 and 2018 were as follows:

(millions, except customers)	Operating Revenues							Therms
Three months ended September 30,	2019		2018		% Change			2019		2018		% Change
By Customer Type
Residential	$	30	$	29		3			12		13		(8	)
Commercial		32		34		(6	)		116		115		1
Industrial		4		3		33			106		89		19
Power generation		1		1		0			225		222		1
Off system sales		15		26		(42	)		54		75		(28	)
Other operating revenues		16		16		0
Total	$	98	$	109		(10	)		513		514		(0	)
By Sales Type
System supply	$	52	$	62		(16	)		73		93		(22	)
Transportation		30		31		(3	)		440		421		5
Other operating revenues		16		16		0
Total	$	98	$	109		(10	)		513		514		(0	)
Customers at September 30, (thousands)		400		388		3
Nine months ended September 30,
By Customer Type
Residential	$	116	$	120		(3	)		63		66		(5	)
Commercial		109		115		(5	)		384		384		0
Industrial		12		11		9			316		267		18
Power generation		4		4		0			642		592		8
Off system sales		42		57		(26	)		141		161		(12	)
Other operating revenues		52		52		0
Total	$	335	$	359		(7	)		1,546		1,470		5
By Sales Type
System supply	$	186	$	206		(10	)		222		245		(9	)
Transportation		97		101		(4	)		1,324		1,225		8
Other operating revenues		52		52		0
Total	$	335	$	359		(7	)		1,546		1,470		5
Customers at September 30, (thousands)		400		388		3

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Other Income

For the third quarter of 2019 and 2018, TEC’s other income was $5 million and $8 million, respectively, and included AFUDC-equity of $3 million and $6 million, respectively. The decrease in AFUDC-equity is due to a lower number of solar projects under construction in the third quarter of 2019. For the year-to-date periods in 2019 and 2018, TEC’s other income was $14 million and $13 million, respectively, and included AFUDC-equity of $7 million for both periods.

Interest Expense

For the third quarter of 2019 and 2018, TEC’s interest expense, excluding AFUDC-debt, was $36 million and $30 million, respectively. For the year-to-date periods in 2019 and 2018, TEC’s interest expense, excluding AFUDC-debt, was $104 million and $90 million, respectively. The increase is due to an increase in long-term borrowings.

Income Taxes

The provisions for income taxes were $63 million and $65 million for the nine months ended September 30, 2019 and 2018, respectively, and $23 million and $31 million for the three months ended September 30, 2019 and 2018, respectively. The provision for income taxes for both periods decreased mainly due to higher amortization of the regulatory liability resulting from tax reform, higher investment tax credits related to solar projects and the tax benefit resulting from the Florida corporate income tax rate change (see Note 4 to the TEC Consolidated Condensed Financial Statements).

Regulatory Matters

Tampa Electric - Storm Protection Plan Cost Recovery Clause

During the 2019 legislative session, the Florida legislature passed, and the governor signed, a bill that creates a new cost recovery clause, called the storm protection plan cost recovery clause. This new clause establishes a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. The FPSC issued a rule to implement this clause on October 3, 2019. Subject to final approval of the FPSC rule, Tampa Electric expects to file a storm protection plan and associated rates with the FPSC in 2020.

PGS - AFUDC

In July 2019, the FPSC approved a petition filed by PGS for authority to record AFUDC at an annual rate of 5.97% as part of its plans to develop three expansion projects in 2019 and 2020.

Liquidity and Capital Resources

The table below sets forth the September 30, 2019 liquidity, cash balances and amounts available under the TEC credit facilities.

(millions)
Credit facilities	$	475
Drawn amounts/letters of credit		137
Available credit facilities		338
Cash and short-term investments		23
Total liquidity	$	361

Cash Impacts Related to Operating Activities  

Cash flows from operating activities for the nine months ended September 30, 2019 were $646 million, an increase of $59 million compared to the same period in 2018. The increase is primarily due to lower fuel under-recoveries, higher conservation clause over-recoveries, increases in revenue collected for the in-service of solar generation projects, and the timing of accounts payable, partially offset by lower base rates due to the impact of tax reform, lower environmental clause over-recoveries and higher inventory balances due to decreased coal consumption.

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Cash Impacts Related to Financing Activities

Cash flows from financing activities for the nine months ended September 30, 2019 resulted in net cash inflows of $206 million. TEC received $245 million of equity contributions and $293 million of proceeds from long-term debt (see Note 7 to the TEC Consolidated Condensed Financial Statements for further information regarding TEC’s long-term debt issuance). These increases in cash flows were partially offset by dividend payments to Parent of $247 million and a net decrease of borrowings under credit agreements of $85 million (see Note 6 to the TEC Consolidated Condensed Financial Statements for further information regarding TEC’s credit agreements).  

Covenants in Financing Agreements

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At September 30, 2019, TEC was in compliance with all applicable financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at September 30, 2019. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants

			Calculation at
Instrument (1)	Financial Covenant (2)	Requirement/Restriction	September 30, 2019
Credit facility - $325 million	Debt/capital	Cannot exceed 65%	46%
Accounts receivable credit facility - $150 million	Debt/capital	Cannot exceed 65%	46%

(1) See Note 6 to the TEC Consolidated Condensed Financial Statements for details of the credit facilities.

(2) As defined in each applicable instrument.

Credit Ratings of Senior Unsecured Debt at September 30, 2019

	S&P	Moody’s	Fitch (1)
Credit ratings of senior unsecured debt	BBB+	A3	A
Credit ratings outlook	Negative	Stable	Stable

(1) Assigned by Fitch Ratings on June 13, 2019.

Certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TEC Consolidated Condensed Financial Statements).

Commitments and Contingencies

See Note 8 to the TEC Consolidated Condensed Financial Statements for information regarding TEC’s commitments and contingencies as of September 30, 2019.

Capital Investments

In 2019, TEC expects to invest approximately $1,300 million in capital projects, excluding AFUDC-debt and equity. This represents an increase of approximately $90 million from the 2019 forecasted capital investments amount disclosed in TEC’s Annual Report on Form 10-K for the year ended December 31, 2018. The increase is primarily due to timing of solar construction.

Tampa Electric expects to spend approximately $850 million during 2017 through 2021 related to the 600 MW solar project recoverable under the SoBRAs as discussed in Note 3 to the TEC Consolidated Condensed Financial Statements, approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, which received final state approval on July 25, 2019, and approximately $235 million during 2018 through 2022 for its AMI project.

TEC intends to fund those capital expenditures with available cash on hand, cash generated from operating activities, and cash from equity contributions and debt issuances so that Tampa Electric and PGS maintain their capital structures consistent with existing regulatory arrangements. Actual capital expenditures could vary materially due to changes in schedule, costs for materials or labor or changes in plans.

Fair Value Measurements

The valuation methods used to determine fair value are described in Notes 7 and 13 to the TEC Consolidated Condensed Financial Statements. In addition, TEC considered the impact of nonperformance risk in determining the fair value of

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derivatives. TEC considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At September 30, 2019, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

Critical accounting policies and estimates have not materially changed in 2019. For further discussion of critical accounting policies and estimates, see TEC’s Annual Report on Form 10-K for the year ended December 31, 2018.

Environmental Compliance

Carbon Reductions and GHG

On June 19, 2019, EPA released the final rule to replace the Clean Power Plan (CPP), named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing fossil fuel-fired electric generating units (EGUs).  The rule provides emission guidelines to replace the CPP and inform the development of state plans to reduce GHG emissions from certain coal-fired EGUs.  In the guidelines, EPA determined that heat rate improvement measures are the best system of emission reduction for existing coal-fired EGUs. This action also provides implementing regulations for emission guidelines issued under Section 111(d) of the Clean Air Act. Tampa Electric has emission units that are subject to this rule and is preparing to engage in the development of a state plan that could be finalized by 2020.

The outcome of expected litigation and the rule-making process and its impact on TEC’s businesses is uncertain at this time; however, it could result in increased operating costs and/or decreased generation at Tampa Electric’s coal-fired plants. Depending on how the state’s plan could be developed and implemented, the ACE rule could cause an increase in rates charged to customers, which could curtail sales.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information required by Item 3 is omitted pursuant to General Instruction H(2) of Form 10-Q.

Item 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures. TEC’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TEC’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2019. Based on such evaluation, TEC’s principal financial officer and principal executive officer have concluded that, as of September 30, 2019, TEC’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. There was no change in TEC’s internal controls over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TEC’s internal control over financial reporting that occurred during TEC’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

From time to time, TEC is 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. For a discussion of legal proceedings and environmental matters, see Note 8 of the TEC Consolidated Condensed Financial Statements.

Item 6. EXHIBITS

Exhibit
No.	Description
3.1	Restated Articles of Incorporation of Tampa Electric Company, as amended on November 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company). (P)	*
3.2	Bylaws of Tampa Electric Company, as amended effective February 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of Tampa Electric Company).	*
4.1	Fifteenth Supplemental Indenture dated as of July 24, 2019, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.13, Form 8-K dated July 24, 2019 of Tampa Electric Company).	*
31.1	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

(1) This certification accompanies the Quarterly Report on Form 10-Q and is not filed as part of it.

* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and TEC were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: November 7, 2019	By:	/s/ Gregory W. Blunden
		Gregory W. Blunden
		Senior Vice President-Finance and Accounting, Treasurer and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Nancy Tower, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2019	/s/  NANCY TOWER
		NANCY TOWER
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Gregory W. Blunden, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2019	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting, Treasurer and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-32

Exhibit 32

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended September 30, 2019 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2019	/s/  NANCY TOWER
		NANCY TOWER
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	November 7, 2019	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting, Treasurer and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-Q and shall not be considered filed as part of the Form 10-Q.

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Employee Postretirement Benefits (Tables)

9 Months Ended

Sep. 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 September 30,	2019				2018				2019			2018
Components of net periodic benefit cost
Service cost	$	5			$	5			$	1		$	0
Interest cost		8				8				3			1
Expected return on assets		(12	)			(13	)			0			0
Amortization of:
Actuarial (gain) loss		3				5				(2	)		1
Net periodic benefit cost	$	4			$	5			$	2		$	2
Nine months ended September 30,
Components of net periodic benefit cost
Service cost	$	15			$	16			$	1		$	1
Interest cost		24				22				6			5
Expected return on assets		(38	)			(37	)			0			0
Amortization of:
Actuarial (gain) loss		11				14				(2	)		0
Settlement cost		1		(1)		2		(1)		0			0
Net periodic benefit cost	$	13			$	17			$	5		$	6

 (1)Represents TECO Energy’s SERP and Restoration Plan settlement charges as a result of the prior retirements of certain executives.

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Revenue (Tables)

9 Months Ended

Sep. 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 September 30, 2019	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	325		$	0	$	0		$	325
Commercial		160			0		0			160
Industrial		41			0		0			41
Regulatory deferrals and unbilled revenue		(31	)		0		0			(31	)
Other (1)		64			0		(1	)		63
Total electric revenue		559			0		(1	)		558
Gas revenue
Residential		0			30		0			30
Commercial		0			32		0			32
Industrial (2)		0			5		0			5
Other (3)		0			34		(5	)		29
Total gas revenue		0			101		(5	)		96
Total revenue	$	559		$	101	$	(6	)	$	654
Three months ended September 30, 2018
Electric revenue
Residential	$	331		$	0	$	0		$	331
Commercial		163			0		0			163
Industrial		43			0		0			43
Regulatory deferrals and unbilled revenue		(10	)		0		0			(10	)
Other (1)		67			0		(1	)		66
Total electric revenue		594			0		(1	)		593
Gas revenue
Residential		0			29		0			29
Commercial		0			34		0			34
Industrial (2)		0			4		0			4
Other (3)		0			44		(7	)		37
Total gas revenue		0			111		(7	)		104
Total revenue	$	594		$	111	$	(8	)	$	697
(millions)	Tampa								Tampa Electric
Nine months ended September 30, 2019	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	792		$	0	$	0		$	792
Commercial		421			0		0			421
Industrial		117			0		0			117
Regulatory deferrals and unbilled revenue		(21	)		0		0			(21	)
Other (1)		183			0		(3	)		180
Total electric revenue		1,492			0		(3	)		1,489
Gas revenue
Residential		0			116		0			116
Commercial		0			109		0			109
Industrial (2)		0			16		0			16
Other (3)		0			103		(13	)		90
Total gas revenue		0			344		(13	)		331
Total revenue	$	1,492		$	344	$	(16	)	$	1,820
Nine months ended September 30, 2018
Electric revenue
Residential	$	802		$	0	$	0		$	802
Commercial		435			0		0			435
Industrial		121			0		0			121
Regulatory deferrals and unbilled revenue		13			0		0			13
Other (1)		194			0		(2	)		192
Total electric revenue		1,565			0		(2	)		1,563
Gas revenue
Residential		0			120		0			120
Commercial		0			115		0			115
Industrial (2)		0			15		0			15
Other (3)		0			118		(18	)		100
Total gas revenue		0			368		(18	)		350
Total revenue	$	1,565		$	368	$	(20	)	$	1,913

(1)    Other 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.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 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 September 30, 2019 and December 31, 2018, and the results of operations and cash flows for the periods ended September 30, 2019 and September 30, 2018. The results of operations for the three and nine months ended September 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 $262 million and $226 million as of September 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 September 30, 2019 and December 31, 2018, unbilled revenues of $70 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 $32 million and $33 million for the three months ended September 30, 2019 and 2018, respectively, and $88 million and $90 million for the nine months ended September 30, 2019 and 2018, respectively.

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

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Leases - Future Minimum Lease Payments (Detail) $ in Millions	Sep. 30, 2019 USD ($)
Leases [Abstract]
Minimum lease payments, 2019	$ 1
Minimum lease payments, 2020	2
Minimum lease payments, 2021	3
Minimum lease payments, 2022	3
Minimum lease payments, 2023	3
Minimum lease payments, Thereafter	53
Minimum lease payments, Total	65
Imputed interest, Total	(36)
Total lease liabilities	$ 29

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Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 558	$ 593	$ 1,489	$ 1,563
Total gas revenue	96	104	331	350
Total revenue	654	697	1,820	1,913
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	325	331	792	802
Total gas revenue	30	29	116	120
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	160	163	421	435
Total gas revenue	32	34	109	115
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	41	43	117	121
Total gas revenue	5	4	16	15
Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(31)	(10)	(21)	13
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	63	66	180	192
Total gas revenue	29	37	90	100
Tampa Electric [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	559	594	1,492	1,565
Total gas revenue	0	0	0	0
Total revenue	559	594	1,492	1,565
Tampa Electric [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	325	331	792	802
Total gas revenue	0	0	0	0
Tampa Electric [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	160	163	421	435
Total gas revenue	0	0	0	0
Tampa Electric [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	41	43	117	121
Total gas revenue	0	0	0	0
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(31)	(10)	(21)	13
Tampa Electric [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	64	67	183	194
Total gas revenue	0	0	0	0
PGS [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	101	111	344	368
Total revenue	101	111	344	368
PGS [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	30	29	116	120
PGS [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	32	34	109	115
PGS [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	5	4	16	15
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	44	103	118
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)	(1)	(3)	(2)
Total gas revenue	(5)	(7)	(13)	(18)
Total revenue	(6)	(8)	(16)	(20)
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)	(3)	(2)
Total gas revenue	$ (5)	$ (7)	$ (13)	$ (18)

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Fair Value Measurements - Additional Information (Detail) - Level 3 [Member] - Fair Value, Measurements, Recurring [Member] - USD ($)	Sep. 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

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Short-Term Debt - Credit Facilities and Related Borrowings (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 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

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Federal statutory tax rate			21.00%			35.00%
Asset expensing			100.00%
Provision for income taxes	$ 23	$ 31	$ 63	$ 65
Unrecognized tax benefits	8		8		$ 8
Unrecognized tax benefit that would reduce effective tax rate	8		$ 8		$ 8
Tampa Electric [Member]
Income Taxes [Line Items]
Effective tax rate			17.50%	19.60%
Florida [Member]
Income Taxes [Line Items]
Federal statutory tax rate			4.458%		5.50%
Provision for income taxes			$ (3)
Customer refund liability	$ 2		2
Decrease in deferred income taxes offset to regulatory liability			$ 5

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Income Taxes

9 Months Ended

Sep. 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.

Change in Florida Corporate Income Tax Rate

On September 12, 2019, the state of Florida issued a corporate tax rate reduction from 5.5% to 4.458% effective January 1, 2019 through December 31, 2021. Through September 30, 2019, TEC recorded a $3 million tax benefit, of which $2 million is expected to be refunded to customers and is reflected as a regulatory liability. In addition, TEC recorded an estimated $5 million decrease to its deferred tax liability and an increase to its regulatory tax liability due to the revaluation of TEC’s state deferred income tax balances at 4.458% over the 2019-2021 period. 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 nine months ended September 30, 2019 and 2018 were 17.5% and 19.6%, respectively. The September 30, 2019 effective tax rate is an estimate of the annual effective income tax rate. TEC’s effective tax rate for the nine months ended September 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 for further information regarding the regulatory tax liability.

Unrecognized Tax Benefits

As of September 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 September 30, 2019 and December 31, 2018, that, if recognized, would reduce TEC’s effective tax rate.

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Commitments and Contingencies

9 Months Ended

Sep. 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 September 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 various purchases as disclosed below, including payment obligations under contractual agreements for fuel, fuel transportation and power purchases that are recovered from customers under regulatory clauses. The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at September 30, 2019:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total
2019	$	6	$	50	$	186	$	85	$	0	$	1	$	1	$	329
2020		0		198		127		217		6		2		1		551
2021		0		210		28		49		7		3		0		297
2022		0		212		8		3		10		3		0		236
2023		0		189		1		1		13		3		0		207
Thereafter		0		2,206		0		0		86		53		0		2,345
Total future minimum payments	$	6	$	3,065	$	350	$	355	$	122	$	65	$	2	$	3,965

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements and has certain restrictive covenants in specific agreements and debt instruments. At September 30, 2019, TEC was in compliance with all required financial covenants.

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Accounting for Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 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 includes a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022 (see Note 3). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had $1 million of derivative liabilities related to natural gas storage and transportation optimization as of September 30, 2019 and zero derivative assets and liabilities on its Consolidated Condensed Balance Sheets as of December 31, 2018.      

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 September 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 September 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.  

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Short-Term Debt - Credit Facilities and Related Borrowings (Detail) - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Line Of Credit Facility [Line Items]
Credit Facilities	$ 475,000,000	$ 475,000,000
Borrowings Outstanding	136,000,000	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	71,000,000	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	65,000,000	90,000,000
Letters of Credit Outstanding	$ 0	$ 0

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

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Fair Value Measurements

9 Months Ended

Sep. 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 September 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 for information regarding the fair value of long-term debt.

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Employee Postretirement Benefits

9 Months Ended

Sep. 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 September 30,	2019				2018				2019			2018
Components of net periodic benefit cost
Service cost	$	5			$	5			$	1		$	0
Interest cost		8				8				3			1
Expected return on assets		(12	)			(13	)			0			0
Amortization of:
Actuarial (gain) loss		3				5				(2	)		1
Net periodic benefit cost	$	4			$	5			$	2		$	2
Nine months ended September 30,
Components of net periodic benefit cost
Service cost	$	15			$	16			$	1		$	1
Interest cost		24				22				6			5
Expected return on assets		(38	)			(37	)			0			0
Amortization of:
Actuarial (gain) loss		11				14				(2	)		0
Settlement cost		1		(1)		2		(1)		0			0
Net periodic benefit cost	$	13			$	17			$	5		$	6

 (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 September 30, 2019 and 2018, respectively, was $2 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 nine months ended September 30, 2019 and 2018, respectively, was $9 million and $9 million for pension benefits, and $5 million and $6 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 $20 million and $10 million to its qualified pension plan in the nine months ended September 30, 2019 and 2018, respectively. TEC’s portion of these contributions was $15 million and $8 million, respectively. TECO Energy and TEC do not expect to make additional contributions to the pension plan for the remainder of 2019.

Included in the benefit cost discussed above, for the three and nine months ended September 30, 2019, $3 million and $9 million, respectively, of unamortized prior service benefits and costs and actuarial gains and losses were reclassified by TEC from regulatory assets to the Consolidated Condensed Statement of Income, compared with $4 million and $14 million for the three and nine months ended September 30, 2018, respectively.

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Segment Information

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Segment Information

9. Segment Information

(millions)	Tampa								Tampa Electric
Three months ended September 30,	Electric		PGS		Eliminations				Company
2019
Revenues - external	$	558	$	96	$	0			$	654
Intracompany sales		1		5		(6	)			0
Total revenues		559		101		(6	)			654
Total interest charges		30		5		0				35
Net income	$	116	$	10	$	0			$	126
2018
Revenues - external	$	593	$	104	$	0			$	697
Intracompany sales		1		7		(8	)			0
Total revenues		594		111		(8	)			697
Total interest charges		23		4		0				27
Net income	$	109	$	9	$	0			$	118
Nine months ended September 30,
2019
Revenues - external	$	1,489	$	331	$	0			$	1,820
Intracompany sales		3		13		(16	)			0
Total revenues		1,492		344		(16	)			1,820
Total interest charges		88		13		0				101
Net income	$	255	$	42	$	0			$	297
2018
Revenues - external	$	1,563	$	350	$	0			$	1,913
Intracompany sales		2		18		(20	)			0
Total revenues		1,565		368		(20	)			1,913
Total interest charges		75		11		0				86
Net income	$	230	$	36	$	0			$	266
Total assets at September 30, 2019	$	8,801	$	1,531	$	(592	)	(1)	$	9,740
Total assets at December 31, 2018	$	8,235	$	1,407	$	(487	)	(1)	$	9,155

(1) Amounts primarily relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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Short-Term Debt (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Short-Term Debt Credit Facilities and Related Borrowings

Details of TEC’s credit facilities and related borrowings are presented in the following table:

	September 30, 2019						December 31, 2018
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	325	$	71	$	1	$	325	$	131	$	1
3-year accounts    receivable facility (3)		150		65		0		150		90		0
Total	$	475	$	136	$	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.

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Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Summary of Lease Assets and Liabilities

(millions)	Classification	September 30, 2019
Right-of-use asset	Other deferred debits	$	28
Lease liabilities
Current	Other current liabilities	$	1
Long-term	Deferred credits and other liabilities		28
Total lease liabilities		$	29

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 September 30, 2019: 

(millions)	2019		2020		2021		2022		2023		Thereafter		Total
Minimum lease payments	$	1	$	2	$	3	$	3	$	3	$	53	$	65
Less imputed interest														(36	)
Total future minimum payments													$	29

Additional Information Related to Leases

Additional information related to TEC’s leases is as follows: 

Nine months ended September 30,	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	3
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions)	$	11
Weighted average remaining lease term (years)		43
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)	September 30, 2019
Total minimum lease payments to be received	$	34
Less amounts representing estimated executory costs		(13	)
Minimum lease payments receivable	$	21
Less unearned finance lease income		(11	)
Net investment in direct finance leases	$	10
Principal due within one year (included in "Receivables")		(2	)
Net investment in direct finance leases - long-term (included in "Other deferred debits")	$	8

Future Minimum Direct Finance Lease Payments to be Received

As of September 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	$	1	$	2	$	2	$	2	$	2	$	25	$	34
Less executory costs														(13	)
Total minimum lease payments receivable													$	21

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Consolidated Condensed Statements of Capital (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Beginning balance	$ 3,554	$ 3,182	$ 3,303	$ 2,978
Net income	126	118	297	266
Other comprehensive income, after tax				1
Equity contributions from Parent	25	120	245	335
Dividends to Parent	(107)	(84)	(247)	(244)
Other	1		1
Ending balance	3,599	3,336	3,599	3,336
Common Stock [Member]
Beginning balance	$ 3,210	$ 2,860	$ 2,990	$ 2,645
Beginning balance	10	10	10	10
Equity contributions from Parent	$ 25	$ 120	$ 245	$ 335
Ending balance	$ 3,235	$ 2,980	$ 3,235	$ 2,980
Ending balance	10	10	10	10
Retained Earnings [Member]
Beginning balance	$ 345	$ 323	$ 314	$ 335
Net income	126	118	297	266
Dividends to Parent	(107)	(84)	(247)	(244)
Other	1		1
Ending balance	365	357	365	357
Accumulated Other Comprehensive Loss [Member]
Beginning balance	(1)	(1)	(1)	(2)
Other comprehensive income, after tax				1
Ending balance	$ (1)	$ (1)	$ (1)	$ (1)

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Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Property, plant and equipment
Utility plant, at original costs	$ 12,191	$ 11,438
Accumulated depreciation	(3,422)	(3,214)
Utility plant, net	8,769	8,224
Other property	13	12
Total property, plant and equipment, net	8,782	8,236
Current assets
Cash and cash equivalents	23	15
Receivables, less allowance for uncollectibles of $2 at September 30, 2019 and December 31, 2018	264	258
Due from affiliates	12	4
Inventories, at average cost
Regulatory assets	55	88
Prepayments and other current assets	9	6
Total current assets	510	517
Deferred debits
Regulatory assets	390	370
Other	58	32
Total deferred debits	448	402
Total assets	9,740	9,155
Capitalization
Common stock	3,235	2,990
Accumulated other comprehensive loss	(1)	(1)
Retained earnings	365	314
Total capital	3,599	3,303
Long-term debt	2,868	2,575
Total capitalization	6,467	5,878
Current liabilities
Notes payable	136	221
Accounts payable	246	251
Due to affiliates	29	24
Customer deposits	131	132
Regulatory liabilities	83	44
Accrued interest	44	16
Accrued taxes	69	13
Other	48	84
Total current liabilities	786	785
Long-term liabilities
Deferred income taxes	740	799
Regulatory liabilities	1,228	1,266
Investment tax credits	172	74
Deferred credits and other liabilities	347	353
Total long-term liabilities	2,487	2,492
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	9,740	9,155
Fuel [Member]
Inventories, at average cost
Utility inventories	39	46
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	108	100
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	10,246	9,645
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 1,945	$ 1,793

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Leases - Summary of Lease Assets and Liabilities (Detail) $ in Millions	Sep. 30, 2019 USD ($)
Schedule Of Assets And Liabilities Lessee [Line Items]
Total lease liabilities	$ 29
Other Deferred Debits [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Right-of-use asset	28
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	$ 28

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Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Segment Reporting Information [Line Items]
Total revenues	$ 654	$ 697	$ 1,820	$ 1,913
Total interest charges	35	27	101	86
Net income	126	118	297	266
Total assets	9,740		9,740		$ 9,155
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	654	697	1,820	1,913
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(6)	(8)	(16)	(20)
Total interest charges	0	0	0	0
Net income	0	0	0	0
Total assets	(592)		(592)		(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	(6)	(8)	(16)	(20)
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Total revenues	559	594	1,492	1,565
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	559	594	1,492	1,565
Total interest charges	30	23	88	75
Net income	116	109	255	230
Total assets	8,801		8,801		8,235
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	558	593	1,489	1,563
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	1	1	3	2
PGS [Member]
Segment Reporting Information [Line Items]
Total revenues	101	111	344	368
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	101	111	344	368
Total interest charges	5	4	13	11
Net income	10	9	42	36
Total assets	1,531		1,531		$ 1,407
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	96	104	331	350
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 5	$ 7	$ 13	$ 18

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Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 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

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Long-Term Debt

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At September 30, 2019, TEC’s long-term debt had a carrying amount of $2,868 million and an estimated fair market value of $3,385 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(see Note 13 for information regarding the fair value hierarchy).

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.

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Leases

9 Months Ended

Sep. 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 are 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	September 30, 2019
Right-of-use asset	Other deferred debits	$	28
Lease liabilities
Current	Other current liabilities	$	1
Long-term	Deferred credits and other liabilities		28
Total lease liabilities		$	29

TEC has recorded operating lease expense for the three and nine months ended September 30, 2019 of $1 million and $3 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 September 30, 2019: 

(millions)	2019		2020		2021		2022		2023		Thereafter		Total
Minimum lease payments	$	1	$	2	$	3	$	3	$	3	$	53	$	65
Less imputed interest														(36	)
Total future minimum payments													$	29

Additional information related to TEC’s leases is as follows: 

Nine months ended September 30,	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	3
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions)	$	11
Weighted average remaining lease term (years)		43
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)	September 30, 2019
Total minimum lease payments to be received	$	34
Less amounts representing estimated executory costs		(13	)
Minimum lease payments receivable	$	21
Less unearned finance lease income		(11	)
Net investment in direct finance leases	$	10
Principal due within one year (included in "Receivables")		(2	)
Net investment in direct finance leases - long-term (included in "Other deferred debits")	$	8

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 year five of the agreement, which is in 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 September 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	$	1	$	2	$	2	$	2	$	2	$	25	$	34
Less executory costs														(13	)
Total minimum lease payments receivable													$	21

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Short-Term Debt - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Line Of Credit Facility [Line Items]
Weighted-average interest rate	2.96%	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%

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Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 2	$ 4	$ 9	$ 9
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	2	2	5	6
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	5	5	15	16
Interest cost	8	8	24	22
Expected return on assets	(12)	(13)	(38)	(37)
Amortization of:
Actuarial (gain) loss	3	5	11	14
Settlement cost			1	2
Net periodic benefit cost	4	5	13	17
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	0	1	1
Interest cost	3	1	6	5
Expected return on assets	0	0	0	0
Amortization of:
Actuarial (gain) loss	(2)	1	(2)	0
Settlement cost			0	0
Net periodic benefit cost	$ 2	$ 2	$ 5	$ 6

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Regulatory - Additional Information (Detail) $ in Millions							3 Months Ended			9 Months Ended		12 Months Ended
	Jun. 28, 2019 USD ($) MW	Apr. 09, 2019 USD ($)	Aug. 20, 2018 USD ($)	Jun. 29, 2018 USD ($) MW	Dec. 12, 2017 USD ($) MW	Sep. 27, 2017 USD ($) MW	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)	Oct. 31, 2013 USD ($)
Public Utilities General Disclosures [Line Items]
Tax reform benefits							$ (23)	$ (31)		$ (63)	$ (65)
O&M expense							134	$ 153		396	472
Regulatory liability							1,311			1,311		$ 1,310
Amount refundable on settlement		$ 12
Regulatory asset for amortization										0	$ (80)
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
Hurricane Dorian [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration preparation costs							8
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. 06, 2017
Solar energy capacity | MW						600
Solar generation capacity investments						$ 850
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

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Regulatory (Tables)

9 Months Ended

Sep. 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)	September 30, 2019		December 31, 2018
Regulatory assets:
Regulatory tax asset (1)	$	74	$	56
Cost-recovery clauses (2)		30		55
Environmental remediation (3)		27		23
Postretirement benefits (4)		285		295
Storm reserve (5)		2		3
Asset retirement obligation (6)		19		18
Other		8		8
Total regulatory assets		445		458
Less: Current portion		55		88
Long-term regulatory assets	$	390	$	370
Regulatory liabilities:
Regulatory tax liability (7)	$	710	$	715
Cost-recovery clauses (2)		30		17
Accumulated reserve - cost of removal (8)		507		513
Storm reserve (9)		48		56
Other		16		9
Total regulatory liabilities		1,311		1,310
Less: Current portion		83		44
Long-term regulatory liabilities	$	1,228	$	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 are being recovered on a dollar-for-dollar basis during 2019.

(6) This asset is related to costs associated with an asset retirement obligation, which is a legal obligation for the future retirement of certain tangible, long-lived assets. This regulatory asset does not earn a return because it is offset with related assets and liabilities within rate base. It is recovered and removed as the obligation is settled and removed as the activities for the retirement of the related assets have been completed.

(7) 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. This regulatory tax liability also includes TEC’s estimate for the state corporate tax rate change enacted in the third quarter of 2019. See Note 4 to the TEC Consolidated Financial Statements for further information.

(8) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

(9) See “Tampa Electric Storm Restoration Cost Recovery” discussion above for information regarding this reserve.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Schedule of Segment Information

(millions)	Tampa								Tampa Electric
Three months ended September 30,	Electric		PGS		Eliminations				Company
2019
Revenues - external	$	558	$	96	$	0			$	654
Intracompany sales		1		5		(6	)			0
Total revenues		559		101		(6	)			654
Total interest charges		30		5		0				35
Net income	$	116	$	10	$	0			$	126
2018
Revenues - external	$	593	$	104	$	0			$	697
Intracompany sales		1		7		(8	)			0
Total revenues		594		111		(8	)			697
Total interest charges		23		4		0				27
Net income	$	109	$	9	$	0			$	118
Nine months ended September 30,
2019
Revenues - external	$	1,489	$	331	$	0			$	1,820
Intracompany sales		3		13		(16	)			0
Total revenues		1,492		344		(16	)			1,820
Total interest charges		88		13		0				101
Net income	$	255	$	42	$	0			$	297
2018
Revenues - external	$	1,563	$	350	$	0			$	1,913
Intracompany sales		2		18		(20	)			0
Total revenues		1,565		368		(20	)			1,913
Total interest charges		75		11		0				86
Net income	$	230	$	36	$	0			$	266
Total assets at September 30, 2019	$	8,801	$	1,531	$	(592	)	(1)	$	9,740
Total assets at December 31, 2018	$	8,235	$	1,407	$	(487	)	(1)	$	9,155

(1) Amounts primarily relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.

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New Accounting Pronouncements - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Jan. 01, 2019
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Lease liability	$ 29
ASU 2016-02 [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Right-of-use asset		$ 20
Lease liability		$ 20

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Leases - Additional Information Related to Leases (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Leases [Abstract]
Operating cash flows for operating leases (millions)	$ 3
Operating leases (millions)	$ 11
Weighted average remaining lease term (years)	48 years
Weighted average discount rate - operating leases	4.30%

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Revenue - Additional Information (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Regulated Operating Revenue [Abstract]
Remaining performance obligations, transaction price	$ 129	$ 135
Remaining performance obligations, expected year of revenue recognition	2033

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Commitments and Contingencies - Additional Information (Detail) $ in Millions	Sep. 30, 2019 USD ($)
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 28

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New Accounting Pronouncements

9 Months Ended

Sep. 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), including all related amendments, using the modified retrospective approach. The standard requires lessees to recognize leases on the balance sheet for all leases with a term of longer than twelve months and disclose key information about leasing arrangements.

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 nine months ended September 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 for further detail.

Targeted Improvements to Accounting for Hedging Activities

On January 1, 2019, TEC adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. There was no impact on the consolidated condensed financial statements as a result of the adoption of this standard.

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. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. TEC early adopted the standard effective January 1, 2019 and elected to apply the guidance prospectively. There was no material impact on the consolidated condensed financial statements as a result of the adoption of this standard.

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, with updates noted below.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019 and will be applied using a modified retrospective approach. Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018. TEC will not early adopt the standard. TEC does not expect a material impact on its consolidated financial statements as a result of adoption of this standard.

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Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues
Electric	$ 558	$ 593	$ 1,489	$ 1,563
Gas	96	104	331	350
Total revenues	654	697	1,820	1,913
Expenses
Fuel	141	162	387	417
Purchased power	22	21	39	48
Cost of natural gas sold	30	41	115	135
Operations and maintenance	134	153	396	472
Depreciation and amortization	95	97	281	279
Taxes, other than income	53	55	155	158
Total expenses	475	529	1,373	1,509
Income from operations	179	168	447	404
Other income
Allowance for equity funds used during construction	3	6	7	7
Other income, net	2	2	7	6
Total other income	5	8	14	13
Interest charges
Interest expense	36	30	104	90
Allowance for borrowed funds used during construction	(1)	(3)	(3)	(4)
Total interest charges	35	27	101	86
Income before provision for income taxes	149	149	360	331
Provision for income taxes	23	31	63	65
Net income	126	118	297	266
Other comprehensive income, net of tax
Gain on cash flow hedges			0	1
Comprehensive income	$ 126	$ 118	$ 297	$ 267

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Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Accounting Policies [Abstract]
Receivables from contracts with customers	$ 262		$ 262		$ 226
Unbilled revenues	70		70		$ 67
Franchise fees and gross receipts taxes	$ 32	$ 33	$ 88	$ 90

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 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 September 30, 2019 and December 31, 2018, and the results of operations and cash flows for the periods ended September 30, 2019 and September 30, 2018. The results of operations for the three and nine months ended September 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 $262 million and $226 million as of September 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 September 30, 2019 and December 31, 2018, unbilled revenues of $70 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 $32 million and $33 million for the three months ended September 30, 2019 and 2018, respectively, and $88 million and $90 million for the nine months ended September 30, 2019 and 2018, respectively.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 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 September 30, 2019:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total
2019	$	6	$	50	$	186	$	85	$	0	$	1	$	1	$	329
2020		0		198		127		217		6		2		1		551
2021		0		210		28		49		7		3		0		297
2022		0		212		8		3		10		3		0		236
2023		0		189		1		1		13		3		0		207
Thereafter		0		2,206		0		0		86		53		0		2,345
Total future minimum payments	$	6	$	3,065	$	350	$	355	$	122	$	65	$	2	$	3,965

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Leases - Additional Information (Detail) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)
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	$ 3
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 year five of the agreement, which is in 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

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Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Sep. 30, 2019 USD ($)
Other Commitments [Line Items]
2019	$ 329
2020	551
2021	297
2022	236
2023	207
Thereafter	2,345
Total future minimum payments	3,965
Purchased Power [Member]
Other Commitments [Line Items]
2019	6
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total future minimum payments	6
Transportation [Member]
Other Commitments [Line Items]
2019	50
2020	198
2021	210
2022	212
2023	189
Thereafter	2,206
Total future minimum payments	3,065
Capital Projects [Member]
Other Commitments [Line Items]
2019	186
2020	127
2021	28
2022	8
2023	1
Thereafter	0
Total future minimum payments	350
Fuel and Gas Supply [Member]
Other Commitments [Line Items]
2019	85
2020	217
2021	49
2022	3
2023	1
Thereafter	0
Total future minimum payments	355
Long-term Service Agreements [Member]
Other Commitments [Line Items]
2019	0
2020	6
2021	7
2022	10
2023	13
Thereafter	86
Total future minimum payments	122
Operating Leases [Member]
Other Commitments [Line Items]
2019	1
2020	2
2021	3
2022	3
2023	3
Thereafter	53
Total future minimum payments	65
Demand Side Management [Member]
Other Commitments [Line Items]
2019	1
2020	1
2021	0
2022	0
2023	0
Thereafter	0
Total future minimum payments	$ 2

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Leases - Net Investment in Direct Finance Leases (Detail) $ in Millions	Sep. 30, 2019 USD ($)
Leases [Abstract]
Total minimum lease payments to be received	$ 34
Less amounts representing estimated executory costs	(13)
Minimum lease payments receivable	21
Less unearned finance lease income	(11)
Net investment in direct finance leases	10
Principal due within one year (included in "Receivables")	(2)
Net investment in direct finance leases - long-term (included in "Other deferred debits")	$ 8

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Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash flows from operating activities
Net income	$ 297	$ 266
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	281	279
Deferred income taxes and investment tax credits	17	5
Deferred recovery clauses	37	(28)
Receivables, less allowance for uncollectibles	(15)	(49)
Inventories	(1)	6
Taxes accrued	59	59
Interest accrued	28	23
Accounts payable	(18)	(41)
Regulatory assets and liabilities	0	80
Other	(39)	(13)
Cash flows from operating activities	646	587
Cash flows used in investing activities
Capital expenditures	(844)	(815)
Cash flows used in investing activities	(844)	(815)
Cash flows from financing activities
Equity contributions from Parent	245	335
Proceeds from long-term debt issuance	293	344
Repayment of long-term debt	0	(304)
Net increase (decrease) in short-term debt	(85)	106
Dividends to Parent	(247)	(244)
Cash flows from financing activities	206	237
Net increase in cash and cash equivalents	8	9
Cash and cash equivalents at beginning of period	15	13
Cash and cash equivalents at end of period	23	22
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	5	27
Reclassification of note payable from short-term to long-term	$ 0	$ 300

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Nov. 05, 2019
Cover [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Interactive Data Current	Yes
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	FL
Entity Tax Identification Number	59-0475140
Entity Incorporation, State or Country Code	FL
Entity Address, Postal Zip Code	33602
City Area Code	813
Local Phone Number	228-1111
Document Quarterly Report	true
Document Transition Report	false
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

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Regulatory

9 Months Ended

Sep. 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 up to 600 MW of cost-effective 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. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue 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 approved the tariffs on this SoBRA filing on October 17, 2019. TEC expects to file its fourth SoBRA petition for the January 1, 2021 tranche in June 2020.

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. 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) while keeping customer rates stable in 2018. Beginning on April 1, 2018, the agreement authorized Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits of $103 million. As a result, during 2018, Tampa Electric recorded O&M expense and a reduction of the storm reserve regulatory asset of $47 million and recorded O&M expense for the increase in the storm reserve regulatory liability of $56 million to reflect effective recovery of the storm costs due to the allowed netting of storm cost recovery with tax reform benefits. On August 20, 2018, the FPSC approved lowering base rates by $103 million annually beginning on January 1, 2019 as a result of lower tax expense.

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, Tampa Electric will refund $12 million to customers in January 2020, resulting in minimal impact to the Consolidated Condensed Statements of Income.

In the third quarter of 2019, Tampa Electric incurred storm restoration preparation costs for Hurricane Dorian estimated to be approximately $8 million, which was charged to the storm reserve regulatory liability.

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)	September 30, 2019		December 31, 2018
Regulatory assets:
Regulatory tax asset (1)	$	74	$	56
Cost-recovery clauses (2)		30		55
Environmental remediation (3)		27		23
Postretirement benefits (4)		285		295
Storm reserve (5)		2		3
Asset retirement obligation (6)		19		18
Other		8		8
Total regulatory assets		445		458
Less: Current portion		55		88
Long-term regulatory assets	$	390	$	370
Regulatory liabilities:
Regulatory tax liability (7)	$	710	$	715
Cost-recovery clauses (2)		30		17
Accumulated reserve - cost of removal (8)		507		513
Storm reserve (9)		48		56
Other		16		9
Total regulatory liabilities		1,311		1,310
Less: Current portion		83		44
Long-term regulatory liabilities	$	1,228	$	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 are being recovered on a dollar-for-dollar basis during 2019.

(6) This asset is related to costs associated with an asset retirement obligation, which is a legal obligation for the future retirement of certain tangible, long-lived assets. This regulatory asset does not earn a return because it is offset with related assets and liabilities within rate base. It is recovered and removed as the obligation is settled and removed as the activities for the retirement of the related assets have been completed.

(7) 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. This regulatory tax liability also includes TEC’s estimate for the state corporate tax rate change enacted in the third quarter of 2019. See Note 4 to the TEC Consolidated Financial Statements for further information.

(8) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation. AROs are costs for legally required removal of property, plant and equipment. Non-ARO cost of removal represents estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as costs of removal are incurred.

(9) See “Tampa Electric Storm Restoration Cost Recovery” discussion above for information regarding this reserve.

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Leases - Future Minimum Direct Finance Lease Payments to be Received (Detail) $ in Millions	Sep. 30, 2019 USD ($)
Leases [Abstract]
Minimum lease payments to be received, 2019	$ 1
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	34
Executory costs, Total	(13)
Minimum lease payments receivable	$ 21

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Short-Term Debt

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Short-Term Debt

6. Short-Term Debt

Details of TEC’s credit facilities and related borrowings are presented in the following table:

	September 30, 2019						December 31, 2018
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	325	$	71	$	1	$	325	$	131	$	1
3-year accounts    receivable facility (3)		150		65		0		150		90		0
Total	$	475	$	136	$	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 September 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 September 30, 2019 and December 31, 2018 was 2.96% and 3.14%, respectively.

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Revenue

9 Months Ended

Sep. 30, 2019

Revenues [Abstract]

Revenue

10. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
Three months ended September 30, 2019	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	325		$	0	$	0		$	325
Commercial		160			0		0			160
Industrial		41			0		0			41
Regulatory deferrals and unbilled revenue		(31	)		0		0			(31	)
Other (1)		64			0		(1	)		63
Total electric revenue		559			0		(1	)		558
Gas revenue
Residential		0			30		0			30
Commercial		0			32		0			32
Industrial (2)		0			5		0			5
Other (3)		0			34		(5	)		29
Total gas revenue		0			101		(5	)		96
Total revenue	$	559		$	101	$	(6	)	$	654
Three months ended September 30, 2018
Electric revenue
Residential	$	331		$	0	$	0		$	331
Commercial		163			0		0			163
Industrial		43			0		0			43
Regulatory deferrals and unbilled revenue		(10	)		0		0			(10	)
Other (1)		67			0		(1	)		66
Total electric revenue		594			0		(1	)		593
Gas revenue
Residential		0			29		0			29
Commercial		0			34		0			34
Industrial (2)		0			4		0			4
Other (3)		0			44		(7	)		37
Total gas revenue		0			111		(7	)		104
Total revenue	$	594		$	111	$	(8	)	$	697
(millions)	Tampa								Tampa Electric
Nine months ended September 30, 2019	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	792		$	0	$	0		$	792
Commercial		421			0		0			421
Industrial		117			0		0			117
Regulatory deferrals and unbilled revenue		(21	)		0		0			(21	)
Other (1)		183			0		(3	)		180
Total electric revenue		1,492			0		(3	)		1,489
Gas revenue
Residential		0			116		0			116
Commercial		0			109		0			109
Industrial (2)		0			16		0			16
Other (3)		0			103		(13	)		90
Total gas revenue		0			344		(13	)		331
Total revenue	$	1,492		$	344	$	(16	)	$	1,820
Nine months ended September 30, 2018
Electric revenue
Residential	$	802		$	0	$	0		$	802
Commercial		435			0		0			435
Industrial		121			0		0			121
Regulatory deferrals and unbilled revenue		13			0		0			13
Other (1)		194			0		(2	)		192
Total electric revenue		1,565			0		(2	)		1,563
Gas revenue
Residential		0			120		0			120
Commercial		0			115		0			115
Industrial (2)		0			15		0			15
Other (3)		0			118		(18	)		100
Total gas revenue		0			368		(18	)		350
Total revenue	$	1,565		$	368	$	(20	)	$	1,913

(1)    Other 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

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms. As of September 30, 2019 and December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $129 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. 

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Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Defined Benefit Plan Disclosure [Line Items]
Reclassification of regulatory assets to net income as part of periodic benefit cost	$ 3	$ 4	$ 9	$ 14
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	2	4	$ 9	9
Employer contributions			15	8
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	4	5	$ 13	17
Discount rate			4.34%
Employer contributions			$ 20	10
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	2	2	5	6
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 2	$ 2	$ 5	$ 6
Discount rate			4.38%

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Regulatory assets:
Regulatory assets	$ 445	$ 458
Less: Current portion	55	88
Long-term regulatory assets	390	370
Regulatory liabilities:
Regulatory liabilities	1,311	1,310
Less: Current portion	83	44
Long-term regulatory liabilities	1,228	1,266
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	74	56
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	30	55
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	27	23
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	285	295
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	2	3
Asset Retirement Obligation [Member]
Regulatory assets:
Regulatory assets	19	18
Other [Member]
Regulatory assets:
Regulatory assets	8	8
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	710	715
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	30	17
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	48	56
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	507	513
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 16	$ 9

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Jul. 24, 2019	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt		$ 2,868	$ 2,575
Estimated fair value		$ 3,385	$ 2,686
3.625% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2050
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