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 June 30, 2021  

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 August 10, 2021, 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 2021 and 2020 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
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
ASC	Accounting Standards Codification
CAD	Canadian dollars
CAIR	Clean Air Interstate Rule
CCRs	coal combustion residuals
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CO2	carbon dioxide
COVID-19	coronavirus disease 2019
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
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
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ITCs	investment tax credits
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 Emera US Inc. with and into TECO Energy, with TECO Energy as the surviving corporation
MGP	manufactured gas plant
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
NPNS	normal purchase normal sale
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income
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

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Term	Meaning
PRP	potentially responsible party
R&D	research and development
REIT	real estate investment trust
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
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

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This Form 10-Q contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by TEC include those factors discussed herein, including those factors discussed with respect to TEC in (1) TEC’s 2020 Annual Report on Form 10-K in (a) Part I, Item 1A. Risk Factors, (b) Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, Item 8. Financial Statements: Note 8, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (b) Part 1, Item 1. Financial Statements: Note 8, Commitments and Contingencies, and (3) other factors discussed in filings with the SEC by TEC. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. TEC does not undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Form 10-Q.

All references to “dollars” and “$” in this and other filings with the U.S. Securities and Exchange Commission are references to U.S. dollars, unless specifically indicated otherwise.

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	June 30,			December 31,
(millions)	2021			2020
Property, plant and equipment
Utility plant
Electric	$	11,876		$	11,486
Gas		2,470			2,332
Utility plant, at original costs		14,346			13,818
Accumulated depreciation		(3,897	)		(3,712	)
Utility plant, net		10,449			10,106
Other property		14			14
Total property, plant and equipment, net		10,463			10,120
Current assets
Cash and cash equivalents		24			10
Receivables, less allowance for credit losses of $8 and $7 at June 30, 2021 and December 31, 2020, respectively		265			219
Due from affiliates		10			11
Inventories, at average cost
Fuel		21			26
Materials and supplies		114			107
Regulatory assets		68			79
Prepayments and other current assets		22			10
Total current assets		524			462
Deferred debits
Regulatory assets		413			406
Other		59			60
Total deferred debits		472			466
Total assets	$	11,459		$	11,048

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	June 30,			December 31,
(millions)	2021			2020
Capitalization
Common stock	$	4,180		$	3,890
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		359			327
Total capital		4,538			4,216
Long-term debt		3,385			2,594
Total capitalization		7,923			6,810
Current liabilities
Long-term debt due within one year		0			278
Notes payable		410			775
Accounts payable		264			321
Due to affiliates		22			46
Customer deposits		130			130
Regulatory liabilities		57			67
Accrued interest		20			13
Accrued taxes		63			22
Other		43			57
Total current liabilities		1,009			1,709
Long-term liabilities
Deferred income taxes		815			783
Regulatory liabilities		1,156			1,194
Investment tax credits		233			216
Deferred credits and other liabilities		323			336
Total long-term liabilities		2,527			2,529
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	11,459		$	11,048

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended June 30,
(millions)	2021			2020
Revenues
Electric	$	531		$	453
Gas		123			96
Total revenues		654			549
Expenses
Fuel		129			67
Purchased power		26			25
Cost of natural gas sold		33			25
Operations and maintenance		139			126
Depreciation and amortization		107			92
Taxes, other than income		56			50
Total expenses		490			385
Income from operations		164			164
Other income
Allowance for equity funds used during construction		10			7
Other income, net		2			2
Total other income		12			9
Interest charges
Interest expense		39			35
Allowance for borrowed funds used during construction		(5	)		(3	)
Total interest charges		34			32
Income before provision for income taxes		142			141
Provision for income taxes		21			24
Net income	$	121		$	117
Comprehensive income	$	121		$	117

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

	Six months ended June 30,
(millions)	2021			2020
Revenues
Electric	$	977		$	873
Gas		276			223
Total revenues		1,253			1,096
Expenses
Fuel		238			168
Purchased power		44			27
Cost of natural gas sold		83			67
Operations and maintenance		267			260
Depreciation and amortization		213			189
Taxes, other than income		110			101
Total expenses		955			812
Income from operations		298			284
Other income
Allowance for equity funds used during construction		20			13
Other income, net		3			3
Total other income		23			16
Interest charges
Interest expense		77			72
Allowance for borrowed funds used during construction		(10	)		(6	)
Total interest charges		67			66
Income before provision for income taxes		254			234
Provision for income taxes		41			40
Net income	$	213		$	194
Comprehensive income	$	213		$	194

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

7

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended June 30,
(millions)	2021			2020
Cash flows from operating activities
Net income	$	213		$	194
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		213			189
Deferred income taxes and investment tax credits		27			43
Allowance for equity funds used during construction		(20	)		(13	)
Deferred recovery clauses		(10	)		37
Receivables, less allowance for credit losses		(43	)		(22	)
Prepayments and other deposits		(11	)		(9	)
Taxes accrued		20			20
Accounts payable		(45	)		(41	)
Regulatory assets and liabilities		(2	)		(12	)
Other		4			(4	)
Cash flows from operating activities		346			382
Cash flows used in investing activities
Capital expenditures		(588	)		(653	)
Net proceeds from sale of assets		0			6
Cash flows used in investing activities		(588	)		(647	)
Cash flows from financing activities
Equity contributions from Parent		290			265
Proceeds from long-term debt issuance		790			0
Repayment of long-term debt		(278	)		0
Net decrease in short-term debt (maturities of 90 days or less)		(65	)		(154	)
Proceeds from other short-term debt (maturities over 90 days)		0			300
Repayment of other short-term debt (maturities over 90 days)		(300	)		0
Dividends to Parent		(181	)		(150	)
Cash flows from financing activities		256			261
Net increase (decrease) in cash and cash equivalents		14			(4	)
Cash and cash equivalents at beginning of period		10			14
Cash and cash equivalents at end of period	$	24		$	10
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(20	)	$	(12	)

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 June 30, 2021
Balance, March 31, 2021		10		4,045	$	331		$	(1	)	$	4,375
Net income						121						121
Equity contributions from Parent				135								135
Dividends to Parent						(93	)					(93	)
Balance, June 30, 2021		10	$	4,180	$	359		$	(1	)	$	4,538
Three months ended June 30, 2020
Balance, March 31, 2020		10		3,530	$	316		$	(1	)	$	3,845
Net income						117						117
Equity contributions from Parent			120									120
Dividends to Parent						(77	)					(77	)
Other						(2	)					(2	)
Balance, June 30, 2020		10	$	3,650	$	354		$	(1	)	$	4,003
Six months ended June 30, 2021
Balance, December 31, 2020		10		3,890	$	327		$	(1	)	$	4,216
Net income						213						213
Equity contributions from Parent			290									290
Dividends to Parent						(181	)					(181	)
Balance, June 30, 2021		10	$	4,180	$	359		$	(1	)	$	4,538
Six months ended June 30, 2020
Balance, December 31, 2019		10		3,385	$	311		$	(1	)	$	3,695
Net income						194						194
Equity contributions from Parent			265									265
Dividends to Parent						(150	)					(150	)
Other						(1	)					(1	)
Balance, June 30, 2020		10	$	3,650	$	354		$	(1	)	$	4,003

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

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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, 2020 for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS.

Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2021 and December 31, 2020, and the results of operations and cash flows for the periods ended June 30, 2021 and 2020. The results of operations for the three and six months ended June 30, 2021 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2021.

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.

Since 2020, the outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of June 30, 2021 and December 31, 2020 and for the three and six months ended June 30, 2021 and 2020 were not materially impacted by the COVID-19 pandemic.

Receivables and Allowance for Credit Losses

Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $258 million and $214 million as of June 30, 2021 and December 31, 2020, respectively. An allowance for credit losses is established based on TEC’s collection experience and reasonable and supportable forecasts that affect the collectibility of the reported amount. Circumstances that could affect Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, generating fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

As of June 30, 2021 and December 31, 2020, unbilled revenues of $83 million and $73 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 $31 million and $26 million for the three months ended June 30, 2021 and 2020, respectively, and totaled $60 million and $53 million for the six months ended June 30, 2021 and 2020, respectively.

2. New 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, 2020.

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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 has invested approximately $850 million during 2017 through 2021 related to 600 MW of solar projects recoverable under the SoBRAs, and AFUDC was accrued during construction.

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 $26 million annually in estimated revenue requirements. The FPSC approved the tariffs on this SoBRA filing, including an adjustment to reflect the reduction in the state corporate income tax discussed below, on December 10, 2019 and TEC began receiving these revenues in January 2020. On July 31, 2020, TEC filed its fourth and final SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2021 tranche representing 46 MW and $8 million annually in estimated revenues. The FPSC approved the tariffs on this SoBRA filing on November 3, 2020 and TEC began receiving these revenues in January 2021.

The true-up filing for SoBRA tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. The $5 million true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was submitted to the FPSC on May 27, 2021. An estimated $4 million true-up is being returned to customers during 2021. The true-up for SoBRA tranche 4 will be filed in 2022.

   On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 (the Settlement Agreement) by and among TEC and the intervenors in TEC’s rate case filed with the FPSC in April 2021. The Settlement Agreement agrees to an increase in base rates annually effective with January 2022 bills, to generate a $191 million increase in revenue consisting of $123 million of traditional base rate charges and $68 million in a new charge to recover the costs of retiring assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million and $21 million, effective January 2023 and January 2024, respectively. Under the agreement, the allowed equity in the capital structure will continue to be 54% from investor sources of capital. The Settlement Agreement includes an allowed regulatory ROE range of 9.0% to 11.0% with a 9.95% midpoint. The Settlement Agreement allows a 25 basis point increase in the allowed ROE range and mid-point, and $10 million of additional revenue, if the average 30-year United States Treasury Bond yield rate for any period of six consecutive months is at least 50 basis points greater than the yield rate on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not change from January 1, 2022 through December 31, 2024, unless TEC’s earned ROE was to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby TEC agrees to quantify the future impact of a decrease or increase in corporate income tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of this agreement. The Settlement Agreement would not become effective unless and until approved by the FPSC, which is expected to consider the matter by October 2021.

Tampa Electric Big Bend Modernization Project

Tampa Electric expects to invest approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $611 million has been invested through June 30, 2021. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the Big Bend modernization project, on June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At June 30, 2021 and December 31, 2020, Tampa Electric’s balance sheet included $200 million in electric utility plant and $91 million and $88 million, respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until December 31, 2021. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 as part of the Big Bend modernization project.        

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Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of customers from economic, environmental risk and operational perspectives. Similar to the retirement plan for Unit 1 and Unit 2, Tampa Electric will continue to account for its existing investment in Unit 3 in electric utility plant and depreciate the assets using the current depreciation rates until December 31, 2021.

On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedule for all three units with the FPSC.

Tampa Electric’s Settlement Agreement provides recovery for the Big Bend Modernization project in two phases. The first phase is a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. The Settlement Agreement also includes a new charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread over 15 years and will survive the termination of the Settlement Agreement. The special capital recovery schedule for all three units will be applied beginning January 1, 2022.

Tampa Electric Mid-Course Adjustment to Fuel Recovery

In July 2021, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover $83 million of additional costs during the months of September through December 2021.

Tampa Electric Storm Protection Cost Recovery Clause and Settlement Agreement

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This new clause provides 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. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million base rate reduction for SPP program costs previously recovered in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million of costs removed from base rates. This settlement agreement was approved on August 10, 2020, and Tampa Electric’s cost recovery began in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.

The June 9, 2020 settlement agreement approved by the FPSC described above also included approval of Tampa Electric’s petition to eliminate its $16 million accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020.     

PGS Base Rates       

On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement provides for an increase in base rates by $58 million annually effective January 2021, which is a $34 million increase in revenue and $24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint. It provides PGS the ability to reverse a total of $34 million of accumulated depreciation through 2023 and sets new depreciation rates effective January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.90% before that time with an allowed equity in the capital structure of 54.7% from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024.

Regulatory Assets and Liabilities

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

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Regulatory Assets and Liabilities
(millions)	June 30, 2021		December 31, 2020
Regulatory assets:
Regulatory tax asset (1)	$	98	$	90
Cost-recovery clauses (2)		43		38
Environmental remediation (3)		25		22
Postretirement benefits (4)		298		309
Asset retirement obligation (5)		9		13
Other		8		13
Total regulatory assets		481		485
Less: Current portion		68		79
Long-term regulatory assets	$	413	$	406
Regulatory liabilities:
Regulatory tax liability (6)	$	678	$	691
Cost-recovery clauses (2)		18		23
Accumulated reserve - cost of removal (7)		469		498
Storm reserve (8)		48		48
Other		0		1
Total regulatory liabilities		1,213		1,261
Less: Current portion		57		67
Long-term regulatory liabilities	$	1,156	$	1,194

(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 a subsequent period.

(3) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC.

(4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.

(5) This asset 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.

(6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC.

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

(8) 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 2019, Tampa Electric incurred storm restoration preparation costs for Hurricane Dorian of approximately $8 million, which was charged to the storm reserve regulatory liability.

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4. Income Taxes

CARES Act

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (CARES) Act was signed into law. The CARES Act includes several business provisions including deferral in employer payroll taxes and an employee retention payroll tax credit. On December 27, 2020, the Consolidated Appropriations Act, 2021 (the 2021 Act) was signed into law. The 2021 Act provides for modifications and expansion of the employee retention payroll tax credit enacted under the CARES Act.  These Acts did not have a material impact to TEC’s financial statements.

American Rescue Plan Act of 2021

On March 11, 2021, the American Rescue Plan Act of 2021 (the Act) was signed into law. The Act includes an extension of the employee retention credit through December 31, 2021.  The Act did not have a material impact to TEC’s financial statements.

Income Tax Expense

TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements with TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is reflected in common stock.

TEC’s effective tax rates for the six months ended June 30, 2021 and 2020 were 16.1% and 17.1%, respectively. The June 30, 2021 and 2020 effective tax rates are an estimate of the annual effective income tax rate. TEC’s effective tax rate for the six months ended June 30, 2021 and 2020 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 June 30, 2021 and December 31, 2020, the amount of unrecognized tax benefits was $5 million and $9 million, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC’s unrecognized federal tax benefits decreased in the first quarter of 2021 by approximately $5 million due to the settlement of its 2016 federal IRS Appeals R&D tax credits issue. TEC had $5 million and $9 million of unrecognized tax benefits at June 30, 2021 and December 31, 2020, 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 June 30,	2021			2020			2021			2020
Components of net periodic benefit cost
Service cost	$	6		$	5		$	1		$	0
Interest cost		6			6			2			2
Expected return on assets		(13	)		(12	)		0			0
Amortization of:
Actuarial loss (gain)		5			5			(1	)		0
Net periodic benefit cost	$	4		$	4		$	2		$	2
Six months ended June 30,
Components of net periodic benefit cost
Service cost	$	11		$	10		$	1		$	0
Interest cost		11			13			3			3
Expected return on assets		(26	)		(25	)		0			0
Amortization of:
Actuarial loss (gain)		11			10			0			0
Settlement cost		0			0			0			0
Net periodic benefit cost	$	7		$	8		$	4		$	3

TEC’s portion of the net periodic benefit cost for the three months ended June 30, 2021 and 2020, respectively, was $2 million and $3 million for pension benefits, and $3 million and $1 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the six months ended June 30, 2021 and 2020, respectively, was $5 million and $6 million for pension benefits, and $5 million and $3 million for other postretirement benefits. TEC’s portion of net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Condensed Statements of Income in “Operations & maintenance”.   

TECO Energy assumed a long-term EROA of 6.70% and a discount rate of 2.38% for pension benefits under its qualified pension plan for 2021. For TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 2.47% for 2021.

TECO Energy made contributions of $11 million and $10 million to its qualified pension plan in each of the six months ended June 30, 2021 and 2020, respectively. TEC’s portion of these contributions was $9 million and $8 million, respectively. TECO Energy expects to make contributions to the pension plan of $10 million for the remainder of 2021. TEC estimates its portion of the remaining 2021 contribution to be $8 million.        

Included in the benefit cost discussed above, for the three and six months ended June 30, 2021, $5 million and $11 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 $9 million for the three and six months ended June 30, 2020, respectively.

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6. Short-Term Debt

Details of TEC’s short-term borrowings are presented in the following table:

	June 30, 2021								December 31, 2020
			Borrowings		Borrowings		Letters						Letters
	Credit		Outstanding -		Outstanding -		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	800		0	$	410	$	1	$	800	$	345	$	1
3-year accounts    receivable facility (3)		0		0		0		0		150		130		0
1-year term facility (4)		0		0		0		0		300		300		0
Total	$	800		0	$	410	$	1	$	1,250	$	775	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023. TEC also has an active commercial paper program for up to $800 million, of which the full amount outstanding is backed by TEC’s credit facility. The amount of commercial paper issued results in an equal amount of its credit facility being considered drawn and unavailable.

(3) This 3-year facility matured on March 22, 2021.

(4) This 1-year term facility was terminated on March 23, 2021.

At June 30, 2021, the credit facility required a commitment fee of 12.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities and commercial paper program at June 30, 2021 and December 31, 2020 was 0.25% and 0.89%, respectively.

Commercial Paper Program

On May 25, 2021, TEC established a commercial paper program (the Program) under which TEC may issue on a private placement basis unsecured commercial paper notes (the Notes). Amounts available under the Program may be borrowed, repaid and reborrowed with the aggregate amount of the Notes outstanding under the Program at any time not to exceed $800 million.  The maturities of the Notes will vary, but may not exceed 270 days from the date of issue. The rates of interest will depend on whether the Note will be a fixed or floating rate. TEC must have credit facilities in place, at least equal to the amount of its commercial paper program. TEC does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

Accounts Receivable Facility

On July 14, 2020 and October 30, 2020, TEC amended its $150 million accounts receivable collateralized borrowing facility (Loan Agreement) in order to change certain performance ratios. The amended Loan Agreement was effective as of June 30, 2020 and September 30, 2020. On March 22, 2021, this agreement matured and terminated.

Non Revolving Term Loan

On February 6, 2020, TEC entered into a 364-day, $300 million credit agreement with a group of banks. The credit agreement had a maturity date of February 4, 2021; contained customary representations and warranties, events of default, and financial and other covenants; and provided for interest to accrue at variable rates based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. On January 29, 2021, TEC extended the maturity date of the agreement to April 29, 2021. On March 23, 2021, this loan was repaid and terminated.

5-Year Credit Facility

On December 18, 2020, TEC amended and restated its bank credit facility, entering into a Sixth Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2022 to March 22, 2023 (subject to further extension with the consent of each lender); increased the amount of the commitment by the lenders to $800 million; and provided for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $100 million in the aggregate; includes a $80 million letter of credit facility; and made other technical changes.

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7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2021, TEC’s long-term debt, including the current portion, had a carrying amount of $3,385 million and an estimated fair market value of $4,035 million. At December 31, 2020, TEC’s total long-term debt, including the current portion, had a carrying amount of $2,872 million and an estimated fair market value of $3,597 million. The fair value of the debt securities is determined using Level 2 measurements (see Note 11 for information regarding the fair value hierarchy).

Tampa Electric Company 2.40% Notes due 2031 and 3.45% Notes due 2051

On March 18, 2021, TEC completed a sale of (i) $400 million aggregate principal amount of 2.40% Notes due March 15, 2031 (the 2031 Notes) and (ii) $400 million aggregate principal amount of 3.45% Notes due March 15, 2051 (the 2051 Notes, and collectively, the Notes). Until December 15, 2030, in the case of the 2031 Notes, or September 15, 2050, in the case of the 2051 Notes, TEC may redeem all or any part of such series of Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of such series of Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the Notes to be redeemed that would be due if the Notes matured on (a) December 15, 2030, in the case of the 2031 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate (as defined in the Indenture), plus 15 basis points, or (b) September 15, 2050, in the case of the 2051 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, 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, 2030, in the case of the 2031 Notes or September 15, 2050, in the case of the 2051 Notes, TEC may, at its option, redeem such series of the Notes, in whole or in part, at 100% of the principal amount of such series 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 June 30, 2021 and December 31, 2020, TEC has estimated its ultimate financial liability to be $17 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s currently assessed percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. See Note 3 for information regarding the related regulatory asset.

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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 June 30, 2021:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total
2021	$	35	$	119	$	297	$	173	$	35	$	2	$	2	$	663
2022		0		232		84		52		32		3		3		406
2023		0		211		58		1		43		3		0		316
2024		0		205		0		0		26		3		0		234
2025		0		191		0		0		18		2		0		211
Thereafter		0		2,014		0		0		66		48		0		2,128
Total future minimum payments	$	35	$	2,972	$	439	$	226	$	220	$	61	$	5	$	3,958

Debt Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements and has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2021, TEC was in compliance with all required covenants.

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9. Segment Information

(millions)	Tampa								Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations				Company
2021
Revenues - external	$	531	$	123	$	0			$	654
Intracompany sales		1		0		(1	)			0
Total revenues		532		123		(1	)			654
Total interest charges		29		5		0				34
Net income	$	102	$	19	$	0			$	121
2020
Revenues - external	$	453	$	96	$	0			$	549
Intracompany sales		1		1		(2	)			0
Total revenues		454		97		(2	)			549
Total interest charges		28		4		0				32
Net income	$	106	$	11	$	0			$	117
Six months ended June 30,
2021
Revenues - external	$	977	$	276	$	0			$	1,253
Intracompany sales		2		2		(4	)			0
Total revenues		979		278		(4	)			1,253
Total interest charges		57		10		0				67
Net income	$	167	$	46	$	0			$	213
2020
Revenues - external	$	873	$	223	$	0			$	1,096
Intracompany sales		2		4		(6	)			0
Total revenues		875		227		(6	)			1,096
Total interest charges		58		8		0				66
Net income	$	165	$	29	$	0			$	194
Total assets at June 30, 2021	$	10,101	$	2,021	$	(663	)	(1)	$	11,459
Total assets at December 31, 2020	$	9,800	$	1,901	$	(653	)	(1)	$	11,048

(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 June 30, 2021	Electric		PGS		Eliminations			Company
Electric revenue
Residential	$	276	$	0	$	0		$	276
Commercial		144		0		0			144
Industrial		41		0		0			41
Regulatory deferrals and unbilled revenue		11		0		0			11
Other (1)		60		0		(1	)		59
Total electric revenue		532		0		(1	)		531
Gas revenue
Residential		0		49		0			49
Commercial		0		46		0			46
Industrial (2)		0		6		0			6
Other (3)		0		22		0			22
Total gas revenue		0		123		0			123
Total revenue	$	532	$	123	$	(1	)	$	654

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Three months ended June 30, 2020
Electric revenue
Residential	$	254			$	0	$	0		$	254
Commercial		121				0		0			121
Industrial		32				0		0			32
Regulatory deferrals and unbilled revenue		(3	)			0		0			(3	)
Other (1)		50		`		0		(1	)		49
Total electric revenue		454				0		(1	)		453
Gas revenue
Residential		0				36		0			36
Commercial		0				28		0			28
Industrial (2)		0				5		0			5
Other (3)		0				28		(1	)		27
Total gas revenue		0				97		(1	)		96
Total revenue	$	454			$	97	$	(2	)	$	549

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(millions)	Tampa								Tampa Electric
Six months ended June 30, 2021	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	508		$	0	$	0		$	508
Commercial		270			0		0			270
Industrial		78			0		0			78
Regulatory deferrals and unbilled revenue		9			0		0			9
Other (1)		114			0		(2	)		112
Total electric revenue		979			0		(2	)		977
Gas revenue
Residential		0			116		0			116
Commercial		0			99		0			99
Industrial (2)		0			12		0			12
Other (3)		0			51		(2	)		49
Total gas revenue		0			278		(2	)		276
Total revenue	$	979		$	278	$	(4	)	$	1,253
Six months ended June 30, 2020
Electric revenue
Residential	$	459		$	0	$	0		$	459
Commercial		246			0		0			246
Industrial		69			0		0			69
Regulatory deferrals and unbilled revenue		(5	)		0		0			(5	)
Other (1)		106			0		(2	)		104
Total electric revenue		875			0		(2	)		873
Gas revenue
Residential		0			84		0			84
Commercial		0			69		0			69
Industrial (2)		0			11		0			11
Other (3)		0			63		(4	)		59
Total gas revenue		0			227		(4	)		223
Total revenue	$	875		$	227	$	(6	)	$	1,096

(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 June 30, 2021 and December 31, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $130 million and $135 million, respectively. As allowed under ASC 606, these amounts exclude 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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11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:	Observable inputs, such as quoted prices in active markets;
Level 2:	Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and
Level 3:	Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

There were no Level 3 assets or liabilities for the periods presented.

As of June 30, 2021 and December 31, 2020, 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.

12. Subsequent Events

 On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 by and among TEC and the intervenors in TEC’s rate case filed with the FPSC in April 2021. In addition, on August 3, 2021, the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges, effective with September 2021 customer bills. See Note 3 – Tampa Electric Base Rates, Tampa Electric Big Bend Modernization Project and Tampa Electric Mid-Course Adjustment to Fuel Recovery for further information.

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

Earnings Summary - Unaudited  

		Three months ended June 30,						Six months ended June 30,
(millions)		2021			2020			2021			2020
Revenues
	Tampa Electric	$	532		$	454		$	979		$	875
	PGS		123			97			278			227
	Eliminations		(1	)		(2	)		(4	)		(6	)
	TEC	$	654		$	549		$	1,253		$	1,096
Net income
	Tampa Electric	$	102		$	106		$	167		$	165
	PGS		19			11			46			29
	TEC	$	121		$	117		$	213		$	194

Operating Results

Second quarter 2021 net income was $121 million, compared to $117 million in the second quarter of 2020. Second quarter 2021 results were impacted by higher base revenues and AFUDC, partially offset by higher depreciation expense, O&M expense and interest expense at Tampa Electric and PGS. Year-to-date 2021 net income was $213 million, compared to $194 million in the 2020 year-to-date period. Year-to-date 2021 results were impacted by higher base revenues at PGS, lower O&M at Tampa Electric and higher AFUDC at Tampa Electric, partially offset by higher depreciation expense at Tampa Electric and PGS. See Operating Company Results below for further detail.

COVID-19 Pandemic

To date, the COVID-19 pandemic has not had a material financial impact on TEC’s earnings. TEC’s top priority continues to be the health and safety of its customers and employees. Management continues to monitor developments, economic conditions and recommendations by local and national public health authorities related to COVID-19 and is adjusting operational requirements as needed.

To date, customer defaults have not been material and as of June 30, 2021, adjustments to the allowance for credit losses have not had a material impact on the financial statements. TEC is continuing to monitor customer accounts and to work with customers on payment arrangements.

The extent of the future impact of the COVID-19 pandemic on TEC’s financial results and business operations is uncertain at this time but is not expected to have a material financial impact in 2021. Future impacts will depend on a variety of factors, including the duration and severity of the pandemic, further government actions, timing and effectiveness of vaccinations, future economic activity and energy usage. TEC plans to complete its capital investment projects and continue to reliably and safely serve its customers. Capital project delays and supply chain disruptions have been immaterial to date but, depending on the duration of the COVID-19 pandemic, forecasted capital expenditures may be delayed due to supply chain disruptions, travel restrictions or the deferral of non-essential capital work. TEC currently expects to continue to have adequate liquidity given its cash position, existing bank facilities and access to capital but will continue to monitor the impact of the COVID-19 pandemic on future cash flows. For further information on the potential future impacts of COVID-19 on TEC, refer to the COVID-19 Pandemic and Liquidity and Capital Resources sections of TEC’s Annual Report on Form 10-K for the year ended December 31, 2020.  

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 second quarter of 2021 was $102 million, compared with $106 million for the same period in 2020. Results primarily reflected higher depreciation expense and higher interest expense, partially offset by higher AFUDC, lower income tax expense and higher base revenues. 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 clause and other pass-through costs.

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Revenues were $78 million higher than in the same quarter in 2020 primarily driven by higher fuel recovery clause revenue as a result of higher fuel costs. Base revenue increased by $3 million primarily due to customer growth, warmer weather and higher base rates from additional solar generation projects being placed in-service, partially offset by the revenues now being recovered through the Storm Protection Plan Cost Recovery Clause. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in the second quarter of 2021 were 8% above normal (a 20-year statistical degree day average) and 3% above the 2020 period, reflecting favorable weather in the second quarter of 2021 compared to 2020. Total net energy for load, which is a calendar measurement of energy output, in the second quarter of 2021 was 2% higher than the same period in 2020.

O&M expense, excluding all FPSC-approved cost-recovery clauses, was $2 million higher than in the same period of 2020 primarily due to higher employee benefit costs. Depreciation and amortization expense increased $12 million in the second quarter of 2021 compared to the same period in 2020 primarily due to normal additions to facilities to reliably serve customers, the in-service of solar generation projects, and an $8 million intangible software amortization credit in 2020 due to a regulatory agreement approved by the FPSC (see Note 3 to the TEC Consolidated Condensed Financial Statements for further information).

Tampa Electric’s net income year-to-date 2021 was $167 million, compared with $165 million for the same period in 2020. Results primarily reflected higher AFUDC and lower O&M expense, partially offset by higher depreciation expense.

Revenues were $104 million higher than year-to-date 2020 primarily driven by higher fuel recovery clause revenue as a result of higher fuel costs. Base revenue was consistent with year-to-date 2020 due to customer growth and higher base rates from additional solar generation projects being placed in-service, offset by less warm weather in the first quarter of 2021 and the revenues now being recovered through the Storm Protection Plan Cost Recovery Clause. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area year-to-date 2021 were 6% above normal (a 20-year statistical degree day average) and 4% below the 2020 period, reflecting milder weather year-to-date 2021 compared to 2020. Total net energy for load, which is a calendar measurement of energy output, year-to-date 2021 was consistent with year-to-date 2020.

O&M expense, excluding all FPSC-approved cost-recovery clauses, was $10 million lower than year-to-date 2020 primarily due to lower generation costs related to timing and scope of outages, lower labor costs as a result of lower coal generation, the recovery of Storm Protection Plan clause expenses and lower employee benefit costs. Depreciation and amortization expense was $17 million higher in year-to-date 2021 primarily due to normal additions to facilities to reliably serve customers, the in-service of solar generation projects, and an $8 million intangible software amortization credit in 2020 due to a regulatory agreement approved by the FPSC (see Note 3 to the TEC Consolidated Condensed Financial Statements for further information).

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Tampa Electric’s regulated operating statistics for the three and six months ended June 30, 2021 and 2020 were as follows:

(millions, except customers and total degree days)	Operating Revenues								Kilowatt-Hours Billed
Three months ended June 30,	2021		2020			% Change			2021		2020		% Change
By Customer Type
Residential (1)	$	276	$	254			9			2,472		2,518		(2	)
Commercial (1)		144		121			19			1,525		1,431		7
Industrial (1)		41		32			28			541		452		20
Other (1)		47		39			21			478		439		9
Regulatory deferrals and unbilled revenue (2)		11		(3	)		(467	)
Total retail sales of electricity		519		443			17			5,016		4,840		4
Off system sales of electricity		1		0			#DIV/0	!		16		11		45
Other operating revenue		12		11			9
Total revenues	$	532	$	454			17			5,032		4,851		4
Customers at June 30, (thousands)		802		786			2
Retail net energy for load (kilowatt hours)		5,516		5,388			2
Total degree days		1,345		1,311			3
Six months ended June 30,
By Customer Type
Residential (1)	$	508	$	459			11			4,525		4,398		3
Commercial (1)		270		246			10			2,850		2,804		2
Industrial (1)		78		69			13			1,015		949		7
Other (1)		90		81			11			912		883		3
Regulatory deferrals and unbilled revenue (2)		9		(5	)		(280	)
Total retail sales of electricity		955		850			12			9,302		9,034		3
Off system sales of electricity		1		1			0			27		33		(18	)
Other operating revenue		23		24			(4	)
Total revenues	$	979	$	875			12			9,329		9,067		3
Customers at June 30, (thousands)		802		786			2
Retail net energy for load (kilowatt-hours)		9,952		9,939			0
Total degree days		1,953		2,034			(4	)

(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 $19 million for the second quarter, compared with $11 million in the second quarter of 2020. Results reflect a 5% higher number of customers in the second quarter of 2021 compared to the second quarter of 2020. Revenues were $26 million higher than the prior year quarter primarily due to higher base rates that went into effect January 2021, customer growth, higher PGA clause-related revenues, and COVID-19 impacts lowering commercial sales in the 2020 period. These revenue increases were partially offset by lower cast iron bare steel replacement rider revenue that is now being recovered through the new base rates and lower off-system sales in 2021. The base revenues increase, excluding the shift of cast iron bare steel rider-related revenue, was $18 million. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $2 million higher than in the 2020 quarter primarily due to higher labor and contractor costs to operate and maintain the growing distribution system. Depreciation and amortization increased $3 million due to asset growth.

PGS had net income of $46 million for the 2021 year-to-date period, compared with $29 million in the 2020 period. Revenues were $51 million higher than the prior period primarily due to higher base rates that went into effect January 2021, customer growth, higher PGA clause-related revenues, and COVID-19 impacts lowering commercial sales in the second quarter of 2020. These revenue increases were partially offset by lower cast iron bare steel replacement rider revenue that is now being recovered through the new base rates and lower off-system sales in 2021. The base revenues increase excluding the shift of cast iron bare steel rider-related revenue was $32 million. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $2 million higher than in 2020 primarily due to the same quarterly drivers mentioned above. Depreciation and amortization increased $5 million due to asset growth.  

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PGS’s regulated operating statistics for the three and six months ended June 30, 2021 and 2020 were as follows:

(millions, except customers)	Operating Revenues							Therms
Three months ended June 30,	2021		2020		% Change			2021		2020		% Change
By Customer Type
Residential	$	49	$	36		36			21		19		11
Commercial		46		28		64			126		99		27
Industrial		5		4		25			117		118		(1	)
Power generation		1		1		0			200		238		(16	)
Off system sales		4		8		(50	)		10		38		(74	)
Other operating revenues		15		17		(12	)
Total	$	120	$	94		28			474		512		(7	)
By Sales Type
System supply	$	66	$	50		32			39		62		(37	)
Transportation		39		27		44			435		450		(3	)
Other operating revenues		15		17		(12	)
Total	$	120	$	94		28			474		512		(7	)
Customers at June 30, (thousands)		436		414		5
Six months ended June 30,
By Customer Type
Residential	$	116	$	84		38			59		52		13
Commercial		99		69		43			266		244		9
Industrial		9		8		13			229		230		(0	)
Power generation		3		3		0			418		472		(11	)
Off system sales		10		17		(41	)		25		80		(69	)
Other operating revenues		34		39		(13	)
Total	$	271	$	220		23			997		1,078		(8	)
By Sales Type
System supply	$	154	$	118		31			101		144		(30	)
Transportation		83		63		32			896		934		(4	)
Other operating revenues		34		39		(13	)
Total	$	271	$	220		23			997		1,078		(8	)
Customers at June 30, (thousands)		436		414		5

Other Income

For the second quarter of 2021 and 2020, TEC’s other income was $12 million and $9 million, respectively, and included AFUDC-equity of $10 million and $7 million, respectively. For the year-to-date periods in 2021 and 2020, TEC’s other income was $23 million and $16 million, respectively, and included AFUDC-equity of $20 million and $13 million, respectively. The increase in AFUDC-equity was primarily due to the timing of Tampa Electric’s modernization of its Big Bend Power Station and the construction of solar projects.

Interest Expense

For the second quarter of 2021 and 2020, TEC’s interest expense, excluding AFUDC-debt, was $39 million and $35 million, respectively. For the year-to-date periods in 2021 and 2020, TEC’s interest expense, excluding AFUDC-debt, was $77 million and $72 million, respectively. The increase was due to higher borrowings to support TEC’s ongoing capital investment program.

Income Taxes

The provisions for income taxes were $21 million and $24 million for the three months ended June 30, 2021 and 2020, respectively, and $41 million and $40 million for the six months ended June 30, 2021 and 2020, respectively. Compared to the 2020 period, the provision for income taxes for the six months ended June 30, 2021 was the result of higher pre-tax income, offset by higher tax benefits due to AFUDC, higher amortization of the regulatory liability related to tax reform, higher investment tax credit amortization related to solar projects and higher R&D tax credits. Compared to the second quarter in prior year, the provision for incomes taxes for the three months ended June 30, 2021 decreased primarily due to higher tax benefits due to AFUDC, higher amortization of the regulatory liability related to tax reform, higher investment tax credit

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amortization related to solar projects and higher R&D tax credits.

Liquidity and Capital Resources

The table below sets forth the June 30, 2021 liquidity, cash balances and amounts available under the TEC credit facilities.  

(millions)
Credit facilities	$	800
Drawn amounts/letters of credit		411
Available credit facilities		389
Cash and short-term investments		24
Total liquidity	$	413

Cash Impacts Related to Operating Activities  

Cash flows from operating activities for the six months ended June 30, 2021 were $346 million, a decrease of $36 million compared to the same period in 2020. Decreases to cash from operations were primarily the result of higher fuel under-recoveries, partially offset by the timing of invoice payments.

Cash Impacts Related to Financing Activities

Cash flows from financing activities for the six months ended June 30, 2021 resulted in net cash inflows of $256 million. TEC received $790 million of proceeds from long-term debt and $290 million of equity contributions (see Note 7 to the TEC Consolidated Condensed Financial Statements for further information regarding TEC’s long-term debt). These increases in cash flows were partially offset by repayment of $300 million of other short-term debt with a maturity of greater than 90 days, repayment of long-term debt of $278 million, dividend payments to Parent of $181 million and a net repayment of $65 million of short-term debt with maturities of 90 days or less.  

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 June 30, 2021, TEC was in compliance with all applicable financial covenants. The following table contains the significant financial covenant and the performance relative to it at June 30, 2021.

Significant Financial Covenants

			Calculation at
Instrument (1)	Financial Covenant (2)	Requirement/Restriction	June 30, 2021
Credit facility - $800 million	Debt/capital	Cannot exceed 65%	46%

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

(2) As defined in the instrument.

Credit Ratings of Senior Unsecured Debt at June 30, 2021

	S&P	Moody’s	Fitch
Credit ratings of senior unsecured debt	BBB+	A3	A
Credit ratings outlook	Stable	Positive	Stable

Certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings.

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Commitments and Contingencies

See Note 8 to the TEC Consolidated Condensed Financial Statements for information regarding TEC’s commitments and contingencies as of June 30, 2021.

Regulatory Matters

See Note 3 to the TEC Consolidated Condensed Financial Statements for information regarding TEC’s regulatory matters as of June 30, 2021.

Fair Value Measurements

The valuation methods used to determine fair value are described in Notes 7 and 11 to the TEC Consolidated Condensed Financial Statements. In addition, TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At June 30, 2021, 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 2021. For further discussion of critical accounting policies and estimates, see TEC’s Annual Report on Form 10-K for the year ended December 31, 2020.

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 June 30, 2021. Based on such evaluation, TEC’s principal financial officer and principal executive officer have concluded that, as of June 30, 2021, 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 5. OTHER INFORMATION

On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 (the Settlement Agreement) by and among TEC and the intervenors in TEC’s rate case filed with the FPSC in April 2021. The Settlement Agreement agrees to an increase in base rates annually effective with January 2022 bills, to generate a $191 million increase in revenue consisting of $123 million of traditional base rate charges and $68 million in a new charge to recover the costs of retiring assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million and $21 million, effective January 2023 and January 2024, respectively. Under the agreement, the allowed equity in the capital structure will continue to be 54% from investor sources of capital. The Settlement Agreement includes an allowed regulatory ROE range of 9.0% to 11.0% with a 9.95% midpoint. The Settlement Agreement allows a 25 basis point increase in the allowed ROE range and mid-point, and $10 million of additional revenue, if the average 30-year United States Treasury Bond yield rate for any period of six consecutive months is at least 50 basis points greater than the yield rate on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not change from January 1, 2022 through December 31, 2024, unless TEC’s earned ROE was to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby TEC agrees to quantify the future impact of a decrease or increase in corporate income tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of this agreement. The Settlement Agreement would not become effective unless and until approved by the FPSC, which is expected to consider the matter by October 2021.

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	Sixteenth Supplemental Indenture dated as of March 18, 2021, 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 4.9, Form 8-K dated March 18, 2021 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)
99.1	Stipulation and Settlement Agreement, dated as of August 6, 2021, by and among Tampa Electric Company, the Office of Public Counsel, the Florida Industrial Power Users Group, Federal Executive Agencies, the Florida Retail Federation, Walmart, Inc., and the West Central Florida Hospital Utility Alliance.
101.INS**	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the inline XBRL document.

29

Exhibit
No.	Description
101.SCH**	Inline XBRL Taxonomy Extension Schema Document.
101.CAL**	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF**	Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB**	Inline XBRL Taxonomy Label Linkbase Document.
101.PRE**	Inline XBRL Taxonomy Presentation Linkbase Document.
104	The cover page from TEC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 has been formatted in Inline XBRL.

(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.

** The XBRL related information in Exhibit 101 to this quarterly report on Form 10-Q shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability of that section and shall not be incorporated by reference into any filing or other document pursuant to the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing or document.

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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: August 10, 2021	By:	/s/ Gregory W. Blunden
		Gregory W. Blunden
		Treasurer and Chief Financial Officer      (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

31

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Archie Collins, 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:	August 10, 2021	/s/  ARCHIE COLLINS
		ARCHIE COLLINS
		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:	August 10, 2021	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		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 June 30, 2021 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:	August 10, 2021	/s/  ARCHIE COLLINS
		ARCHIE COLLINS
		President and Chief Executive Officer
		(Principal Executive Officer)
Date:	August 10, 2021	/s/  GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		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.

EX-99.1

Exhibit 99.1

BEFORE THE FLORIDA PUBLIC SERVICE COMMISSION

In re:  Petition for Rate Increase by	)	DOCKET NO.: 20210034-EI
Tampa Electric Company	)
	)
In re:  Petition of Tampa Electric Company	)
for Approval of 2020 Depreciation and	)	DOCKET NO. 20200264-EI
Dismantlement Study and Capital Recovery	)
Schedules	)
	)	Dated:August 6, 2021

2021 STIPULATION AND SETTLEMENT AGREEMENT

THIS AGREEMENT is dated this 6th day of August, 2021, and is by and between Tampa Electric Company (“Tampa Electric” or the “company”), the Office of Public Counsel (“OPC” or “Citizens”), the Florida Industrial Power Users Group (“FIPUG”), the Florida Retail Federation (“FRF”), the Federal Executive Agencies (“FEA”), Walmart Inc. (“Walmart”), and the West Central Florida Hospital Utility Alliance (“HUA”). Collectively, Tampa Electric, OPC, FIPUG, FRF, FEA, Walmart, and HUA shall be referred to herein as the “Parties” and the term “Party” shall be the singular form of the term “Parties.”  OPC, FIPUG, FRF, FEA, Walmart, and HUA will be referred to herein as the “Consumer Parties.” This agreement, including Exhibits appended hereto, shall be referred to as the “2021 Agreement.”

Background

Tampa Electric filed its last depreciation and dismantlement study in 2011. The Commission approved depreciation rates for the company on April 3, 2012 by Order No. 2012-0175-PAA-EI in Docket No. 20110131-EI. That order became final on April 30, 2012 by Order No. 2012-0226-CO-EI. The company used the rates approved in Docket No. 20110131-EI when it filed its most recent general base rate case in 2013, i.e., Petition of Tampa Electric Company for an Increase in Base Rates and Service Charges, Docket No. 20130040-EI (“2013 Rate Case”).

On September 8, 2013, Tampa Electric and some of the Consumer Parties filed a Stipulation and Settlement Agreement (“2013 Stipulation”) that resolved all the issues in the 2013 Rate Case. Among other things, Tampa Electric agreed that the general base rates established in the 2013 Stipulation would remain in effect through December 31, 2017, and thereafter, until the company’s next general base rate case. The 2013 Stipulation also specified that Tampa Electric would forego seeking future general base rate increases with an effective date prior to January 1, 2018, except in limited,definedcircumstances. The Florida Public Service Commission (“FPSC” or “Commission”) approved the 2013 Stipulation and memorialized its decision in Order No. PSC-2013-0443-FOF-EI, issued September 30, 2013.

Tampa Electric and the parties to the 2013 Stipulation amended and extended that stipulation by entering into the 2017 Amended and Restated Stipulation and Settlement Agreement (“2017 Agreement”), which was approved by the FPSC in November 2017.¹ The general base rate freeze provisions in the 2017 Agreement will expire on January 1, 2022.

In September 2020, the Parties began extensive discussions related to the anticipated 2021 Tampa Electric general rate case and the depreciation study filing. Experts of the Parties exchanged information and conducted extensive informal discovery. Late in 2020, the Parties agreed to pause the discussions to allow Tampa Electric to file depreciation studies and its rate case petition with supporting information. Ultimately, these three months of intensive and thorough discussions proved to be productive and helpful when the Parties resumed discussions in 2021.

¹  The Commission approved the 2017 Agreement by Order No. PSC-2017-0456-S-EI, issued on November 27, 2017 in Docket Nos. 20170210-EI and 20160160-EI.

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Consistent with Paragraph 8 of the 2017 Agreement, Tampa Electric filed a depreciation and dismantlement study for approval with the Commission on December 30, 2020, which petition was assigned to Docket No. 20200264-EI. In its depreciation petition, the company indicated that it would propose to recover the portion of the capital recovery schedules associated with Big Bend Units One, Two, and Three assets being recovered through the Environmental Cost Recovery Clause (“ECRC”) when it makes its projection filing for ECRC in 2021. It also indicated that it would request cost recovery for the portions of the capital recovery schedules associated with Big Bend Units One, Two, and Three and AMR assets to be retired being recovered through base rates when it files its next request for a general base rate increase. The total company amounts as of December 31, 2021 for these items are $517.7 million of net book value and approximately $111 million of projected dismantlement reserve deficiency of Big Bend assets to be retired.

On April 9, 2021, the company filed a petition for a general base rate increase, which was assigned to Docket No. 20210034-EI. Its general base rate case petition (“Rate Case”) was accompanied by the prepared direct testimony of 21 witnesses and 12 volumes of minimum filing requirement (“MFR”) schedules (“Initial Rate Case Filing”).

Docket Nos. 20200264-EI (depreciation and dismantlement costs) and 20210034-EI (Rate Case) were consolidated by Order No. PSC-2021-0147-PCO-EI, issued on April 22, 2021, which designated the Rate Case docket as the docket for filing all future pleadings, motions, notices, and other documents.

In its Rate Case petition, Tampa Electric requested a $294,995,000 permanent annual increase in general base revenues and a reduction in its miscellaneous service charge revenues by $6,635,000 annually, effective with the first billing cycle in January 2022. In addition, it argued that to mitigate the need for additional general base rate relief in 2023 and 2024, it should be

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authorized to implement two generation base rate adjustments (“GBRAs”) of approximately $102,236,000 and $25,639,000 effective with the first billing cycles for January 2023 and 2024, respectively. The company’s petition requested that the Commission approve a return on equity of 10.75%, an equity ratio of 54.6% and certain cost-of-service and rate design changes.

During these two dockets, Tampa Electric has responded to hundreds of interrogatories and produced over 35,000 pages of documents to assist the FPSC Staff and Consumer Parties in their evaluation of the company’s proposals. The FPSC Staff conducted an audit of the company’s Rate Case filing and experts of the Parties exchanged information and conducted extensive informal discovery. The company and its subject matter experts have also engaged in detailed and candid informal discussions with the lawyers, staff, and experts representing the Consumer Parties. As a result of these formal and informal discovery activities, the Consumer Parties and Tampa Electric are well informed about the issues presented by the company’s depreciation and dismantlement study and Rate Case proposals, and the risks and costs associated with further litigation.

Accordingly, the Parties have undertaken to resolve by agreement and settle the issues presented by the company’s depreciation and dismantlement study and Rate Case proposals so as to maintain predictability with respect to Tampa Electric’s base rates and charges and to avoid the inherent risks, uncertainties, dedication of resources and costs of further litigation. The Parties have entered into this 2021 Agreement in compromise of positions in accord with their rights and interests under Chapters 120, 350, and 366, Florida Statutes, as applicable, and believe that this 2021 Agreement is in the public interest. As part of a negotiated exchange of consideration among the Parties to this 2021 Agreement, each Party has agreed to concessions to the others with the expectation, intent, and understanding such that all provisions of the 2021 Agreement, upon

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approval by the Commission, will be enforced by the Commission as to all matters addressed herein with respect to all Parties.

NOW, THEREFORE, in consideration of the foregoing, and the mutual covenants contained herein, which the Parties agree and acknowledge constitutes good and valuable consideration, the Parties hereby stipulate and agree as follows:

Provisions

1. Term.

This 2021 Agreement will become effective upon the date of the Commission’s vote approving it (“Effective Date”) and, except as specified otherwise herein, shall continue through and including December 31, 2024, such that, except as specified in this 2021 Agreement, no base rates, charges, or credits (including the CCV and Stand-by Generation credits that are specifically the subject of this 2021 Agreement) or rate design methodologies will be changed with an effective date before January 1, 2025. The period from the Effective Date through December 31, 2024 (subject to subparagraph 10(c)) shall be referred to herein as the "Term." The Parties retain all rights unless such rights are expressly waived, expressly limited, or expressly eliminated by the terms of this 2021 Agreement. Upon expiration of the Term or termination of the 2021 Agreement pursuant to Paragraph 10, the provisions of this 2021 Agreement shall terminate or remain in effect as specified herein.

2. Return on Equity and Equity Ratio.

(a)Subject to the Trigger provisions in subparagraph 2(b) and beginning January 1, 2022, Tampa Electric's authorized return on common equity ("ROE") shall be within a range of 9.00% to 11.00% (“ROE range”), with a mid-point of 9.95% (“mid-point”), except under the

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conditions specifically provided in this 2021 Agreement in Paragraphs 2(b) and 10. Tampa Electric’s authorized ROE range and mid-point (as adjusted by the Trigger if applicable) using a 54 percent equity ratio (investor sources with any difference to actual equity ratio spread ratably over long-term debt and short-term debt) shall be used for all regulatory purposes from January 1, 2022 to the end of the Term (and thereafter until the company’s general base rates and charges are revised by a future unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as the result of the next subsequent general base rate proceeding), including, but not limited to, cost recovery clauses, recovery mechanism(s), earnings surveillance reporting, authorizing a potential exit from this 2021 Agreement pursuant to Paragraph 10, calculating the company’s Allowance for Funds Used During Construction (“AFUDC”), and calculating interim rates as allowed herein.

(b)ROE Trigger Mechanism. The purpose of the provisions in this subparagraph 2(b) is to provide Tampa Electric with rate relief if the interest rate on U.S. Treasury bonds, as identified in subparagraph 2(b)(i), rise above the level specified herein; these provisions are generically referred to as the “Trigger” mechanism or the “Trigger provisions,” or simply as the “Trigger.”  

(i)If at any time during the Term, but no more than once during the Term, the average 30-year United States Treasury Bond yield rate for any period of six (6) consecutive months is at least 50 basis points greater than the yield rate on the date the Commission votes to approve this 2021 Agreement (“Trigger”), Tampa Electric’s authorized ROE shall, after an elective filing by Tampa Electric (“Petition”), be increased by 25 basis points to be within a range of 9.25 percent to 11.25 percent with a mid-point of 10.20 percent (“Revised Authorized ROE”) from the Trigger Effective Date defined below in subparagraph 2(b)(vi) for and through the remainder of the Term, and for any period in which the company’s base rates established in this 2021 Agreement continue

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in effect after December 31, 2024, until the Commission issues a final order in the next subsequent proceeding changing the company’sbase rates and its authorized ROE. No later than five business days after the Commission votes to approve this 2021 Agreement, Tampa Electric shall notify the Parties of the 30-year United States Treasury Bond yield rate that was in effect upon the date the Commission votes to approve this 2021 Agreement by filing in this docket proof of the rate with the Commission Clerk and serving the Parties.

(ii)If the Trigger occurs during the Term, the company’s base rates will be increased by the amount that, if collected for 12 consecutive months would total $10 million, prorated for the remaining billing cycles in the calendar year that it is implemented if the rate change occurs after the first billing cycle of the calendar year, using an equal percentage increase to the basic service, demand, and energy base rates reflected in the company's base rate schedules existing at the time of the increase, except that the service charges and CCV and Stand-by Generation credits shall not be adjusted. If the Trigger occurs, the revenue requirement increase will be $10 million on the basis of 12 consecutive subsequent months whether the Trigger occurs in 2022, 2023, or 2024.

(iii)This $10 million annual base rate increase amount shall be reduced to the extent that the revenue increase would cause the company’s adjusted earnings, as reflected on its pro forma weather adjusted latest, routinely filed earnings surveillance report (“ESR”) for the latest month as of the Trigger Effective Date, to exceed the midpoint of the new range as specified above. The use of the pro forma, weather adjusted ESR for the highly specific circumstances of the Trigger shall not be precedent for use of the pro forma weather adjustment information for any other purpose.

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(iv)The Commission shall approve the company’s verified request for anequal percentage rate increaseto recover the designated revenue requirement pursuant to this Paragraph within sixty (60) days following the filing of the Petition, and such rate increase will be effective with the first billing cycle following Commission approval. The equal percentage increase shall be calculated using the billing determinants included in the company’s most recent projection Energy Conservation Cost Recovery Clause (“ECCR”) filing unless otherwise agreed to by the Parties, with the understanding that the Consumer Parties do not waive the right to challenge the accuracy and validity of the billing determinants.

(v)The Trigger shall be calculated by summing the reported 30-year U.S. Treasury bond rates for each business day over any continuous six-month period, e.g., January 1, 2022 through July 1, 2022, or March 17, 2022 through September 17, 2022, for which rates are reported, and dividing the resulting sum by the number of such business days in such period.

(vi)The effective date of the Revised Authorized ROE (“Trigger Effective Date”) shall be the first day of the month following the day in which the Trigger is reached. If the Trigger is reached and the Revised Authorized ROE becomes effective, except as otherwise specifically provided in this Agreement, Tampa Electric’s Revised Authorized ROE range and mid-point shall prospectively be used for the remainder of the Term (and thereafter until the company’s general base rates and charges are revised by the next subsequent unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as the result of the next subsequent base rate proceeding) for cost recovery clauses, earnings surveillance reporting, Paragraph 10 of this 2021 Agreement regarding an ROE adjustment, and AFUDC.

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(vii)By seeking and receiving a rate increase under this Paragraph, Tampa Electric will be affirming that it remains under this 2021 Agreement for the remainder of the Term, unless and until it subsequently invokes the provisions under Paragraph 10 to exit the 2021 Agreement. Tampa Electric cannot double count the impact of the Trigger and the ability to achieve a higher mid-point by virtue of Paragraph 10. For example, if application of the Trigger were to result in Tampa Electric earning below the new ROE floor, Tampa Electric must choose whether to utilize the Trigger mechanism or to avail itself of Paragraph 10 and exit the 2021 Agreement. Since the purpose of Paragraph 11 on Tax the cost recovery revenue distribution shown on Exhibit Changes is to increase or decrease revenues to counterbalance the impact of corporate income tax rate changes, the net operating income impact of the operation of Paragraph 11 should be zero and thus shall not impact application of the Trigger.

(c)The company may exercise the Trigger mechanism provided in the Paragraph during the Term, but not thereafter. The ROE midpoint and range and equity ratio in effect at the expiration of the Term of this 2021 Agreement, and including ROE midpoint and range that are adjusted pursuant to subparagraph 2(b) shall continue in effect until the company’s ROE is next reset by a final order of the Commission whether by Paragraph 10 or otherwise.

3.2022 Revenue Increase.

(a)The Parties agree that Tampa Electric shall change its base rates and charges for a net annual revenue increase amount of $122,678,000 (“2022 Increase”) effective with the first billing cycle of January 2022 and as more specifically described in this Paragraph. Exhibit A shows the changes from the company’s Initial Rate Case Filing that have been agreed to by the Parties and incorporated in the determination of the 2022 Increase. The 2022 Increase shall be reflected in customer bills using the cost-of-service principles, billing determinants, rate design

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considerations, and tariffs specified in Paragraph 6, below. The 2022 Increase is described as a net increase herein, because some of the company’s service charges will be lower than the service charges currently in effect.

(b)The calculation of the 6.26 percent overall rate of return used to calculate the 2022 Increase is shown in Exhibit B, which is incorporated herein by reference, and reflects the ROE and equity ratio described in Paragraph 2, above.

(c)The Parties agree to the calculation of the company’s 2022 annual revenue requirement and 2022 Increase as shown on Exhibit C, which is incorporated herein by reference. The calculation of the 2022 Increase reflects the removal of the (a) undepreciated net book values as of December 31, 2021 of the AMR assets to be retired; (b) undepreciated net book value as of December 31, 2021 of the portions of Big Bend Units One, Two, and Three to be retired from operations no later than December 31, 2023; and (c) reserve deficiency associated with the dismantlement of Big Bend Units One, Two, and Three from the 2022 revenue requirement recovered through base rates and charges and transfer of those costs for cost recovery via the Clean Energy Transition Mechanism (“CETM”) described in Paragraph 5, below, and the following six (6) agreed to adjustments to the 2022 projected FPSC jurisdictional rate base and net operating income amounts shown in the company’s Initial Rate Case Filing minimum filing requirement schedules (“MFRs”):

(i)Clean Energy Transition Mechanism. The Parties agree that revenue requirement for the cost recovery of the: (a) undepreciated net book values as of December 31, 2021 of the AMR assets to be retired; (b) undepreciated net book value as of December 31, 2021 of the portions of Big Bend Units One, Two, and Three to be retired; and (c) reserve deficiency associated with the dismantlement of Big Bend Units One, Two, and Three shall be removed from the: (i) revenue

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requirement used to develop 2022 base rates and chargesand (ii) the 2022 ECRC clause factor determination;and will be recovered through the CETM described in Paragraph 5, below. The adjustments related to the CETM shall be reflected on future ESRs consistent with the cost-of-service adjustment agreed to herein and Commission ESR reporting requirements for clauses.

(ii)GBRA Assets and Expenses. The Parties agree that the 2022 thirteen-month average rate base amount shall be reduced by $84,449,106 to eliminate the potential of double counting in the calculation of the GBRAs described in Paragraph 4, below. The effect of this change on the 2022 thirteen-month average rate base is shown on Exhibit D. The Parties also agree that 2022 test year O&M expenses should be reduced by $1.6 million for the same reason. The effect of this change on the 2022 net operating income is shown on Exhibit E. This is a one-time adjustment needed to correct the revenue requirement for 2022 and shall not be reflected on future ESRs.

(iii)Solar ITC Credits. The Parties have agreed that the life of solar assets to be used when calculating depreciation rates and expenses shall be extended from 30 years (as initially proposed by the company) to 35 years; consequently, the Parties agree that the amortization period to reflect solar ITCs on a normalized basis should also be extended from 30 to 35 years, resulting in an annual test year increase to income tax expense and reduction to net operating income of $1,482,776, which when grossed up has the effect of increasing the 2022 revenue requirement by $1,991,591. This calculation is shown on Exhibit F. The calculation of the 2023 and 2024 GBRAs specified in Paragraph 4 reflect the economic impact of the change to a 35-year life for solar assets. The impact of this change will be reflected in system per books amounts for future ESRs.

(iv)O&M Expense - Incentive Compensation. The Parties have agreed that the amount of incentive compensation expense included in the calculation of 2022 jurisdictional net operating income in the company’s Initial Rate Case Filing shall be reduced by $5 million. This amount is a

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negotiated amount that compromises a dispute among theParties, acknowledges the fact that a certain portion of executive and non-executive incentive compensation is related to financial incentives including increasing shareholder value in the form of earnings per share, while also recognizing that incentive compensation can contribute to increased safety and reliability, and that this negotiated adjustmentshall have no precedential value as to any Party in the future. The effect of this change on the 2022 net operating income is shown on Exhibit E. This adjustment shall be reflected on future ESRs.

(v)Other O&M Expenses. The Parties have agreed that the total amount of O&M Expenses in the 2022 test year shall be reduced by an additional $11.5 million from levels identified in the company’s Initial Rate Case Filing over the $5 million incentive compensation adjustment specified above, resulting in a total O&M reduction of $16.5 million for the 2022 test year. The effect of the incremental $11.5 million change on the 2022 net operating income is shown on Exhibit E. This additional $11.5 million reduction is a negotiated amount intended to resolve differences between the Consumer Parties and the Company regarding (a) the level of anticipated savings from future system and process improvements; (b) the appropriate amount of shared services expenses, employee staffing, and other miscellaneous O&M expenses recoverable for the 2022 test year; and (c) to address the resolution of potential disputes about the effects of inflation and the company’s 2022 revenue forecast. Instead of the $11.5 million adjustment that was used to develop the 2022 Revenue Increase, the company will make a $6 million adjustment on future ESRs to reflect a compromise among the Parties regarding the appropriate level of shared services expenses.

(vi)Depreciation and Dismantlement Expense. The 2022 proposed jurisdictional annual depreciation and dismantlement expense proposed by the company in its Initial Rate Case

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Filing has been reduced by $28.7 million resulting in a net annual 2022 FPSC Adjusted depreciation and amortization expense of $376,000,000. This change is a product of certain changes to the company’s proposed depreciation and dismantlement rates specified in Paragraph 9, below. The agreed-to depreciation and dismantlement rates and the calculation of the $28.7 and $376.0 million amounts specified above are detailed on Exhibit G and the solar asset change calculations are shown on Exhibit H. The FPSC Adjusted depreciation and amortization expense above is based on (a) the agreed-to depreciation and dismantlement rates specified in Paragraph 9, below, (b) the accelerated recovery of the retiring Big Bend Unit One, Two and Three assets and retiring AMR assets moving to the  CETMdescribed in Paragraph 5, below, and (c) the recovery of the dismantlement deficiency for the retiring Big Bend Unit One, Two and Three assets moving to the CETM described in Paragraph 5, below. The effect of these rate changes on the2022 thirteen-month average rate base system per books is shown on Exhibit D. The effect of these rate changes on the 2022 net operating income is shown on Exhibit E. The impact of these changes will be reflected in system per books amounts for future ESRs.

(d)In addition to the adjustments established in this 2021 Agreement as specified in subparagraph 3(c), above, and except as modified by or specified in subparagraph 3(c), the company beginning January 1, 2022 shall reflect the adjustments shown on MFR schedules B-2 (rate base adjustments), C-2 (net operating income adjustments), and D-1b (cost of capital adjustments) on the surveillance reports to be filed during the Term of this 2021 Agreement, and thereafter until the company’s general base rates and charges are revised by a future unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as the result of the next subsequent general base rate proceeding. Without limiting the generality of the foregoing, the Parties agree that the company’s proposed coal

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inventory target as explained in the testimony of John Heisey and the company’s proposed level of economic development expenses as explained in the testimony of Jeffrey S. Chronisterare reasonable and prudent, are specifically approved, and shall remain in effect until the company’s general base rates and charges are revised by a future unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as the result of the next subsequent general base rate proceeding.

4.Generation Base Rate Adjustments (GBRA).

(a)Notwithstanding the general base rate freeze specified in Paragraph 10, the company shall recover the cost of its investment in, and operation of, Phase Two of its Big Bend Modernization Project and Phases Two and Three of its Future Solar projects to the extent of the GBRAs as specified in this Paragraph 4.

(b)Effective with the first billing cycle in January 2023 and 2024, the Parties agree that Tampa Electric shall increase its base rates and charges to reflect GBRAs in the annual amounts of $89,754,622 and $21,376,909, respectively. The calculation of these amounts is shown on Exhibit I, which is incorporated herein by reference.

(c)If the applicable federal or state corporate income tax rate for the company changes before any of the increases provided for in this Paragraph 4, the company will adjust the amount of any such base rate increase to reflect the new corporate income tax rate before the implementation of such increase as specified in Paragraph 11.

(d)If the company’s authorized mid-point return on equity changes by operation of subparagraph 2(b) of this 2021 Agreement prior to the effective date of the rate adjustments specified in this subparagraph, the calculation of the GBRA amounts shown on Exhibit I shall be

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updated to reflect the new mid-point return on equity and customer’s bills for billing cycles following such authorization shall reflect the updated mid-point return on equity.

(e)While 4 CP is the principle on which the company’s next base rate case will be filed, during the Term of the 2021 Agreement, the GBRAs shall be reflected on customer bills by allocating each GBRA revenue requirement to rate classes as shown in Exhibit K and demand and energy base rate charges shall be increased on an equal percentage basis (to the extent practicable) within each class to recover the allocated revenue requirement increase for each class, and shall be calculated based upon the billing determinants used in the company’s then-most-current ECCR filing with the Commission for the twelve months following the effective date of any respective GBRA. For GSD, GSLDPR, and GSLDSU rate classes, the increase will be recovered exclusively based on demand charges.

(f)In order to provide adequate time for review by the Commission and the Parties and to provide notice to customers as required by the Commission’s rules, the company shall file the tariff changes necessary to implement the GBRAs specified in this Paragraph 4 on or before the dates specified for projected ECRC filings in 2022 and 2023.

(g)Except as specified in this 2021 Agreement, Tampa Electric’s base rate and credit levels applied to customer bills, including the effects of the GBRAs implemented pursuant to this 2021 Agreement, shall continue in effect until next reset by future unanimous agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as a result of the next subsequent general base rate proceeding.

(h)Nothing in this 2021 Agreement shall preclude any Party to this 2021 Agreement or any other lawful party from participating, consistent with the full rights of an intervenor, in any

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proceeding that addresses any matter or issue concerning the GBRA provisions of this 2021 Agreement.

5.Clean Energy Transition Mechanism (“CETM”).

(a)The Parties agree that (i) the net book value as of December 31, 2021 of the company’s AMR assets to be retired, (ii) the net book value as of December 31, 2021 for the portions of Big Bend Units One, Two, and Three to be retired (including costs slated for recovery via the ECRC) (“Big Bend Retirement Assets”), and (iii) the company’s dismantlement reserve deficiency for the Big Bend Retirement Assets as shown in the company’s MFRs and described in its testimony and as are currently slated for recovery through the ECRC, shall be moved into regulatory asset accounts and recovered from customers using the levelized Clean Energy Transition Mechanism (“CETM”) described in this Paragraph 5 and not through its general base rates and charges or the ECRC. The calculation of the annual levelized CETM revenue amount of $68,550,000 is attached hereto as Exhibit J, which is incorporated by reference. The company’s new CETM tariff shall be filed in conjunction with the tariff filing specified in Paragraph 6. The following cost-of-service principles and rate design considerations were used to calculate the CETM:

(i)The levelized annual revenue requirement of $68,550,000 was used to design the initial CETM charges. That amount is made up of two categories of cost: costs associated with the Big Bend retirements and costs associated with the AMR meter retirements. The Big Bend costs were allocated to each rate class for rate design using the allocation factor last approved by the FPSC in the overall cost-of-service study for the most recent base rate proceeding associated with fossil fueled production plant cost. The AMR costs will be allocated based on the allocation factor last approved by the FPSC in the overall cost-of-service study for the most recent base rate

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proceeding associated with meter plant cost.   For purposes of the 2022 CETM charge calculations, the energy billing determinants utilized (to the extent applicable) were the ones contained in the company’s Initial Rate Case Filing. For recovery of its CETM charges, TECO agrees to recover CETM costs from demand-metered customers on a demand (i.e., $/kW) basis, during the term of this 2021 agreement. For non-demand-metered customers, TECO agrees to recover CETM costs on an energy (i.e., $/kWh) basis, i.e., once allocated to relevant rate classes, each rate class-allocated revenue requirement was divided by the energy billing determinants to derive class rates.

(ii)The CETM factors will be updated periodically, beginning with rates that are effective with the billing cycle that begins approximately on or after January 1, 2025, and as described in subparagraph 5(d) below and as qualified in this subparagraph if any third year identified in that subparagraph is also a test year in a Tampa Electric general base rate proceeding then the update will occur as soon as possible but no later than 90 days after the conclusion of each company general base rate proceeding. The periods subsequent to December 31, 2024 that are covered by the update shall each be known as the “Update Period.” The starting point for each subsequent Update Period will be reset based on the effective date of the then most current update as described in subparagraph 5(d).

(b)Each update will be calculated using new forecasted billing determinants for the divisor and updated allocation factors for allocation of the levelized revenue requirement to rate classes based on new forecasted loads of the applicable rate classes. Each Update Period filing shall be submitted for review by the Commission contemporaneous with the projected ECCR filings in the year prior to the proposed effective date of the new CETM factors. For each Update Period, TECO agrees to continue recovering CETM costs from demand-metered customers on a

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demand (i.e., $/kW) basis. For non-demand-metered customers, TECO agrees to recover CETM costs on an energy (i.e., $/kWh) basis.

(c)The CETM tariff established in this Paragraph 5 shall become effective with the first billing cycle in January 2022. The CETM shall appear on customer bills as a separate line item denominated as the “Clean Energy Transition Mechanism” (or a reasonable and clear abbreviation of that term if an abbreviation is needed to meet space limitations on the bills) and shall remain in effect for a period of 15 years from the first billing cycle in January 2022 through the last billing cycle of 2036, subject to a final true up in 2036 as described in subparagraph 5(h), below, and shall not be modified except as specified in subparagraphs 5(d), (e), (f), and (g). The mechanism established in this Paragraph 5 was specifically negotiated and established for the fair and reasonable recovery of known, defined costs, resulting in substantial rate mitigation benefits for customers during the Term and thereafter. It is based on the highly specific circumstances of Tampa Electric Company’s unique technological transition to smart meters and solar energy, is not intended to be a new cost recovery clause and shall not be expanded to allow recovery of costs other than those specified herein without the express written consent of all of the Parties to this 2021 Agreement. Further, the creation of the CETM is based on the give-and-take and compromises among the Parties and is in no way intended to be a precedent for adoption by the Commission for another utility who does not share the identical circumstances.

(d)Periodic CETM Factor Updates. Beginning in 2024, and every three years, or as modified by the timing of a general base rate proceeding provided in subparagraph 5(a)(ii) above, and thereafter until the 15-year CETM period expires, the company shall prepare and file with the FPSC a tariff filing reflecting the company’s proposed CETM billing factors for the next Update Period to be effective with the first billing cycle of the following year. The CETM factors for each

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Update Period shall be calculated using the $68,550,000 annual CETM amount as adjusted pursuant to this Paragraph 5 and the billing determinants used in the company’s ECCR filing with the Commission for the first calendar year CETM factors will be in effect. The Parties agree that theseUpdate Period filingsare not a clause-like proceeding and shall not be a vehicle for a “rate case” type inquiry into the operations, investments, and finances of the company, and that annual amount of revenue to be recovered through the CETM shall not be changed except as specified in this Paragraph 5. If the CETM is adjusted prospectively as specified in subparagraphs 5(e), (f), or (g, the Update Period for the next factor adjustment shall be re-set and run from January of the year following the effective date of the changes resulting from application of subparagraphs 5(e), (f), or (g). Nothing in this 2021 Agreement shall preclude any Party to this 2021 Agreement or any other lawful party from participating in the Update Period review of the CETM charges, consistent with the full rights of an intervenor.

(e)Dismantlement Cost True-Up.

(i)The amount for the Big Bend Unit One, Two, and Three assets to be retired (“Big Bend Retirement Assets”) in the company’s projected dismantlement reserve balance as of December 31, 2021 is $8,301,987. The company’s projected dismantlement reserve deficiency as of December 31, 2021 is $111,088,808. The calculation of the CETM reflects recovery of this $111,088,808 reserve deficiency over a period of 13 years beginning January 2024, as shown in Exhibit J. The total of the company’s projected depreciation and dismantlement reserve balance as of December 31, 2021 and the company’s projected dismantlement reserve deficiency as of December 31, 2021 for the Big Bend Retirement Assets is $119,301,987 and shall be referred to herein as the “Big Bend Retirement Asset Dismantlement Estimate.”

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(ii)The amount of dismantlement costs the company will actually incur to dismantle the Big Bend Retirement Assets will not be known with certainty until the dismantlement work occurs and has been completed. During the first annual CETM Factor Filing after the dismantlement of the Big Bend Retirement Assets is complete and the related work orders have been closed, the company shall propose to adjust the CETM prospectively to reflect the actual costs associated with dismantlement recorded in the regulatory asset accounts. While the company shall have sole discretion as to the timing of the dismantlement true-up process, it agrees to incorporate such dismantlement true-up proposal into the Update Period true-up, to the extent it is feasible. As part of this true-up process, the difference between the actual amount of dismantlement costs incurred and the Big Bend Retirement Asset Dismantlement Estimate, plus the associated carrying costs calculated using the company’s then applicable overall ROR, shall result in the true-up amount – whether positive or negative – and the CETM factors shall be adjusted to reflect the true-up amount over whatever portion of the 15-year CETM period remains. Nothing in this 2021 Agreement shall preclude any Party to this 2021 Agreement or any other lawful party from participating, consistent with the full rights of an intervenor, in any proceeding that addresses any matter or issue concerning the Dismantlement True-Up of the CETM.

(f)Overall Rate of Return Adjustments to the CETM. The CETM annual revenue recovery amount shall be adjusted prospectively to reflect changes to the company’s updated overall rate of return each time the company’s midpoint return on equity is reset in a proceeding that adjusts the company’s general base rates and charges, including, but not limited to, by operation of the Trigger. The adjustment contemplated in this subparagraph will apply the company’s new overall rate of return (based on the company’s new FPSC-approved weighted average cost-of-capital calculated using updated capital balances and cost rates) to the return

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calculation used to compute the CETMannual revenue amount. Within a reasonable time after the company’s authorized midpoint return on equity has been adjusted and a new overall rate of return has been approved, the company will file a petition with the FPSC to adjust the CETMannual revenue amount prospectively to reflect the updated overall rate of return. While the company shall have sole discretion as to the timing of the dismantlement true-up process, it agrees to incorporate such overall rate of return true-up proposal into the Update Period true-up, to the extent it is feasible. Nothing in this 2021 Agreement shall preclude any Party to this 2021 Agreement or any other lawful party from participating, consistent with the full rights of an intervenor, in any proceeding that addresses any matter or issue concerning a Rate of Return Adjustment to the CETM annual revenue amount.

(g)Corporate Income Tax Rate Changes to CETM. The CETM annual revenue recovery amount shall be adjusted prospectively each time federal or state corporate income tax rates (or another provision covered under Paragraph 11 which is applicable to the cost elements included for recovery through the CETM) are increased or decreased. The adjustment contemplated in this subparagraph will apply the new statutory corporate income tax rates in the revenue requirement calculation used to compute the CETM amount. Within a reasonable time after the company becomes aware of a federal or state corporate income tax rate change, the company will file a petition with the FPSC to adjust the CETM annual recovery amount prospectively to reflect the new statutory corporate income tax rate(s) as of the effective date of the rate change. While the company shall have sole discretion as to the timing of the tax true-up process, it agrees to incorporate such overall rate of return true-up proposal into the Update Period true-up, to the extent it is feasible. Any effects of the Paragraph 11 Tax Change provision changes on the CETM annual revenue amount from the effective date of the corporate income tax rate

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change through the date the updated CETM factors become effective shall be flowed back to or collected from customers through the ECCR on the same basis as used in any base rate adjustment. Nothing in this 2021 Agreement shall preclude any Party to this 2021 Agreement or any other lawful party from participating, consistent with the full rights of an intervenor, in any proceeding that addresses any matter or issue concerning a corporate income tax rate adjustment to the CETM annual revenue amount.

(h)Final True-Up. During 2037, the company shall petition the Commission to true up the total amount recovered for the CETM through the end of 2036 so the total amount of costs recovered from the CETM equals the annual $68,550,000 specified above as adjusted for actual dismantlement costs in subparagraph (e), overall rate of return in subparagraph (f), and any corporate income tax changes in subparagraph (g), above. The total true-up amount shall be credited or debited to the ECCR (or another clause if there is no ECCR in 2037) in conjunction with the 2036 true-up filing in 2037. This true-up shall also be designed to adjust for any over- or under-recovery of the revenue requirement applicable to the 15^th year of the CETM.

(i)Survival of CETM Provisions. This Paragraph 5 shall survive the Term, the expiration of the Term by operation of the 2021 Agreement and any early termination of this 2021 Agreement pursuant to Paragraph 10, and shall remain in effect until the last billing cycle of December 31, 2036, subject to the Final True Up specified in subparagraph 5(h). The Parties acknowledge that (i) the levelized nature of the CETM benefits customers in the early years of the CETM, because the levelized annual revenue amount for recovery is lower than it would be using a traditional declining net book value ratemaking approach, (ii) this benefit to the customers has a corresponding and material cost to the company, (iii) that the benefits and costs to the customers and the company even out over the life of the mechanism, (iv) that the company’s willingness to

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agree to the  levelized cost-recovery approach reflected in the CETM is reasonable and in justifiable reliance on the CETM remaining in effect for the entire 15-year period contemplated herein, and (v) it would be inequitable for the CETM to be terminated before the company fully recovers the costsanticipated to be recovered via CETM as specified in Exhibit J, and as adjusted for actual dismantlement costs as described in subparagraph 5(d), but no more than the adjusted amount.

6.Cost-of-Service Study, Billing Determinants, Rate Design, and Customer Rates.

(a)Effective with the first billing cycle in January 2022, the company shall be authorized to change its base rates and charges for a net annual revenue increase amount of approximately $122,678,000 based on the 2022 billing determinants reflected in the company’s Initial Rate Case Filing in this proceeding, adjusted to reflect correction of errors identified during the discovery process and the cost recovery revenue distribution shown on Exhibit K. The updated and agreed-to tariffs reflecting the customer rates and charges and other terms and conditions of service specified herein to become effective with the first billing cycle in January 2022 will be those in the company’s Initial Rate Case Filing as updated to reflect the changes specified in this 2021 Agreement, and shall be filed with the FPSC within two-weeks of the date of submission of this 2021 Agreement for approval. Approval of this 2021 Agreement by the Commission shall constitute approval of the tariffs filed pursuant to this Paragraph 6.

(b)The following cost-of-service principles and rate design considerations are agreed to by the Parties and will be reflected in the tariff sheets to be filed as specified above:

(i)Transition to 100% implementation and application of Minimum Distribution System (“MDS”) in the cost-of-service study for rate allocation purposes; however, retain the

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proposed basic service charge rate design for the RS and GS rate classes notwithstanding the 100% implementation of MDS in this case;

(ii)Allocate solar production plant costs in the cost-of-service study consistent with how non-solar production plant costs are allocated;

(iii)Transition to allocation, using a full 4 CP (three summer and one winter month) method for all production and transmission costs to each rate schedule within the cost- of-service study;

(iv)Increase stand by generator conservation program and interruptible conservation program credits as described in subparagraph 6(i) below;

(v)Certain changes and additions to (a) Lighting Tariff’s LS-1 and LS-2 and (b) standard lighting contracts as shown on Exhibit L; and

(vi)The company’s proposed service charges as included in its Initial Rate Case Filing.

(c)Except as specified in this 2021 Agreement, the company’s general base rates, charges, credits, and rate design methodologies, for retail electric service specified in Paragraph 6, above, shall remain in effect for billing cycles through and including December 31, 2024, until revised by a future unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as the result of the next subsequent general base rate proceeding; however, nothing in this 2021 Agreement shall limit the ability of the company to begin collecting proposed new base rates and charges or a portion thereof subject to refund effective after the first billing cycle in January 2025 if the eight-month period of withheld consent specified in Section 366.06(3), Florida Statutes, has expired.

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(d)The company shall, effective with the first billing cycle of 2022, allocate among its respective rate schedules all the revenue requirements established under this 2021 Agreement by applying the cost recovery revenue distribution shown on Exhibit K.This revenue attribution was derived by application of the 4 CP methodology for allocating production and transmission plant costs and the use of the full Minimum Distribution System (“MDS”) costing method for allocating distribution plant costs, as mitigated. The Parties have agreed to the transitional revenue percentage allocations shown in Exhibit K.with the further understanding that the company will, for purposes of meeting its initial burden of proof in complying with Rule 25-6.043, F.A.C., in Tampa Electric Company’s next general base rate proceeding, file the cost-of-service MFRs using the 4 CP and full MDS methods for cost allocation. The company further commits to base its filed revenue attribution among customer classes in its next general base rate proceeding on full implementation of the 4 CP and MDS methodologies, and in that initial filing tosubstantially and materially improve the position of all above-parity customer classes toward parity, such that costs are allocated and revenue is collected consistent with 4 CP and full MDS methods. All Parties and affiliates of TECO (“Precluded Parties”) will either not oppose, or will support, the 4 CP and full MDS implementation. If the 4 CP or full MDS methodology is opposed in the next general base rate case by an entity other than a PrecludedParty,the Parties will indicate that they continue to support or not oppose implementation of the 4 CP and full MDS, but in response, may offer responsive information on alternative cost-of-service methodologies and revenue allocation methodologies solely on an alternative basis.

(e)With respect to cost recovery clauses that recover plant investment costs, it is the intent of the Parties that the company shall use the midpoint return on equity and equity ratio specified in Paragraph 2 and shall allocate among its respective rate schedules the annual cost

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recovery amounts to be recovered by applying the cost recovery revenue distribution shown on Exhibit K, and that the revenue distribution in Exhibit K shall be used in cost recovery clauses that recover plant investment costs until the company’s general base rates and charges are revised by a future unanimous agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as the result of the next subsequent general base rate proceeding, subject to the following:

(i)Storm Protection Plan Cost Recovery Clause. The Commission’s proceeding to establish 2022 cost recovery factors for the Storm Protection Plan (“SPP”) is complete and the Commission has given its staff authority to administratively approve updates the company’s 2022 SPP factors to reflect the provisions of this 2021 Agreement if it is approved. Upon approval of this 2021 Agreement, the company shall submit revised 2022 SPP factors for review and approval by Staff within a reasonable time so that the impact of this 2021 Agreement will be reflected in the 2022 SPP factors effective with the first billing cycle in January 2022.

(ii)Other Clauses that Recover Plant Investment. The Parties acknowledge that the company’s 2022 projection filings for the ECCR and ECRC will likely be made before the Commission has an opportunity to approve this Agreement, but nevertheless desire that the company begin using the midpoint return on equity, equity ratio and revenue allocations specified in this 2021 Agreement for those clauses beginning with the first billing cycle of January 2022. Accordingly, the company may submit its 2022 projection filings in these two dockets without reflecting the terms of this 2021 Agreement, but upon approval of this 2021 Agreement will promptly submit to the Commission updated projection filings reflecting the midpoint return on equity, equity ratio and revenue allocations specified in this 2021 Agreement so that the 2022 cost

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recovery factors reflecting these inputs can become effective with the first billing cycle in January 2022.

(f)Except as expressly provided in this 2021 Agreement, the company may not petition to change any of its general base rates, charges, credits, cost allocation or rate design methodologies for retail electric service with an effective date for any such changes earlier than January 1, 2025.

(g)Notwithstanding subparagraphs 6(c) and 6(f), the company shall be authorized to change its base rates during the Term of this 2021 Agreement as set forth in Paragraphs 2(b), 4, 5, 6(c), and 11 in accordance with procedures identified therein for the Trigger, the GBRA mechanism, CETM factor updates, and the Tax Change provision.

(h)The current lock period for the Contracted Credit Value (“CCV”) shall remain 72 months (6 years).

(i) The company’s standby generator credit and commercial demand response credit shall be increased from $5.35/kW/month to $6.15/kW/month, concurrent with meter reads for the first billing cycle of January 2022. The CCV credit shall be increased from $10.23/kW/month to $11.75/kW/month for secondary, $10.13/kW/month to $11.63/kW/month for primary, and $10.03/kW/month to $11.52/kW/month for sub-transmission voltage customers, concurrently with meter readings for the first billing cycle of January 2022. To the extent that implementation of these revised credits results in an under-recovery or over-recovery of revenues that are subject to the ECCR, the company shall be authorized to make an adjustment to remedy any such under-recovery or over-recovery in its ECCR charges for 2023 and thereafter. The level of these credits will not change during the Term and will remain in effect after the expiration of the Term until

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changed, if at all, by a future unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as a result ofthe next subsequent general base rate proceeding. The credit modifications addressed in this subparagraph 6(g) will be reflected in the revised tariff sheets to be filed pursuant to this 2021 Agreement, the approval of which shall constitute approval of the revised tariff sheets.

(j)The company’s Economic Development Rider, which is set forth in Rate Schedule ECONOMIC DEVELOPMENT RATE – EDR of the company’s retail tariff, shall remain in effect during the Term and thereafter until modified or terminated by order of the Commission. The Parties intend that the Commission’s approval of this 2021 Agreement shall constitute continuing approval of the Economic Development Rider and that such approval shall satisfy the requirements of Rule 25-6.0426(3) - (6), F.A.C., and accordingly, the reductions afforded in Rate Schedule EDR shall be included as a cost in the company’s cost of service for all ratemaking purposes and surveillance reporting. The rates in the Economic Development Rider shall be open for new customers and for new applications by existing customers through December 31, 2024, unless the maximum amount of economic development expenditures as specified in Rule 25-6.0426, F.A.C., is met, at which time the Economic Development Rider will be closed to new customers and to new applications by existing customers until the amount again falls below the maximum allowed.

(k)The provisions of this Paragraph 6 shall remain in effect during the Term except as otherwise permitted or provided for in this 2021 Agreement and shall continue in effect until changed by a unanimous signed agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as a result of the next subsequent general base rate proceeding.

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7.Other Cost Recovery. Nothing in this 2021 Agreement shall preclude the company from requesting the Commission to approve the recovery of costs that are: (a) of a type which traditionally or historically would be, have been, or are presently recovered through cost recovery clauses or surcharges, or (b) incremental costs not currently recovered in base rates which the Legislature expressly requires shall be clause recoverable. Except as specified in this 2021 Agreement, the company shall not seek to recover, nor shall the company be allowed to recover, through any cost recovery clause or charge, or through the functional equivalent of such cost recovery clauses and charges, costs of any type or category that have historically or traditionally been recovered in base rates, unless such costs are: (i) the direct and unavoidable result of new governmental impositions or requirements such as, for example and without limitation, expresscarbon reduction or expressrenewable energy mandates; or (ii) new or atypical costs that have not been litigated before the Commission because they were unforeseeable (in contrast to, for instance, pandemic costs) and could not have been contemplated by the Parties resulting from significantly changed industry-wide circumstances directly affecting the company’s operations. As a part of the base rate freeze agreed to herein, the company will not seek Commission approval to defer for later recovery in rates, any costs incurred or reasonably expected to be incurred (such as those which have been litigated before the Commission (e.g. pandemic costs)), from the Effective Date through and including December 31, 2024, which are of the type which historically or traditionally have been or would be recovered in base rates, unless such deferral and subsequent recovery is expressly authorized herein or otherwise agreed to in a writing signed by each of the Parties. The Parties are not precluded from participating in any proceedings pursuant to this Paragraph 7, nor is any Party precluded from raising any issues pertinent to any such proceedings or the enforcement of this 2021 Agreement.This Paragraph 7 shall expire at the end of the Term or upon termination of the 2021 Agreement pursuant to Paragraph 10.

8.Storm Damage.

(a)Nothing in this 2021 Agreement shall preclude Tampa Electric from petitioning the Commission to seek recovery of costs associated with any tropical systems named by the National Hurricane Center or its successor without the application of any form of earnings test or measure and irrespective of previous or current base rate earnings. Consistent with the rate design and cost allocation methods approved in this 2021 Agreement, the Parties agree that recovery of storm costs from customers will begin, on an interim basis (subject to refund following a hearing or a full opportunity for a formal proceeding), sixty days following the filing by the company of a cost recovery petition and tariff with the Commission and will be based on a 12-month recovery period if the storm costs do not exceed $4.00/1,000 kWh on monthly residential customer bills. In the event the company’s reasonable and prudent storm costs exceed that level, any additional costs in excess of $4.00/1,000 kWh shall be recovered in a subsequent year or years as determined by the Commission, after hearing or after the opportunity for a formal proceeding has been afforded to all substantially affected persons or parties. All storm related costs shall be calculated and disposed of pursuant to Rule 25-6.0143, F.A.C., and shall be limited to (i) costs resulting from such tropical system named by the National Hurricane Center or its successor, (ii) the estimate of incremental storm restoration costs above the level of storm reserve prior to the storm, and (iii) the replenishment of the storm reserve to $55,860,642. The Parties to this 2021 Agreement are not precluded from participating in any such proceedings and opposing the amount of Tampa Electric's claimed costs (for example, and without limitation, on grounds that such claimed costs were not reasonable or were not prudently incurred) or whether the proposed recovery is consistent with this Paragraph 8, but not the mechanism agreed to herein.

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(b)The Parties agree that the $4.00/1,000 kWh cap in this Paragraph 8 shall apply in aggregate for a calendar year; provided, however, that Tampa Electric may petition the Commission to allow Tampa Electric to increase the initial 12 month recovery at rates greater than $4.00/1,000 kWh or for a period longer than 12 months if Tampa Electric incurs in excess of $100 million of storm recovery costs that qualify for recovery under subparagraph 8(a) in a given calendar year, inclusive of the amount needed to replenish the storm reserve to $55,860,642. All Consumer Parties reserve their right to oppose such a petition or take any position thereon.

(c)The Parties expressly agree that any proceeding to recover costs associated with any storm shall not be a vehicle for a "rate case" type inquiry concerning the expenses, investment, or financial results of operations of Tampa Electric and shall not apply any form of earnings test or measure or consider previous or current base rate earnings. Such issues may be fully addressed in any subsequent Tampa Electric base rate case.

(d)The provisions of this Paragraph 8 shall remain in effect during the Term except as otherwise permitted or provided for in this 2021 Agreement and shall continue in effect until the company’s base rates are next reset by the Commission. For clarity, this means that if this 2021 Agreement is terminated pursuant to Paragraph 10 hereof, the company’s rights regarding storm cost recovery under this 2021 Agreement are terminated at the same time, except that any Commission-approved surcharge then in effect shall remain in effect until the costs subject to that surcharge are fully recovered. A storm surcharge in effect without approval of the Commission shall be terminated at the time this 2021 Agreement is terminated pursuant to Paragraph 10 hereof.

(e)During the Term, the company will continue to follow the Future Process Improvements specified in the Tampa Electric Storm Cost Settlement Agreement filed with the FPSC on April 9, 2019 and approved by Order No. PSC-2019-0234-AS-EI, issued June 14, 2019

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in Docket No. 201702711-EI. Inclusion of this subparagraph (e) shall not be construed to mean that the expiration of the Term or termination of this 2021 Agreement has any effect on the effectiveness or validity of Order No. PSC-2019-0234-AS-EI.

9.Depreciation.

(a)The Parties agree and intend that, notwithstanding any requirements of Rules 25-6.0436 and 25-6.04364, F.A.C., the company shall not be required during the Term of this 2021 Agreement to file any depreciation study or dismantlement study. The depreciation and amortization accrual rates specified on Exhibit G to this 2021 Agreement or otherwise in effect on December 31, 2021 shall remain in effect during the Term or until the company’s next depreciation study and resulting depreciation and dismantlement rates have been approved, whichever is later. Notwithstanding the previous sentence, during the Term, the company may in its sole discretion petition, on an estimated earnings-neutral basis, the Commission to extend the lives of lighting assets and thereby reduce depreciation rates for lighting assets, and the Parties reserve all rights to oppose such petition, except that they may not claim that the petition violates this 2021Agreement.

(b)Notwithstanding the provisions of subparagraph 9(a) above, the company shall file a depreciation and dismantlement study or studies no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding, such that there is a reasonable opportunity for the Consumer Parties to review, analyze and potentially rebut depreciation rates or other aspects of such depreciation and dismantlement studies contemporaneously with the company’s general base rate proceeding referenced in the first sentence of this subparagraph 9(b). The depreciation and dismantlement study period shall match the test year in the MFRs accompanying the general base rate case filed in accordance with this subparagraph, with all supporting data in

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electronic format with links, cells, and formulae intact and functional, and shall be timely served upon all Consumer Parties and all intervenors in such subsequent rate case.

10.Earnings.

(a)Notwithstanding Paragraph 2, and subject to the Trigger provisions in subparagraph 2(b) above, if Tampa Electric's earned return on common equity falls below 9.00% during the Term on a compliant monthly earnings surveillance report stated on an actual Commission thirteen-month average adjusted basis, Tampa Electric may petition the Commission to amend its base rates either through a general rate proceeding under Sections 366.06 and 366.07, Florida Statutes, or through a limited proceeding under Section 366.076, Florida Statutes. Nothing in this 2021 Agreement shall be construed as an agreement by the Consumer Parties that a limited proceeding would be appropriate, and Tampa Electric acknowledges and agrees that the Parties reserve and retain all rights to challenge the propriety of any limited proceeding or to assert that any request for base rate changes should properly be addressed through a general base rate case, as well as to challenge any substantive proposals to change the company’s rates in any such future proceeding. This floor of 9.00% shall be subject to adjustment in accordance with the Trigger provision in subparagraph 2(b). For purposes of this 2021 Agreement, "Commission actual adjusted basis" and "actual adjusted earned return" shall mean results reflecting all adjustments to Tampa Electric's books required by the Commission by rule or order, but excluding pro forma adjustments. No Consumer Parties shall be precluded from participating in any proceeding initiated by Tampa Electric to increase base rates pursuant to this Paragraph 10, and no Consumer Party is precluded from opposing or seeking to modify Tampa Electric's request.

(b)Notwithstanding Paragraph 2, and subject to the Trigger in subparagraph 2(b) above, if Tampa Electric's earned return on common equity exceeds 11.00% during the Term on a

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compliantmonthly earnings surveillance report stated on an actual Commission thirteen-month average adjusted basis, no Party shall be precluded from petitioning the Commission for a review of Tampa Electric's base rates. In any case initiated by Tampa Electric or any other Party pursuant to Paragraph 7, all Parties will retain full rights conferred by law. The ceiling of 11.00% set forth in this subparagraph shall be subject to adjustment in accordance with the Trigger provision in subparagraph 2(b).

(c)Notwithstanding Paragraph 2 and subject to the Trigger provisions in subparagraph 2(b) above, this 2021 Agreement shall terminate upon the effective date of any Final Order of the Commission issued in any proceeding pursuant to Paragraph 10 that changes Tampa Electric's base rates prior to the last billing cycle of December 2024.

(d)This Paragraph 10 shall not: (i) be construed to bar Tampa Electric from requesting any recovery of costs otherwise contemplated by this 2021 Agreement; (ii) apply to any request to change Tampa Electric's base rates that would become effective after the expiration of the Term of this 2021 Agreement; (iii) limit any Party's rights in proceedings concerning changes to base rates that would become effective subsequent to the Term of this 2021 Agreement to argue that Tampa Electric's authorized ROE range should be different than as set forth in this 2021 Agreement; or (iv) affect the provisions of subparagraphs 6(d), 6(f) and 6(g) of this 2021 Agreement.

(e)Notwithstanding any other provision of this 2021 Agreement, the Parties fully and completely reserve all rights available to them under the law to challenge the level or rate structure (or the cost-of-service or cost allocation methodologies underlying them) of Tampa Electric’s base rates, charges, credits, and rate design methodologies effective as of January 1, 2025 or thereafter, except as modified by Paragraph 6(c) above. It is specifically understood and agreed that this 2021

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Agreement does not preclude any Consumer Party from filing before January 1, 2025, an action to challenge the level or rate structure (or the cost-of-service methodologies underlying them) of Tampa Electric’s base rates, charges, and credits effective as of January 1, 2025 or thereafter, provided they support full MDS and 4 CP cost allocations.

11.Corporate Income Tax Changes.

(a)Changes to federal and state corporate income tax rules after the Effective Date of this 2021 Agreement (“Tax Changes”) can take many forms, including changes to corporate income tax rates, deductibility of costs, and the timing of deductibility of certain costs. It can also affect the availability of existing or new tax credits. Tax Changes can impact the effective corporate income tax rate used by a utility to (1) calculate and report FPSC adjusted net operating income and (2) measure existing and prospective deferred income tax assets and liabilities in the FPSC adjusted capital structure. Corporate income tax rate decreases will decrease the statutory tax rate used to calculate net operating income and generate excess accumulated deferred income tax ("ADIT”) excesses. Corporate income tax rate increases will increase the statutory tax rate used to calculate net operating income and create ADIT deficiencies.

(b)Accumulated Deferred Income Taxes and Normalization.

(i)The Internal Revenue Code (“IRC”) requires public utilities who use accelerated depreciation on utility property for tax purposes (like Tampa Electric) to follow a set of rules called “normalization requirements.” These rules specify that a public utility can only use accelerated depreciation for income tax purposes if its regulator permits recovery of deferred income taxes on the differences resulting from using accelerated depreciation for income tax purposes and straight-line depreciation for regulatory accounting.

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(ii)Depreciation-related method and life differences are currently considered “protected” under the IRC; other book-tax temporary differences are considered “unprotected.” The normalization requirements also apply to investment tax credits and certain contributions in aid of construction. Losing the ability to claim accelerated depreciation for federal corporate income tax purposes is the penalty for failure to follow the normalization requirements. FPSC Rule 25-14.013, F.A.C. (“FPSC Tax Rule”), acknowledges the protected/unprotected distinction in the IRC.

(iii)Consistent with the FPSC Tax Rule, the company records accumulated deferred income taxes in its accounting records when they arise based on the corporate income tax rate expected to be in effect when the difference reverses, which ordinarily is the tax rate in effect at the time an item of utility plant is placed in service. If the corporate income tax rate later declines, applicable accounting standards and the FPSC Tax Rule require the company to remeasure its ADIT balances at the lower rate, and a portion of the ADIT balance becomes “excess.”  If the corporate income tax rate later increases, the company must remeasure its ADIT balances at the higher rate, which can result in an ADIT “deficiency.”

(iv)The FPSC Tax Rule addresses the impact of corporate income tax rate decreases and increases on ADIT, and states: “Each utility shall then recalculate all deferred income tax balances to reflect the enacted income tax rates in the period the timing differences are expected to reverse. The difference between the deferred income tax balances per books and the recalculated balances shall be recorded in regulatory asset and liability accounts as prescribed by the applicable Uniform System of Accounts at the time of recalculation.”

(v)When the federal corporate income tax rate was reduced in 1986 (Tax Reform Act of 1986) and 2017 (Tax Cuts and Jobs Act of 2017 or “TCJA”), Congress included a transition

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rule governing the remeasurement of protected ADIT at the new, lower rates called the average rate assumption method (“ARAM”), and Tampa Electric followed it. The ARAM required that protected ADIT be reduced (remeasured at the new, lower tax rate) over the remaining lives of the property that gave rise to the ADIT as the temporary differences reverse. Failure to follow the ARAM for protected ADIT would have violated the normalization requirements in the IRC.

(vi)The TCJA did not specify a remeasurement rule for excess unprotected ADIT, but the Tax Reform provision in the company’s 2017 Agreement (Paragraph 9) required the company to amortize excess unprotected ADIT as a reduction to income tax expense ratably over a five- or ten-year period depending on the amount of unprotected excess ADIT.

(c)If Tax Changes are enacted and become effective after this 2021 Agreement has been executed by the Parties and during the Term, the following provisions shall apply:

(i)The company will calculate the impact of Tax Changes on its retail jurisdictional net operating income thereby neutralizing the FPSC adjusted net operating income of the Tax Changes up or down to a net zero. The company will use its forecasted earnings surveillance report for the calendar year that includes the period in which Tax Changes are effective to calculate the impact of Tax Changes.

(ii)The impacts of Tax Changes, including, without limitation, rate changes and changes to the availability of existing and new tax credits and other similar tax benefits on a normalized basis, on base revenue requirements as calculated in subparagraph 11(c)(i)  – up or down - will be reflected in the company’s general base rates and charges through a prospective adjustment to those rates and charges to be effective within the later of: (a) 180 days from the date when Tax Changes become law or (b) the effective date of Tax Changes. This prospective

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adjustment to base rates and charges shall be accomplished through an equal percentage change – up or down - to customer, demand, and energy base rate charges as applicable for all retail customer classes.

(iii)Any effects of Tax Changes on retail revenue requirements from the effective date through the date of the base rate adjustment shall be flowed back to or collected from customers through the ECCR on the same basis as used in any base rate adjustment.

(iv)The company will adjust any GBRA that has not gone in effect up or down to reflect the new corporate income tax rate and the normalization of any new tax credits applicable to Future Solar projects on the revenue requirement for the GBRA. The effect of Tax Changes on a GBRA that has gone into effect will be addressed as part of the calculation in subparagraph 11(c)(i), above. The company will also adjust the CETM prospectively to reflect any new corporate income tax rate as specified in Paragraph 5.

(v)ADIT Generally. Any excess ADIT or ADIT deficiencies arising from Tax Changes shall be deferred to a regulatory asset or liability which shall be included in FPSC adjusted capital structure and flowed back to or collected from customers over a term consistent with law and the terms of this proposal.

(vi)Protected Deferred Taxes. If the Tax Changes law contains requirements governing the remeasurement of protected ADIT at the new corporate income tax rate – up or down – such as the ARAM, the company will follow those requirements. If the Tax Changes law does not contain requirements for “protected” ADIT, the company shall remeasure the ADIT arising from depreciation-related method and life differences – up or down – and adjust them up or down ratably

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over the total average remaining book life of the assets associated with the depreciation-related method and life differences.

(vii)Unprotected Deferred Taxes – Tax Rate Increase. If the Tax Changes law does not contain requirements governing the remeasurement of the kinds of ADIT that are currently considered “unprotected” and the corporate income tax rate goes up, the company shall net the  amount of unamortized excess ADIT remaining on its books (from TCJA) as of the effective date of Tax  Changes against the total unprotected ADIT deficiency arising from Tax Changes and shall amortize the resulting net ADIT excess or deficiency ratably for five years or ten years as follows: (a) for five years if the net excess or deficiency amount is $100 million or less or (b) over ten years if the amount is over $100 million.

(viii)Unprotected Deferred Taxes –Corporate Income Tax Rate Decrease. If the Tax Changes law does not contain requirements governing the remeasurement of the kinds of ADIT that are currently considered “unprotected” and the corporate income tax rate goes down, the company shall add the amount of unamortized excess deferred taxes remaining on its books (from TCJA) as of the effective date of Tax Changes to the total unprotected ADIT excess arising from Tax Changes and shall amortize the resulting total ADIT excess ratably for five years or ten years as follows: (a) for five years if the total excess is $100 million or less or (b) over ten years if the amount is over $100 million.

(ix)The annual effect of the remeasurement of ADIT specified in subparagraphs 11(c)(vi – viii) shall be included as an increase or decrease to annual tax expense calculated at the new corporate income tax rate as specified in subparagraph 11(c)(i).

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(x)As subsequent information becomes available, such as the tax return being filed, any true ups or adjustments will be evaluated and implemented within 120 days of that information being available.

(d)This action contemplated in this Paragraph 11 shall be accomplished in a limited proceeding initiated by the company and, except as required to perform the calculation in subparagraph 11(c)(i), without regard to the actual or projected earnings levels of the company and without a “base rate case” type inquiry into the operations, investments, and finances of the company. Nothing in this 2021 Agreement shall preclude any Party or any other lawful party from participating, consistent with the full rights of an intervenor, in any proceeding that addresses any matter or issue concerning the Tax Change provisions of this 2021 Agreement.

(e)This Paragraph 11 shall expire at the end of the Term or upon termination of the 2021 Agreement pursuant to Paragraph 10.

12.Asset Optimization Mechanism. The Parties consent to the FPSC’s approval of, and request that the Commission approve, an extension of, the company’s Asset Optimization Mechanism as set forth in its Petition in Docket No. 20160160-EI, dated June 30, 2016, for a three-year period beginning January 1, 2022, with the following sharing thresholds: (a) up to $4.5 million/year, 100 percent gain to customers; (b) greater than $4.5 million/year and less than $8.0 million/year, 60 percent to shareholders and 40 percent to customers; and (c) greater than $8.0 million/year, 50 percent to shareholders and 50 percent to customers. The Parties further agree that (i) 100 percent of any revenue from the release of natural gas pipeline capacity by Tampa Electric either directly or indirectly (e.g., through arrangement with an affiliate) during the Term shall not be subject to sharing under the Asset Optimization Mechanism and shall be credited entirely to retail customers through the fuel and purchase power adjustment clause (“Fuel Clause”) and (ii)

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any retirement/release of railcars will be taken into account in the Fuel Clause and will not be a matter subject to sharing through the Asset Optimization Mechanism. This Paragraph 12 shall expire at the end of the Term or upon termination of the 2021 Agreement pursuant to Paragraph 10.

13.Other.

(a) Except as specified in this 2021 Agreement, the company will enter into no new natural gas financial hedging contracts for fuel during the Term.

(b)The company agrees that it will not seek to recover any costs from its customers related to investments in oil and/or natural gas exploration, reserves, acreage and/or production, including but not limited to investments in gas or oil exploration or production projects that utilize “fracking” (hydraulic fracturing) or similar technology, during the Term.

(c)For any non-separated or non-stratified wholesale energy sales during the Term, the company will credit its fuel clause for an amount equal to the company’s incremental cost of generating or purchasing the amount of energy sold during the hours that any such sale was made.

(d)The full benefits of solar renewable energy credits (“RECs”) (including any and all rights attaching to environmental attributes) associated with the company’s Future Solar projects as described in the testimony of David Sweat, if any, will be retained for, and flowed through to, retail customers through the ECRC during the Term.

(e)All dollar values, asset determinations, rate impact values and revenue requirements in this 2021 Agreement are intended by the Parties to be retail jurisdictional in amount or formulation basis, unless otherwise specified.

40

(f)The Parties agree that, among other things, the company’s pre-filed testimony and MFRs in this case establish that its Big Bend Modernization, Future Solar, and AMI projects as reflected therein are reasonable, prudent and in the public interest. The Parties further agree that the early retirement and associated approval of cost recovery schedules for the (1) net book value as of December 31, 2021 of the company’s investment in AMR meters and Big Bend Retirement Assets and the (2) projected dismantlement reserve deficiency as of December 31, 2021 for the Big Bend Retirement assets via the CETM specified in this 2021Agreement are reasonable, prudent and in the public interest. This subparagraph 13(f) shall survive the end of the Term or termination of the 2021 Agreement pursuant to Paragraph 10.

(g)Tampa Electric confirms and represents that all Storm Protection Plan-eligible costs have been removed from base rates and agrees to provide prompt notice and corrective action should the company discover otherwise. This subparagraph 13(g) shall survive the end of the Term or termination of the 2021 Agreement pursuant to Paragraph 10.

(h)Beginning January 1, 2022, Tampa Electric may increase the (a) number of residential customers served under its Neighborhood Weatherization program from 6,500 to 7,500 and (b) the number of energy efficiency kits provided to customers under its Energy and Renewable Education, Awareness and Agency Outreach programs by 1,000 to 1,750 and recover the associated costs through the ECCR. This subparagraph 13(h) shall survive the end of the Term or termination of the 2021 Agreement pursuant to Paragraph 10.

14.New Tariffs. Nothing in this 2021 Agreement shall preclude Tampa Electric from filing and the Commission from approving any new or revised tariff provisions or rate schedules required by law or FPSC rule changes. Likewise, nothing in this 2021 Agreement shall preclude Tampa Electric from filing and the Commission from approving any new or revised tariff

41

provisions or rate schedules as requested by Tampa Electric, provided that any such tariff request does not (i) recover any of the same costs previously collected under base rates or another tariff provision and (ii) increase any existing base rate component of a tariff or rate schedule, or any other charge imposed on customers during the Term unless the application of such new or revised tariff, rate schedule, or charge is optional to Tampa Electric's customers. The Parties acknowledge that changing the time periods for time-of-use rates constitutes a change to a voluntary rate and that the company doing so during the Term does not violate this Paragraph 14 or the general prohibition against rate design changes in this 2021 Agreement. This Paragraph 14 shall expire at the end of the Term or upon termination of the 2021 Agreement pursuant to Paragraph 10.

15.Application of 2021 Agreement. No Party to this 2021 Agreement will request, support, or seek to impose a change to any term or provision of this 2021 Agreement. Except as provided in Paragraph 10, no Party to this 2021 Agreement will either seek or support any reduction in Tampa Electric's base rate charges, or credits, including limited, limited-scope, interim, or any other rate decreases, or changes to rate design methodologies, that would take effect prior to the first billing cycle for January 2025, except for any changes in base rates or charges (but not credits) requested by Tampa Electric or as otherwise provided for in this 2021 Agreement. Tampa Electric shall not seek interim, limited, or general base rate relief during the Term except as provided for in Paragraphs 2, 3, 4, 10, or 11 of this 2021 Agreement. Tampa Electric is not precluded from seeking interim, limited, or general base rate relief that would be effective during or after the first billing cycle in January 2025, nor are the Consumer Parties precluded from opposing such relief, or from seeking to lower or change Tampa Electric rates (consistent with preserving the CETM) effective as of the first billing cycle in January 2025. Such interim relief may be based on time periods before January 1, 2025, consistent with Section 366.071, Florida

42

Statutes, and calculated without regard to the provisions of this 2021 Agreement, except as provided in subparagraph 6(c), above. Tampa Electric will not seek to adjust either the standby generator credit or the CCV credit either during the Term, except by a unanimous written agreement of the Parties approved by a Final Order of the Commission or a Final Order of the Commission issued as a result ofthe next subsequent general base rate proceeding.

16.Commission Approval.

(a)The provisions of this 2021 Agreement are contingent on approval of this 2021 Agreement in its entirety by the Commission without modification. The Parties further agree, and will support the company in asking that the Commission find, that (a) this 2021 Agreement is in the public interest and (b) results in base rates and charges that are fair, just, and reasonable during the Term. The Parties further agree that they will support this 2021 Agreement, and that they will not request or support any order, relief, outcome, or result in conflict with the terms of this 2021 Agreement in any administrative or judicial proceeding relating to, reviewing, or challenging the establishment, approval, adoption, or implementation of this 2021 Agreement or the subject matter hereof.

(b)No Party will assert in any proceeding before the Commission or before any court that this 2021 Agreement or any of the terms in the 2021 Agreement shall have any precedential value. The Parties’ agreement to the terms in the 2021 Agreement shall be without prejudice to any Party’s ability to advocate a different position in future proceedings not involving this 2021 Agreement. The Parties further expressly agree that no individual provision, by itself, necessarily represents a position of any Party in any future proceeding, and the Parties further agree that no Party shall assert or represent in any future proceeding in any forum that another Party endorses any specific provision of this 2021 Agreement by virtue of that Party’s signature on, or

43

participation in, this 2021 Agreement. It is the intent of the Parties to this 2021 Agreement that the Commission’s approval of all the terms and provisions of this 2021 Agreement is an express recognition that no individual term or provision, by itself, necessarily represents a position, in isolation, of any Party or that a Party to this 2021 Agreement endorses a specific provision, in isolation, of this 2021 Agreement by virtue of that Party’s signature on, or participation in, this 2021 Agreement.

(c)The Parties intend and agree to request that the Commission’s final order approving this 2021 Agreement find that approval of this 2021 Agreement in its entirety resolves all matters in Docket Nos. 20200264-EI and 20210034-EI pursuant to and in accordance with Section 120.57(4), Florida Statutes, and that Dockets will be closed effective on the date the Commission’s order approving this 2021 Agreement becomes final.

(d)No Party shall seek appellate review of any Commission order approving this 2021 Agreement.

(e)This Paragraph 16 shall survive the end of the Term or termination of the 2021 Agreement pursuant to Paragraph 10.

17.Disputes. To the extent a dispute arises among the Parties about the provisions, interpretation, or application of this 2021 Agreement, the Parties agree to meet and confer in an effort to resolve the dispute. To the extent that the Parties cannot resolve any dispute within 30 days, the matter may be submitted to the Commission for resolution. This Paragraph 17 shall survive the end of the Term or termination of the 2021 Agreement pursuant to Paragraph 10.

44

18.Execution. This 2021 Agreement is dated as of July30, 2021. It may be executed in counterpart originals and a facsimile or electronic scan of an original signature shall be deemed an original.

IN WITNESS WHEREOF, the Parties evidence their acceptance and agreement with the provisions of this 2021 Agreement by their signature(s):

[remainder of page intentionally left blank]

45

Signature Page to 2021 Agreement

Tampa Electric Company

702 N. Franklin Street

Tampa, FL 33601

By:	/s/ Archibald D. Collins
Archibald D. Collins, President

46

Signature Page to 2021 Agreement

Office of Public Counsel

Richard Gentry, Public Counsel

Charles Rehwinkel, Deputy Public Counsel

c/o The Florida Legislature

111 West Madison Street, Room 812

Tallahassee, FL 32399-1400

By:	/s/ Richard Gentry
Richard Gentry

Signature Page to 2021 Agreement

The Florida Industrial Power Users Group

Jon C. Moyle, Jr., Esquire

Moyle Law Firm

The Perkins House

118 North Gadsden Street

Tallahassee, FL 32301

By:	/s/ Jon C. Moyle, Jr.
Jon C. Moyle, Jr.

Signature Page to 2021 Agreement

WCF Hospital Utility Alliance

Mark F. Sundback

William M. Rappolt

Andrew P. Mina

Sheppard Mullin Richter & Hampton LLP

2099 Pennsylvania Ave., N.W., Suite 100

Washington, D.C. 20006-6801

msundback@sheppardmullin.com

wrappolt@sheppardmullin.com

amina@sheppardmullin.com

By:	/s/ Mark Sundback
Mark Sundback

Signature Page to 2021 Agreement

Federal Executive Agencies

Thomas A. Jernigan

Holly L. Buchanan, Maj, USAF

Scott L. Kirk, Maj, USAF

Arnold Braxton, TSgt, USAF

Ebony M. Payton

139 Barnes Drive, Suite 1

Tyndall Air Force Base, Florida 32403

thomas.jernigan.3@us.af.mil

holly.buchanan.1@us.af.mil

scott.kirk.2@us.af.mil

arnold.braxton@us.af.mil

ebony.payton.ctr@us.af.mil

By:	/s/ Holly L. Buchanan
Holly L. Buchanan, Maj, USAF

Signature Page to 2021 Agreement

Florida Retail Federation

Robert Scheffel Wright

Gardner, Bist, Bowden, Bush, Dee, LaVia & Wright, P.A.

1300 Thomaswood Drive

Tallahassee, FL 32308

By:	/s/ Robert Scheffel Wright
Robert Scheffel Wright

Signature Page to 2021 Agreement

Walmart Inc.

Stephanie U. Eaton

Spilman Thomas & Battle, PLLC

110 Oakwood Drive, Suite 500

Winston-Salem, NC 27103

seaton@spilmanlaw.com

Barry A. Naum

Spilman Thomas & Battle, PLLC

1100 Bent Creek Boulevard, Suite 101

Mechanicsburg, PA 17050

bnaum@spilmanlaw.com

By: /s/ Stephanie U. Eaton

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2021	Aug. 10, 2021
Cover [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
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

XML

Consolidated Condensed Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Property, plant and equipment
Utility plant, at original costs	$ 14,346	$ 13,818
Accumulated depreciation	(3,897)	(3,712)
Utility plant, net	10,449	10,106
Other property	14	14
Total property, plant and equipment, net	10,463	10,120
Current assets
Cash and cash equivalents	24	10
Receivables, less allowance for credit losses of $8 and $7 at June 30, 2021 and December 31, 2020, respectively	265	219
Due from affiliates	10	11
Inventories, at average cost
Regulatory assets	68	79
Prepayments and other current assets	22	10
Total current assets	524	462
Deferred debits
Regulatory assets	413	406
Other	59	60
Total deferred debits	472	466
Total assets	11,459	11,048
Capitalization
Common stock	4,180	3,890
Accumulated other comprehensive loss	(1)	(1)
Retained earnings	359	327
Total capital	4,538	4,216
Long-term debt	3,385	2,594
Total capitalization	7,923	6,810
Current liabilities
Long-term debt due within one year	0	278
Notes payable	410	775
Accounts payable	264	321
Due to affiliates	22	46
Customer deposits	130	130
Regulatory liabilities	57	67
Accrued interest	20	13
Accrued taxes	63	22
Other	43	57
Total current liabilities	1,009	1,709
Long-term liabilities
Deferred income taxes	815	783
Regulatory liabilities	1,156	1,194
Investment tax credits	233	216
Deferred credits and other liabilities	323	336
Total long-term liabilities	2,527	2,529
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	11,459	11,048
Fuel [Member]
Inventories, at average cost
Utility inventories	21	26
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	114	107
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	11,876	11,486
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 2,470	$ 2,332

XML

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Statement Of Financial Position [Abstract]
Allowance for credit losses	$ 8	$ 7

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Revenues
Electric	$ 531	$ 453	$ 977	$ 873
Gas	123	96	276	223
Total revenues	654	549	1,253	1,096
Expenses
Fuel	129	67	238	168
Purchased power	26	25	44	27
Cost of natural gas sold	33	25	83	67
Operations and maintenance	139	126	267	260
Depreciation and amortization	107	92	213	189
Taxes, other than income	56	50	110	101
Total expenses	490	385	955	812
Income from operations	164	164	298	284
Other income
Allowance for equity funds used during construction	10	7	20	13
Other income, net	2	2	3	3
Total other income	12	9	23	16
Interest charges
Interest expense	39	35	77	72
Allowance for borrowed funds used during construction	(5)	(3)	(10)	(6)
Total interest charges	34	32	67	66
Income before provision for income taxes	142	141	254	234
Provision for income taxes	21	24	41	40
Net income	121	117	213	194
Comprehensive income	$ 121	$ 117	$ 213	$ 194

XML

Consolidated Condensed Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Cash flows from operating activities
Net income	$ 213	$ 194
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	213	189
Deferred income taxes and investment tax credits	27	43
Allowance for equity funds used during construction	(20)	(13)
Deferred recovery clauses	(10)	37
Receivables, less allowance for credit losses	(43)	(22)
Prepayments and other deposits	(11)	(9)
Taxes accrued	20	20
Accounts payable	(45)	(41)
Regulatory assets and liabilities	(2)	(12)
Other	4	(4)
Cash flows from operating activities	346	382
Cash flows used in investing activities
Capital expenditures	(588)	(653)
Net proceeds from sale of assets	0	6
Cash flows used in investing activities	(588)	(647)
Cash flows from financing activities
Equity contributions from Parent	290	265
Proceeds from long-term debt issuance	790	0
Repayment of long-term debt	(278)	0
Net decrease in short-term debt (maturities of 90 days or less)	(65)	(154)
Proceeds from other short-term debt (maturities over 90 days)	0	300
Repayment of other short-term debt (maturities over 90 days)	(300)	0
Dividends to Parent	(181)	(150)
Cash flows from financing activities	256	261
Net increase (decrease) in cash and cash equivalents	14	(4)
Cash and cash equivalents at beginning of period	10	14
Cash and cash equivalents at end of period	24	10
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$ (20)	$ (12)

XML

Consolidated Condensed Statements of Capital (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Beginning balance	$ 4,375	$ 3,845	$ 4,216	$ 3,695
Net income	121	117	213	194
Equity contributions from Parent	135	120	290	265
Dividends to Parent	(93)	(77)	(181)	(150)
Other		(2)		(1)
Ending balance	4,538	4,003	4,538	4,003
Common Stock [Member]
Beginning balance	$ 4,045	$ 3,530	$ 3,890	$ 3,385
Beginning balance	10	10	10	10
Equity contributions from Parent	$ 135	$ 120	$ 290	$ 265
Ending balance	$ 4,180	$ 3,650	$ 4,180	$ 3,650
Ending balance	10	10	10	10
Retained Earnings [Member]
Beginning balance	$ 331	$ 316	$ 327	$ 311
Net income	121	117	213	194
Dividends to Parent	(93)	(77)	(181)	(150)
Other		(2)		(1)
Ending balance	359	354	359	354
Accumulated Other Comprehensive Loss [Member]
Beginning balance	(1)	(1)	(1)	(1)
Ending balance	$ (1)	$ (1)	$ (1)	$ (1)

XML

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2021

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, 2020 for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS.

Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2021 and December 31, 2020, and the results of operations and cash flows for the periods ended June 30, 2021 and 2020. The results of operations for the three and six months ended June 30, 2021 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2021.

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.

Since 2020, the outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of June 30, 2021 and December 31, 2020 and for the three and six months ended June 30, 2021 and 2020 were not materially impacted by the COVID-19 pandemic.

Receivables and Allowance for Credit Losses

Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $258 million and $214 million as of June 30, 2021 and December 31, 2020, respectively. An allowance for credit losses is established based on TEC’s collection experience and reasonable and supportable forecasts that affect the collectibility of the reported amount. Circumstances that could affect Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, generating fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

As of June 30, 2021 and December 31, 2020, unbilled revenues of $83 million and $73 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 $31 million and $26 million for the three months ended June 30, 2021 and 2020, respectively, and totaled $60 million and $53 million for the six months ended June 30, 2021 and 2020, respectively.

XML

New Accounting Pronouncements

6 Months Ended

Jun. 30, 2021

Accounting Changes And Error Corrections [Abstract]

New Accounting Pronouncements

2. New 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, 2020.

XML

Regulatory

6 Months Ended

Jun. 30, 2021

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 has invested approximately $850 million during 2017 through 2021 related to 600 MW of solar projects recoverable under the SoBRAs, and AFUDC was accrued during construction.

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 $26 million annually in estimated revenue requirements. The FPSC approved the tariffs on this SoBRA filing, including an adjustment to reflect the reduction in the state corporate income tax discussed below, on December 10, 2019 and TEC began receiving these revenues in January 2020. On July 31, 2020, TEC filed its fourth and final SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2021 tranche representing 46 MW and $8 million annually in estimated revenues. The FPSC approved the tariffs on this SoBRA filing on November 3, 2020 and TEC began receiving these revenues in January 2021.

The true-up filing for SoBRA tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. The $5 million true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was submitted to the FPSC on May 27, 2021. An estimated $4 million true-up is being returned to customers during 2021. The true-up for SoBRA tranche 4 will be filed in 2022.

   On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 (the Settlement Agreement) by and among TEC and the intervenors in TEC’s rate case filed with the FPSC in April 2021. The Settlement Agreement agrees to an increase in base rates annually effective with January 2022 bills, to generate a $191 million increase in revenue consisting of $123 million of traditional base rate charges and $68 million in a new charge to recover the costs of retiring assets. The Settlement Agreement further includes two subsequent year adjustments of $90 million and $21 million, effective January 2023 and January 2024, respectively. Under the agreement, the allowed equity in the capital structure will continue to be 54% from investor sources of capital. The Settlement Agreement includes an allowed regulatory ROE range of 9.0% to 11.0% with a 9.95% midpoint. The Settlement Agreement allows a 25 basis point increase in the allowed ROE range and mid-point, and $10 million of additional revenue, if the average 30-year United States Treasury Bond yield rate for any period of six consecutive months is at least 50 basis points greater than the yield rate on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not change from January 1, 2022 through December 31, 2024, unless TEC’s earned ROE was to fall below the bottom of the range during that time. The Settlement Agreement contains a provision whereby TEC agrees to quantify the future impact of a decrease or increase in corporate income tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further creates a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of this agreement. The Settlement Agreement would not become effective unless and until approved by the FPSC, which is expected to consider the matter by October 2021.

Tampa Electric Big Bend Modernization Project

Tampa Electric expects to invest approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $611 million has been invested through June 30, 2021. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the Big Bend modernization project, on June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At June 30, 2021 and December 31, 2020, Tampa Electric’s balance sheet included $200 million in electric utility plant and $91 million and $88 million, respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until December 31, 2021. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 as part of the Big Bend modernization project.        

Tampa Electric plans to retire Big Bend Unit 3 in 2023 as it is in the best interest of customers from economic, environmental risk and operational perspectives. Similar to the retirement plan for Unit 1 and Unit 2, Tampa Electric will continue to account for its existing investment in Unit 3 in electric utility plant and depreciate the assets using the current depreciation rates until December 31, 2021.

On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedule for all three units with the FPSC.

Tampa Electric’s Settlement Agreement provides recovery for the Big Bend Modernization project in two phases. The first phase is a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. The Settlement Agreement also includes a new charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread over 15 years and will survive the termination of the Settlement Agreement. The special capital recovery schedule for all three units will be applied beginning January 1, 2022.

Tampa Electric Mid-Course Adjustment to Fuel Recovery

In July 2021, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover $83 million of additional costs during the months of September through December 2021.

Tampa Electric Storm Protection Cost Recovery Clause and Settlement Agreement

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This new clause provides 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. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million base rate reduction for SPP program costs previously recovered in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million of costs removed from base rates. This settlement agreement was approved on August 10, 2020, and Tampa Electric’s cost recovery began in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.

The June 9, 2020 settlement agreement approved by the FPSC described above also included approval of Tampa Electric’s petition to eliminate its $16 million accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020.     

PGS Base Rates       

On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement provides for an increase in base rates by $58 million annually effective January 2021, which is a $34 million increase in revenue and $24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint. It provides PGS the ability to reverse a total of $34 million of accumulated depreciation through 2023 and sets new depreciation rates effective January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.90% before that time with an allowed equity in the capital structure of 54.7% from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024.

Regulatory Assets and Liabilities

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

Regulatory Assets and Liabilities
(millions)	June 30, 2021		December 31, 2020
Regulatory assets:
Regulatory tax asset (1)	$	98	$	90
Cost-recovery clauses (2)		43		38
Environmental remediation (3)		25		22
Postretirement benefits (4)		298		309
Asset retirement obligation (5)		9		13
Other		8		13
Total regulatory assets		481		485
Less: Current portion		68		79
Long-term regulatory assets	$	413	$	406
Regulatory liabilities:
Regulatory tax liability (6)	$	678	$	691
Cost-recovery clauses (2)		18		23
Accumulated reserve - cost of removal (7)		469		498
Storm reserve (8)		48		48
Other		0		1
Total regulatory liabilities		1,213		1,261
Less: Current portion		57		67
Long-term regulatory liabilities	$	1,156	$	1,194

(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 a subsequent period.

(3) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC.

(4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.

(5) This asset 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.

(6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC.

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

(8) 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 2019, Tampa Electric incurred storm restoration preparation costs for Hurricane Dorian of approximately $8 million, which was charged to the storm reserve regulatory liability.

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Income Taxes

6 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes

4. Income Taxes

CARES Act

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (CARES) Act was signed into law. The CARES Act includes several business provisions including deferral in employer payroll taxes and an employee retention payroll tax credit. On December 27, 2020, the Consolidated Appropriations Act, 2021 (the 2021 Act) was signed into law. The 2021 Act provides for modifications and expansion of the employee retention payroll tax credit enacted under the CARES Act.  These Acts did not have a material impact to TEC’s financial statements.

American Rescue Plan Act of 2021

On March 11, 2021, the American Rescue Plan Act of 2021 (the Act) was signed into law. The Act includes an extension of the employee retention credit through December 31, 2021.  The Act did not have a material impact to TEC’s financial statements.

Income Tax Expense

TEC is included in a consolidated U.S. federal income tax return with EUSHI and its subsidiaries. TEC’s income tax expense is based upon a separate return method, modified for the benefits-for-loss allocation in accordance with respective tax sharing agreements with TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is reflected in common stock.

TEC’s effective tax rates for the six months ended June 30, 2021 and 2020 were 16.1% and 17.1%, respectively. The June 30, 2021 and 2020 effective tax rates are an estimate of the annual effective income tax rate. TEC’s effective tax rate for the six months ended June 30, 2021 and 2020 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 June 30, 2021 and December 31, 2020, the amount of unrecognized tax benefits was $5 million and $9 million, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC’s unrecognized federal tax benefits decreased in the first quarter of 2021 by approximately $5 million due to the settlement of its 2016 federal IRS Appeals R&D tax credits issue. TEC had $5 million and $9 million of unrecognized tax benefits at June 30, 2021 and December 31, 2020, that, if recognized, would reduce TEC’s effective tax rate.

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Employee Postretirement Benefits

6 Months Ended

Jun. 30, 2021

Compensation And Retirement Disclosure [Abstract]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

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

TECO Energy Benefit Cost
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended June 30,	2021			2020			2021			2020
Components of net periodic benefit cost
Service cost	$	6		$	5		$	1		$	0
Interest cost		6			6			2			2
Expected return on assets		(13	)		(12	)		0			0
Amortization of:
Actuarial loss (gain)		5			5			(1	)		0
Net periodic benefit cost	$	4		$	4		$	2		$	2
Six months ended June 30,
Components of net periodic benefit cost
Service cost	$	11		$	10		$	1		$	0
Interest cost		11			13			3			3
Expected return on assets		(26	)		(25	)		0			0
Amortization of:
Actuarial loss (gain)		11			10			0			0
Settlement cost		0			0			0			0
Net periodic benefit cost	$	7		$	8		$	4		$	3

TEC’s portion of the net periodic benefit cost for the three months ended June 30, 2021 and 2020, respectively, was $2 million and $3 million for pension benefits, and $3 million and $1 million for other postretirement benefits. TEC’s portion of the net periodic benefit cost for the six months ended June 30, 2021 and 2020, respectively, was $5 million and $6 million for pension benefits, and $5 million and $3 million for other postretirement benefits. TEC’s portion of net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Condensed Statements of Income in “Operations & maintenance”.   

TECO Energy assumed a long-term EROA of 6.70% and a discount rate of 2.38% for pension benefits under its qualified pension plan for 2021. For TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 2.47% for 2021.

TECO Energy made contributions of $11 million and $10 million to its qualified pension plan in each of the six months ended June 30, 2021 and 2020, respectively. TEC’s portion of these contributions was $9 million and $8 million, respectively. TECO Energy expects to make contributions to the pension plan of $10 million for the remainder of 2021. TEC estimates its portion of the remaining 2021 contribution to be $8 million.        

Included in the benefit cost discussed above, for the three and six months ended June 30, 2021, $5 million and $11 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 $9 million for the three and six months ended June 30, 2020, respectively.

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Short-Term Debt

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Short-Term Debt

6. Short-Term Debt

Details of TEC’s short-term borrowings are presented in the following table:

	June 30, 2021								December 31, 2020
			Borrowings		Borrowings		Letters						Letters
	Credit		Outstanding -		Outstanding -		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	800		0	$	410	$	1	$	800	$	345	$	1
3-year accounts    receivable facility (3)		0		0		0		0		150		130		0
1-year term facility (4)		0		0		0		0		300		300		0
Total	$	800		0	$	410	$	1	$	1,250	$	775	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023. TEC also has an active commercial paper program for up to $800 million, of which the full amount outstanding is backed by TEC’s credit facility. The amount of commercial paper issued results in an equal amount of its credit facility being considered drawn and unavailable.

(3) This 3-year facility matured on March 22, 2021.

(4) This 1-year term facility was terminated on March 23, 2021.

At June 30, 2021, the credit facility required a commitment fee of 12.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities and commercial paper program at June 30, 2021 and December 31, 2020 was 0.25% and 0.89%, respectively.

Commercial Paper Program

On May 25, 2021, TEC established a commercial paper program (the Program) under which TEC may issue on a private placement basis unsecured commercial paper notes (the Notes). Amounts available under the Program may be borrowed, repaid and reborrowed with the aggregate amount of the Notes outstanding under the Program at any time not to exceed $800 million.  The maturities of the Notes will vary, but may not exceed 270 days from the date of issue. The rates of interest will depend on whether the Note will be a fixed or floating rate. TEC must have credit facilities in place, at least equal to the amount of its commercial paper program. TEC does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

Accounts Receivable Facility

On July 14, 2020 and October 30, 2020, TEC amended its $150 million accounts receivable collateralized borrowing facility (Loan Agreement) in order to change certain performance ratios. The amended Loan Agreement was effective as of June 30, 2020 and September 30, 2020. On March 22, 2021, this agreement matured and terminated.

Non Revolving Term Loan

On February 6, 2020, TEC entered into a 364-day, $300 million credit agreement with a group of banks. The credit agreement had a maturity date of February 4, 2021; contained customary representations and warranties, events of default, and financial and other covenants; and provided for interest to accrue at variable rates based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. On January 29, 2021, TEC extended the maturity date of the agreement to April 29, 2021. On March 23, 2021, this loan was repaid and terminated.

5-Year Credit Facility

On December 18, 2020, TEC amended and restated its bank credit facility, entering into a Sixth Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2022 to March 22, 2023 (subject to further extension with the consent of each lender); increased the amount of the commitment by the lenders to $800 million; and provided for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $100 million in the aggregate; includes a $80 million letter of credit facility; and made other technical changes.

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Long-Term Debt

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2021, TEC’s long-term debt, including the current portion, had a carrying amount of $3,385 million and an estimated fair market value of $4,035 million. At December 31, 2020, TEC’s total long-term debt, including the current portion, had a carrying amount of $2,872 million and an estimated fair market value of $3,597 million. The fair value of the debt securities is determined using Level 2 measurements (see Note 11 for information regarding the fair value hierarchy).

Tampa Electric Company 2.40% Notes due 2031 and 3.45% Notes due 2051

On March 18, 2021, TEC completed a sale of (i) $400 million aggregate principal amount of 2.40% Notes due March 15, 2031 (the 2031 Notes) and (ii) $400 million aggregate principal amount of 3.45% Notes due March 15, 2051 (the 2051 Notes, and collectively, the Notes). Until December 15, 2030, in the case of the 2031 Notes, or September 15, 2050, in the case of the 2051 Notes, TEC may redeem all or any part of such series of Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of such series of Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the Notes to be redeemed that would be due if the Notes matured on (a) December 15, 2030, in the case of the 2031 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate (as defined in the Indenture), plus 15 basis points, or (b) September 15, 2050, in the case of the 2051 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, 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, 2030, in the case of the 2031 Notes or September 15, 2050, in the case of the 2051 Notes, TEC may, at its option, redeem such series of the Notes, in whole or in part, at 100% of the principal amount of such series of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2021

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

8. Commitments and Contingencies

Legal Contingencies

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of June 30, 2021 and December 31, 2020, TEC has estimated its ultimate financial liability to be $17 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s currently assessed percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. See Note 3 for information regarding the related regulatory asset.

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 June 30, 2021:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total
2021	$	35	$	119	$	297	$	173	$	35	$	2	$	2	$	663
2022		0		232		84		52		32		3		3		406
2023		0		211		58		1		43		3		0		316
2024		0		205		0		0		26		3		0		234
2025		0		191		0		0		18		2		0		211
Thereafter		0		2,014		0		0		66		48		0		2,128
Total future minimum payments	$	35	$	2,972	$	439	$	226	$	220	$	61	$	5	$	3,958

Debt Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements and has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2021, TEC was in compliance with all required covenants.

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Segment Information

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Segment Information

9. Segment Information

(millions)	Tampa								Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations				Company
2021
Revenues - external	$	531	$	123	$	0			$	654
Intracompany sales		1		0		(1	)			0
Total revenues		532		123		(1	)			654
Total interest charges		29		5		0				34
Net income	$	102	$	19	$	0			$	121
2020
Revenues - external	$	453	$	96	$	0			$	549
Intracompany sales		1		1		(2	)			0
Total revenues		454		97		(2	)			549
Total interest charges		28		4		0				32
Net income	$	106	$	11	$	0			$	117
Six months ended June 30,
2021
Revenues - external	$	977	$	276	$	0			$	1,253
Intracompany sales		2		2		(4	)			0
Total revenues		979		278		(4	)			1,253
Total interest charges		57		10		0				67
Net income	$	167	$	46	$	0			$	213
2020
Revenues - external	$	873	$	223	$	0			$	1,096
Intracompany sales		2		4		(6	)			0
Total revenues		875		227		(6	)			1,096
Total interest charges		58		8		0				66
Net income	$	165	$	29	$	0			$	194
Total assets at June 30, 2021	$	10,101	$	2,021	$	(663	)	(1)	$	11,459
Total assets at December 31, 2020	$	9,800	$	1,901	$	(653	)	(1)	$	11,048

(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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Revenue

6 Months Ended

Jun. 30, 2021

Revenues [Abstract]

Revenue

10. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa							Tampa Electric
Three months ended June 30, 2021	Electric		PGS		Eliminations			Company
Electric revenue
Residential	$	276	$	0	$	0		$	276
Commercial		144		0		0			144
Industrial		41		0		0			41
Regulatory deferrals and unbilled revenue		11		0		0			11
Other (1)		60		0		(1	)		59
Total electric revenue		532		0		(1	)		531
Gas revenue
Residential		0		49		0			49
Commercial		0		46		0			46
Industrial (2)		0		6		0			6
Other (3)		0		22		0			22
Total gas revenue		0		123		0			123
Total revenue	$	532	$	123	$	(1	)	$	654

Three months ended June 30, 2020
Electric revenue
Residential	$	254			$	0	$	0		$	254
Commercial		121				0		0			121
Industrial		32				0		0			32
Regulatory deferrals and unbilled revenue		(3	)			0		0			(3	)
Other (1)		50		`		0		(1	)		49
Total electric revenue		454				0		(1	)		453
Gas revenue
Residential		0				36		0			36
Commercial		0				28		0			28
Industrial (2)		0				5		0			5
Other (3)		0				28		(1	)		27
Total gas revenue		0				97		(1	)		96
Total revenue	$	454			$	97	$	(2	)	$	549

(millions)	Tampa								Tampa Electric
Six months ended June 30, 2021	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	508		$	0	$	0		$	508
Commercial		270			0		0			270
Industrial		78			0		0			78
Regulatory deferrals and unbilled revenue		9			0		0			9
Other (1)		114			0		(2	)		112
Total electric revenue		979			0		(2	)		977
Gas revenue
Residential		0			116		0			116
Commercial		0			99		0			99
Industrial (2)		0			12		0			12
Other (3)		0			51		(2	)		49
Total gas revenue		0			278		(2	)		276
Total revenue	$	979		$	278	$	(4	)	$	1,253
Six months ended June 30, 2020
Electric revenue
Residential	$	459		$	0	$	0		$	459
Commercial		246			0		0			246
Industrial		69			0		0			69
Regulatory deferrals and unbilled revenue		(5	)		0		0			(5	)
Other (1)		106			0		(2	)		104
Total electric revenue		875			0		(2	)		873
Gas revenue
Residential		0			84		0			84
Commercial		0			69		0			69
Industrial (2)		0			11		0			11
Other (3)		0			63		(4	)		59
Total gas revenue		0			227		(4	)		223
Total revenue	$	875		$	227	$	(6	)	$	1,096

(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 June 30, 2021 and December 31, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $130 million and $135 million, respectively. As allowed under ASC 606, these amounts exclude 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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Fair Value Measurements

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:	Observable inputs, such as quoted prices in active markets;
Level 2:	Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and
Level 3:	Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

There were no Level 3 assets or liabilities for the periods presented.

As of June 30, 2021 and December 31, 2020, 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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Subsequent Events

6 Months Ended

Jun. 30, 2021

Subsequent Events [Abstract]

Subsequent Events

12. Subsequent Events

 On August 6, 2021, TEC filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 by and among TEC and the intervenors in TEC’s rate case filed with the FPSC in April 2021. In addition, on August 3, 2021, the FPSC approved Tampa Electric’s request for a mid-course adjustment to its fuel and capacity charges, effective with September 2021 customer bills. See Note 3 – Tampa Electric Base Rates, Tampa Electric Big Bend Modernization Project and Tampa Electric Mid-Course Adjustment to Fuel Recovery for further information.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2021

Accounting Policies [Abstract]

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

TEC is a wholly owned subsidiary of TECO Energy, which is an indirect, wholly owned subsidiary of Emera. TEC is comprised of the electric division, referred to as Tampa Electric, and the natural gas division, referred to as PGS.

Intercompany balances and transactions within the divisions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2021 and December 31, 2020, and the results of operations and cash flows for the periods ended June 30, 2021 and 2020. The results of operations for the three and six months ended June 30, 2021 are not necessarily indicative of the results that can be expected for the entire fiscal year ending December 31, 2021.

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.

Since 2020, the outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of June 30, 2021 and December 31, 2020 and for the three and six months ended June 30, 2021 and 2020 were not materially impacted by the COVID-19 pandemic.

Receivables and Allowance for Credit Losses

Receivables and Allowance for Credit Losses

Receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $258 million and $214 million as of June 30, 2021 and December 31, 2020, respectively. An allowance for credit losses is established based on TEC’s collection experience and reasonable and supportable forecasts that affect the collectibility of the reported amount. Circumstances that could affect Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, generating fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

As of June 30, 2021 and December 31, 2020, unbilled revenues of $83 million and $73 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 $31 million and $26 million for the three months ended June 30, 2021 and 2020, respectively, and totaled $60 million and $53 million for the six months ended June 30, 2021 and 2020, respectively.

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Regulatory (Tables)

6 Months Ended

Jun. 30, 2021

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Regulatory Liabilities

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

Regulatory Assets and Liabilities
(millions)	June 30, 2021		December 31, 2020
Regulatory assets:
Regulatory tax asset (1)	$	98	$	90
Cost-recovery clauses (2)		43		38
Environmental remediation (3)		25		22
Postretirement benefits (4)		298		309
Asset retirement obligation (5)		9		13
Other		8		13
Total regulatory assets		481		485
Less: Current portion		68		79
Long-term regulatory assets	$	413	$	406
Regulatory liabilities:
Regulatory tax liability (6)	$	678	$	691
Cost-recovery clauses (2)		18		23
Accumulated reserve - cost of removal (7)		469		498
Storm reserve (8)		48		48
Other		0		1
Total regulatory liabilities		1,213		1,261
Less: Current portion		57		67
Long-term regulatory liabilities	$	1,156	$	1,194

(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 a subsequent period.

(3) This asset is related to costs associated with environmental remediation primarily at MGP sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC.

(4) This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.

(5) This asset 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.

(6) The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC.

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

(8) 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 2019, Tampa Electric incurred storm restoration preparation costs for Hurricane Dorian of approximately $8 million, which was charged to the storm reserve regulatory liability.

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Employee Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2021

TECO Energy [Member]

Schedule of Net Periodic Benefit Cost

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

TECO Energy Benefit Cost
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended June 30,	2021			2020			2021			2020
Components of net periodic benefit cost
Service cost	$	6		$	5		$	1		$	0
Interest cost		6			6			2			2
Expected return on assets		(13	)		(12	)		0			0
Amortization of:
Actuarial loss (gain)		5			5			(1	)		0
Net periodic benefit cost	$	4		$	4		$	2		$	2
Six months ended June 30,
Components of net periodic benefit cost
Service cost	$	11		$	10		$	1		$	0
Interest cost		11			13			3			3
Expected return on assets		(26	)		(25	)		0			0
Amortization of:
Actuarial loss (gain)		11			10			0			0
Settlement cost		0			0			0			0
Net periodic benefit cost	$	7		$	8		$	4		$	3

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Short-Term Debt (Tables)

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Schedule of Short-term Borrowings

Details of TEC’s short-term borrowings are presented in the following table:

	June 30, 2021								December 31, 2020
			Borrowings		Borrowings		Letters						Letters
	Credit		Outstanding -		Outstanding -		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	800		0	$	410	$	1	$	800	$	345	$	1
3-year accounts    receivable facility (3)		0		0		0		0		150		130		0
1-year term facility (4)		0		0		0		0		300		300		0
Total	$	800		0	$	410	$	1	$	1,250	$	775	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023. TEC also has an active commercial paper program for up to $800 million, of which the full amount outstanding is backed by TEC’s credit facility. The amount of commercial paper issued results in an equal amount of its credit facility being considered drawn and unavailable.

(3) This 3-year facility matured on March 22, 2021.

(4) This 1-year term facility was terminated on March 23, 2021.

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2021

Commitments And Contingencies Disclosure [Abstract]

Schedule of Long-term Commitments

The following is a schedule of future payments under PPAs, minimum lease payments with non-cancelable lease terms in excess of one year, and other net purchase obligations/commitments at June 30, 2021:

									Long-term				Demand
	Purchased				Capital		Fuel and		Service		Operating		Side
(millions)	Power		Transportation		Projects		Gas Supply		Agreements		Leases		Management		Total
2021	$	35	$	119	$	297	$	173	$	35	$	2	$	2	$	663
2022		0		232		84		52		32		3		3		406
2023		0		211		58		1		43		3		0		316
2024		0		205		0		0		26		3		0		234
2025		0		191		0		0		18		2		0		211
Thereafter		0		2,014		0		0		66		48		0		2,128
Total future minimum payments	$	35	$	2,972	$	439	$	226	$	220	$	61	$	5	$	3,958

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Schedule of Segment Information

(millions)	Tampa								Tampa Electric
Three months ended June 30,	Electric		PGS		Eliminations				Company
2021
Revenues - external	$	531	$	123	$	0			$	654
Intracompany sales		1		0		(1	)			0
Total revenues		532		123		(1	)			654
Total interest charges		29		5		0				34
Net income	$	102	$	19	$	0			$	121
2020
Revenues - external	$	453	$	96	$	0			$	549
Intracompany sales		1		1		(2	)			0
Total revenues		454		97		(2	)			549
Total interest charges		28		4		0				32
Net income	$	106	$	11	$	0			$	117
Six months ended June 30,
2021
Revenues - external	$	977	$	276	$	0			$	1,253
Intracompany sales		2		2		(4	)			0
Total revenues		979		278		(4	)			1,253
Total interest charges		57		10		0				67
Net income	$	167	$	46	$	0			$	213
2020
Revenues - external	$	873	$	223	$	0			$	1,096
Intracompany sales		2		4		(6	)			0
Total revenues		875		227		(6	)			1,096
Total interest charges		58		8		0				66
Net income	$	165	$	29	$	0			$	194
Total assets at June 30, 2021	$	10,101	$	2,021	$	(663	)	(1)	$	11,459
Total assets at December 31, 2020	$	9,800	$	1,901	$	(653	)	(1)	$	11,048

(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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Revenue (Tables)

6 Months Ended

Jun. 30, 2021

Revenue Recognition [Abstract]

Summary of Disaggregates TEC Revenue by Major Source

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa							Tampa Electric
Three months ended June 30, 2021	Electric		PGS		Eliminations			Company
Electric revenue
Residential	$	276	$	0	$	0		$	276
Commercial		144		0		0			144
Industrial		41		0		0			41
Regulatory deferrals and unbilled revenue		11		0		0			11
Other (1)		60		0		(1	)		59
Total electric revenue		532		0		(1	)		531
Gas revenue
Residential		0		49		0			49
Commercial		0		46		0			46
Industrial (2)		0		6		0			6
Other (3)		0		22		0			22
Total gas revenue		0		123		0			123
Total revenue	$	532	$	123	$	(1	)	$	654

Three months ended June 30, 2020
Electric revenue
Residential	$	254			$	0	$	0		$	254
Commercial		121				0		0			121
Industrial		32				0		0			32
Regulatory deferrals and unbilled revenue		(3	)			0		0			(3	)
Other (1)		50		`		0		(1	)		49
Total electric revenue		454				0		(1	)		453
Gas revenue
Residential		0				36		0			36
Commercial		0				28		0			28
Industrial (2)		0				5		0			5
Other (3)		0				28		(1	)		27
Total gas revenue		0				97		(1	)		96
Total revenue	$	454			$	97	$	(2	)	$	549

(millions)	Tampa								Tampa Electric
Six months ended June 30, 2021	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	508		$	0	$	0		$	508
Commercial		270			0		0			270
Industrial		78			0		0			78
Regulatory deferrals and unbilled revenue		9			0		0			9
Other (1)		114			0		(2	)		112
Total electric revenue		979			0		(2	)		977
Gas revenue
Residential		0			116		0			116
Commercial		0			99		0			99
Industrial (2)		0			12		0			12
Other (3)		0			51		(2	)		49
Total gas revenue		0			278		(2	)		276
Total revenue	$	979		$	278	$	(4	)	$	1,253
Six months ended June 30, 2020
Electric revenue
Residential	$	459		$	0	$	0		$	459
Commercial		246			0		0			246
Industrial		69			0		0			69
Regulatory deferrals and unbilled revenue		(5	)		0		0			(5	)
Other (1)		106			0		(2	)		104
Total electric revenue		875			0		(2	)		873
Gas revenue
Residential		0			84		0			84
Commercial		0			69		0			69
Industrial (2)		0			11		0			11
Other (3)		0			63		(4	)		59
Total gas revenue		0			227		(4	)		223
Total revenue	$	875		$	227	$	(6	)	$	1,096

(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 - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Accounting Policies [Abstract]
Receivables from contracts with customers	$ 258		$ 258		$ 214
Unbilled revenues	83		83		$ 73
Franchise fees and gross receipts taxes	$ 31	$ 26	$ 60	$ 53

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Regulatory - Additional Information (Detail)											1 Months Ended		6 Months Ended
	Aug. 06, 2021 USD ($)	Aug. 03, 2021 USD ($)	Nov. 19, 2020 USD ($)	Aug. 18, 2020 USD ($)	Aug. 03, 2020 USD ($)	Apr. 27, 2020 USD ($)	Jun. 28, 2019 USD ($) MW	Jun. 29, 2018 USD ($) MW	Dec. 12, 2017 USD ($) MW	Sep. 27, 2017 USD ($) MW	Jan. 31, 2024 USD ($)	Jan. 31, 2023 USD ($)	Jun. 30, 2021 USD ($) Unit	Dec. 31, 2020 USD ($)	Jun. 09, 2020 USD ($)
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs													$ 14,346,000,000	$ 13,818,000,000
Accumulated depreciation													$ 3,897,000,000	3,712,000,000
Number of units applied for recovery | Unit													3
Intangible Software Assets [Member]
Public Utilities General Disclosures [Line Items]
Accumulated amortization reserve surplus															$ 16,000,000
Electric Utility Plant [Member]
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs													$ 11,876,000,000	11,486,000,000
Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Increase in revenue			$ 34,000,000
Allowed equity in the capital structure			54.70%
Impact of tax reform through reduction in base revenue days			120 days
Accumulated depreciation			$ 34,000,000
Increase in annual base rate			58,000,000
Peoples Gas System [Member] | Cast Iron and Bare Steel Replacement Rider [Member]
Public Utilities General Disclosures [Line Items]
Increase in revenue			$ 24,000,000
Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Additional cost recovery from settlement agreement		$ 83,000,000
Settlement Agreement [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement, approval date	Aug. 06, 2021
Base rate adjustment amount	$ 123,000,000
Increase in revenue	$ 191,000,000
Settlement agreement number of subsequent years adjustments	2 years
Allowed equity in the capital structure	54.00%
Basis point increase applicable	0.25%
Additional attainable revenue under settlement agreement	$ 10,000,000
Changes in base rate under agreement	$ 0
Impact of tax reform through reduction in base revenue days	180 days
Settlement Agreement [Member] | Scenario Forecast [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement adjustment amount											$ 21,000,000	$ 90,000,000
Settlement Agreement [Member] | US Treasury Bond [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Calculating period	30 years
Determining period	6 months
Minimum [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE			8.90%
Base rate agreement frozen period			Jan. 01, 2021
Minimum [Member] | Settlement Agreement [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE	9.00%
Base rate agreement frozen period	Jan. 01, 2022
Minimum [Member] | Settlement Agreement [Member] | US Treasury Bond [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
ROE revenue basis point on yield rate	0.50%
Maximum [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE			11.00%
Base rate agreement frozen period			Dec. 31, 2023
Maximum [Member] | Settlement Agreement [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE	11.00%
Base rate agreement frozen period	Dec. 31, 2024
Mid Point [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE			9.90%
Mid Point [Member] | Settlement Agreement [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE	9.95%
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										$ 850,000,000
Solar Project Cost Recovery [Member] | Solar Base Rate Adjustments [Member]
Public Utilities General Disclosures [Line Items]
True-up amount returned to customers				$ 5,000,000
Estimated true-up amount returned to customers													4,000,000
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									$ 24,000,000
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								$ 46,000,000
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							$ 26,000,000
Solar Project Cost Recovery [Member] | Effective January 1, 2021 [Member]
Public Utilities General Disclosures [Line Items]
Solar energy capacity | MW									46
Estimated annual revenue requirements									$ 8,000,000
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
Retiring Assets [Member] | Settlement Agreement [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Cost recovery from settlement agreement	$ 68,000,000
Retiring Coal Generation Units and Meter Assets [Member] | Settlement Agreement [Member] | Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement cost recovery period	15 years
Big Bend Modernization Project [Member]
Public Utilities General Disclosures [Line Items]
Energy generation capacity investments													850,000,000
Investments in energy projects till date													611,000,000
Accumulated depreciation													$ 91,000,000	88,000,000
Settlement agreement recovery description													Tampa Electric’s Settlement Agreement provides recovery for the Big Bend Modernization project in two phases. The first phase is a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment.
Big Bend Modernization Project [Member] | Electric Utility Plant [Member]
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs													$ 200,000,000	$ 200,000,000
Big Bend Modernization Project [Member] | Minimum [Member]
Public Utilities General Disclosures [Line Items]
Energy project investment term													2018
Big Bend Modernization Project [Member] | Maximum [Member]
Public Utilities General Disclosures [Line Items]
Energy project investment term													2023
Big Bend Coal Generation Assets [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement cost recovery period													15 years
Storm Protection Plan [Member]
Public Utilities General Disclosures [Line Items]
Cost recovery from settlement agreement					$ 39,000,000
Reduction in annual base rates						$ 15,000,000

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Regulatory assets:
Regulatory assets	$ 481	$ 485
Less: Current portion	68	79
Long-term regulatory assets	413	406
Regulatory liabilities:
Regulatory liabilities	1,213	1,261
Less: Current portion	57	67
Long-term regulatory liabilities	1,156	1,194
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	98	90
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	43	38
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	25	22
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	298	309
Asset Retirement Obligation [Member]
Regulatory assets:
Regulatory assets	9	13
Other [Member]
Regulatory assets:
Regulatory assets	8	13
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	678	691
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	18	23
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	48	48
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	469	498
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 0	$ 1

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2019	Oct. 31, 2013
Storm Restoration Cost Recovery [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Minimum cost recovery period	12 months
Replenishment reserve for recovery of cost			$ 56
Hurricane Dorian [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Storm restoration preparation costs		$ 8

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Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2021	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Income Taxes [Line Items]
Unrecognized tax benefits		$ 5		$ 9
Unrecognized tax benefit that would reduce effective tax rate		$ 5		$ 9
Federal [Member] | R&D Tax Credits [Member]
Income Taxes [Line Items]
Unrecognized tax benefits decreased	$ 5
Tampa Electric [Member]
Income Taxes [Line Items]
Effective tax rate		16.10%	17.10%

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Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 2	$ 3	$ 5	$ 6
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	3	1	5	3
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	6	5	11	10
Interest cost	6	6	11	13
Expected return on assets	(13)	(12)	(26)	(25)
Amortization of:
Actuarial loss (gain)	5	5	11	10
Settlement cost			0	0
Net periodic benefit cost	4	4	7	8
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	0	1	0
Interest cost	2	2	3	3
Expected return on assets	0	0	0	0
Amortization of:
Actuarial loss (gain)	(1)	0	0	0
Settlement cost			0	0
Net periodic benefit cost	$ 2	$ 2	$ 4	$ 3

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Employee Postretirement Benefits - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
Reclassification of regulatory assets to net income as part of periodic benefit cost	$ 5	$ 4	$ 11	$ 9
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA			6.70%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	2	3	$ 5	6
Employer contributions			9	8
Employer contributions in remainder of year	8		8
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	4	4	$ 7	8
Discount rate			2.38%
Employer contributions			$ 11	10
Employer contributions in remainder of year	10		10
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	3	1	5	3
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 2	$ 2	$ 4	$ 3
Discount rate			2.47%

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Short-Term Debt - Schedule of Short-Term Borrowings (Detail) - USD ($)	Jun. 30, 2021	Dec. 31, 2020	Dec. 18, 2020	Oct. 30, 2020	Jul. 14, 2020
Line Of Credit Facility [Line Items]
Credit Facilities	$ 800,000,000	$ 1,250,000,000	$ 80,000,000
Borrowings Outstanding	410,000,000	775,000,000
Letters of Credit Outstanding	1,000,000	1,000,000
Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	410,000,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	800,000,000	800,000,000
Borrowings Outstanding		345,000,000
Letters of Credit Outstanding	1,000,000	1,000,000
5-year Facility [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
5-year Facility [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	410,000,000
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	0	300,000,000
Borrowings Outstanding		300,000,000
Letters of Credit Outstanding	0	0
1-year Term Facility [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
1-year Term Facility [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	0	150,000,000		$ 150,000,000	$ 150,000,000
Borrowings Outstanding		130,000,000
Letters of Credit Outstanding	0	$ 0
3-year Accounts Receivable Facility [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
3-year Accounts Receivable Facility [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	$ 0

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Short-Term Debt - Schedule of Short-Term Borrowings (Parenthetical) (Detail) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2020	May 25, 2021
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2023	Mar. 22, 2023
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2021	Mar. 22, 2021
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 23, 2021	Mar. 23, 2021
Maximum [Member] | Commercial Paper Program [Member]
Line Of Credit Facility [Line Items]
Commercial paper issued	$ 800,000,000		$ 800,000,000

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Short-Term Debt - Additional Information (Detail) - USD ($)						6 Months Ended	12 Months Ended
	Jan. 29, 2021	Dec. 18, 2020	Oct. 30, 2020	Jul. 14, 2020	Feb. 06, 2020	Jun. 30, 2021	Dec. 31, 2020	May 25, 2021
Line Of Credit Facility [Line Items]
Commitment fees, percentage						0.125%
Weighted-average interest rate						0.25%	0.89%
Line of credit facility maximum borrowing capacity		$ 80,000,000				$ 800,000,000	$ 1,250,000,000
Lenders commitment amount		800,000,000
Increase of credit facility		$ 100,000,000
Commercial Paper Program [Member]
Line Of Credit Facility [Line Items]
Debt instrument, restrictive covenants						The maturities of the Notes will vary, but may not exceed 270 days from the date of issue.
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility amendment date			Oct. 30, 2020	Jul. 14, 2020
Line of credit facility maximum borrowing capacity			$ 150,000,000	$ 150,000,000		$ 0	$ 150,000,000
Credit facility maturity date						Mar. 22, 2021	Mar. 22, 2021
364-day Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity					$ 300,000,000
Credit facility maturity period					364 days
Credit facility maturity date					Feb. 04, 2021
Credit Facility extended maturity date	Apr. 29, 2021
Maximum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		Mar. 22, 2023
Maximum [Member] | Commercial Paper Program [Member]
Line Of Credit Facility [Line Items]
Commercial paper issued						$ 800,000,000		$ 800,000,000
Minimum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		Mar. 22, 2022

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Mar. 18, 2021	Jun. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term debt		$ 3,385	$ 2,872
Estimated fair value		$ 4,035	$ 3,597
2.40% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2031
Aggregate principal amount issued	$ 400
Stated interest rate	2.40%
Debt instrument maturity date	Mar. 15, 2031
Redeemable principal amount percentage	100.00%
Basis spread on federal funds rate	0.15%
Redeemable principal amount percentage	100.00%
Debt instrument, start date of redemption	Dec. 15, 2030
Debt instrument, offering date	Mar. 18, 2021
3.45% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2051
Aggregate principal amount issued	$ 400
Stated interest rate	3.45%
Debt instrument maturity date	Mar. 15, 2051
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	Sep. 15, 2050
Debt instrument, offering date	Mar. 18, 2021

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Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 17	$ 17

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Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Jun. 30, 2021 USD ($)
Other Commitments [Line Items]
2021	$ 663
2022	406
2023	316
2024	234
2025	211
Thereafter	2,128
Total future minimum payments	3,958
Purchased Power [Member]
Other Commitments [Line Items]
2021	35
2022	0
2023	0
2024	0
2025	0
Thereafter	0
Total future minimum payments	35
Transportation [Member]
Other Commitments [Line Items]
2021	119
2022	232
2023	211
2024	205
2025	191
Thereafter	2,014
Total future minimum payments	2,972
Capital Projects [Member]
Other Commitments [Line Items]
2021	297
2022	84
2023	58
2024	0
2025	0
Thereafter	0
Total future minimum payments	439
Fuel and Gas Supply [Member]
Other Commitments [Line Items]
2021	173
2022	52
2023	1
2024	0
2025	0
Thereafter	0
Total future minimum payments	226
Long-term Service Agreements [Member]
Other Commitments [Line Items]
2021	35
2022	32
2023	43
2024	26
2025	18
Thereafter	66
Total future minimum payments	220
Operating Leases [Member]
Other Commitments [Line Items]
2021	2
2022	3
2023	3
2024	3
2025	2
Thereafter	48
Total future minimum payments	61
Demand Side Management [Member]
Other Commitments [Line Items]
2021	2
2022	3
2023	0
2024	0
2025	0
Thereafter	0
Total future minimum payments	$ 5

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Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Segment Reporting Information [Line Items]
Total revenues	$ 654	$ 549	$ 1,253	$ 1,096
Total interest charges	34	32	67	66
Net income	121	117	213	194
Total assets	11,459		11,459		$ 11,048
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	654	549	1,253	1,096
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	0	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(1)	(2)	(4)	(6)
Total interest charges	0	0	0	0
Net income	0	0	0	0
Total assets	(663)		(663)		(653)
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	(1)	(2)	(4)	(6)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	532	454	979	875
Total interest charges	29	28	57	58
Net income	102	106	167	165
Total assets	10,101		10,101		9,800
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	531	453	977	873
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	1	1	2	2
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	123	97	278	227
Total interest charges	5	4	10	8
Net income	19	11	46	29
Total assets	2,021		2,021		$ 1,901
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	123	96	276	223
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Intracompany sales	$ 0	$ 1	$ 2	$ 4

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Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 531	$ 453	$ 977	$ 873
Total gas revenue	123	96	276	223
Total revenue	654	549	1,253	1,096
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	276	254	508	459
Total gas revenue	49	36	116	84
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	144	121	270	246
Total gas revenue	46	28	99	69
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	41	32	78	69
Total gas revenue	6	5	12	11
Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	11	(3)	9	(5)
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	59	49	112	104
Total gas revenue	22	27	49	59
Operating Segments [Member] | Tampa Electric [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	532	454	979	875
Total gas revenue	0	0	0	0
Total revenue	532	454	979	875
Operating Segments [Member] | Tampa Electric [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	276	254	508	459
Total gas revenue	0	0	0	0
Operating Segments [Member] | Tampa Electric [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	144	121	270	246
Total gas revenue	0	0	0	0
Operating Segments [Member] | Tampa Electric [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	41	32	78	69
Total gas revenue	0	0	0	0
Operating Segments [Member] | Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	11	(3)	9	(5)
Operating Segments [Member] | Tampa Electric [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	60	50	114	106
Total gas revenue	0	0	0	0
Operating Segments [Member] | PGS [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	123	97	278	227
Total revenue	123	97	278	227
Operating Segments [Member] | PGS [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	49	36	116	84
Operating Segments [Member] | PGS [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	46	28	99	69
Operating Segments [Member] | PGS [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	6	5	12	11
Operating Segments [Member] | PGS [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Operating Segments [Member] | PGS [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	22	28	51	63
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)	(1)	(2)	(2)
Total gas revenue	0	(1)	(2)	(4)
Total revenue	(1)	(2)	(4)	(6)
Eliminations [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	0	0	0	0
Eliminations [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	0	0	0	0
Eliminations [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Total gas revenue	0	0	0	0
Eliminations [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0	0
Eliminations [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(1)	(1)	(2)	(2)
Total gas revenue	$ 0	$ (1)	$ (2)	$ (4)

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Revenue - Additional Information (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Regulated Operating Revenue [Abstract]
Remaining performance obligations, transaction price	$ 130	$ 135
Remaining performance obligations, expected year of revenue recognition	2033