10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2023

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 pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

Indicate by check mark if Tampa Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes ☐ No ☒

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 the 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 the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Act).

Yes ☐ No ☒

The aggregate market value of Tampa Electric Company’s common stock held by non-affiliates of the registrant as of June 30, 2023 was zero.

As of February 20, 2024, 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., an indirect wholly-owned subsidiary of Emera Inc.

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

DEFINITIONS

Acronyms and defined terms used in this and other filings with the U.S. Securities and Exchange Commission 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
ASU	Accounting Standards Update
BCF	billion cubic feet
CCRs	coal combustion residuals
CMO	collateralized mortgage obligation
CO2	carbon dioxide
CPI	consumer price index
CT	combustion turbine
D.C. Circuit Court	D.C. Circuit Court of Appeals
ECRC	environmental cost recovery clause
Emera	Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada and the indirect parent company of Tampa Electric Company
EPA	U.S. Environmental Protection Agency
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
EUSHI	Emera US Holdings Inc., a wholly owned subsidiary of Emera, which is the sole shareholder of TECO Energy’s common stock
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FPSC	Florida Public Service Commission
GHG	greenhouse gas
IRS	Internal Revenue Service
ITCs	investment tax credits
kWac	kilowatt on an alternating current basis
MBS	mortgage-backed securities
MD&A	the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
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
NPDES	National Pollutant Discharge Elimination System
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
PBO	projected benefit obligation
PGS	Peoples Gas System, the former gas division of Tampa Electric Company
PGSI	Peoples Gas System, Inc.
PPA	power purchase agreement
PRP	potentially responsible party
R&D	research and development
REIT	real estate investment trust

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ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
S&P	Standard and Poor’s
SEC	U.S. Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SoBRAs	solar base rate adjustments
SPP	storm protection plan
STIF	short-term investment fund
TEC	Tampa Electric Company
TECO Energy	TECO Energy, Inc., the direct parent company of Tampa Electric Company
U.S. GAAP	generally accepted accounting principles in the United States

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This Form 10-K 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 discussed 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; and (d) 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-K.

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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PART I

Item 1. BUSINESS

Tampa Electric Company, referred to as TEC, was incorporated in Florida in 1899 and was reincorporated in 1949. All of TEC’s common stock is owned by TECO Energy, a holding company. TECO Energy is an indirect, wholly owned subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera.

TEC is a public utility operating within the State of Florida. TEC is comprised of the electric division, referred to as Tampa Electric, and prior to January 1, 2023, also included the natural gas division, referred to as PGS. Tampa Electric provides retail electric service to approximately 839,960 customers in West Central Florida with a net winter system generating capacity of 6,433 MW at December 31, 2023.

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC.

TEC makes its SEC filings available free of charge on Tampa Electric’s website (www.tampaelectric.com/company/about/) as soon as reasonably practicable after they are filed with the SEC. TEC’s electronic SEC filings are also available on the SEC’s website (www.sec.gov).

TEC Revenues

TEC’s revenues consist of sales to residential, commercial, industrial and other customers. TEC’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities, power generation customers and other large volume operations. Other sales volumes consist primarily of off-system sales to other utilities and revenues from street lighting.

For TEC’s revenue and other financial information by operating segments, see Note 11 to the 2023 Annual TEC Consolidated Financial Statements.

TEC Human Capital

Tampa Electric had 2,546 employees as of December 31, 2023, substantially all of whom are located in Florida. Of these employees, 706 were represented by the International Brotherhood of Electrical Workers and 143 were represented by the Office and Professional Employees International Union.

Maintaining a robust pipeline of talent is crucial to TEC’s ongoing success and is a key aspect of succession planning efforts across the organization. TEC is committed to investing in its employees through training and development programs as well as a tuition assistance program to promote continued professional growth. TEC provides a competitive compensation package that includes base pay, annual short-term incentives based on the achievement of corporate goals and performance, long-term incentives (applicable to eligible employee population), and health and retirement benefits.

TAMPA ELECTRIC – Electric Operations

Tampa Electric is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. At December 31, 2023, Tampa Electric had two generating stations in or near Tampa, one generating station in southwestern Polk County, and 25 photovoltaic power stations (thirteen in Hillsborough County, ten in Polk County, and two in Pasco County).

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The sources of Tampa Electric’s operating revenue and MWH sales were as follows:

Tampa Electric Operating Revenue

(millions)	2023			2022			2021
By Customer Type
Residential	$	1,711		$	1,381		$	1,156
Commercial		803			666			602
Industrial		203			176			172
Other sales of electricity		248			215			194
Regulatory deferrals and unbilled revenue		(389	)		(12	)		(8	)
Total energy sales		2,576			2,426			2,116
Off system sales		8			37			6
Other		53			60			52
Total revenues	$	2,637		$	2,523		$	2,174
By Sales Type
Base	$	1,458		$	1,342		$	1,179
Clause		802			901			836
Capital cost recovery for early retired assets		69			69			0
Storm surcharge		107			0			0
Gross receipts taxes and franchise fees		139			114			100
Other		62			97			59
Total revenues	$	2,637		$	2,523		$	2,174

Megawatt-hour Sales

(thousands)	2023		2022		2021
Residential		10,307		10,109		9,941
Commercial		6,462		6,300		6,144
Industrial		2,082		2,111		2,122
Other sales of electricity		1,940		1,947		1,886
Total retail		20,791		20,467		20,093
Off system sales		254		405		114
Total energy sold		21,045		20,872		20,207

No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or several would have a significant adverse effect on Tampa Electric. Tampa Electric experiences summer peak loads due to the use of air conditioning and other cooling equipment and winter peak loads due to electric space heating and fewer daylight hours.

Regulation

Base Rates

Tampa Electric’s retail operations are regulated by the FPSC. The FPSC’s objective is to set rates at a level that provides an opportunity for the utility to collect revenues (revenue requirements) equal to its prudently incurred costs of providing service to customers, plus a reasonable return on invested capital.

The costs of owning, operating and maintaining the utility systems, excluding fuel, conservation costs, purchased power, storm protection plan projects and certain environmental costs, are recovered through base rates. These costs include O&M expenses, depreciation, taxes, and a return on investment in assets providing electric service (rate base). The rate of return on rate base, which is intended to approximate a company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes (at a zero cost rate) and an allowed ROE. Base rates are determined in FPSC rate setting hearings which occur at the initiative of Tampa Electric, the FPSC or other interested parties.

Tampa Electric’s 2023 and 2022 base rates reflect a settlement agreement approved by the FPSC on November 10, 2021. Tampa Electric’s 2021 results reflect a settlement agreement approved by the FPSC on November 6, 2017. See Note 3 to the 2023 Annual TEC Consolidated Financial Statements for information regarding Tampa Electric’s base rates, ROE and other regulatory matters.

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Other Cost Recovery

Tampa Electric has five cost recovery clauses.

(1)Tampa Electric has a fuel recovery clause allowing recovery of actual fuel costs from customers through annual fuel rate adjustments. Differences between actual prudently incurred fuel costs and amounts recovered from customers in a year are recovered from or returned to customers in a subsequent period.

(2)Tampa Electric has a capacity recovery clause allowing recovery of firm demand payments associated with purchased power agreements.

(3)Tampa Electric has an environmental cost recovery clause which allows it to earn a return on investments in new facilities to comply with new environmental regulations and to recover the costs to operate and maintain these facilities.

(4)Through its conservation cost recovery clause, Tampa Electric offers its customers a comprehensive array of residential and commercial programs that have enabled it to meet its required demand side management goals, reduce weather-sensitive peak demand and conserve energy.

(5)Tampa Electric has a Storm Protection Plan cost recovery clause allowing recovery of prudent transmission and distribution storm hardening costs for incremental activities not already included in base rates as outlined in the programs in its approved Storm Protection Plan.

During the fourth quarter of 2023, the FPSC approved cost-recovery rates for the above clauses effective January 1, 2024. See Note 3 to the 2023 Annual TEC Consolidated Financial Statements for further information. In addition, Tampa Electric’s 2021 rate case settlement agreement established a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years. The recovery started in January 2022 and will survive the term of the settlement agreement.

FERC and Other Regulations

Tampa Electric is subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Tampa Electric is subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section of the MD&A).

Competition

Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. The principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.

Generation Sources

In 2023 and 2022, 88% and 86%, respectively, of Tampa Electric’s gross generation of electricity was natural gas-fired, with solar representing 8% and 7%, respectively, and coal representing 4% and 7%, respectively. In 2023 and 2022, Tampa Electric used its generating units to meet 92% and 90%, respectively, of the total system load requirements, with the remaining 8% and 10%, respectively coming from purchased power. Tampa Electric is required to maintain a generation capacity greater than firm peak demand. Tampa Electric meets the planning criteria for reserve capacity established by the FPSC, which is a 20% reserve margin over firm peak demand.

The table below presents information regarding Tampa Electric’s generation costs.

Average cost per MMBTU	2023		2022		2021
Natural Gas (1)	$	2.81	$	8.32	$	4.83
Coal (2)		5.00		3.52		3.49
Average generation cost per MWh (3)		30.97		37.85		33.73

(1)Represents the cost of natural gas, transportation, storage, balancing, and fuel losses for delivery to the energy center.

(2)Represents the cost of coal and transportation.

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(3)Represents the average generation cost per MWh including solar.

Tampa Electric’s fuel costs are affected by commodity prices and generation mix that is largely dependent on economic dispatch of the generating fleet, dispatching the lowest fuel cost options first (solar renewable energy being zero fuel costs), such that the incremental cost of generation increases as sales volumes increase. Generation mix may also be affected by plant outages, plant performance, availability of lower priced short-term purchased power, compliance with environmental standards and regulations, and availability of solar resources.

Natural Gas. Tampa Electric maintains gas commodity, pipeline transportation and storage contracts. As of December 31, 2023, 69% of Tampa Electric’s 2.0 million BCF of gas storage capacity was full. Tampa Electric has contracted for, on average, 52% of its expected gas needs for the January through December 2024 period. Tampa Electric expects to issue requests for proposals (RFPs) to meet its remaining 2024 gas needs and begin contracting for its 2025 requirements. Additional volume requirements are purchased in the short-term spot market.

Coal. Tampa Electric burned less than 0.4 million tons of coal during 2023. Coal consumption is expected to decrease in 2024 compared to 2023. Consistent with 2023, Tampa Electric will be purchasing its coal in 2024 under a contract with two different commodity suppliers. 100% of Tampa Electric's expected coal need in 2024 is under contract. Tampa Electric takes coal deliveries primarily by water and uses transportation agreements with a rail provider if spot coal supplies are needed.

Franchises and Other Rights

Florida utilities must obtain franchises to operate in certain municipalities. Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights-of-way that it carries for its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years.

Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. At December 31, 2023, these agreements have various expiration dates ranging through 2052 and are expected to be renewed under similar terms and conditions.

Franchise fees expense totaled $67 million and $56 million in 2023 and 2022, respectively. Franchise fees are calculated using a formula based primarily on electric revenues and are recovered on a dollar-for-dollar basis from customers.

Utility operations in Hillsborough, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits granted by the Florida Department of Transportation or the County Commissioners of such counties. There is no law limiting the time for which such permits may be granted. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements.

Environmental Matters

Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters. TEC, through its Tampa Electric division and former PGS division, is a PRP for certain superfund sites and, through its former PGS division, for certain former manufactured gas plant sites. See Environmental Compliance section of the MD&A for additional information. As a result of the separation of the PGS division, PGS is now the responsible party for those sites (in addition to third party PRPs for certain sites). See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC.

PEOPLES GAS SYSTEM – Gas Operations

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. From and after January 1, 2023, the PGS business is no longer operated by TEC. See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for further information regarding the separation of PGS from TEC. For information regarding PGS's Business in 2022 and 2021, see “Item 1. Business” of TEC’s Annual Report on Form 10-K for the year ended December 31, 2022.

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Item 1A. RISK FACTORS

Risks Relating to TEC’s Business and Strategy

Regulatory, Legislative, and Legal Risks

Tampa Electric is regulated; changes in regulation or the regulatory environment could reduce revenues, increase costs or competition.

Tampa Electric operates in a regulated industry. Retail operations, including the rates charged and costs eligible for recovery under clauses, are regulated by the FPSC, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or regulatory actions could have an adverse effect on TEC’s financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure. Additionally, if regulators deny or delay cost recovery approvals, Tampa Electric’s earnings could be negatively impacted.

If Tampa Electric earns returns on equity above its allowed range, indicating a trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged returns above its allowed range could result in credits or refunds to customers, which could reduce future earnings and cash flow.

Changes in the environmental and land use laws and regulations affecting its business could increase TEC’s costs or curtail its activities.

TEC’s business is subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TEC, requiring cost-recovery proceedings and/or requiring it to modify its business model.

Federal or state regulation of GHG emissions, depending on how they are enacted, could increase Tampa Electric’s costs or the rates charged to its customers, which could curtail sales.

On June 19, 2019, the EPA released a final rule named the Affordable Clean Energy (ACE) rule. The ACE rule, which replaces the Clean Power Plan adopted in 2015, contained emission guidelines for states to address GHG emissions from existing coal-fired electric generating units. On January 19, 2021, the D.C. Circuit vacated the ACE rule and remanded it to the EPA. A replacement rule is under development.

The outcome of the pending rulemaking process and expected further litigation, and its impact on Tampa Electric’s business, is uncertain at ‎this time; however, it could result in increased operating costs and/or decreased operations at Tampa Electric’s coal-fired plants. Tampa Electric currently expects prudently incurred costs for compliance to be recovered through rates. However, timing of recovery could impact earnings and cash flows, and increases in rates charged to customers could result in reduced sales.

The computation of TEC’s provision for income taxes is impacted by changes in tax legislation.

Any changes in tax legislation could affect TEC’s future cash flows and financial position. The value of TEC’s existing deferred tax assets and liabilities are determined by existing tax laws and could be impacted by changes in laws. See Note 4 of the 2023 Annual TEC Consolidated Financial Statements for further information regarding TEC’s income taxes.

Tampa Electric may not be able to secure adequate rights-of-way to construct transmission lines and distribution-related facilities and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers.

Tampa Electric relies on federal, state and local governmental agencies to secure rights-of-way and siting permits to construct transmission lines and distribution-related facilities. If adequate rights-of-way and siting permits to build new transportation and transmission lines cannot be secured, then Tampa Electric:

• May need to remove or abandon its facilities on the property covered by rights-of-way or franchises and seek alternative locations for its transmission or distribution facilities;

• May need to rely on more costly alternatives to provide energy to its customers;

• May not be able to maintain reliability in its service area;

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• May need to exercise the power of eminent domain, which can be costly and take time; and/or

• May experience a negative impact on its ability to provide electric service to new customers.

The franchise rights held by Tampa Electric could be lost in the event of a breach by such utilities or could expire and not be renewed.

Tampa Electric holds franchise agreements with counterparties throughout its service area. In some cases, these rights could be lost in the event of a breach of these agreements. These agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. From time to time municipalities seek to include provisions allowing them to purchase the portion of the utility’s system located within a given municipality’s boundaries under certain conditions.

Operational and Construction Risks

TEC’s business is sensitive to variations in weather and the effects of extreme weather and has seasonal variations.

TEC’s utility business is affected by variations in general weather conditions including severe weather. Energy sales by its electric utility are particularly sensitive to seasonal variations in weather conditions, including unusually mild summer or winter weather that cause lower energy usage for cooling or heating purposes. Tampa Electric has both summer and winter peak periods that are dependent on weather conditions. Tampa Electric forecasts energy sales based on normal weather, which represents a long-term historical average. If there is unusually mild weather, or if climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

TEC is subject to several risks that arise or may arise from climate change.

TEC is subject to risks that may arise from the impacts of climate change. There is increasing public concern about climate change and growing support for reducing carbon dioxide emissions. Municipal, state, and federal governments have been setting policies and enacting laws and regulations to deal with climate change impacts in a variety of ways, including de-carbonization initiatives and promotion of cleaner energy and renewable energy generation of electricity. Refer to “changes in the environmental and land use laws and regulations” above. Insurance companies have begun to limit their exposure to coal-fired electricity generation and are evaluating the medium and long-term impacts of climate change which may result in fewer insurers, more restrictive coverage and increased premiums.

Climate change may lead to increased frequency and intensity of weather events and related impacts such as storms, hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and storm surge. The potential impacts of climate change, such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce even greater damage to coastal generation and other facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures may bring increased frequency and severity of wildfires, including within TEC’s service territory. Refer to “variations in weather” above.

High winds and lack of precipitation increase the risk of wildfires resulting from TEC’s infrastructure. The risk of wildfires is addressed primarily through asset management, storm hardening, and vegetation management programs for the electric utility. If it is found to be responsible for such a fire, TEC could suffer material costs, losses and damages, which could materially affect TEC’s business, access to capital, financial condition and results of operations including its reputation with customers, regulators, governments and financial markets. Resulting costs could include fire suppression costs, regeneration, timber value, increased insurance costs and costs arising from damages and losses incurred by third parties.

TEC is subject to physical risks that arise, or may arise, from global climate change, including damage to operating assets from more frequent and intense weather events and from wildfires due to warming air temperatures and increasing drought conditions. Some of Tampa Electric’s fossil fueled generation assets are located at or near coastal sites and as such are exposed to the separate and combined effects of rising sea levels and increasing storm intensity, including storm surges and flooding. Refer to “variations in weather” above.

Failure to address issues related to climate change could affect TEC’s reputation with stakeholders, its ability to operate and grow, and TEC’s access to, and cost of, capital. Refer to “Financial, Economic, and Market Risks” below.

Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors could lead to more expensive or more scarce products and services that are required by TEC in its operations. This could lead to supply shortages, delivery delays and the need to source alternate products and services.

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Depending on the regulatory response to government legislation and regulations, TEC may be exposed to the risk of reduced recovery through rates in respect of the affected assets. Valuation impairments could result from such regulatory outcomes.

TEC could face litigation or regulatory action related to environmental harms from carbon dioxide emissions or climate change public disclosure issues.

For thermal plants requiring cooling water, reduced availability of water resulting from climate change could adversely impact operations or the costs of operations.

The facilities and operations of TEC could be affected by natural disasters or other catastrophic events.

TEC’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g., hurricanes, floods, high winds, fires and earthquakes), equipment failures, terrorist or physical attacks, vandalism, a major accident or incident at one of the sites, and other events beyond the control of TEC. The operation of generation, transmission and distribution systems involves certain risks, including fires, explosions, pipeline ruptures, damage to solar panels and other generation assets, and other hazards and risks that may cause unforeseen interruptions, personal injury, death, or property damage. There have also been physical attacks on critical infrastructure around the world. In the event of a physical attack that disrupts service to customers, revenues would be reduced, and costs would be incurred to repair and restore systems. These types of events, either impacting TEC’s facilities or the industry in general, could cause TEC to incur additional security and insurance-related costs, and could have adverse effects on its business and financial results. Any costs relating to such events may not be recoverable through insurance or rates.

TEC is exposed to potential risks related to cyberattacks and unauthorized access, which could cause system failures, disrupt operations or adversely affect safety.

TEC increasingly relies on information technology systems and network infrastructure to manage its business and safely operate its assets, including controls for interconnected systems of generation, distribution and transmission and financial, billing and other business systems. TEC also relies on third party service providers to conduct business. As TEC operates critical infrastructure, it may be at greater risk of cyberattacks by third parties, which could include nation-state controlled parties.

Cyberattacks can reach TEC’s networks with access to critical assets and information via their interfaces with less critical internal networks or via the public internet. Cyberattacks can also occur via personnel with direct access to critical assets or trusted networks. An outbreak of infectious disease, a pandemic or a similar public health threat may cause disruption in normal working patterns including wide scale “work from home” policies, which could increase cybersecurity risk as the quantity of both cyberattacks and network interfaces increases. Refer to the risk factor below regarding public health risk. Methods used to attack critical assets could include general purpose or energy-sector-specific malware delivered via network transfer, removable media, viruses, attachments or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect.

TEC’s systems, assets and information could experience security breaches that could cause system failures, disrupt operations or adversely affect safety. Such breaches could compromise customer, employee-related or other information systems and could result in loss of service to customers or the unavailability, release, destruction or misuse of critical, sensitive or confidential information. These breaches could also delay delivery or result in contamination or degradation of hydrocarbon products TEC transports, stores or distributes.

Should such cyberattacks or unauthorized accesses materialize, TEC could suffer costs, losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory cost recovery or other processes. If not recovered through these means, they could materially adversely affect TEC’s business and financial results including its reputation and standing with customers, regulators, governments and financial markets. Resulting costs could include, amongst others, response, recovery and remediation costs, increased protection or insurance costs and costs arising from damages and losses incurred by third parties. If any such security breaches occur, there is no assurance that they can be adequately addressed in a timely manner.

With respect to certain of its assets, TEC is required to comply with rules and standards relating to cybersecurity and information technology including, but not limited to, those mandated by bodies such as the North American Electric Reliability Corporation. TEC cannot be assured that its operations will not be negatively impacted by a cyberattack.

Effects of an outbreak of infectious disease, another pandemic or a similar public health threat could have a negative impact on TEC’s operations.

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An outbreak of infectious disease, a pandemic or a similar public health threat or a fear of any of the foregoing, could adversely impact TEC, including by causing operating, supply chain and project development delays and disruptions, labor shortages and shutdowns (including as a result of government regulation and prevention measures), and delays in regulatory decisions and proceedings, which could have a negative impact on TEC’s operations.

Any adverse changes in general economic and market conditions arising as a result of a public health threat could negatively impact demand for electricity, revenue, operating costs, timing and extent of capital expenditures, results of financing efforts, or credit risk, counterparty risk and collection risk, which could result in a material adverse effect on TEC’s business.

Financial, Economic, and Market Risks

National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TEC.

The business of TEC is concentrated in Florida. If economic conditions decline, retail customer growth rates may stagnate or decline, and customers’ energy usage may decline, adversely affecting TEC’s results of operations, net income and cash flows. A factor in customer growth in Florida is net in-migration of new residents, both domestic and non-U.S. A slowdown in the U.S. economy could reduce the number of new residents and slow customer growth.

Potential competitive changes may adversely affect TEC.

There is competition in wholesale power sales across the United States. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers or voters, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

Florida electric utilities, including Tampa Electric, currently benefit from operating in a regulated environment with limited competition in their market for retail customers. However, the commercial and regulatory frameworks under which Tampa Electric operates can be impacted by changes in government and shifts in government policy. These include initiatives regarding deregulation or restructuring of the energy industry, which may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows.

Disruption of fuel supply could have an adverse impact on the financial condition of TEC.

Tampa Electric depends on third parties to supply fuel, including natural gas and coal. As a result, there are risks of supply interruptions and fuel-price volatility. Disruption of fuel supplies or transportation services for fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of transportation facilities, pipeline failures or other events, could impair the ability to deliver or generate electricity and could adversely affect operations. The loss of fuel suppliers or the inability to renew existing coal and natural gas contracts at favorable terms could significantly affect the ability to serve customers and have an adverse impact on the financial condition and results of operations of TEC.

Commodity price changes may affect the operating costs and competitive positions of TEC’s business.

TEC’s business is sensitive to changes in gas, coal and other commodity prices. Any changes in the availability of these commodities could affect the prices charged by suppliers as well as suppliers’ operating costs and the competitive positions of their products and services.

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of natural gas and coal. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales of, and the margins earned on, wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

Developments in technology could reduce demand for electricity.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy-efficient

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appliances and equipment. Advances in these or other technologies could reduce the cost of producing electricity, or otherwise make Tampa Electric’s existing generating facilities uneconomic. Advances in such technologies could reduce demand for electricity, which could negatively impact the results of operations, net income and cash flows of TEC.

Results at TEC may be affected by changes in customer energy-usage patterns.

For the past several years, at Tampa Electric and electric utilities across the United States, weather-normalized electricity consumption per residential customer has declined due to the combined effects of voluntary conservation efforts and improvements in equipment efficiency.

Forecasts by TEC are based on normal weather patterns and trends in customer energy-usage patterns. TEC could be negatively impacted if customers further reduce their energy usage in response to increased energy efficiency, economic conditions or other factors.

Increased customer use of distributed generation could adversely affect Tampa Electric.

In many areas of the United States, including in the markets where TEC operates, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, known as distributed generation. Distributed generation is encouraged and supported by various constituent groups, tax incentives, renewable portfolio standards and special rates designed to support such generation.

Increased usage of distributed generation can reduce utility electricity sales but does not reduce the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce future earnings and cash flows.

Failure to attract and retain an appropriately qualified workforce, or workforce disruptions, could adversely affect TEC’s financial results.

Events such as increased retirements due to an aging workforce or the departure of employees for other reasons without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development. Failure to attract and hire employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or workforce disruptions due to work stoppages or strikes, or the future availability and cost of contract labor may cause costs to operate TEC’s systems to rise. If TEC is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

Liquidity and Capital Requirements Risks

TEC’s indebtedness could adversely affect its business, financial condition and results of operations, as well as its ability to meet its payment obligations on its debt.

TEC has indebtedness that it is obligated to pay. It must meet certain financial covenants as defined in the applicable agreements to borrow under its credit facilities. Also, TEC has certain restrictive covenants in specific agreements and debt instruments. The level of TEC’s indebtedness and potential inability to meet the requirements of the restrictive covenants contained in its debt obligations could have significant consequences to its business, could create risk for the holders of its debt, and could limit its ability to obtain additional financing (see Management’s Discussion & Analysis – Significant Financial Covenants section). Such risks include:

•making it more difficult for TEC to satisfy its debt obligations and other ongoing business obligations, which may result in defaults;

•events of default if it fails to comply with the financial and other covenants contained in the agreements governing such debt, which could result in all of its debt becoming immediately due and payable or require it to negotiate an amendment to financial or other covenants that could cause it to incur additional fees and expenses;

•reducing the availability of cash flow to finance its business and limiting its ability to obtain additional financing for these purposes;

•increasing its vulnerability to the impact of adverse economic and industry conditions;

•limiting its flexibility in planning for, or reacting to, and increasing its vulnerability to, changes in its business and the overall economy;

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•and increasing its cost of borrowing.

TEC has obligations that do not appear on its balance sheet, such as letters of credit. To the extent material, these obligations are disclosed in the notes to the financial statements.

Financial market conditions could limit TEC’s access to capital and increase TEC’s costs of borrowing or refinancing, or have other adverse effects on its results.

TEC has debt maturing in subsequent years, which TEC anticipates will need to be refinanced. Future financial market conditions could limit TEC’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings and cash flows.

Declines in the financial markets or in interest rates or rates of return used to determine benefit assets or obligations could increase TEC’s pension expense or the required cash contributions to maintain required levels of funding for its plan.

TEC is a participant in the comprehensive retirement plans of TECO Energy. Under calculation requirements of the Pension Protection Act, as of the January 1, 2023 measurement date, TECO Energy’s pension plan was fully funded. Any future declines in the financial markets or interest rates could increase the amount of contributions required to fund its pension plan in the future and could cause pension expense to increase.

TEC’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast or costs are not recoverable through rates.

TEC’s capital plan includes significant investments in generation, infrastructure modernization and customer-focused technologies. Any projects planned or currently in construction, particularly significant capital projects, may be subject to risks including, but not limited to, impact on costs from schedule delays, risk of cost overruns, ensuring compliance with operating and environmental requirements and other events within or beyond TEC’s control. Total costs may be higher than estimated, and there can be no assurance that TEC will be able to obtain the necessary project approvals, regulatory outcomes or applicable permits at the federal, state and or local level to recover such expenditures through regulated rates. If TEC’s capital expenditures exceed the forecasted levels or are not recoverable, it may need to draw on credit facilities or access the capital markets on unfavorable terms.

TEC’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade.

The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A3’ and by Fitch at ‘A’. A downgrade to below investment grade by the rating agencies, which would require a four-notch downgrade by Moody’s and Fitch and a three-notch downgrade by S&P, may affect TEC’s ability to borrow, may change requirements for future collateral or margin postings, and may increase financing costs, which may decrease earnings. Downgrades could adversely affect TEC’s relationships with customers and counterparties. Some of the factors that can affect TEC’s credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, political, legislative, and regulatory actions, and changes in Emera’s credit ratings.

In the event TEC’s ratings were downgraded to below investment grade, certain agreements could require immediate payment or full collateralization of net liability positions. Counterparties to its derivative instruments could request immediate payment or full collateralization of net liability positions. Credit provisions in long-term gas transportation agreements would give the transportation providers the right to demand collateral, which is estimated to be approximately $166 million at December 31, 2023.

TEC may be subject to risks relating to its separation from PGS.

On January 1, 2023, TEC completed the separation from its former PGS division to PGSI. TEC’s business is less diversified as a result of the separation since its remaining Tampa Electric business serves only electric utility customers and operates in a more narrow geographic area than its former PGS division.

The separation is intended to be a tax-free transaction for U.S. federal income tax purposes. The IRS has issued a private letter ruling (IRS Ruling) to the effect that, subject to the limitations specified therein and the accuracy and compliance with certain representations, warranties and covenants, the distribution of the PGSI stock, together with certain related transactions, will qualify as a tax-free “reorganization” for U.S. federal income tax purposes. If any of these items are inaccurate, the separation may not qualify for tax-free treatment, which could result in material tax liabilities for TEC.

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Item 1C. CYBERSECURITY

TEC assesses, identifies, and manages material risks from cybersecurity threats under the governance of its Cyber Security Framework and Information Security Policy, as well as several related policies and procedures addressing areas such as threat vulnerability management, cyber risk management, data protection and classification, network security, access control, incident response, security awareness, employee training and asset management. These policies and related standards require identification of all Information Technology (IT) and Operational Technology (OT) critical facilities and/or cyber assets, and sufficient controls for IT and OT asset inventory, including responsibilities for assets, information owners, and asset disposition processes. From a security perspective, TEC’s Information Security group is directed at protecting all aspects of data and how information is stored, transmitted, processed, and used in business processes. TEC’s Corporate Security group is responsible for protecting physical assets including critical facilities, protection of employees, and related physical security risks.

TEC’s Information Security group of the Information Technology department has the direct responsibility for developing, monitoring, and enforcing information security standards and procedures; reviewing and approving all network interconnections for compliance to security standards; and assisting, consulting, and training individuals throughout TEC in the use of appropriate information security practices. This group is responsible for ensuring that all IT and OT cyber systems, assets, and networks are aligned with Emera and affiliate cybersecurity framework. TEC engages independent third party consultants from time to time to assess the adequacy of its cybersecurity measures and assist in implementing any appropriate actions to address any vulnerabilities identified. In addition, TEC participates in an Electric Power Research Institute (EPRI) research project to develop cybersecurity performance metrics. EPRI offers a web-based platform, which supports automated cybersecurity data collection, security metrics calculation, visualization, and analysis. The Vice President of Information Technology and Chief Information Officer (CIO), who reports to the President and Chief Executive Officer, oversees this group and is responsible for managing the program, in collaboration with TEC’s businesses and functions. TEC’s CIO has advanced degrees in computer science and extensive experience in cybersecurity and information technology, including many years of experience at large organizations leading cybersecurity, IT processes and controls, strategy, architecture, delivery and support of IT applications, and overseeing large groups of employees and contractors responsible for carrying out these responsibilities.

TEC’s Vendor Risk Management process includes conducting risk assessments to identify and monitor cybersecurity risks associated with third-party service providers, including threat detection and security event notifications. TEC also has requirements for third-party service providers which include regulatory compliance and meeting the National Institute of Standards and Technology Cybersecurity Framework policy and standards. TEC’s processes also provide for mitigating cybersecurity risk from third parties through seeking to include in its agreements with third-party service providers, as applicable, cybersecurity provisions designed to appropriately address such risks.

TEC’s IT Business Continuity – Emergency Contingency Response Plan is updated periodically and reviewed at least annually. This plan includes guidelines for the escalation and communication of cybersecurity incidents, including a requirement to timely report to TEC’s executive leadership and Board of Directors based on an assessment of the risk and other specified criteria. TEC has established a cyber incident response team to prepare for, mitigate, and remediate cybersecurity incidents, which is integrated within Emera’s enterprise crisis management framework.

Cybersecurity risks are integrated into TEC’s overall risk management process through the collaboration of the cybersecurity professionals and TEC’s and Emera’s risk management functions to assess threat levels on an affiliate and corporate basis and identify steps and resources appropriate to manage such risks. The Board of Directors oversees the management of risks from cybersecurity threats through receiving regular reports from the CIO, which include updates on TEC’s performance with preparing, preventing, detecting, responding to, mitigating, and recovering from cybersecurity incidents. Should a cybersecurity threat or incident pose a significant risk to TEC, TEC's processes provide that the CIO, through the CEO, as appropriate, would promptly inform the Board regarding any such threat or incident. The CIO also provides regular updates on the key elements of its cybersecurity program to the Emera Board’s Risk and Sustainability Committee, which has oversight over Emera’s enterprise risk management framework, including oversight over cybersecurity risk.

While to date TEC has not detected a significant compromise of its cybersecurity systems, significant data loss or any material financial losses related to cybersecurity attacks, it is possible that TEC could experience a significant event in the future. Risks and exposures related to cybersecurity attacks are expected to remain high for the foreseeable future due to the rapidly evolving nature and sophistication of these threats. See Item 1A. Risk Factors, “TEC is exposed to potential risks related to cyberattacks and unauthorized access, which could cause system failures, disrupt operations or adversely affect safety” for a further discussion of risks related to cybersecurity.

Item 2. PROPERTIES

TEC believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric are subject to a first mortgage bond indenture under which no bonds are currently outstanding.

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Tampa Electric has electric generating stations in service, with a December 2023 net winter generating capability of 6,433 MWs. Tampa Electric assets include the Big Bend Power Station (1,623 MWs capacity), the Bayside Power Station (2,138 capacity) and the Polk Power Station (1,420 MWs capacity). Also included in Tampa Electric’s assets as of December 31, 2023 are twenty-five solar arrays (1,252 MWs).

Tampa Electric owns 72 transmission substations and 138 distribution substations with an aggregate transformer capacity of 16,823 mega volts amps. The Tampa Electric system has an 7,865 mega volts amps of generator step up unit capacity. The transmission system consists of 1,362 total circuit miles of high voltage transmission lines, including underground and double-circuit lines. The distribution system consists of 6,137 circuit miles of overhead lines and 6,476 circuit miles of underground lines. As of December 31, 2023, there were 853,555 meters in service. All of this property is located in Florida.

Tampa Electric’s property, plant and equipment are owned, except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances common to properties of the size and character of those of Tampa Electric.

Tampa Electric has easements or other property rights for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. Transmission and distribution lines located in public ways are maintained under franchises or permits.

Tampa Electric has a long-term lease for the office building in downtown Tampa, which serves as headquarters for TECO Energy, Tampa Electric and PGS.

Item 3. 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 2023 Annual TEC Consolidated Financial Statements.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of TEC’s common stock is owned by TECO Energy, which in turn is owned by a subsidiary of Emera and, thus, is not listed on a stock exchange. Therefore, there is no market for such stock.

Item 6. [RESERVED]

Item 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS

OVERVIEW

At December 31, 2023, Tampa Electric served approximately 840,000 customers in a 2,000-square-mile service area in West Central Florida and had electric generating plants with a winter peak generating capacity of 6,433 MW.

Prior to January 1, 2023, TEC had regulated electric and gas utility operations in Florida. From and after January 1, 2023, the gas utility operations are operated by PGSI, which is no longer a subsidiary of TEC. See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC. For information regarding PGS in 2022 and 2021, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of TEC’s Annual Report on Form 10-K for the year ended December 31, 2022.

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TEC is a wholly owned subsidiary of TECO Energy, and TECO Energy is a wholly owned subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera. See Note 10 to the 2023 Annual TEC Consolidated Financial Statements for information regarding related party transactions.

2023 PERFORMANCE

All amounts included in this MD&A are pre-tax, except net income and income taxes.

In 2023, TEC’s net income was $466 million, compared with $540 million in 2022. 2023 net income decreased compared to 2022 primarily due to the separation of PGS from TEC on January 1, 2023 (see section below for further information on the separation). See Operating Company Results below for detail on the results of operations at Tampa Electric during 2023 compared to 2022. For information regarding 2022 results as compared to 2021, including PGS results, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of TEC’s Annual Report on Form 10-K for the year ended December 31, 2022.

OUTLOOK

TEC’s earnings are most directly impacted by the allowed rate of return on equity and the capital structures approved by the FPSC, the prudent management of operating costs, the approved recovery of regulatory deferrals, weather and its impact on energy sales, and the timing and amount of capital expenditures.

Tampa Electric anticipates earning towards the lower end of the ROE range in 2024. Normalizing 2023 for weather, Tampa Electric sales volumes in 2024 are projected to be higher than in 2023 due to customer growth. Tampa Electric expects customer growth rates in 2024 to be comparable to 2023, reflective of the expected economic growth in Florida.

On August 16, 2023, Tampa Electric filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of Tampa Electric’s ROE adjustment, the increase of $22 million was approved by the FPSC and the order reflecting such approval was issued on November 17, 2023, effective in January 2024.

On February 1, 2024, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting a revenue requirement increase of approximately $290 to $320 million, effective in January 2025, and additional adjustments of approximately $100 million and $70 million for 2026 and 2027, respectively. Tampa Electric’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until Tampa Electric completes its analysis and files the case in April 2024. The FPSC will hear the case in the third quarter of 2024 with a decision expected by the end of 2024.

On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the previously approved storm reserve level of $56 million, for a total of $131 million. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and TEC began applying the surcharge on April 2023 bills. Subsequently, on November 9, 2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $134 million. It also changed the collection of the expected remaining balance of $29 million as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC and issuance of an order by the FPSC is expected by the third quarter of 2024. In September 2023, Tampa Electric was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million, which were charged to the storm reserve regulatory asset and not included in the petition above. Tampa Electric will determine the timing of the request for recovery of Hurricane Idalia costs at a future time.

On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under-recovery of $518 million over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, and were effective beginning on April 1, 2023.

Tampa Electric has a capital investment program that supports achieving its goal to reduce CO2 emissions to 60% of 2000 levels by 2025. Since 2000, Tampa Electric has reduced its CO2 emissions by more than 50%.

In 2024, Tampa Electric expects to invest approximately $1.3 billion, excluding AFUDC, in capital projects. Capital projects include solar investments, storm hardening investments, grid modernization and building resilience. See Capital Investments below for further information.

These forecasts are based on our current assumptions described in the operating company discussion, which are subject to risks and uncertainties (see the Risk Factors section).

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OPERATING RESULTS

TEC’s consolidated financial statements have been prepared in accordance with U.S. GAAP. TEC's reported operating results are affected by several critical accounting estimates (see the Critical Accounting Policies and Estimates section).

The following table shows the revenues and net income of the business segments on a U.S. GAAP basis (see Note 11 to the 2023 Annual TEC Consolidated Financial Statements).

(millions)		2023		2022			2021
Revenues
	Tampa Electric	$	2,637	$	2,523		$	2,174
	PGS				656			528
	Eliminations				(10	)		(7	)
	TEC	$	2,637	$	3,169		$	2,695
Net income
	Tampa Electric	$	466	$	458		$	369
	PGS				82			77
	TEC	$	466	$	540		$	446

TAMPA ELECTRIC

Electric Operations Results

Tampa Electric’s net income in 2023 was $466 million, compared with $458 million in 2022. Results primarily reflected higher revenues resulting from the 2021 rate case settlement agreement and customer growth, partially offset by higher interest expense and higher depreciation expense. 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. See the Operating Revenues and Operating Expenses sections below for additional information.

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The table below provides a summary of Tampa Electric’s revenue and expenses and energy sales by customer type.

Summary of Operating Results

(millions, except customers and total degree days)	2023		% Change			2022		% Change			2021
Revenues	$	2,637		5		$	2,523		16		$	2,174
O&M expense		595		30			459		10			416
Depreciation and amortization expense		422		8			389		4			374
Taxes, other than income		234		16			201		11			181
Non-fuel operating expenses		1,251		19			1,049		8			971
Fuel expense		605		(11	)		681		12			607
Purchased power expense		78		(48	)		151		42			106
Total fuel & purchased power expense		683		(18	)		832		17			713
Total operating expenses		1,934		3			1,881		12			1,684
Operating income		703		10			642		31			490
Other income		89		71			52		13			46
Interest charges		239		68			142		29			110
Provision for income taxes		87		(7	)		94		65			57
Net income	$	466		2		$	458		24		$	369
Megawatt-Hour Sales (thousands)
Residential		10,307		2			10,109		2			9,941
Commercial		6,462		3			6,300		3			6,144
Industrial		2,082		(1	)		2,111		(1	)		2,122
Other		1,940		(0	)		1,947		3			1,886
Total retail		20,791		2			20,467		2			20,093
Off system sales		254		(37	)		405		255			114
Total energy sold		21,045		1			20,872		3			20,207
Retail customers—(thousands)
At December 31		840		2			827		2			811
Retail net energy for load		21,767		1			21,572		3			21,033
Total degree days		4,671		(3	)		4,820		6			4,565

Operating Revenues

Revenues were $114 million higher in 2023 than in 2022 primarily driven by higher base revenues due to new base rates as a result of the 2021 rate case settlement agreement and customer growth and storm surcharge revenue, partially offset by changes in fuel recovery clause revenue and less favorable weather compared to the same period in 2022. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in 2023 were 7% above normal (a 20-year statistical degree day average) and 3% below 2022, reflecting less favorable weather in 2023 compared to 2022. Total net energy for load, which is a calendar measurement of energy output, in 2023 was 1% higher compared to 2022.

Customer and Energy Sales Growth Outlook

The Tampa labor market (as measured by employment levels) continues to outperform the U.S. labor markets. The Tampa area unemployment rate was 2.8% in both 2023 and 2022. Florida’s unemployment rate decreased slightly to 2.8% in 2023 from 2.9% in 2022 and the U.S. rate also decreased slightly from 3.7% to 3.6%. Population growth in the area is forecasted to continue to be a major driver of customer growth. In 2024, retail energy sales volumes are expected to be similar to 2023 levels. In 2023, energy sales benefited from weather that was warmer than normal. Normalizing 2023 for weather, 2024 energy sales volumes are expected to be above 2023 levels due to customer growth. Tampa Electric expects 2024 customer growth to be approximately 1.7% and to continue at that level annually over the next few years.

Operating Expenses

In 2023, operations and maintenance expense was $136 million higher than in 2022 due to storm restoration cost recognition of $107 million related to storm surcharge revenue, increased expenses related to clauses and regulatory deferrals of $20 million, and increased operational expenses of $9 million. The increase in operating expenses was primarily due to higher transmission and distribution expense, generation maintenance, bad debt expense and customer support costs. Depreciation and amortization expense increased $33 million in 2023 compared to 2022 as a result of additions to facilities and the in-service of generation projects.

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O&M expense in 2024 is expected to increase compared to 2023 due to inflation. In 2024, depreciation expense is expected to increase compared to 2023 due to solar projects and other plant additions.

Fuel Expense, Purchased Power and Fuel Cost Recovery

Total fuel expense decreased in 2023 from 2022 primarily due to lower natural gas prices. Delivered natural gas prices increased approximately 70% in 2022 due to market forces affected by global events. Total 2024 fuel and purchased power costs are expected to be less than in 2023 due to decreased prices for natural gas.

In January 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million beginning April 1, 2022 through December 2022 due to an increase in fuel commodity and capacity costs. On March 1, 2022, the FPSC voted to approve the mid-course adjustment, and the order reflecting such approval was issued on March 18, 2022.

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the $518 million final 2022 fuel under-recovery over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, effective April 1, 2023.

In November 2023, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental, conservation and storm protection plan costs for 2024. The rates include the expected cost for natural gas and coal in 2024. These rates are typically set annually, based on information provided in September of the year prior to the year the rates take effect.

OTHER ITEMS IMPACTING NET INCOME

Other Income

For the years 2023 and 2022, TEC’s other income was $89 million and $55 million, respectively, which included AFUDC-equity of $19 million and $35 million, respectively, interest income from affiliate of $38 million and $0, respectively, and other income of $32 million and $20 million, respectively. The decrease in AFUDC-equity was primarily due to the in-service timing of Tampa Electric’s modernization of its Big Bend Power Station. The interest income from affiliate is related to the note receivable from PGS for PGS's allocation of short-term and long-term debt resulting from the separation of PGS from TEC as of January 1, 2023. See Notes 1 and 10 to the TEC Consolidated Financial Statements for details of the separation of PGS from TEC and the resulting related party transactions. The increase in Other Income is primarily due to interest income on the deferred fuel balance.

AFUDC-equity is expected to decrease in 2024 due to the timing of construction of capital projects, including solar generation and grid modernization. Interest income from affiliate is expected to decrease in 2024, primarily due to the repayment of the receivable from PGS on December 20, 2023.

Interest Expense

For the years 2023 and 2022, TEC’s interest expense, including interest expense to affiliates and excluding AFUDC-debt, was $245 million and $178 million, respectively. The increase in 2023 was due to higher interest rates and higher borrowings to support TEC’s ongoing capital investment program and ongoing operations. The weighted-average interest rate on borrowings outstanding under the credit facilities and commercial paper at December 31, 2023 and 2022 was 5.7% and 5.0%, respectively. See Other Income above for information regarding the interest income from affiliate associated with PGS's allocation of short-term and long-term debt resulting from the separation of PGS from TEC as of January 1, 2023. The interest income from affiliate partially offsets the impact of TEC's interest expense within Net Income on the Consolidated Statement of Income.

Interest expense is expected to decrease in 2024, reflecting lower balances due to Tampa Electric’s repayment of certain short-term borrowings in December 2023 (see Note 6 to the 2023 Annual TEC Consolidated Financial Statements for further detail).

Income Taxes

The provision for income taxes decreased in 2023 compared to 2022 primarily as a result of lower pre-tax income due to PGS’s separation from TEC on January 1, 2023 and production tax credits related to solar facilities. Income tax expense as a percentage of income before taxes was 15.7% in 2023 and 18.3% in 2022. TEC expects the 2024 annual effective tax rate to be approximately 11% due to increased production tax credit benefits.

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 TECO Energy’s and EUSHI’s respective tax sharing agreements. The cash payments for federal income taxes and state income taxes made under those tax sharing agreements totaled $102 million and $2 million in 2023 and 2022, respectively.

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For more information on TEC's income taxes, including a reconciliation between the statutory federal income tax rate, the effective tax rate and impacts of tax reform, see Note 4 to the 2023 Annual TEC Consolidated Financial Statements.

LIQUIDITY, CAPITAL RESOURCES

Balances as of December 31, 2023

(millions)
Credit facilities/ commercial paper / intercompany advances (1)	$	1,200
Drawn amounts/LCs		707
Available credit facilities		493
Cash		5
Total liquidity	$	498

(1)See Note 6 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the credit facilities.

Cash from Operating Activities

Cash flows from operating activities in 2023 were $1,241 million, an increase of $730 million compared to 2022. Increases to cash from operations were primarily the result of higher fuel revenues coupled with lower natural gas prices, partially offset by the timing of invoice payments.

Cash from Investing Activities

Cash flows from investing activities in 2023 resulted in a net use of cash of $1.3 billion, which primarily reflects TEC’s investment in capital. See the Capital Investments section for additional information.

Cash from Financing Activities

Cash flows from financing activities in 2023 resulted in net cash inflows of $48 million. TEC received $956 million from the repayment of a note receivable from PGS, $300 million of equity contributions from Parent, $400 million proceeds from short-term credit agreements greater than 90 days, and $87 million increase in short-term debt with maturities of less than 90 days. These increases in cash flows were partially offset by the repayment of short-term credit agreements greater than 90 days of $800 million, dividend payments to Parent of $472 million, advances to affiliate of $227 million, and the repayment of a note payable to Parent of $195 million.

Cash and Liquidity Outlook

TEC’s tariff-based gross margins are the principal source of cash from operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides TEC with a reasonably predictable source of cash. In addition to using cash generated from operating activities, TEC uses available cash, equity contributions from Parent, credit facility and commercial paper borrowings, intercompany activity, and debt issuances to support normal operations and capital expenditure requirements. TEC may reduce short-term borrowings with cash from operations, long-term borrowings, or capital contributions from Parent. TEC expects to make significant capital expenditures in 2024 (see Capital Investments section below for further detail on TEC’s projected capital expenditures). Debt raised is subject to applicable regulatory approvals and Tampa Electric is required to maintain a capital structure as allowed by the regulator.

As noted earlier, cash from operating activities and short-term borrowings are used to fund normal operations and capital expenditures, which may result in periodic working capital deficits. The working capital deficit as of December 31, 2023 was primarily caused by short-term borrowings and periodic fluctuations in assets and liabilities related to FPSC clauses and riders. At December 31, 2023, TEC’s unused capacity under its credit facilities was $493 million.

TEC has credit facilities and commercial paper that provide $1,200 million of credit, including $400 million maturing in 2024 and $800 million maturing in 2026. See Note 6 to the 2023 Annual TEC Consolidated Financial Statements for additional information regarding the credit facilities and commercial paper. TEC expects that its liquidity will be adequate for both the near and long term, given its expected operating cash flows, capital expenditures and related financing plans.

TEC expects cash from operations in 2024 to be lower than in 2023 primarily due to lower cash inflows from fuel recovery and lower storm surcharge revenue, partially offset by an increase in base rates effective in January 2024 (as stipulated in the 2021

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settlement agreement), lower interest expense payments, and customer growth (see Note 3 to the 2023 Annual TEC Consolidated Financial Statements). TEC plans to use cash in 2024 to fund capital spending and to pay dividends to its shareholder. Dividends are paid at the discretion of TEC’s Board of Directors.

TEC’s credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). TEC estimates that it could fully utilize the total available capacity under its facilities in 2024 and remain within the covenant restrictions.

Short-Term Borrowings

TEC had the following credit facilities and related borrowings as of December 31, 2023 and 2022.

	December 31, 2023								December 31, 2022
			Borrowings		Borrowings		Letters of				Borrowings		Borrowings		Letters of
	Credit		Outstanding -		Outstanding -		Credit		Credit		Outstanding -		Outstanding -		Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding
5-year facility (2)	$	800	$	0	$	706	$	1	$	800	$	0	$	619	$	1
1-year term facility (3)	0		0			0	0			400		400		0	0
1-year term facility (4)		200	0		0		0		0		0		0		0
1-year term facility (5)		200	0		0		0		0		0		0		0
Total	$	1,200	$	0	$	706	$	1	$	1,200	$	400	$	619	$	1

(1)Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets.

(2)This 5-year facility matures December 17, 2026. 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. On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029. TEC used the net proceeds from this offering for the repayment of a portion of the borrowings outstanding under the TEC 5-year credit facility. Therefore, $497 million of borrowings outstanding under the TEC 5-year credit facility were reclassified as long-term debt on the Consolidated Balance Sheet as of December 31, 2023.

(3)This 1-year term facility was set to mature on December 16, 2022. On December 13, 2022, TEC extended the maturity date to December 13, 2023, at which time the facility terminated.

(4)On March 1, 2023, TEC entered into a 1-year term facility that matures on February 28, 2024.

(5)On April 3, 2023, TEC entered into a 1-year term facility that matures on April 1, 2024.

At December 31, 2023, these credit facilities 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 December 31, 2023 and 2022 was 5.7% and 5.0%, respectively. For a complete description of the credit facilities see Note 6 to the 2023 Annual TEC Consolidated Financial Statements.

	Maximum		Minimum		Average		Average
	drawn		drawn		drawn		interest
(millions)	amount		amount		amount		rate
2023 credit facility utilization	$	1,457	$	608	$	1,133		5.62	%

Significant Financial Covenants

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 December 31, 2023, TEC was in compliance with all applicable financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at December 31, 2023. Reference is made to the specific agreements and instruments for more details.

			Calculation
Instrument	Financial Covenant (1)	Requirement/Restriction	at December 31, 2023
Credit facility- $800 million (2)	Debt/capital	Cannot exceed 65%	48.5%
Term facility - $200 million (2)	Debt/capital	Cannot exceed 65%	48.5%
Term facility - $200 million (2)	Debt/capital	Cannot exceed 65%	48.5%

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(1)As defined in each applicable instrument.

(2)See Note 6 to the 2023 Annual TEC Consolidated Financial Statements for a description of the credit facilities.

Credit Ratings

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

S&P, Moody’s and Fitch describe credit ratings in the A3 or A category as having a strong capacity to meet its financial commitments. Ratings in the BBB or Baa category are described as representing adequate capacity for payment of financial obligations. The lowest investment grade credit rating for S&P is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus, the three credit rating agencies assign TEC’s senior unsecured debt investment-grade credit ratings.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. TEC’s access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of its securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings.

Summary of Contractual Obligations

The following table lists the contractual obligations of TEC, including cash payments to repay long-term debt, interest payments, lease payments and unconditional commitments related to capital expenditures.

Contractual Cash Obligations at December 31, 2023

	Payments Due by Period
(millions)	Total		2024		2025		2026		2027		2028		After 2028
Long-term debt (1)	$	4,275	$	300	$	0	$	0	$	0	$	0	$	3,975
Interest payment obligations(2)		3,239		173		173		174		174		174		2,371
Transportation(3)		1,443		135		128		125		125		97		833
Pension plan(4)		22		0		0		7		13		2		0
Capital projects(5)		668		533		81		53		1		0		0
Fuel and gas supply		276		194		60		17		4		1		0
Purchased power		4		4		0		0		0		0		0
Long-term service agreements(6)		151		34		22		23		22		17		33
Operating leases		84		3		3		1		1		1		75
Demand side management		12		5		5		1		1		0		0
Total contractual obligations	$	10,174	$	1,381	$	472	$	401	$	341	$	292	$	7,287

(1)See the Consolidated Statements of Capitalization and Note 7 to the 2023 Annual TEC Consolidated Financial Statements for a list of long-term debt and the respective due dates.

(2)Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2023.

(3)These payment obligations under contractual agreements are recovered from customers under regulatory clauses approved by the FPSC (see the Business section).

(4)Under calculation requirements of the Pension Protection Act, as of the January 1, 2023 measurement date, the pension plan was fully funded. Under ERISA guidelines, TEC is not required to make additional cash contributions until 2026; however, TEC may elect to make discretionary cash contributions prior to that time. Future contributions are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by investment portfolio performance, and other factors (see Liquidity, Capital Resources section and Note 5 to the 2023 Annual TEC Consolidated Financial Statements).

(5)Represents outstanding commitments for major capital projects (see the Capital Investments section).

(6)Represents outstanding commitments for service, including long-term capitalized maintenance agreements for Tampa Electric’s CTs.

See Notes 3, 4, 5 and 12 to the 2023 Annual TEC Consolidated Financial Statements for information regarding additional obligations related to regulatory liabilities, taxes, employee postretirement benefits and asset retirement obligations.

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Off-Balance Sheet Arrangements and Contingent Obligations

TEC does not have any material off-balance sheet arrangements or contingent obligations not otherwise included in our Consolidated Financial Statements as of December 31, 2023.

Capital Investments

(millions)	Actual 2023			Forecasted 2024
Tampa Electric (1)
Renewable generation	$	246		$	200
Transmission		98			90
Distribution		416			375
Generation		248			195
Facilities, equipment, vehicles and other		300			410
Tampa Electric total		1,308			1,270
Net cash effect of accruals, retentions and AFUDC		(14	)
Total	$	1,294		$	1,270

(1)Individual line items exclude AFUDC-debt and equity.

Tampa Electric invested approximately $850 million in solar projects during 2017 to 2021 (solar wave I). On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million in an additional 600 MW of new utility-scale solar photovoltaic projects, which were completed at the end of 2023 (solar wave II). In addition, Tampa Electric intends to invest approximately $590 million in an additional 375 MW of new utility-scale solar photovoltaic projects in 2024 through 2026 (solar wave III) and approximately $812 million in 470 MW of new utility-scale solar photovoltaic projects in 2026 through 2028 (solar wave IV). In 2024 through 2026, Tampa Electric expects to spend approximately $600 million in capital for the storm protection plan, $535 million in grid modernization, $350 million in its new corporate headquarters and operations center for building resilience, and $154 million for 115 MW of energy storage. AFUDC will be earned on eligible capital projects during the construction periods and return on investment will be earned on capital projects running through certain recovery mechanisms.

Tampa Electric’s 2023 capital expenditures included solar generation projects, storm hardening for the transmission and distribution systems, new technology for distribution system grid modernization, energy storage, maintenance and refurbishment of existing generating facilities, and the construction of new headquarters and operations center to improve building resilience. In 2024, Tampa Electric expects capital expenditures to include solar generation and energy storage projects, a generation capacity expansion project to improve system resilience, a new headquarters and operations center to improve building resilience, storm hardening for the transmission and distribution systems, new technology for distribution system grid modernization, and the maintenance and refurbishment of existing generating facilities.

The forecasted capital expenditures shown above are based on current estimates and assumptions. Actual capital expenditures could vary materially from these estimates due to changes in and timing of projects and changes in costs for materials or labor (see the Risk Factors section).

Capital Structure

At December 31, 2023, TEC’s year-end capital structure was 48% debt and 52% common equity. At December 31, 2022, TEC’s year-end capital structure was 47% debt and 53% common equity.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities and disclosures. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for a description of TEC’s significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.

Regulatory Accounting

Tampa Electric’s and PGS’s retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. As a result, Tampa Electric and PGS qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between U.S. GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.

TEC regularly assesses the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities will continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered.

TEC’s most significant regulatory liability relates to non-ARO costs of removal and regulatory tax liability. The non-ARO costs of removal represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment upon retirement. TEC accrues for removal costs over the life of the related assets based on depreciation studies approved by the FPSC. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. The regulatory tax liability is the offset to the adjustment to the deferred tax liability remeasured as a result of tax reform. See Note 4 to the 2023 Annual TEC Consolidated Financial Statements for further information.

The application of regulatory accounting guidance is a critical accounting policy and estimate since a difference in these assumptions and actual results may result in a material impact on reported assets and the results of operations (see Note 3 to the 2023 Annual TEC Consolidated Financial Statements).

Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, TEC estimates the current tax exposure and assesses the temporary differences resulting from differing treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes measured at enacted rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or the entire deferred tax asset will not be realized. If TEC determines that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized. At December 31, 2023, TEC does not have a valuation allowance. At December 31, 2023, TEC had a net deferred income tax liability of $880 million, attributable primarily to property-related items.

See further discussion of uncertainty in income taxes, impacts of tax reform and other tax items in Note 4 to the 2023 Annual TEC Consolidated Financial Statements.

Employee Postretirement Benefits

TEC is a participant in the retirement plans of TECO Energy. TECO Energy sponsors a defined benefit pension plan (pension plan), a fully-funded non-qualified, non-contributory supplemental executive retirement benefit plan available to certain members of senior management and an unfunded non-qualified, non-contributory Restoration Plan that allows certain members of senior management to receive an additional benefit to restore what is limited by the IRS under the pension plan. TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. The accounting related to employee postretirement benefits is a critical accounting estimate for TEC for the following

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reasons: 1) a change in the estimated benefit obligation could have a material impact on reported assets, liabilities and results of operations; and 2) changes in assumptions could change the annual pension funding requirements, which could have a significant impact on TEC’s annual cash requirements.

Several statistical and other factors which attempt to anticipate future events are used in calculating the expenses and liabilities related to these plans. Key factors include assumptions about the expected rates of return on plan assets, discount rates and mortality rates. TECO Energy determines these factors within certain guidelines and with the help of external consultants. TECO Energy considers market conditions, including but not limited to, changes in investment returns and interest rates, in making these assumptions.

Pension plan assets (plan assets) are invested in a mix of equity and fixed-income securities. The expected return on asset assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with the company’s portfolio, with provision for active management and expenses paid from the trust that holds the plan assets. The expected return on assets was 7.05%, 6.50% and 6.70% as of January 1, 2023, 2022 and 2021, respectively. Given recent capital market returns and market expectations for long-term interest rates, TECO Energy expects the expected return on assets to be 7.05% for 2024 (based on actuarial 20-year expected market returns). Actual returns in 2023 were 14.7%.

The discount rate assumption used to measure benefit expense was an above-mean yield curve. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year.

Holding all other assumptions constant, a 1% decrease in the assumed rate of return on pension plan assets or the discount rate assumption would have had in 2023 and is anticipated to have in 2024 the following impact on TEC’s after-tax pension cost:

Year	1% Decrease in Assumed Expected Return on Assets	1% Decrease in Assumed Discount Rate
2023	$5 million increase	$1 million increase
2024	$6 million increase	$1 million increase

Unrecognized actuarial gains and losses for the pension plan are being recognized over a period of approximately 11 years, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with applicable accounting guidance for pensions.

The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under the applicable accounting guidance, include the assumed discount rate and the assumed rate of increases in future health care costs. TECO Energy determines the discount rate for the OPEB’s projected benefit cash flows. In estimating the health care cost trend rate, TECO Energy considers its actual health care cost experience, future benefit structures, industry trends, and advice from our outside actuaries.

See the discussion of employee postretirement benefits in Note 5 to the 2023 Annual TEC Consolidated Financial Statements.

RECENTLY ISSUED ACCOUNTING STANDARDS

Change in Accounting Policy

TEC considers the applicability and impact of all ASUs issued by the FASB. TEC was not required to and did not adopt any new ASUs in 2023. The following update has been issued by FASB, but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements.

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Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. TEC is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (benefit) in accordance with U.S. Securities and Exchange Commission (SEC) Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024, and interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. TEC is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

ENVIRONMENTAL COMPLIANCE

Environmental Matters

TEC has significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters.

Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT) Mercury Air Toxics Standards (MATS)

On June 29, 2015, the U.S. Supreme Court remanded the EPA’s Mercury Air Toxics Standards (MATS) to the D.C. Circuit Court of Appeals for failing to properly consider the cost of compliance. The litigation is currently in abeyance while the EPA reconsiders its action. MATS remain in effect until the D.C. Circuit Court of Appeals acts.

All of Tampa Electric’s conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and selective catalytic reductions, and the Polk Unit 1 integrated gasification combined-cycle unit emissions are minimized in the gasification process. Therefore, Tampa Electric has minimized the impact of this rule and has demonstrated compliance on all applicable units with the most stringent “Low Emitting Electric Generating Unit” classification for MATS with nominal additional capital investment.

Carbon Reductions and GHG

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 2000, Tampa Electric has reduced its system-wide emissions of CO2 by more than 50%, bringing emissions to below 1990 levels. Tampa Electric CO2 emissions continue to remain below 1990 levels. In addition to the emission decreases in 2005 as the result of the repowering of two Gannon Station coal units to natural gas and the shut-down of the remaining Gannon Station coal-fired units, Tampa Electric has optimized its existing coal units to operate on natural gas. During this same time frame, the number of retail customers and retail energy sales have risen. Tampa Electric also substantially reduced CO2 emissions by significantly expanding the use of solar power, repowering Big Bend Unit 1 steam turbine, and retiring Big Bend Unit 2. The Big Bend Unit 1 modernization project is capable of producing 1,090 megawatts of power and will continue to lead to lower system-wide emissions. See Capital Investments above for information regarding Tampa Electric’s solar projects. Tampa Electric has a long-term goal to reduce CO2 emissions to 80% of 2000 levels by 2040 and aspires to reach a net zero future by 2050.

On June 19, 2019, the EPA released a final rule, named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing coal-fired electric generating units. On January 19, 2021, the D.C. Circuit Court of Appeals vacated the ACE rule and remanded it to the EPA. On May 8, 2023, the EPA released a proposed rule establishing CO2 emission standards for new and existing fossil fuel-fired power plants. As proposed under Section 111 of the Clean

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Air Act, the New Source Performance Standards and Best System of Emission Reduction guidelines would require affected electric generating units to achieve CO2 emission limits thorough the implementation of carbon capture and sequestration, or low-GHG hydrogen co-firing. The proposed rule also repeals the ACE rule promulgated under the Trump Administration. TEC expects one or more units to be subject to the rule, if finalized in its current form.

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding. TEC has been awarded funding from the U.S. Department of Energy to evaluate technologies required to comply during 2023 through 2025. In addition, TEC expects tax credits under the Inflation Reduction Act related to these technologies to be an important offset to the cost of compliance.

Ozone

On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone, originally adopted in 2012. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise it. The EPA has announced that the NAAQS is currently under review, which could result in revisions to the standard affecting compliance in Tampa Electric’s service territory. The impact of this potential new standard on the operations of Tampa Electric will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.

Water Supply and Quality

The EPA’s final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to Tampa Electric's Bayside and Big Bend Power Stations. Polk Power Station is not covered by this rule since it does not operate an intake on "waters of the United States". Tampa Electric has two ongoing projects (one for Bayside and one for Big Bend) that require compliance with the rule. Compliance includes the completion of the biological, technical, and financial study elements required by the rule. These study elements have been completed and submitted for Bayside and were used by FDEP to determine the necessity of cooling water system retrofits. FDEP agreed with Tampa Electric’s proposed plan for Bayside and Tampa Electric began a multi-year construction project to install new fish-friendly modified traveling screens and a fish return in 2022. Tampa Electric is negotiating an alternative schedule for Big Bend (as allowed by the rule) but completed a portion of the compliance requirements with the Big Bend modernization project with the installation of fish-friendly modified traveling screens and a fish return on modernized Unit 1. The remainder of the compliance requirements are to be determined and completed at a later date. The full impact of the new regulations on Tampa Electric will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by FDEP.

The final EPA rule for existing steam electric effluent limit guidelines (ELGs) became effective January 4, 2016 and establishes limits for wastewater discharges from flue gas desulfurization (FGD) processes, fly ash and bottom ash transport water, leachate from ponds and landfills containing coal combustion residuals, gasification processes, and flue gas mercury controls. The new guidelines are expected to be incorporated into National Pollutant Discharge Elimination System permit renewals for Big Bend Station (FGD wastewater and bottom ash transport water) and Polk Power Station (gasification wastewater) to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023. The EPA decided to extend the near-term deadlines for FGD wastewater and bottom ash transport water to as soon as possible after November 1, 2020. On November 22, 2019, the EPA published in the Federal Register its proposed updates to the ELGs, in which the EPA revised limits for both bottom ash transport water and FGD wastewater and extended the final compliance deadline by two years for FGD wastewater. The final rule with revised limits was published on October 13, 2020 and became effective December 14, 2020. Although a legal challenge to this rule is pending in the D.C. Circuit Court of Appeals, no stays are in effect. The EPA proposed a new rule in March 2023 to strengthen discharge limits that is expected to be finalized in 2024.

The preliminary draft of the NPDES Permit for Big Bend stated that effluent limitations for total recoverable arsenic, mercury, and selenium and total nitrate/nitrite for FGD wastewater are applicable no later than December 31, 2023. Big Bend completed construction of a deep injection well system in December 2023 for disposal of FGD wastewater, bottom ash transport water and other process wastewaters. Since Polk Power Station disposes of any gasification wastewater created down the deep injection well rather than discharging it to surface water, the effluent limitations do not apply to that power station.

EPA Waters of the US

In January 2020, the EPA and the U.S Army Corps of Engineers (Corps) finalized a rule, called the Navigable Waters Protection Rule (NWPR), to define “waters of the United States” and thereby establish federal regulatory authority under the Clean Water Act. This final rule became effective in June 2020. In November 2021, the EPA and the Corps announced a proposed rule which would re-establish the pre-2015 definition of “waters of the United States” updated “to reflect consideration of Supreme Court decisions". On January 18, 2023, the revised definition rule was published in the Federal Register and the rule took effect on March 20, 2023.

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On August 29, 2023, the EPA and Department of the Army (the agencies) announced a final rule amending the 2023 definition of “waters of the United States”. The amendments conform with the U.S. Supreme Court’s May 25, 2023 decision in the case of Sackett v. Environmental Protection Agency. The conforming rule became effective on September 8, 2023. The final rule is expected to have environmental permitting implications for new Tampa Electric solar sites and permitting renewals for existing facilities requiring approved jurisdictional determinations.

Superfund and Former Manufactured Gas Plant Sites

As of December 31, 2022, TEC, through its Tampa Electric division and former PGS division, was a PRP for certain superfund sites and, through its former PGS division, for certain former MGP sites. As a result of the separation of the PGS division, PGS is now the responsible party for those sites (in addition to third party PRPs for certain sites). See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC.

Coal Combustion Residuals Recycling and Regulation

Tampa Electric produces ash and other by-products, collectively known as CCRs at its Big Bend Power Station. Greater than 90% of all CCRs produced at this facility are marketed to customers for beneficial use in commercial and industrial products. The EPA’s final CCR rule became effective on October 19, 2015 and regulates CCRs as non-hazardous solid waste. In 2016 and 2017, the FPSC approved Environmental Cost Recovery for capital and O&M expenses associated with various projects proposed as part of Tampa Electric’s CCR compliance program. Subsequently, a closure by removal and liner retrofit project for the West Slag Dewatering Pond was completed in 2020 and closure by removal of all CCRs from the Economizer Ash and Pyrite Ponds was completed in October 2021. The final project required for compliance with the CCR Rule at Big Bend is the North Gypsum Stackout Area Drainage Improvements Project, which is scheduled for completion in 2024. FDEP has revised the existing state solid waste regulation to incorporate Florida CCR permit requirements for regulated units and these new requirements will operate in lieu of the Federal permitting program. However, TEC is largely exempt from the state permitting requirements because it completed its mandatory closure projects prior to the state rule’s passage. On May 18, 2023, the EPA proposed new rules requiring identification and regulation of Legacy CCR Management Units. This proposal appears to cover any landfill or impoundment in existence but not receiving CCRs as of the effective date of the 2015 rule and any CCR placed into the environment prior to the rule for beneficial use. TEC is a member of the Utility Solid Waste Activities Group, who filed comments on behalf of its members in July 2023 contesting many of the proposed rule’s provisions.

Conservation

In 2023, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial Demand Side Management (DSM) programs that enabled the company to meet all of its required annual DSM goals. Tampa Electric completed the second full year of operational testing the integrated renewable energy system that utilizes a large solar array integrated with battery storage and electric vehicle and large commercial vehicle battery charging systems. In 2023, Tampa Electric completed the program to convert its remaining high-pressure sodium and metal halide streetlights to LED technology. This conversion program converted 209,821 luminaires over the five-year program. Additionally, Tampa Electric has continued working on the development of the proposed DSM goals and supporting programs for the 2025-2034 period that will be filed with the FPSC in 2024.

In 2023, Tampa Electric achieved all of the residential and commercial annual energy and demand goals. To achieve these DSM goals, Tampa Electric offered 36 cost-effective DSM Programs. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause rate on the customer’s electric bill. Since their inception to January 1, 2023, Tampa Electric’s conservation programs have contributed to reducing the summer peak demand by 814 MWs and the winter peak demand by 1,332 MWs.

REGULATION

See Business - Tampa Electric – Electric Operations and Note 3 to the 2023 Annual TEC Consolidated Financial Statements for a description of base rates, cost-recovery clauses and competition.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management Infrastructure

TEC is subject to various types of market risk in the course of daily operations, as discussed below. TEC has adopted an enterprise-wide approach to the management and control of market and credit risk. Middle Office risk management functions, including credit risk management and risk control, are independent of each transacting entity (Front Office).

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TECO Energy’s Risk Management Policy (Policy) governs all energy transacting activity. The Policy is administered by a Risk Authorizing Committee (RAC) that is comprised of senior management. Within the bounds of the Policy, the RAC approves specific hedging strategies, new transaction types or products, limits, and transacting authorities. Transaction activity is reported daily and measured against limits. For all commodity risk management activities, derivative transaction volumes are limited to the anticipated volume for customer sales or supplier procurement activities.

TEC operates and oversees transaction activity related to interest rate risk exposures. Interest rate derivative transaction activity is directly correlated to borrowing activities.

Risk Management Objectives

The Front Office is responsible for reducing and mitigating the market risk exposures that arise from the ownership of physical assets and contractual obligations. The primary objectives of the risk management organization, the Middle Office, are to quantify, measure, and monitor the market risk exposures arising from the activities of the Front Office and the ownership of physical assets. In addition, the Middle Office is responsible for enforcing the limits and procedures established under the approved risk management policies. Based on the policies approved by TEC’s board of directors and the procedures established by the RAC, from time to time, TEC enters into futures, forwards, swaps and option contracts to limit the exposure to items, such as fuel supply risk and the risk of price fluctuations for physical purchases and sales of natural gas in the course of normal operations.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. The primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers.

On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which includes a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022. On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric related to its 2021 rate case that extended the moratorium to December 31, 2024 (see Note 3 to the 2023 Annual TEC Consolidated Financial Statements for further information on the settlement agreements). As of December 31, 2023 and 2022, TEC had no hedges in place.

Credit Risk

TEC has a rigorous process for the establishment of new trading counterparties and evaluation of current counterparties. This process includes an evaluation of each counterparty’s credit ratings, as applicable, and/or its financial statements, with attention paid to liquidity and capital resources; establishment of counterparty specific credit limits; optimization of credit terms; and execution of standardized enabling agreements. TEC manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all counterparties, and deposits or collateral are requested for counterparties that do not meet the creditworthiness requirements as set out in TEC's internal policies.

Certain of TEC’s derivative instruments, including NPNS agreements, contain provisions that require our debt to maintain an investment-grade credit rating from any or all of the major credit rating agencies. If TEC’s debt ratings were to fall below investment grade or not be rated, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.

Interest Rate Risk

TEC is exposed to changes in interest rates primarily from borrowing under the company's credit facilities and commercial paper program. A hypothetical 10% increase in TEC's weighted-average interest rate on its borrowings under the credit facilities and commercial paper outstanding at December 31, 2023 and 2022 would have resulted in a $6 million and $5 million impact on pre-tax earnings, respectively. This is driven by rising interest rates and higher outstanding balances. A hypothetical 10% increase in interest rates would have decreased the fair market value of TEC's long-term debt by 6.0% at December 31, 2023 and December 31, 2022. See the Financing Activity section and Notes 6 and 7 to the 2023 Annual TEC Consolidated Financial Statements. These amounts were determined based on the variable rate obligations existing on the indicated dates at TEC. The above sensitivities assume no changes to TEC’s current financial structure and could be affected by changes in TEC’s credit ratings, changes in general economic conditions or other external factors (see the Risk Factors section).

Commodity Risk

TEC faces varying degrees of exposure to commodity risks including natural gas, coal and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products

30

and services. Management uses different risk measurement and monitoring tools based on the degree of exposure of each operating company to commodity risks.

Regulated Utilities

Tampa Electric’s fuel costs used for generation are affected primarily by the price of natural gas and, to a lesser degree, the cost of coal. Tampa Electric’s use of natural gas, with its more volatile pricing, for generation of electricity was 88% in 2023 and 86% in 2022 (see the Business section).

Currently, TEC’s commodity price risks are largely mitigated by the fact that increases in the price of prudently incurred fuel and purchased power are recovered through FPSC-approved cost-recovery clauses, with no anticipated effect on earnings. However, increasing fuel cost-recovery has the potential to affect total energy usage and the relative attractiveness of electricity to consumers. TEC manages fuel supply risk and commodity price risk by entering into long-term fuel supply agreements and prudently operating plant facilities to optimize cost. At December 31, 2023 and 2022, a change in commodity prices would not have had a material impact on TEC's earnings but could have and has had an impact on the timing of the cash recovery of the cost of fuel.

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TAMPA ELECTRIC COMPANY

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Shareholder and the Board of Directors of Tampa Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Tampa Electric Company (the Company) as of December 31, 2023 and 2022, the related consolidated statements of income and comprehensive income, capitalization and cash flows for each of the three years in the period ended December 31, 2023 and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the Board of Directors and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the effects of regulatory matters

Description of the Matter

As disclosed in Note 3 of the consolidated financial statements, the Company has $988 million in regulatory assets and $795 million in regulatory liabilities. As disclosed in Note 3, Tampa Electric’s retail business is regulated by the Florida Public Service Commission (FPSC), and Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) (collectively, the regulators). The regulatory rates are designed to recover the prudently incurred costs of providing the regulated products or services and provide a reasonable return on the equity invested or assets, as applicable. In addition to regulatory assets and liabilities, rate regulation impacts multiple financial statement line items, including, but not limited to, property, plant and equipment, revenues, and expenses. Auditing the impact of rate regulation on the Company’s financial statements is complex and highly judgmental due to the significant judgments made by the Company to support its accounting and disclosure for regulatory matters when final regulatory decisions or orders have not yet been obtained or when regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of future regulatory decisions on

32

the financial statements. Although the Company expects to recover costs from customers through rates, there is a risk that the regulator may not approve full recovery of costs incurred. The Company’s judgments include making an assessment of the probable recovery of and return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund to customers through future rates.

How We Addressed the Matter in Our Audit

We performed audit procedures that included, among others, assessing the Company’s evaluation of the probability of future recovery for regulatory assets and refund of regulatory liabilities by obtaining and reviewing relevant regulatory orders, filings, testimony, hearings and correspondence, and other publicly available information. For regulatory matters for which regulatory decisions or orders have not yet been obtained, we inspected the regulatory filings for any evidence that might contradict the Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities within the same jurisdiction to assess the likelihood of recovery in future rates based on the regulator’s treatment of similar costs under similar circumstances. We obtained and evaluated an analysis from the Company and corroborated that analysis with letters from legal counsel, when appropriate, regarding cost recoveries or future changes in rates. We also assessed the methodology, accuracy and completeness of the Company’s calculations of regulatory asset and liability balances based on provisions and formulas outlined in rate orders and other correspondence with the regulators. We also evaluated the Company's disclosures related to the impacts of rate regulation.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2018.

Tampa, Florida

February 26, 2024

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TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets

Assets	December 31,			December 31,
(millions)	2023			2022
Property, plant and equipment
Utility plant
Electric	$	13,655		$	12,536
Gas		0			2,938
Utility plant, at original costs		13,655			15,474
Accumulated depreciation		(3,443	)		(3,845	)
Utility plant, net		10,212			11,629
Other property		16			15
Total property, plant and equipment, net		10,228			11,644
Current assets
Cash and cash equivalents		5			14
Receivables, less allowance for credit losses of $2 and $4 at December 31, 2023 and 2022, respectively		286			295
Due from affiliates		19			22
Inventories, at average cost
Fuel		36			23
Materials and supplies		181			159
Regulatory assets		161			361
Prepayments and other current assets		32			35
Total current assets		720			909
Other assets
Regulatory assets		827			1,191
Deferred charges and other assets		56			59
Total other assets		883			1,250
Total assets	$	11,831		$	13,803

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

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TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets—continued

Liabilities and Capital	December 31,			December 31,
(millions)	2023			2022
Capitalization
Common stock	$	4,505		$	5,075
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		219			346
Total capital		4,723			5,420
Long-term debt		3,933			3,734
Total capital		8,656			9,154
Current liabilities
Long-term debt due within one year		300			0
Notes payable		209			1,019
Accounts payable		354			472
Due to affiliates		10			226
Customer deposits		121			145
Regulatory liabilities		94			85
Accrued interest		28			30
Accrued taxes		14			15
Other		43			45
Total current liabilities		1,173			2,037
Other liabilities
Deferred income taxes		880			1,045
Regulatory liabilities		701			1,055
Investment tax credits		237			243
Deferred credits and other liabilities		184			269
Total other liabilities		2,002			2,612
Commitments and Contingencies (see Note 8)
Total liabilities and capital	$	11,831		$	13,803

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Income and Comprehensive Income

(millions)
For the years ended December 31,	2023			2022			2021
Revenues
Electric	$	2,637		$	2,519		$	2,170
Gas		0			650			525
Total revenues		2,637			3,169			2,695
Expenses
Fuel		605			676			604
Purchased power		78			151			106
Cost of natural gas sold		0			257			155
Operations & maintenance		595			619			566
Depreciation and amortization		422			436			430
Taxes, other than income		234			257			228
Total expenses		1,934			2,396			2,089
Income from operations		703			773			606
Other income
Allowance for other funds used during construction		19			35			45
Interest income from affiliates		38			0			0
Other income, net		32			20			5
Total other income		89			55			50
Interest charges
Interest expense		234			178			151
Interest expense to affiliates		11			0			0
Allowance for borrowed funds used during construction		(6	)		(11	)		(21	)
Total interest charges		239			167			130
Income before provision for income taxes		553			661			526
Provision for income taxes		87			121			80
Net income	$	466		$	540		$	446
Comprehensive income	$	466		$	540		$	446

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Cash Flows

(millions)
For the years ended December 31,	2023			2022			2021
Cash flows from or used in operating activities
Net income	$	466		$	540		$	446
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		422			436			430
Deferred income taxes and investment tax credits		(22	)		137			28
Allowance for equity funds used during construction		(19	)		(35	)		(45	)
Deferred recovery clauses		415			(422	)		(58	)
Regulatory assets and liabilities		116			(100	)		(10	)
Pension and post-retirement asset and liabilities		(23	)		(18	)		(10	)
Other		14			(1	)		23
Changes in working capital:
Receivables, less allowance for credit losses		(44	)		(45	)		(32	)
Inventories		(39	)		(41	)		(8	)
Taxes accrued		12			(23	)		(13	)
Accounts payable		(56	)		75			53
Other		(1	)		8			(7	)
Cash flows from operating activities		1,241			511			797
Cash flows from or used in investing activities
Capital expenditures		(1,294	)		(1,427	)		(1,397	)
Net proceeds from sale of assets		0			10			0
Cash flows used in investing activities		(1,294	)		(1,417	)		(1,397	)
Cash flows from or used in financing activities
Equity contributions from Parent		300			605			580
Dividends to Parent		(472	)		(517	)		(450	)
Proceeds from long-term debt issuance		0			595			790
Repayment of long-term debt		0			(250	)		(279	)
Advances to affiliate		(227	)		0			0
Repayment of advances to affiliate		956			0			0
Advances from Parent		0			195			0
Repayment of advances from Parent		(195	)		0			0
Net change in short-term debt (maturities of 90 days or less)		87			374			(230	)
Proceeds from other short-term debt (maturities over 90 days)		400			400			500
Repayment of other short-term debt (maturities over 90 days)		(800	)		(500	)		(300	)
Other financing activities		(1	)		0			(3	)
Cash flows from financing activities		48			902			608
Net increase (decrease) in cash and cash equivalents		(5	)		(4	)		8
Cash and cash equivalents at beginning of the year		10			18			10
Cash and cash equivalents at end of the year	$	5		$	14		$	18
Supplemental disclosure of cash paid (received):
Interest	$	233		$	152		$	120
Income taxes	$	102		$	2		$	62
Supplemental disclosure of non-cash activities:
Change in accrued capital expenditures	$	20		$	(6	)	$	25
Reclassification of short-term debt to long-term debt	$	497		$	0		$	0
Change in note receivable from PGS	$	(736	)	$	0		$	0

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization

									Accumulated
									Other
			Common			Retained			Comprehensive			Total
(millions, except share amounts)	Shares (1)		Stock			Earnings			Loss			Capital
Balance, December 31, 2020		10	$	3,890		$	327		$	(1	)	$	4,216
Net income							446						446
Equity contributions from Parent				580									580
Dividends to Parent (2)							(450	)					(450	)
Balance, December 31, 2021		10	$	4,470		$	323		$	(1	)	$	4,792
Net income							540						540
Equity contributions from Parent				605									605
Dividends to Parent (2)							(517	)					(517	)
Balance, December 31, 2022		10	$	5,075		$	346		$	(1	)	$	5,420
Net income							466						466
Separation of PGS equity from TEC				(871	)		(121	)					(992	)
Equity contributions from Parent				300									300
Dividends to Parent (2)							(472	)					(472	)
Other				1									1
Balance, December 31, 2023		10	$	4,505		$	219		$	(1	)	$	4,723

Preferred stock – $100 par value

1.5 million shares authorized, none outstanding.

Preferred stock – no par

2.5 million shares authorized, none outstanding.

Preference stock – no par, subordinate to the preferred stock

2.5 million shares authorized, none outstanding.

(1)Common stock without par value, 25 million shares authorized

(2)Dividends are declared and paid at the discretion of TEC’s Board of Directors.

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization – continued

At December 31, 2023 and 2022, TEC had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2023			2022
Tampa Electric	Notes (1)(2)(3) : 3.88%	2024	$	300		$	263
	2.40%	2031		400			285
	6.55%	2036		250			250
	6.15%	2037		250			190
	4.10%	2042		300			250
	4.35%	2044		300			290
	4.20%	2045		250			230
	4.30%	2048		350			275
	4.45%	2049		375			350
	3.63%	2050		300			275
	3.45%	2051		400			285
	5.00%	2052		300			262
	Total long-term debt of Tampa Electric			3,775			3,205
PGS	Notes (1)(2)(3) : 3.88%	2024	0				38
	2.40%	2031	0				115
	6.15%	2037	0				60
	4.10%	2042	0				50
	4.35%	2044	0				10
	4.20%	2045	0				20
	4.30%	2048	0				75
	4.45%	2049	0				25
	3.63%	2050	0				25
	3.45%	2051	0				115
	5.00%	2052	0				37
	Total allocated long-term debt of PGS			0			570
Long-term debt reclassification(4)				500		0
Total long-term debt				4,275			3,775
Unamortized debt discount, net				(14	)		(11	)
Debt issuance costs				(28	)		(30	)
Total carrying amount of long-term debt				4,233			3,734
Less amount due within one year				300		0
Total long-term debt			$	3,933		$	3,734

(1)These senior unsecured debt securities are subject to redemption in whole or in part, at any time, at the option of the issuer.

(2)These long-term debt agreements contain various restrictive covenants.

(3)In 2022, the amounts shown are allocations to Tampa Electric and PGS of TEC Notes. See Note 1 for information regarding the separation of PGS from TEC on January 1, 2023.

(4)See Note 7 for information regarding the long-term debt reclassification of $500 million, net of debt issuance costs.

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

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TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization—continued

At December 31, 2023, long-term debt had a carrying amount of $4,233 million and an estimated fair market value of $3,831 million. At December 31, 2022, total long-term debt had a carrying amount of $3,734 million and an estimated fair market value of $3,234 million. The fair value of the debt securities is determined using Level 2 measurements (see Note 14 for information regarding the fair value hierarchy).

A substantial part of Tampa Electric’s tangible assets is pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Gross maturities and annual sinking fund requirements of long-term debt are as follows:

Long-Term Debt Maturities

													Total
As of December 31, 2023													Long-Term
(millions)	2024		2025		2026		2027		2028		Thereafter		Debt
Tampa Electric	$	300	$	0	$	0	$	0	$	0	$	3,975	$	4,275
Total long-term debt maturities	$	300	$	0	$	0	$	0	$	0	$	3,975	$	4,275

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

Description of the Business

TEC is comprised of the electric division, referred to as Tampa Electric, and prior to January 1, 2023, also included the natural gas division, referred to as PGS. Tampa Electric provides retail electric services in West Central Florida, and PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. See "Separation of PGS from TEC" below for information regarding the separation that occurred on January 1, 2023. TEC’s significant accounting policies are as follows:

Principles of Consolidation and Basis of Presentation

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. 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.

TEC is a wholly owned subsidiary of TECO Energy, Inc. TEC contains the electric division, and prior to January 1, 2023, also included the natural gas division. Prior to January 1, 2023, intercompany balances and transactions within the divisions have been eliminated in consolidation. TECO Energy is a wholly owned indirect subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

As a regulated utility, TEC must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation. The original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

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Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2023			December 31, 2022
Electric generation	10-60 years	$	6,732		$	6,300
Electric transmission	10-75 years		1,182			1,109
Electric distribution	10-60 years		3,609			3,296
Gas transmission and distribution	15-75 years	0				2,567
General plant and other	4-60 years		997			1,020
Total cost			12,520			14,292
Less Tampa Electric accumulated depreciation			(3,443	)		(3,158	)
Less PGS accumulated depreciation		0				(687	)
Tampa Electric construction work in progress			1,151			949
PGS construction work in progress		0				248
Total property, plant and equipment, net		$	10,228		$	11,644

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.2% and 3.5% for 2023, 2022 and 2021, respectively. Construction work in progress is not depreciated until the asset is placed in service. TEC's total depreciation expense for the years ended December 31, 2023, 2022 and 2021 was $390 million, $402 million and $408 million, respectively. For the year ended December 31, 2023, 2022 and 2021, Tampa Electric's depreciation expense was $390 million, $359 million and $357 million, respectively.

TEC computes depreciation and amortization using the following methods:

•the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

•the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rates used to calculate AFUDC are revised periodically to reflect significant changes in cost of capital. In 2023, 2022 and 2021, Tampa Electric’s rate was 6.07%, 6.00% and 6.46%, respectively. PGS’s rate used to calculate its AFUDC in 2022 and 2021 was 6.00%. Total AFUDC for the years ended December 31, 2023, 2022 and 2021 was $25 million, $46 million and $66 million, respectively.

Inventory

TEC values materials, supplies and fossil fuel inventory (natural gas and coal) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or net realizable value.

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3).

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details.

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Investment and Production Tax Credits (PTCs)

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense as required by regulatory practices. TEC recognizes a reduction of income tax expense for PTCs earned by its eligible solar assets. The PTCs are based on per kwH rate prescribed by applicable federal statutes.

Stranded Tax Effects in Accumulated Other Comprehensive Income

TEC utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released.

Revenue Recognition

Regulated electric revenue

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. Tampa Electric’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWH delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, timing of meter reads and line losses.

Regulated gas revenue

Prior to January 1, 2023, gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, were recognized when obligations under the terms of a contract were satisfied. This occurred primarily when gas was delivered to customers over time as the customer simultaneously received and consumed the benefits of the gas. Gas revenues were recognized on an accrual basis and included billed and unbilled revenues. Revenues related to the distribution and sale of gas were recognized at rates approved by the regulator and recorded based on metered usage, which occurred on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, was estimated and the corresponding unbilled revenue was recognized. PGS’s estimate of unbilled revenue at the end of the reporting period was calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate included assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

Other

See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue.

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation, environmental and storm protection plan costs for Tampa Electric and, prior to January 1, 2023, purchased gas, interstate pipeline capacity, replacement of cast iron/bare steel pipe and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are recognized.

Receivables and Allowance for Credit Losses

Receivables on the Consolidated Balance Sheets include receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, totaling $284 million and $295 million as of December 31, 2023 and 2022, 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 impact estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

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TEC accrues base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2023 and 2022, unbilled revenues of $63 million and $82 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Accounting for Franchise Fees and Gross Receipts Taxes

TEC is allowed to recover certain costs incurred on a dollar-for-dollar basis from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $139 million, $145 million and $129 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of pension assets net of accrued pension liabilities (see Note 5) and right-of-use assets related to operating leases (see Note 13).

Deferred Credits and Other Liabilities

Other deferred credits primarily include accrued other postretirement benefits (see Note 5), MGP environmental remediation liability prior to January 1, 2023 (see Note 8), asset retirement obligations (see Note 12), lease liabilities (see Note 13) and a reserve for auto, general and workers’ compensation liability claims.

TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2023 and 2022 ranged from 4.00% to 5.99% and 4.00% to 5.78%, respectively.

Derivatives and Hedging Activities

TEC had $1 million and $5 million derivative assets as of December 31, 2023 and 2022, respectively, and $0 and $1 million derivative liabilities as of December 31, 2023 and December 31, 2022, respectively.

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2023 and 2022, all of TEC’s physical contracts qualified for the NPNS exception, which was elected.

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Separation of PGS from TEC

PGS became an operating division of TEC in 1997 when TECO Energy purchased PGS and merged that corporation into TEC. Since then, PGS has operated as a stand-alone regulated utility, including having its own tariff and its own books and records.

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. (PGSI) pursuant to a Contribution Agreement. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. On January 1, 2023, the assets, liabilities, and equity that had been recorded in the books of PGS were transferred from TEC to the newly formed PGSI at book value in a tax-free transaction. PGSI issued 100 shares of common stock to TEC related to the transfer of PGS, which were subsequently distributed to TECO Energy, Inc. and then contributed to TECO Gas Operations, Inc. This is a transaction between entities under common control; therefore, TEC did not recognize a gain or loss on the transaction. TEC is not required to recast its prior period financial statements and disclosures to exclude PGS prior to January 1, 2023. The TEC Consolidated Statement of Cash Flows for the year ended December 31, 2023 does not include the non-cash impact of separating the PGS assets, liabilities and equity from TEC on January 1, 2023 and excludes PGS’s opening cash balance.

The impact of the separation of PGS from TEC on the Consolidated Statements of Capital for the year ended December 31, 2023 was $992 million, which represents the net assets of PGS transferred as of January 1, 2023. TEC recorded $121 million to

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retained earnings, which was the retained earnings of PGS as of January 1, 2023, and the remainder of $871 million was recorded to additional paid in capital, which is presented with common stock.

Prior to the separation, as a division of TEC, PGS had received an allocation of outstanding unsecured notes and outstanding short-term borrowings issued by TEC. The obligations related to these combined borrowings were reflected in an affiliate loan agreement between TEC and PGS. The initial obligation of PGS under the loan agreement at January 1, 2023 was a term loan in the principal amount of $670 million and a revolving loan in the principal amount of $66 million. The maturity date for both was December 29, 2023. On December 20, 2023, PGS repaid Tampa Electric the outstanding principal amount of the term loan and revolving loan of $670 million and $286 million, respectively, plus outstanding interest. The repayment terminates the affiliate loan agreement and Tampa Electric will no longer provide capital for the operations of PGS. See Note 6 for further information.

See Note 11 for certain financial information related to PGS. In addition, the following table presents the assets and liabilities of PGS in TEC’s Consolidated Balance Sheet as of December 31, 2022:

	December 31,
(millions)	2022
Property, plant and equipment
Utility plant	$	2,938
Accumulated depreciation		(687	)
Total property, plant and equipment, net		2,251
Current assets
Cash and cash equivalents		4
Receivables, less allowance for credit losses of $1 at December 31, 2022		62
Due from affiliates		4
Inventories, at average cost
Materials and supplies		5
Regulatory assets		9
Prepayments and other current assets		4
Total current assets		88
Other assets
Regulatory assets		53
Deferred charges and other assets		79
Total other assets		132
Total assets	$	2,471
Capitalization
Common stock	$	871
Retained earnings		121
Total capital		992
Long-term debt		564
Total capital		1,556
Current liabilities
Notes payable		166
Accounts payable		78
Due to affiliates		27
Customer deposits		30
Regulatory liabilities		11
Accrued interest		4
Accrued taxes		5
Other		4
Total current liabilities		325
Other liabilities
Deferred income taxes		238
Regulatory liabilities		277
Deferred credits and other liabilities		75
Total other liabilities		590

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Total liabilities and capital $ 2,471

2. New Accounting Pronouncements

TEC considers the applicability and impact of all ASUs issued by the FASB. TEC was not required to and did not adopt any new ASUs in 2023. The following update has been issued by FASB, but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements.

Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. TEC is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (benefit) in accordance with U.S. Securities and Exchange Commission (SEC) Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024, and interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. TEC is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. The FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirements) equal to their prudently incurred cost of providing service or products, plus a reasonable return on equity invested or assets. As a result, Tampa Electric and PGS qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between U.S. GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred. In addition to regulatory assets and regulatory liabilities, rate regulation impacts other financial statement balances and activity, including, but not limited to, property, plant, and equipment, revenues, and expenses.

Tampa Electric Base Rates

Tampa Electric’s results for 2021 reflected an amended and restated settlement agreement, approved by the FPSC on November 6, 2017, that replaced the previous 2013 base rate settlement agreement and extended it another four years through 2021. The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. Under the agreement, the allowed equity in the capital structure was 54% from investor sources of capital. The amended agreement provided for SoBRAs for Tampa Electric’s substantial investments in solar generation. Tampa Electric invested approximately $850 million in these solar projects during 2017 to 2021 and accrued AFUDC during construction. The agreement included a sharing provision that allowed customers to benefit from 75% of any cost savings for projects below $1,500/kWac. The 2017 settlement agreement further contained a provision related to tax reform. An asset optimization provision that allows Tampa Electric to share in

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the savings for optimization of its system once certain thresholds are achieved is also included. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make no investments in gas reserves.

On August 6, 2021, Tampa Electric 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 Tampa Electric and the intervenors in Tampa Electric’s rate case filed with the FPSC in April 2021. The Settlement Agreement agreed 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 included 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 continued to be 54% from investor sources of capital. The Settlement Agreement included 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 Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contained a provision whereby Tampa Electric 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 created 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 that agreement. The Settlement Agreement set new depreciation and dismantlement rates effective January 1, 2022 and contained the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2024. On October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting such approval, was issued on November 10, 2021.

Tampa Electric's 2021 settlement agreement provision allowed Tampa Electric to request a revenue and ROE increase due to increases in the 30-year U.S. Treasury bond yield rate. On July 1, 2022, Tampa Electric requested to adjust its base rates to collect an additional $10 million annually (prorated in the first year) effective September 1, 2022 and increase its mid-point ROE and upper and lower allowed ranges. On August 16, 2022, the FPSC approved the change. The new mid-point ROE is 10.20%, and the range is 9.25% to 11.25% effective July 1, 2022.

On August 16, 2023, Tampa Electric filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 Settlement Agreement. Inclusive of Tampa Electric’s ROE adjustment, the increase of $22 million was approved by the FPSC and the order reflecting such approval was issued on November 17, 2023, effective in January 2024.

On February 1, 2024, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting a revenue requirement increase of approximately $290 to $320 million, effective in January 2025, and additional adjustments of approximately $100 million and $70 million for 2026 and 2027, respectively. Tampa Electric’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until Tampa Electric completes its analysis and files the case in April 2024. The FPSC will hear the case in the third quarter of 2024 with a decision expected by the end of 2024.

Tampa Electric Big Bend Modernization Project

Tampa Electric invested $876 million, including $91 million of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The Big Bend modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the Big Bend modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric retired Big Bend Unit 3 in 2023 as it is in the best interest of customers from economic, environmental risk and operational perspectives.

At December 31, 2020, Tampa Electric’s balance sheet included $636 million in electric utility plant and $267 million in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric continued to account for its investment in Units 1, 2 and 3 in electric utility plant and depreciated the assets using the current depreciation rates until December 31, 2021, at which point they were reclassified to a regulatory asset on the balance sheet.

Tampa Electric’s Settlement Agreement provided recovery for the Big Bend modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs was recovered as part of the 2023 subsequent year adjustment. The Settlement Agreement also included 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

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survive the term of the Settlement Agreement. The special capital recovery schedule for all three units was 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.

In January 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million beginning April 1, 2022 through December 2022 due to an increase in fuel commodity and capacity costs. On March 1, 2022, the FPSC voted to approve the mid-course adjustment, and the order reflecting such approval was issued on March 18, 2022.

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the $518 million final 2022 fuel under-recovery over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, effective April 1, 2023.

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 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. A settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in January 2021. The current approved plan addresses the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

Tampa Electric Storm Restoration Cost Recovery

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. Once the storm reserve regulatory liability is exhausted, TEC may petition the FPSC for recovery. This provision was also included in Tampa Electric’s subsequent 2017 amended and restated settlement agreement and in Tampa Electric’s 2021 rate case settlement agreement. In 2021, 2020 and 2019, Tampa Electric incurred total storm restoration costs for multiple hurricanes of approximately $10 million, which was charged to the storm reserve regulatory liability.

In September 2022, Tampa Electric was impacted by Hurricane Ian. Total storm restoration costs were $129 million, with $121 million charged to the storm reserve. Restoration costs charged to the storm reserve exceeded the storm reserve balance and this amount was deferred to be collected from customers in subsequent periods. In November 2022, Tampa Electric incurred costs of approximately $2 million related to Hurricane Nicole. In January 2023, Tampa Electric petitioned the FPSC for recovery of costs associated with Hurricanes Ian and Nicole that exceeded the reserve, $10 million of storm restoration costs charged to the reserve since 2018, and the replenishment of the balance in the reserve to the $56 million level that existed as of October 31, 2013 for a total of approximately $131 million. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and Tampa Electric began applying the surcharge on April 2023 bills. Subsequently, on November 9, 2023, the FPSC approved Tampa Electric’s petition filed on August 16, 2023 to update the total storm cost collection from $129 million to approximately $134 million and change the collection of the expected remaining balance of approximately $29 million as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC and issuance of an order by the FPSC is expected to occur by the third quarter of 2024.

In September 2023, Tampa Electric was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million, which were charged to the storm reserve regulatory asset and not included in the petition above. Tampa Electric will determine the timing of the request for recovery of Hurricane Idalia costs at a future time.

PGS Base Rates

PGS’s results for 2022 and 2021 reflected a rate case settlement agreement filed by PGS and OPC and approved by the FPSC on November 19, 2020. 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, including the ability to reverse a total of $34 million of accumulated depreciation through 2023. During 2022, PGS reversed $14 million of the $34 million accumulated depreciation. No amounts were reversed prior to 2022.

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Regulatory Assets and Liabilities

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

Regulatory Assets and Liabilities

	December 31,		December 31,
(millions)	2023		2022
Regulatory assets:
Regulatory tax asset (1)	$	112	$	124
Cost-recovery clauses (2)		94		525
Capital cost recovery for early retired assets (3)		507		497
Environmental remediation (4)		0		20
Postretirement benefits (5)		236		272
Storm reserve (6)		7		76
Other		32		38
Total regulatory assets		988		1,552
Less: Current portion		161		361
Long-term regulatory assets	$	827	$	1,191
Regulatory liabilities:
Regulatory tax liability (7)	$	477	$	601
Cost-recovery clauses - deferred balances (2)		20		30
Accumulated reserve—cost of removal (8)		271		498
Other		27		11
Total regulatory liabilities		795		1,140
Less: Current portion		94		85
Long-term regulatory liabilities	$	701	$	1,055

(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.

(2)These assets and liabilities are related to FPSC clauses and riders, primarily related to the fuel clause and the increase in natural gas prices experienced in 2022. 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 regulatory asset is related to the remaining net book value of Big Bend Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years. See “Tampa Electric Big Bend Modernization Project” above for further information.

(4)This asset was related to PGS costs associated with environmental remediation primarily at MGP sites. See Note 1 for information regarding the separation of PGS from TEC.

(5)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.

(6)See "Tampa Electric Storm Restoration Cost Recovery" above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC.

(7)The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower corporate 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.

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

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4. Income Taxes

Change in Florida Corporate Income Tax Rate

On September 14, 2021, the state of Florida issued a corporate tax rate reduction from 4.46% to 3.53% effective January 1, 2021 through December 31, 2021. In 2021, TEC recorded a $4 million regulatory liability in recognition of its obligation to pass the tax rate reduction expense benefit to customers per the 2017 settlement agreement. Effective January 1, 2022, the Florida corporate income tax rate is 5.5%.

Inflation Reduction Act

On August 16, 2022, the Inflation Reduction Act was signed into legislation and includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024, the expansion of ITC for energy storage technology beginning 2023 and introduces new technology-neutral clean energy related credits beginning in 2025. TEC has determined that electing production tax credits for its solar plants placed in service in 2022 and 2023 will be more beneficial for customers compared to ITCs and has recorded a regulatory liability in recognition of its obligation to pass the tax benefits to customers of $23 million and $7 million as of December 31, 2023 and 2022, respectively.

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 of TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution.

In 2023, 2022 and 2021, TEC recorded net tax provisions of $87 million, $121 million and $80 million, respectively.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2023			2022			2021
Current income taxes
Federal	$	84		$	(13	)	$	48
State		25			(3	)		4
Deferred income taxes
Federal		(19	)		105			24
State		5			38			13
Investment tax credits amortization		(8	)		(6	)		(9	)
Total income tax expense	$	87		$	121		$	80

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During 2022, TEC increased its net operating loss carryforward. Total current income tax expense for the year ended December 31, 2022, was reduced by $59 million to reflect the benefits of operating loss carryforwards.

For the three years presented, the overall effective tax rate differs from the U.S. federal statutory rate as presented below:

Effective Income Tax Rate

(millions)
For the year ended December 31,	2023			2022			2021
Income before provision for income taxes	$	553		$	661		$	526
Federal statutory income tax rates		21	%		21	%		21	%
Income taxes, at statutory income tax rate		116			139			110
Increase (decrease) due to
State income tax, net of federal income tax		23			27			13
Excess deferred tax amortization		(25	)		(25	)		(26	)
ITC amortization		(8	)		(6	)		(9	)
AFUDC-equity		(4	)		(7	)		(9	)
Production Tax Credits		(15	)		(6	)		0
Other Tax credits		(4	)		(3	)		(3	)
Other		4			2			4
Total income tax expense on consolidated statements of income	$	87		$	121		$	80
Income tax expense as a percent of income before income taxes		15.7	%		18.3	%		15.2	%

Deferred Income Taxes

Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

(millions)
As of December 31,	2023		2022
Deferred tax liabilities (1)
Property related	$	1,227	$	1,318
Deferred fuel		23		133
Pension and postretirement benefits		100		111
Insurance reserves		0		15
Total deferred tax liabilities		1,350		1,577
Deferred tax assets (1)
Loss and credit carryforwards (2)		383		408
Medical benefits		19		24
Insurance reserves		1		0
Pension and postretirement benefits		49		57
Capitalized energy conservation assistance costs		0		23
Other		18		20
Total deferred tax assets		470		532
Total deferred tax liability, net	$	880	$	1,045

(1)Certain property related assets and liabilities have been netted. At December 31, 2022, PGS total deferred tax liabilities and deferred tax assets were $213 million and $37 million, respectively, with the majority of the balances related to property and capitalized energy conservation assistance costs.

(2)Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $10 million and $9 million at December 31, 2023 and 2022, respectively.

The expiration of TEC's tax credits and NOL carryforwards are as follows:

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(millions)	December 31, 2023		Expiration Year
General business credits	$	324	2027-2043
Federal NOL carryforwards		135	2037
Federal NOL carryforwards (1)		199	indefinite
State NOL carryforwards (1)		305	indefinite
Total tax credits and NOL carryforwards	$	963

(1)Indefinite carryforward for Federal NOLs and NOLs for states that have adopted the U.S. Tax Cuts and Jobs Act of 2017 provisions, generated in tax years beginning after December 31, 2017.

TEC has unused general business credits of $324 million expiring between 2027 and 2043, of which $266 million relate to ITCs expiring between 2034 and 2043. As a result of TECO Energy's merger with Emera in 2016, TECs NOLs and credits will be utilized by EUSHI, in accordance with the benefits-for-loss allocation which provide that tax attributes are utilized by the consolidated tax return group of EUSHI.

Unrecognized Tax Benefits

TEC accounts for uncertain tax positions as required by U.S. GAAP. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.

The following table provides details of the change in unrecognized tax benefits as follows:

(millions)	2023		2022		2021
Balance at January 1,	$	9	$	6	$	9
Increases due to tax positions related to prior year	0		2		1
Increases due to tax positions related to current year	1		1		1
Decreases due to settlements with tax authorities	0		0			(5	)
Balance at December 31,	$	10	$	9	$	6

As of December 31, 2023 and 2022, TEC’s uncertain tax positions for federal R&D tax credits were $10 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 2021 by approximately $5 million due to the resolution of its 2016 federal tax credits issue with IRS Appeals. The settlement of the federal R&D credits audit did not impact the effective tax rate during 2021. The unrecognized tax benefits, if recognized, would reduce TEC’s effective tax rate.

TEC recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance expense” in the Consolidated Statements of Income. In 2023, 2022 and 2021, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest or amounts recorded for penalties at December 31, 2023, 2022 and 2021.

The U.S. federal statute of limitations remains open for the year 2017 and forward. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized.

5. Employee Postretirement Benefits

Pension Benefits

TEC is a participant in the retirement plans of TECO Energy, including a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.

Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP and the unfunded obligations of the Restoration Plan. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. The Restoration Plan is a non-qualified, non-contributory defined benefit retirement plan that allows certain members of senior management to receive contributions as if no IRS limits were in place.

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Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (other benefits) for most employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.

TECO Energy has made a change to the postretirement health plan to replace the pharmacy services provider. The change was treated as a plan amendment and the plan was remeasured as of September 30, 2023. See "Plan Amendments" line item in the "Obligations and Plan Assets" table below.

Obligations and Funded Status

TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted.

The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and TECO Energy’s Florida-based other postretirement benefit plan (other benefits).

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2023			2022			2023			2022
Change in benefit obligation
Benefit obligation at beginning of year	$	666		$	850		$	142		$	200
Service cost		15			18			1			2
Interest cost		35			23			7			5
Plan participants’ contributions		0			0			4			4
Benefits paid		(59	)		(79	)		(19	)		(19	)
Actuarial loss (gain)		27			(142	)		7			(50	)
Plan amendments		0			0			(10	)		0
Plan settlements (3)		(6	)		(4	)		0			0
Benefit obligation at end of year	$	678		$	666		$	132		$	142

Change in plan assets
Fair value of plan assets at beginning of year	$	650		$	924		$	0		$	0
Actual gain (loss) return on plan assets		78			(214	)		0			0
Employer contributions		16			18			0			0
Employer direct benefit payments		7			5			15			15
Plan participants’ contributions		0			0			4			4
Benefits paid		(58	)		(78	)		0			0
Direct benefit payments		(1	)		(1	)		(19	)		(19	)
Plan settlements (3)		(6	)		(4	)		0			0
Fair value of plan assets at end of year (1)	$	686		$	650		$	0		$	0

(1)The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

(2)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

(3)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

Increases in the benefit obligation for the period ended December 31, 2023 are the result of decreases in the discount rate used to calculate the benefit obligation and the updating of the salary assumption as the result of an experience study performed during the year.

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At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with projected benefit obligations and accumulated projected benefit obligations in excess of plan assets was as follows:

TECO Energy	Pension Benefits					Other Benefits (1)
Funded Status
(millions)	2023		2022			2023			2022
Benefit obligation (PBO/APBO)	$	678	$	666		$	132		$	142
Less: Fair value of plan assets		686		650			0			0
Funded status at end of year	$	8	$	(16	)	$	(132	)	$	(142	)

(1)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $642 million at December 31, 2023 and $634 million at December 31, 2022.

The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations and plan assets at December 31 were as follows:

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2023			2022			2023			2022
Noncurrent assets	$	10		$	0		$	0		$	0
Accrued benefit costs and other current liabilities		0			(7	)		(10	)		(12	)
Deferred credits and other liabilities		(1	)		(9	)		(99	)		(121	)
	$	9		$	(16	)	$	(109	)	$	(133	)

Unrecognized gains and losses and prior service credits and costs are recorded in regulatory assets for TEC. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2023		2022		2023		2022
Net actuarial loss	$	207	$	242	$	29	$	30
Amount recognized	$	207	$	242	$	29	$	30

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2023			2022			2023			2022
Discount rate		5.27	%		5.55	%		5.28	%		5.53	%
Rate of compensation increase		4.42	%		3.79	%		4.42	%		3.79	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.09	%		6.39	%
Ultimate rate	n/a			n/a				4.00	%		4.00	%
Year rate reaches ultimate trend rate	n/a			n/a			2047			2047

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The discount rate assumption used to determine the December 31, 2023 and 2022 benefit obligation was based on a cash flow matching technique that matches yields from high-quality (AA-rated, non-callable) corporate bonds to TECO Energy’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption.

Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets

TECO Energy	Pension Benefits									Other Benefits (1)
	2023			2022			2021			2023			2022			2021
(millions)
Service cost	$	15		$	18		$	19		$	1		$	2		$	2
Interest cost		35			23			21			7			5			5
Expected return on plan assets		(54	)		(51	)		(52	)		0			0			0
Amortization of:
Actuarial loss		5			17			24			0			3			4
Prior service cost		0			0			0			(2	)		(2	)		(2	)
Settlement loss (2)		2			2		0				0			0			0
Net periodic benefit cost	$	3		$	9		$	12		$	6		$	8		$	9

Net loss (gain) arising during the year (includes curtailment gain)		2			123			(56	)		7			(50	)		(5	)
Prior service cost	$	0		$	0		$	0		$	(11	)	$	0		$	0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service credit		0			0			0			3			2			2
Amortization or settlement of actuarial loss		(7	)		(19	)		(23	)		0			(3	)		(4	)
Total recognized in OCI and regulatory assets	$	(5	)	$	104		$	(79	)	$	(1	)	$	(51	)	$	(7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(2	)	$	113		$	(67	)	$	5		$	(43	)	$	2

(1)Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

(2)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

TEC’s portion of the net periodic benefit costs for pension benefits was $1 million, $8 million and $10 million for 2023, 2022 and 2021, respectively. Tampa Electric’s portion of the net periodic benefit costs for pension benefits was $1 million, $4 million and $7 million for 2023, 2022 and 2021, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $5 million, $9 million and $11 million for 2023, 2022 and 2021, respectively. Tampa Electric’s portion of the net periodic benefit costs for other benefits was $5 million, $8 million and $9 million for 2023, 2022 and 2021, respectively. Net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Statements of Income in “Operations & maintenance”.

Assumptions used to determine net periodic benefit cost for years ended December 31:

	Pension Benefits									Other Benefits
	2023			2022			2021			2023			2022			2021
Discount rate (1)	4.19%-5.55%				2.77	%		2.37	%	5.53%-6.14%				2.84	%		2.47	%
Expected long-term return on plan assets		7.05	%		6.50	%		6.70	%	n/a			n/a			n/a
Rate of compensation increase		3.79	%		3.05	%		3.08	%		3.79	%		3.04	%		3.07	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.39	%		5.61	%		5.74	%
Ultimate rate	n/a			n/a			n/a				4.00	%		4.00	%		4.50	%
Year rate reaches ultimate trend rate	n/a			n/a			n/a			2047			2045			2038

(1)Discount rate range is the result of remeasurements that occurred in 2023.

The discount rate assumption used to determine the benefit cost for 2023, 2022 and 2021 was based on the same technique that was used to determine the December 31, 2023 and 2022 benefit obligation as discussed above.

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The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended December 31, 2023, TECO Energy’s pension plan’s actual return was approximately 14.7%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

Pension Plan Assets

Pension plan assets are invested in a mix of equity and fixed-income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

TECO Energy	2023 Target Allocation			2022 Target Allocation			Actual Allocation, End of Year
Asset Category							2023			2022
Cash and cash equivalents	0%-10%			n/a				3	%	n/a
Equity securities	48%-68%			50%-70%				57	%		58	%
Fixed income securities	29%-49%			30%-50%				40	%		42	%
Total		100	%		100	%		100	%		100	%

TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy will continue to monitor the matching of plan assets with plan liabilities over the long term.

The plan’s investments are held by a trust fund administered by The Bank of New York Mellon. Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments.

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Pension Plan Investments

TECO Energy	At Fair Value as of December 31, 2023
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	(1	)	$	0		$	0	$	0	$	(1	)
Accounts receivable		3			0			0		0		3
Accounts payable		(10	)		0			0		0		(10	)
Short-term investment funds (STIFs)		24			0			0		0		24
Common stock		1			0			0		0		1
Real estate investment trusts (REITs)		3			0			0		0		3
Mutual funds		38			0			0		0		38
Municipal bonds		0			2			0		0		2
Government bonds		0			108			0		0		108
Corporate bonds		0			57			0		0		57
Long futures		5			0			0		0		5
Short Sales		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		63			166			0		0		229
Common and collective trusts (1)		0			0			0		443		443
Mutual fund (1)		0			0			0		14		14
Total investments	$	63		$	166		$	0	$	457	$	686

(1)In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

TECO Energy	At Fair Value as of December 31, 2022
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	5		$	0		$	0	$	0	$	5
Accounts receivable		10			0			0		0		10
Accounts payable		(62	)		0			0		0		(62	)
Short-term investment funds (STIFs)		32			0			0		0		32
Real estate investment trusts (REITs)		2			0			0		0		2
Mutual funds		50			0			0		0		50
Municipal bonds		0			1			0		0		1
Government bonds		0			58			0		0		58
Corporate bonds		0			50			0		0		50
Mortgage backed securities (MBS)		0			5			0		0		5
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Short Sales		0			(3	)		0		0		(3	)
Written Options		0			2			0		0		2
Swaps		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		37			113			0		0		150
Common and collective trusts (1)		0			0			0		444		444
Mutual fund (1)		0			0			0		56		56
Total investments	$	37		$	113		$	0	$	500	$	650

(1)In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

•Cash collateral is valued at cash posted due to its short-term nature.

•The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset.

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•The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets.

•The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-end mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets.

•The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

•Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

•The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-end mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is an open-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. The redemption frequency is daily. The redemption notice period is the same day. There were no unfunded commitments as of December 31, 2023.

•The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days. There were no unfunded commitments as of December 31, 2023.

•Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

•Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

Additionally, the non-qualified SERP had $4 million and $8 million of assets as of December 31, 2023 and 2022, respectively. Since the plan is non-qualified, its assets are included in the “Deferred charges and other assets” line item in the Consolidated Balance Sheets rather than being netted with the related liability. The non-qualified trust holds investments in a money market fund. The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make it a level 1 asset. The SERP was fully funded as of December 31, 2023 and 2022.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s Florida-based other postretirement benefits plan.

Contributions

The qualified pension plan’s actuarial value of assets, including credit balance, was 107.24% of the Pension Protection Act funded target as of January 1, 2023 and is estimated at 111.50% of the Pension Protection Act funded target as of January 1, 2024.

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions. TEC’s contribution is first set equal to its service cost. If a contribution in excess of service cost for the year is made, TEC’s portion is based on TEC’s proportion of the TECO Energy unfunded liability. TECO Energy made contributions to this plan in 2023, 2022 and 2021, which met the minimum funding requirements for 2023, 2022 and 2021. TEC’s portion of the contribution in 2023 was $10 million, in 2022 was $15 million and in 2021 was $17 million. Tampa Electric’s portion of the contribution was $10 million in 2023, $12 million in 2022 and $14 million 2021. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. Tampa Electric estimates its portion of the 2024 contribution to be $10 million. The amount TECO Energy expects to contribute is in excess of the minimum funding required under ERISA guidelines.

TEC’s portion of the contributions to the SERP in 2023, 2022 and 2021 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2024. TEC made SERP payments of approximately $5 million, $2 million and $1 million from the trust in 2023, 2022 and 2021, respectively.

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between January 1, 1990 and June 30, 2001 is limited to a defined

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dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2024, Tampa Electric expects to make a contribution of approximately $10 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2024	$	76	$	12
2025		67		12
2026		66		12
2027		66		12
2028		65		11
2029-2033		295		51

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match 75% of the first 6% of the participant’s payroll savings deductions. Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended December 31, 2023, 2022 and 2021, TEC’s portion of expense totaled $18 million, $22 million and $22 million, respectively, related to the matching contributions made to this plan. Tampa Electric’s portion of expense totaled $18 million, $19 million and $18 million, respectively, related to the matching contributions made to this plan. The expense related to the matching contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.

Effective October 21, 2019, TECO Energy amended the defined contribution plan such that certain participants covered by the IBEW collective bargaining agreement shall not be eligible to participate in the plan for purposes of receiving the fixed matching contribution. This has been replaced with a non-elective employer contribution on a bi-weekly basis equal to a percentage of the member’s compensation for that period based on years of tenure of employment. For the years ended December 31, 2023, 2022 and 2021, Tampa Electric recognized expense totaling $10 million, $10 million and $10 million, respectively, related to the contributions made to this plan. The expense related to this contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.

6. Short-Term Debt

Credit Facilities

	December 31, 2023								December 31, 2022
			Borrowings		Borrowings		Letters				Borrowings		Borrowings		Letters
	Credit		Outstanding -		Outstanding -		of Credit		Credit		Outstanding -		Outstanding -		of Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding
5-year facility (2)	$	800	$	0	$	706	$	1	$	800	$	0	$	619	$	1
1-year term facility (3)		0		0		0		0		400		400		0		0
1-year term facility (4)		200		0		0		0		0		0		0		0
1-year term facility (5)		200		0		0		0		0		0		0		0
Total	$	1,200	$	0	$	706	$	1	$	1,200	$	400	$	619	$	1

(1)Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets.

(2)This 5-year facility matures on December 17, 2026. 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. On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029. TEC used the net proceeds from this offering for the repayment of a portion of the borrowings outstanding under the 5-year credit facility. Therefore, $497 million of borrowings outstanding under the 5-year credit facility were reclassified as long-term debt on the Consolidated Balance Sheet as of December 31, 2023.

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(3)This 1-year term facility was set to mature on December 16, 2022. On December 13, 2022, TEC extended the maturity date to December 13, 2023, at which time the facility terminated.

(4)On March 1, 2023, TEC entered into a 1-year term facility that matures on February 28, 2024.

(5)On April 3, 2023, TEC entered into a 1-year term facility that matures on April 1, 2024.

At December 31, 2023, these credit facilities required a commitment fee of 12.5 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities and commercial paper at December 31, 2023 and 2022 was 5.68% and 5.00%, respectively.

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called PGSI pursuant to a Contribution Agreement. Prior to the separation, as a division of TEC, PGS had received an allocation of outstanding unsecured notes and outstanding short-term borrowings issued by TEC. The obligations related to these combined borrowings were reflected in an affiliate loan agreement between Tampa Electric and PGS. The initial obligation of PGS under the loan agreement at January 1, 2023 was a term loan in the principal amount of $670 million and a revolving loan in the principal amount of $66 million. The maturity date for both was December 29, 2023. On December 20, 2023, PGS repaid Tampa Electric the outstanding principal amount of the term loan and revolving loan of $670 million and $286 million, respectively, plus outstanding interest. The repayment terminates the affiliate loan agreement and Tampa Electric will no longer provide capital for the operations of PGS.

In December 2023, Tampa Electric used the proceeds of the PGS repayment in part to repay $400 million in credit facility borrowings, the $195 million note payable to TECO Energy and $149 million of the commercial paper borrowed under the 5-year term facility.

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 cannot issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

TEC Term Loan

On April 3, 2023, TEC entered into a 364-day, $200 million senior unsecured revolving loan credit facility with a group of banks. The credit facility has a maturity date of April 1, 2024. The credit agreement contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term SOFR, Wells Fargo’s prime rate, the federal funds rate or the one-month secured overnight financing rate, plus a margin.

TEC Term Loan

On March 1, 2023, TEC entered into a 364-day, $200 million senior unsecured revolving loan credit facility with a maturity date of February 28, 2024. The credit agreement contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term secured overnight financing rate (SOFR), The Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month secured overnight financing rate, plus a margin.

TEC Term Loan

On December 13, 2022, TEC extended the maturity date of its $500 million credit agreement that was set to mature on December 16, 2022 and reduced the amount of the loan to $400 million. The credit agreement has a maturity date of December 13, 2023; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term secured overnight financing rate (SOFR), Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. On November 24, 2023, TEC repaid the facility. On December 13, 2023, the facility terminated.

5-Year Credit Facility

On December 17, 2021, TEC amended and restated its $800 million bank credit facility, entering into a Seventh Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2023 to December 17, 2026 (subject to further extension with the consent of each lender); 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

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aggregate; and made other technical changes. On April 3, 2023, TEC amended the agreement to replace the London interbank deposit rate with the SOFR.

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7. Long-Term Debt

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time.

TEC 4.90% Notes due 2029

On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029 (the 2029 Notes). Prior to February 1, 2029, in the case of the 2029 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) the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the redemption date on a semi-annual basis at the Treasury Rate plus 15 basis points less interest accrued to the date of redemption or (ii) 100% of the principal amount of the notes to be redeemed, plus, in either case, accrued and unpaid interest thereon to the redemption date. On or after February 1, 2029, TEC may redeem the 2029 Notes, in whole or in part, at any time and from time to time, at a redemption price equal to 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to the redemption date. TEC used the net proceeds from this offering for the repayment of a portion of the borrowings outstanding under the 5-year credit facility. Therefore, $497 million of borrowings outstanding under the 5-year credit facility were reclassified from notes payable to long-term debt on the Consolidated Balance Sheet as of December 31, 2023.

TEC 3.875% Notes due 2024 and 5.00% Notes due 2052

On July 12, 2022, TEC completed a sale of (i) $300 million aggregate principal amount of 3.875% Notes due July 12, 2024 (the 2024 Notes) and (ii) $300 million aggregate principal amount of 5.00% Notes due July 15, 2052 (the 2052 Notes, and collectively, the Notes). Until July 12, 2024, in the case of the 2024 Notes, or January 15, 2052, in the case of the 2052 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) July 12, 2024, in the case of the 2024 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) July 15, 2052, in the case of the 2052 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, plus 30 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after January 15, 2052, in the case of the 2052 Notes, TEC may, at its option, redeem the 2052 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.

TEC 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

As of December 31, 2023, TEC, through its Tampa Electric division and former PGS division, was a PRP for certain superfund sites and, through its former PGS division, for certain former MGP sites. As a result of the separation of the PGS division, PGS is now the responsible party for those sites (in addition to third party PRPs for certain sites). See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC.

Long-Term Commitments

TEC has commitments for various purchases as disclosed below, including payment obligations for capital projects, such as Tampa Electric’s solar projects (see Note 3), and 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 minimum lease payments with non-cancelable lease terms in excess of one year and other net purchase obligations/commitments at December 31, 2023:

	Purchased				Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Power		Transportation		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2024	$	4	$	135	$	533	$	194	$	34	$	3	$	5	$	908
2025		0		128		81		60		22		3		5		299
2026		0		125		53		17		23		1		1		220
2027		0		125		1		4		22		1		1		154
2028		0		97		0		1		17		1		0		116
Thereafter		0		833		0		0		33		75		0		941
Total future minimum payments	$	4	$	1,443	$	668	$	276	$	151	$	84	$	12	$	2,638

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2023 and 2022, TEC was in compliance with all required financial covenants.

9. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
For the year ended December 31, 2023	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,711							$	1,711
Commercial		803								803
Industrial		203								203
Regulatory deferrals		(387	)							(387	)
Unbilled revenue		(2	)							(2	)
Other (1)		309								309
Total electric revenue		2,637								2,637
Total revenue	$	2,637							$	2,637
For the year ended December 31, 2022
Electric revenue
Residential	$	1,381		$	0	$	0		$	1,381
Commercial		666			0		0			666
Industrial		176			0		0			176
Regulatory deferrals		(21	)		0		0			(21	)
Unbilled revenue		9			0		0			9
Other (1)		312			0		(4	)		308
Total electric revenue		2,523			0		(4	)		2,519
Gas revenue
Residential		0			229		0			229
Commercial		0			200		0			200
Industrial (2)		0			31		0			31
Other (3)		0			196		(6	)		190
Total gas revenue		0			656		(6	)		650
Total revenue	$	2,523		$	656	$	(10	)	$	3,169
For the year ended December 31, 2021
Electric revenue
Residential	$	1,156		$	0	$	0		$	1,156
Commercial		602			0		0			602
Industrial		172			0		0			172
Regulatory deferrals		(6	)		0		0			(6	)
Unbilled revenue		(2	)		0		0			(2	)
Other (1)		252			0		(4	)		248
Total electric revenue		2,174			0		(4	)		2,170
Gas revenue
Residential		0			212		0			212
Commercial		0			191		0			191
Industrial (2)		0			25		0			25
Other (3)		0			100		(3	)		97
Total gas revenue		0			528		(3	)		525
Total revenue	$	2,174		$	528	$	(7	)	$	2,695

(1)Other includes sales to public authorities, off-system sales to other utilities and various other items.

(2)Industrial includes sales to power generation customers.

(3)Other includes off-system sales to other utilities and various other items.

Remaining Performance Obligations

Remaining performance obligations primarily represent lighting contracts and, prior to January 1, 2023, gas transportation contracts with fixed contract terms. As of December 31, 2023 and 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $78 million and $140 million, respectively. The decrease is due to TEC's January 1, 2023 separation from its former PGS division. See Note 1 for further information regarding the separation of PGS from TEC. As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2043.

10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2023		2022			2021
Natural gas purchases (net of sales) from affiliates	$	65	$	232		$	236
Services to/(from) affiliates		28		(4	)		(7	)
Interest income from affiliate		38		0			0
Interest expense to affiliate		11		0			0
Dividends to TECO Energy		472		517			450
Equity contributions from TECO Energy		300		605			580

Amounts due from or to affiliates at December 31,

(millions)	2023		2022
Accounts receivable related to asset management agreements with Emera Energy Services Inc. (1)	$	4	$	7
Accounts receivable excluding asset management agreements (1)		12		5
Taxes receivable (2)		3		10
Accounts payable (1)		10		31
Note payable to TECO Energy (3)		0		195

(1)Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2)Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.

(3)The note payable with TECO Energy bears interest at a rate approximating the market rate of TEC's commercial paper.

See Note 6 for further information regarding related party transactions between TEC and PGS as a result of financing activities due to the separation of PGS from TEC on January 1, 2023..

11. Segment Information

Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. Management reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TEC but are included in determining reportable segments.

TEC is a public utility operating within the State of Florida. Due to the separation of PGS from TEC, TEC operates under a single operating and reportable segment effective January 1, 2023 because the operations of TEC only include the operations of the Electric division. See "Separation of PGS from TEC" in Note 1 for further information regarding the separation of PGS from TEC. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 840,000 customers in West Central Florida.

	Tampa				Eliminations/
(millions)	Electric		PGS		Reclassifications				TEC
2023
Revenues - external	$	2,637							$	2,637
Intracompany sales		0								0
Total revenues		2,637								2,637
Depreciation and amortization		422								422
Interest income from affiliates		38								38
Total interest charges		239								239
Provision for income taxes		87								87
Net income		466								466
Total assets		11,831								11,831
Capital expenditures		1,294								1,294
2022
Revenues - external	$	2,519	$	650	$	0			$	3,169
Intracompany sales		4		6		(10	)			0
Total revenues		2,523		656		(10	)			3,169
Depreciation and amortization		389		47		0				436
Total interest charges		142		25		0				167
Provision for income taxes		94		27		0				121
Net income		458		82		0				540
Total assets		12,064		2,471		(732	)	(1)		13,803
Capital expenditures		1,099		328		0				1,427
2021
Revenues - external	$	2,170	$	525	$	0			$	2,695
Intracompany sales		4		3		(7	)			0
Total revenues		2,174		528		(7	)			2,695
Depreciation and amortization		374		56		0				430
Total interest charges		110		20		0				130
Provision for income taxes		57		23		0				80
Net income		369		77		0				446
Total assets		10,650		2,209		(663	)	(1)		12,196
Capital expenditures		1,081		316		0				1,397

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

12. Asset Retirement Obligations

Tampa Electric accounts for AROs at fair value at inception of the obligation if there is a legal obligation under applicable law, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. When the liability is initially recorded in “Deferred credits and other liabilities” in the Consolidated Balance Sheets, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The ARO estimates are reviewed quarterly. Any updates are revalued based on current market prices.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:

	December 31,
(millions)	2023			2022
Beginning balance	$	35		$	31
Additional liabilities		1			1
Liabilities settled		(4	)		0
Other		0			3
Ending balance	$	32		$	35

13. Leases

TEC determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

Operating lease ROU assets and operating lease liabilities are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of TEC’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operations and maintenance expenses” on the Consolidated Statements of Income.

TEC has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases in which TEC is the lessee.

Lessee

Tampa Electric has operating leases for buildings, land, telecommunication services and rail cars. Tampa Electric’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to an additional 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.

(millions)	Classification	2023		2022
Right-of-use asset	Deferred charges and other assets	$	21	$	23
Lease liabilities
Current	Other current liabilities	$	2	$	2
Long-term	Deferred credits and other liabilities		20		22
Total lease liabilities		$	22	$	24

Tampa Electric has recorded operating lease expense for the year ended December 31, 2023, 2022 and 2021 of $4 million, $4 million and $5 million, respectively.

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at December 31, 2023:

(millions)
Year ended December 31:	2024		2025		2026		2027		2028		Thereafter		Total
Minimum lease payments	$	3	$	2	$	1	$	1	$	1	$	46	$	54
Less imputed interest														(32	)
Total future minimum payments													$	22

Additional information related to Tampa Electric’s leases is as follows:

Year ended December 31,	2023			2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	4		$	4
Weighted average remaining lease term (years)		45			44
Weighted average discount rate - operating leases		4.4	%		4.4	%

14. 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 December 31, 2023 and 2022, the fair value of TEC’s short-term debt was not materially different from the carrying 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 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively.

15. Stock-Based Compensation

Emera has a performance share unit (PSU) plan and a restricted share unit (RSU) plan. The PSU and RSU liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA.

Performance Share Unit Plan

Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and are paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the Emera Management Resources and Compensation Committee (MRCC) early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to TEC employee PSUs is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2022		176			56.21		9
Granted including DRIP		73			52.83		4
Exercised		(70	)		54.62		4
Forfeited		(5	)		54.72		0
Transferred (1)		(31	)		56.17		2
Outstanding as of December 31, 2023		143			55.32		7

(1)This amount includes 38,197 units transferred to PGS upon their separation from TEC on January 1, 2023.

Compensation cost recognized for the PSU plan for the years ended December 31, 2023, 2022 and 2021 was $2 million, $4 million and $3 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2023, 2022 and 2021 were $1 million, $1 million and $1 million, respectively. Cash payments made during the year ended December 31, 2023, 2022 and 2021 associated with the PSU plan were $3 million, $7 million and $10 million, respectively. As of December 31, 2023 and 2022, there was $2 million and $3 million, respectively, of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years.

Restricted Share Unit Plan

Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to TEC employee RSUs is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2022		173			56.23		9
Granted including DRIP		60			52.11		3
Exercised		(49	)		54.62		3
Forfeited		(5	)		54.72		0
Transferred (1)		(29	)		56.30		1
Outstanding as of December 31, 2023		150			55.15		8

(1)This amount includes 35,774 units transferred to PGS upon their separation from TEC on January 1, 2023.

Compensation cost recognized for the RSU plan for the years ended December 31, 2023, 2022 and 2021 was $2 million, $3 million and $2 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2023, 2022 and 2021 were $1 million, $1 million and zero, respectively. Cash payments made during the year ended December 31, 2023, 2022 and 2021 associated with the RSU plan were $3 million, none and none, respectively. As of December 31, 2023 and 2022, there was $2 million and $3 million, respectively, of unrecognized compensation cost related to non-vested RSUs that is expected to be recognized over a weighted-average period of two years.

16. Long-Term PPAs

In 2019, Tampa Electric entered into a long-term PPA with a wholesale energy provider in Florida with up to 515 MW of available capacity, which expires in 2024. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric reviewed these risks and determined that the owners of these entities retain the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric was not the primary beneficiary and was not required to consolidate any of these entities. Tampa Electric purchased $35 million, $70 million and $46 million under this long-term PPA for the three years ended December 31, 2023, 2022 and 2021, respectively.

TEC does not provide any material financial or other support to any of the variable interests it is involved with, nor is TEC under any obligation to absorb losses associated with these variable interests. Excluding the payments for energy under these contracts, TEC’s involvement with these variable interests does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows.

17. Subsequent Events

On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029. See Note 7 for additional information.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Conclusions Regarding Effectiveness 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 Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this annual report, December 31, 2023 (Evaluation Date). Based on such evaluation, TEC’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TEC’s disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting.

TEC’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of TEC’s internal control over financial reporting as of December 31, 2023 based on the 2013 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that TEC’s internal control over financial reporting was effective as of December 31, 2023.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting.

There was no change in TEC’s internal control 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 controls that occurred during TEC’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Item 9B. OTHER INFORMATION

None.

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required by Item 10 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 11. EXECUTIVE COMPENSATION

Information required by Item 11 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by Item 12 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 is omitted pursuant to General Instruction I(2) of Form 10-K.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Fees Paid by TEC to the Independent Auditors

The following table presents fees for professional audit services and other services rendered by Ernst & Young LLP for the audit of TEC’s annual financial statements and other services for the years ended December 31, 2023 and 2022, respectively.

	2023		2022
Audit fees	$	612,000	$	694,800
Audit-related fees		0		17,600
Tax fees
Tax planning fees		0		128,696
Total	$	612,000	$	841,096

Audit fees consist of fees for professional services performed for (i) the audit of TEC’s annual financial statements (ii) the related reviews of the financial statements included in TEC’s 10-Q filings (iii) services related to securities offerings (iv) services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-related fees consist of fees for professional services that are reasonably related to the performance of the audit or review of our financial statements, such as required activities related to agreed upon procedures.

Tax fees consist of certain property tax planning fees.

Audit Committee Pre-Approval Policy

All services performed by the independent auditor are approved by the Audit Committee of the Emera Board of Directors in accordance with Emera’s pre-approval policy for services provided by the independent auditor.
 

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)Certain Documents Filed as Part of this Form 10-K

1.Financial Statements

Tampa Electric Company Financial Statements

Reports of Independent Registered Public Accounting Firms (PCAOB ID: 42)

Consolidated Balance Sheets at December 31, 2023 and 2022

Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021

Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021

Consolidated Statements of Capitalization for the Years Ended December 31, 2023, 2022 and 2021

Notes to Consolidated Financial Statements

2.Financial Statement Schedules

Tampa Electric Company Schedule II - Valuation and Qualifying Accounts and Reserves

3.Exhibits

(b)The exhibits filed as part of this Form 10-K are listed on the List of Exhibits below.

(c)The financial statement schedules filed as part of this Form 10-K are listed in paragraph (a)(2) above, and follow immediately.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended December 31, 2023, 2022 and 2021

(millions)

	Balance at		Additions							Balance at
	Beginning		Charged to		Other			Payments &		End of
	of Period		Income		Charges			Deductions (1)		Period
Allowance for Credit Losses:
2023	$	4	$	9	$	(1	)	$	10	$	2
2022	$	7	$	5	$	0		$	8	$	4
2021	$	7	$	8	$	0		$	8	$	7

(1)Write-off of individual bad debt accounts

LIST OF 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	Loan and Trust Agreement dated as of Jul. 2, 2007 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (including the form of Bond) (Exhibit 4.1, Form 8-K dated Jul. 25, 2007 of Tampa Electric Company).	*
4.2	First Supplemental Loan and Trust Agreement dated as of March 26, 2008 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1, Form 8-K dated March 26, 2008 of Tampa Electric Company).	*
4.3	Loan and Trust Agreement dated as of November 15, 2010 among Tampa Electric Company, Polk County Industrial Development Authority and The Bank of New York Mellon Trust Company, N.A., as trustee (including the form of bond) (Exhibit 4.1, Form 8-K dated November 23, 2010 of Tampa Electric Company).	*
4.4	Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee, dated as of January 5, 2006 (including the form of bond) (Exhibit 4.1, Form 8-K dated January 19, 2006 of Tampa Electric Company).	*
4.5	Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jul. 1, 1998 (Exhibit 4.1, Registration Statement No. 333-55873 of Tampa Electric Company).	*
4.6	Third Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jun. 15, 2001 (Exhibit 4.2, Form 8-K dated Jun. 25, 2001 of Tampa Electric Company).	*
4.7	Fifth Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of May 1, 2006 (Exhibit 4.16, Form 8-K dated May 12, 2006 of Tampa Electric Company).	*
4.8	Sixth Supplemental Indenture dated as of May 1, 2007 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.18, Form 8-K dated May 25, 2007 of Tampa Electric Company).	*
4.9	Seventh Supplemental Indenture dated as of May 1, 2008 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.20, Form 8-K dated May 16, 2008 of Tampa Electric Company).	*
4.10	Eighth Supplemental Indenture dated as of November 15, 2010 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee (including the form of 5.40% Notes due 2021) (Exhibit 4.1, Form 8-K dated December 9, 2010 of Tampa Electric Company).	*
4.11	Ninth Supplemental Indenture dated as of May 31, 2012 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 (including the form of 4.10% Notes due 2042) (Exhibit 4.23, Form 8-K dated June 5, 2012 for Tampa Electric Company).	*
4.12	Tenth Supplemental Indenture dated as of September 19, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing and amending the Indenture dated as of July 1, 1998, as amended (including the form of 2.60% Notes due 2022) (Exhibit 4.25, Form 8-K dated September 28, 2012 for Tampa Electric Company).	*
4.13	Eleventh Supplemental Indenture dated as of May 12, 2014 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 (including the form of 4.35% Notes due 2044) (Exhibit 4.27, Form 8-K dated May 15, 2014).	*

4.14	Twentieth Supplemental Indenture dated as of December 1, 2013 between Tampa Electric Company and US Bank, N.A., as successor trustee, amending and restating the Indenture of Mortgage among Tampa Electric Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of August 1, 1946 (Exhibit 4.30, Form 10-K for 2013 of Tampa Electric Company).	*
4.15	Twelfth Supplemental Indenture dated as of May 20, 2015, 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 (including the form of 4.20% Notes due 2045) (Exhibit 4.24, Form 8-K dated May 20, 2015 of Tampa Electric Company).	*
4.16	Thirteenth Supplemental Indenture dated as of June 7, 2018, 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 June 7, 2018 of Tampa Electric Company).	*
4.17	Fourteenth Supplemental Indenture dated as of October 4, 2018 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 4.11, Form 8-K dated October 4, 2018 of Tampa Electric Company).	*
4.18	Fifteenth Supplemental Indenture dated as of July 24, 2019, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.13, Form 8-K dated July 24, 2019 of Tampa Electric Company).	*
4.19	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).	*
4.20	Seventeenth Supplemental Indenture dated as of July 12, 2022, 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 4.12, Form 8-K dated July 12, 2022 of Tampa Electric Company).	*
4.21	Eighteenth Supplemental Indenture dated as of January 30, 2024, 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 January 30, 2024 of Tampa Electric Company).	*
10.1	TECO Energy Group Supplemental Executive Retirement Plan, as amended and restated as of November 1, 2007 (Exhibit 10.1, Form 10-K for 2007 of Tampa Electric Company).	*
10.2	TECO Energy Group Supplemental Disability Income Plan, dated as of March 20, 1989 (Exhibit 10.22, Form 10-K for 1988 of TECO Energy, Inc.). (P)	*
10.3	TECO Energy Group Supplemental Benefits Trust Agreement effective as of January 1, 2020 (Exhibit 10.4, Form 10-K for 2019 of Tampa Electric Company).	*
10.4	TECO Energy Group Benefit Restoration Plan dated as of November 13, 2015 (Exhibit 10.4, Form 10-K for 2015 of Tampa Electric Company).	*
10.5	Insurance Agreement dated as of January 5, 2006 between Tampa Electric Company and Ambac Assurance Corporation (Exhibit 10.1, Form 8-K dated January 19, 2006 of Tampa Electric Company).	*
10.6	Amended and Restated Purchase and Contribution Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Originator, and TEC Receivables Corp., as the Purchaser (Exhibit 10.1, Form 8-K dated March 24, 2015 of TECO Energy, Inc.).	*
10.7	Loan and Servicing Agreement dated as of March 24, 2015, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent (Exhibit 10.2, Form 8-K dated March 24, 2015 of TECO Energy, Inc.).	*

10.8	Amendment No. 1 to Loan and Servicing Agreement dated as of August 10, 2016, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2016 of Tampa Electric Company).	*
10.9	Amendment No. 2 dated as of March 23, 2018 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 8-K dated March 23, 2018 of Tampa Electric Company).	*
10.10	Fifth Amended and Restated Credit Agreement dated as of March 22, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.1, Form 8-K dated March 22, 2017 of Tampa Electric Company).	*
10.11	Master Lenders’ Amendment and Consent dated as of December 19, 2019 to the Fifth Amended and Restated Credit Agreement dated as of March 22, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.12, Form 10-K for 2019 of Tampa Electric Company).	*
10.12	Credit Agreement dated as of February 6, 2020, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated February 6, 2020 of Tampa Electric Company).	*
10.13	Amendment No. 4 dated as of July 14, 2020 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2020 of Tampa Electric Company).	*
10.14	Amendment No. 5 dated as of October 30, 2020 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2020 of Tampa Electric Company).	*
10.15	Amendment No. 1 dated January 29, 2021 to Credit Agreement dated as of February 6, 2020, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.15, Form 10-K for 2020 of Tampa Electric Company).	*
10.16	Sixth Amended and Restated Credit Agreement dated as of December 18, 2020, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated December 18, 2020 of Tampa Electric Company).	*
10.17	Seventh Amended and Restated Credit Agreement dated as of December 17, 2021, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Credit Facility Lenders party thereto (Exhibit 10.2, Form 8-K dated December 17, 2021 of Tampa Electric Company).	*
10.18	Credit Agreement dated as of December 17, 2021, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated December 17, 2021 of Tampa Electric Company).	*
10.19	Amended and Restated Credit Agreement dated as of December 14, 2022, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated as of December 14, 2022 of Tampa Electric Company).	*

10.20	Contribution Agreement dated January 1, 2023 between Tampa Electric Company and Peoples Gas Systems, Inc. (Exhibit 10.1, Form 8-K dated January 1, 2023 of Tampa Electric Company).	*
10.21	Loan Agreement dated January 1, 2023 between Tampa Electric Company and Peoples Gas Systems, Inc. (Exhibit 10.2, Form 8-K dated January 1, 2023 of Tampa Electric Company).	*
10.22	Credit Agreement dated as of March 1, 2023, among Tampa Electric Company, as Borrower, The Bank of Nova Scotia, as Administrative Agent, and the Lenders party thereto. (Exhibit 10.1, Form 8-K dated March 6, 2023 of Tampa Electric Company).	*
10.23	Credit Agreement dated as of April 3, 2023, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto. (Exhibit 10.1, Form 8-K dated April 7, 2023 of Tampa Electric Company).	*
10.24	Amendment No. 1 to Seventh Amended and Restated Credit Agreement dated as of April 3, 2023, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto. (Exhibit 10.2, Form 8-K dated April 7, 2023 of Tampa Electric Company).	*
23	Consent of Independent Certified Public Accountants.
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 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 (Exhibit 99.1, Form 10-Q for the quarter ended June 30, 2021 of Tampa Electric Company).	*
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.
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 Annual Report on Form 10-K 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 Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.

Executive Compensation Plans and Arrangements

Exhibits 10.1 through 10.4, above are management contracts or compensatory plans or arrangements in which executive officers or directors of Tampa Electric Company participate.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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
Dated: February 26, 2024	By:	/s/ Archie Collins
		Archie Collins
		President and Chief Executive Officer and Director
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 26, 2024:

	Title
/s/ Archie Collins	President and Chief Executive Officer and Director
Archie Collins	(Principal Executive Officer)
/s/ Gregory W. Blunden	Treasurer and Chief Financial Officer (Chief Accounting Officer)
Gregory W. Blunden	(Principal Financial and Accounting Officer)

Signature	Title
/s/ Scott Balfour	Chairman of the Board and Director	/s/ Jacqueline Bradley	Director
Scott Balfour		Jacqueline Bradley
/s/ Patrick J. Geraghty	Director	/s/ Pamela D. Iorio	Director
Patrick J. Geraghty		Pamela D. Iorio
/s/ Rhea F. Law	Director	/s/ Daniel Muldoon	Director
Rhea F. Law		Daniel Muldoon
/s/ Chris Sprowls	Director	/s/ Ralph Tedesco	Director
Chris Sprowls		Ralph Tedesco
/s/ Rasesh Thakkar	Director
Rasesh Thakkar

Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report or proxy material has been sent to Tampa Electric Company’s security holders because all of its equity securities are held by TECO Energy, Inc.

EX-23

Exhibit 23

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-267890) of Tampa Electric Company and in the related Prospectus of our report dated February 26, 2024, with respect to the consolidated financial statements and financial statement schedule listed in the Index at Item 15(a) of Tampa Electric Company included in this Annual Report (Form 10-K) for the year ended December 31, 2023.

/s/ Ernst & Young LLP

Tampa, Florida

February 26, 2024

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Archie Collins, certify that:

1.I have reviewed this annual report on Form 10-K 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: February 26, 2024	/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 annual report on Form 10-K 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: February 26, 2024	/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 Annual Report on Form 10-K of the Company for the year ended December 31, 2023 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-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 26, 2024	/s/	ARCHIE COLLINS
		ARCHIE COLLINS
		President and Chief Executive Officer
		(Principal Executive Officer)

Dated: February 26, 2024	/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 signatures that appear 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-K and shall not be considered filed as part of the Form 10-K.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 20, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2023
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction [Flag]	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Filer Category	Non-accelerated Filer
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 Annual Report	true
Document Transition Report	false
Entity Interactive Data Current	Yes
Entity Common Stock, Shares Outstanding		10
Entity Public Float			$ 0
Auditor Name	Ernst & Young LLP
Auditor Location	Tampa, Florida
Auditor Firm ID	42

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, plant and equipment
Utility plant, at original costs	$ 13,655	$ 15,474
Accumulated depreciation	(3,443)	(3,845)
Utility plant, net	10,212	11,629
Other property	16	15
Total property, plant and equipment, net	10,228	11,644
Current assets
Cash and cash equivalents	5	14
Receivables, less allowance for credit losses of $2 and $4 at December 31, 2023 and 2022, respectively	286	295
Inventories, at average cost
Regulatory assets	161	361
Prepayments and other current assets	32	35
Total current assets	720	909
Other assets
Regulatory assets	827	1,191
Deferred charges and other assets	56	59
Total other assets	883	1,250
Total assets	11,831	13,803
Capitalization
Common stock	4,505	5,075
Accumulated other comprehensive loss	(1)	(1)
Retained earnings	219	346
Total capital	4,723	5,420
Long-term debt	3,933	3,734
Total capital	8,656	9,154
Current liabilities
Long-term debt due within one year	300	0
Notes payable	209	1,019
Accounts payable	354	472
Customer deposits	121	145
Regulatory liabilities	94	85
Accrued interest	28	30
Accrued taxes	14	15
Other	43	45
Total current liabilities	1,173	2,037
Other liabilities
Deferred income taxes	880	1,045
Regulatory liabilities	701	1,055
Investment tax credits	237	243
Deferred credits and other liabilities	184	269
Total Other liabilities	2,002	2,612
Commitments and Contingencies (see Note 8)
Total liabilities and capital	11,831	13,803
Related Party [Member]
Current assets
Due from affiliates	19	22
Current liabilities
Due to affiliates	10	226
Fuel [Member]
Inventories, at average cost
Utility inventories	36	23
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	181	159
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	13,655	12,536
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 0	$ 2,938

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Allowance for credit losses	$ 2	$ 4

XML

Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues
Electric	$ 2,637	$ 2,519	$ 2,170
Gas	0	650	525
Total revenues	2,637	3,169	2,695
Expenses
Fuel	605	676	604
Purchased power	78	151	106
Cost of natural gas sold	0	257	155
Operations & maintenance	595	619	566
Depreciation and amortization	422	436	430
Taxes, other than income	234	257	228
Total expenses	1,934	2,396	2,089
Income from operations	703	773	606
Other income
Allowance for other funds used during construction	19	35	45
Interest income from affiliates	38	0	0
Other income, net	32	20	5
Total other income	89	55	50
Interest charges
Interest expense	234	178	151
Interest expense to affiliates	11	0	0
Allowance for borrowed funds used during construction	(6)	(11)	(21)
Total interest charges	239	167	130
Income before provision for income taxes	553	661	526
Provision for income taxes	87	121	80
Net income	466	540	446
Comprehensive income	$ 466	$ 540	$ 446

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from or used in operating activities
Net income	$ 466	$ 540	$ 446
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization	422	436	430
Deferred income taxes and investment tax credits	(22)	137	28
Allowance for equity funds used during construction	(19)	(35)	(45)
Deferred recovery clauses	415	(422)	(58)
Regulatory assets and liabilities	116	(100)	(10)
Pension and post-retirement asset and liabilities	(23)	(18)	(10)
Other	14	(1)	23
Changes in working capital:
Receivables, less allowance for credit losses	(44)	(45)	(32)
Inventories	(39)	(41)	(8)
Taxes accrued	12	(23)	(13)
Accounts payable	(56)	75	53
Other	(1)	8	(7)
Cash flows from operating activities	1,241	511	797
Cash flows from or used in investing activities
Capital expenditures	(1,294)	(1,427)	(1,397)
Net proceeds from sale of assets	0	10	0
Cash flows used in investing activities	(1,294)	(1,417)	(1,397)
Cash flows from or used in financing activities
Equity contributions from Parent	300	605	580
Dividends to Parent	(472)	(517)	(450)
Proceeds from long-term debt issuance	0	595	790
Repayment of long-term debt	0	(250)	(279)
Advances to affiliate	(227)	0	0
Repayment of advances to affiliate	956	0	0
Advances from Parent	0	195	0
Repayment of advances from Parent	(195)	0	0
Net change in short-term debt (maturities of 90 days or less)	87	374	(230)
Proceeds from other short-term debt (maturities over 90 days)	400	400	500
Repayment of other short-term debt (maturities over 90 days)	(800)	(500)	(300)
Other financing activities	(1)	0	(3)
Cash flows from financing activities	48	902	608
Net increase (decrease) in cash and cash equivalents	(5)	(4)	8
Cash and cash equivalents at beginning of the year	10
Cash and cash equivalents at beginning of the year	14	18	10
Cash and cash equivalents at end of the year	5	14	18
Supplemental disclosure of cash paid (received):
Interest	233	152	120
Income taxes	102	2	62
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	20	(6)	25
Reclassification of short-term debt to long-term debt	497	0	0
Change in note receivable from PGS	$ (736)	$ 0	$ 0

XML

Consolidated Statements of Capitalization - Capital Stock - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Beginning balance	$ 5,420	$ 4,792	$ 4,216
Net income	466	540	446
Separation of PGS equity from TEC	(992)
Equity contributions from Parent	300	605	580
Dividends to Parent	(472)	(517)	(450)
Other	1
Ending balance	4,723	5,420	4,792
Common Stock [Member]
Beginning balance	$ 5,075	$ 4,470	$ 3,890
Beginning balance	10	10	10
Separation of PGS equity from TEC	$ (871)
Equity contributions from Parent	300	$ 605	$ 580
Other	1
Ending balance	$ 4,505	$ 5,075	$ 4,470
Ending balance	10	10	10
Retained Earnings [Member]
Beginning balance	$ 346	$ 323	$ 327
Net income	466	540	446
Separation of PGS equity from TEC	(121)
Dividends to Parent	(472)	(517)	(450)
Ending balance	219	346	323
Accumulated Other Comprehensive Loss [Member]
Beginning balance	(1)	(1)	(1)
Ending balance	$ (1)	$ (1)	$ (1)

XML

Consolidated Statements of Capitalization - Capital Stock (Parenthetical)	Dec. 31, 2023 $ / shares shares
Preferred stock - par value | $ / shares	$ 100
Common equity, shares authorized	25,000,000
Preferred Stock Par Value [Member]
Preferred stock, shares authorized	1,500,000
Preferred stock, shares outstanding	0
Preferred Stock No Par Value [Member]
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0
Preferred stock, no par value | $ / shares	$ 0
Preference Stock No Par Value Subordinate to the Preferred Stock [Member]
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0
Preferred stock, no par value | $ / shares	$ 0

XML

Consolidated Statements of Capitalization - Long-Term Debt - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term debt, total	$ 4,275	$ 3,775
Unamortized debt discount, net	(14)	(11)
Debt issuance costs	(28)	(30)
Long-term debt, carrying amount	4,233	3,734
Less amount due within one year	300	0
Total long-term debt	3,933	3,734
Long-term debt, fair value	3,831	3,234
LongTerm Debt Reclassification [Member]
Debt Instrument [Line Items]
Long-term debt, total	500	0
Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 3,775	3,205
Tampa Electric [Member] | 3.88% Notes [Member]
Debt Instrument [Line Items]
Due	2024
Long-term debt, total	$ 300	263
Tampa Electric [Member] | 2.40% Notes [Member]
Debt Instrument [Line Items]
Due	2031
Long-term debt, total	$ 400	285
Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	$ 250	250
Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	$ 250	190
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 300	250
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$ 300	290
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2045
Long-term debt, total	$ 250	230
Tampa Electric [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Due	2048
Long-term debt, total	$ 350	275
Tampa Electric [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Due	2049
Long-term debt, total	$ 375	350
Tampa Electric [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Due	2050
Long-term debt, total	$ 300	275
Tampa Electric [Member] | 3.45% Notes [Member]
Debt Instrument [Line Items]
Due	2051
Long-term debt, total	$ 400	285
Tampa Electric [Member] | 5.00% Notes [Member]
Debt Instrument [Line Items]
Due	2052
Long-term debt, total	$ 300	262
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 0	570
PGS [Member] | 3.88% Notes [Member]
Debt Instrument [Line Items]
Due	2024
Long-term debt, total	$ 0	38
PGS [Member] | 2.40% Notes [Member]
Debt Instrument [Line Items]
Due	2031
Long-term debt, total	$ 0	115
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	$ 0	60
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 0	50
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$ 0	10
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2045
Long-term debt, total	$ 0	20
PGS [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, total	0	75
PGS [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 0	25
PGS [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Due	2050
Long-term debt, total	$ 0	25
PGS [Member] | 3.45% Notes [Member]
Debt Instrument [Line Items]
Due	2051
Long-term debt, total	$ 0	115
PGS [Member] | 5.00% Notes [Member]
Debt Instrument [Line Items]
Due	2052
Long-term debt, total	$ 0	$ 37

XML

Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Jul. 12, 2022	Mar. 18, 2021
Debt Instrument [Line Items]
Long-term debt, total	$ 4,275	$ 3,775
2.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate				2.40%
3.45% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate				3.45%
5.00% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate			5.00%
LongTerm Debt Reclassification [Member]
Debt Instrument [Line Items]
Long-term debt, total	500	0
Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 3,775	3,205
Tampa Electric [Member] | 3.88% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.88%
Long-term debt, total	$ 300	263
Tampa Electric [Member] | 2.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.40%
Long-term debt, total	$ 400	285
Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.55%
Long-term debt, total	$ 250	250
Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
Long-term debt, total	$ 250	190
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Long-term debt, total	$ 300	250
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
Long-term debt, total	$ 300	290
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
Long-term debt, total	$ 250	230
Tampa Electric [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.30%
Long-term debt, total	$ 350	275
Tampa Electric [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.45%
Long-term debt, total	$ 375	350
Tampa Electric [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.63%
Long-term debt, total	$ 300	275
Tampa Electric [Member] | 3.45% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.45%
Long-term debt, total	$ 400	285
Tampa Electric [Member] | 5.00% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
Long-term debt, total	$ 300	262
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 0	570
PGS [Member] | 3.88% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.88%
Long-term debt, total	$ 0	38
PGS [Member] | 2.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.40%
Long-term debt, total	$ 0	115
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
Long-term debt, total	$ 0	60
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Long-term debt, total	$ 0	50
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
Long-term debt, total	$ 0	10
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
Long-term debt, total	$ 0	20
PGS [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, total	0	75
PGS [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, total	$ 0	25
PGS [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.63%
Long-term debt, total	$ 0	25
PGS [Member] | 3.45% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.45%
Long-term debt, total	$ 0	115
PGS [Member] | 5.00% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.00%
Long-term debt, total	$ 0	$ 37

XML

Consolidated Statements of Capitalization - Long-term Debt Maturities $ in Millions	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
Total Long-Term Debt	$ 4,275
Long Term Debt Maturities
Debt Instrument [Line Items]
2024	300
2025	0
2026	0
2027	0
2028	0
Thereafter	3,975
Total Long-Term Debt	4,275
Tampa Electric [Member]
Debt Instrument [Line Items]
2024	300
2025	0
2026	0
2027	0
2028	0
Thereafter	3,975
Total Long-Term Debt	4,275
Total Long-Term Debt	$ 3,775

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Significant Accounting Policies

1. Significant Accounting Policies

Description of the Business

TEC is comprised of the electric division, referred to as Tampa Electric, and prior to January 1, 2023, also included the natural gas division, referred to as PGS. Tampa Electric provides retail electric services in West Central Florida, and PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. See "Separation of PGS from TEC" below for information regarding the separation that occurred on January 1, 2023. TEC’s significant accounting policies are as follows:

Principles of Consolidation and Basis of Presentation

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. 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.

TEC is a wholly owned subsidiary of TECO Energy, Inc. TEC contains the electric division, and prior to January 1, 2023, also included the natural gas division. Prior to January 1, 2023, intercompany balances and transactions within the divisions have been eliminated in consolidation. TECO Energy is a wholly owned indirect subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

As a regulated utility, TEC must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation. The original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2023			December 31, 2022
Electric generation	10-60 years	$	6,732		$	6,300
Electric transmission	10-75 years		1,182			1,109
Electric distribution	10-60 years		3,609			3,296
Gas transmission and distribution	15-75 years	0				2,567
General plant and other	4-60 years		997			1,020
Total cost			12,520			14,292
Less Tampa Electric accumulated depreciation			(3,443	)		(3,158	)
Less PGS accumulated depreciation		0				(687	)
Tampa Electric construction work in progress			1,151			949
PGS construction work in progress		0				248
Total property, plant and equipment, net		$	10,228		$	11,644

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.2% and 3.5% for 2023, 2022 and 2021, respectively. Construction work in progress is not depreciated until the asset is placed in service. TEC's total depreciation expense for the years ended December 31, 2023, 2022 and 2021 was $390 million, $402 million and $408 million, respectively. For the year ended December 31, 2023, 2022 and 2021, Tampa Electric's depreciation expense was $390 million, $359 million and $357 million, respectively.

TEC computes depreciation and amortization using the following methods:

•the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

•the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rates used to calculate AFUDC are revised periodically to reflect significant changes in cost of capital. In 2023, 2022 and 2021, Tampa Electric’s rate was 6.07%, 6.00% and 6.46%, respectively. PGS’s rate used to calculate its AFUDC in 2022 and 2021 was 6.00%. Total AFUDC for the years ended December 31, 2023, 2022 and 2021 was $25 million, $46 million and $66 million, respectively.

Inventory

TEC values materials, supplies and fossil fuel inventory (natural gas and coal) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or net realizable value.

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3).

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details.

Investment and Production Tax Credits (PTCs)

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense as required by regulatory practices. TEC recognizes a reduction of income tax expense for PTCs earned by its eligible solar assets. The PTCs are based on per kwH rate prescribed by applicable federal statutes.

Stranded Tax Effects in Accumulated Other Comprehensive Income

TEC utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released.

Revenue Recognition

Regulated electric revenue

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. Tampa Electric’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWH delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, timing of meter reads and line losses.

Regulated gas revenue

Prior to January 1, 2023, gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, were recognized when obligations under the terms of a contract were satisfied. This occurred primarily when gas was delivered to customers over time as the customer simultaneously received and consumed the benefits of the gas. Gas revenues were recognized on an accrual basis and included billed and unbilled revenues. Revenues related to the distribution and sale of gas were recognized at rates approved by the regulator and recorded based on metered usage, which occurred on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, was estimated and the corresponding unbilled revenue was recognized. PGS’s estimate of unbilled revenue at the end of the reporting period was calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate included assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

Other

See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue.

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation, environmental and storm protection plan costs for Tampa Electric and, prior to January 1, 2023, purchased gas, interstate pipeline capacity, replacement of cast iron/bare steel pipe and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are recognized.

Receivables and Allowance for Credit Losses

Receivables on the Consolidated Balance Sheets include receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, totaling $284 million and $295 million as of December 31, 2023 and 2022, 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 impact estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2023 and 2022, unbilled revenues of $63 million and $82 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Accounting for Franchise Fees and Gross Receipts Taxes

TEC is allowed to recover certain costs incurred on a dollar-for-dollar basis from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $139 million, $145 million and $129 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of pension assets net of accrued pension liabilities (see Note 5) and right-of-use assets related to operating leases (see Note 13).

Deferred Credits and Other Liabilities

Other deferred credits primarily include accrued other postretirement benefits (see Note 5), MGP environmental remediation liability prior to January 1, 2023 (see Note 8), asset retirement obligations (see Note 12), lease liabilities (see Note 13) and a reserve for auto, general and workers’ compensation liability claims.

TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2023 and 2022 ranged from 4.00% to 5.99% and 4.00% to 5.78%, respectively.

Derivatives and Hedging Activities

TEC had $1 million and $5 million derivative assets as of December 31, 2023 and 2022, respectively, and $0 and $1 million derivative liabilities as of December 31, 2023 and December 31, 2022, respectively.

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2023 and 2022, all of TEC’s physical contracts qualified for the NPNS exception, which was elected.

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Separation of PGS from TEC

PGS became an operating division of TEC in 1997 when TECO Energy purchased PGS and merged that corporation into TEC. Since then, PGS has operated as a stand-alone regulated utility, including having its own tariff and its own books and records.

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. (PGSI) pursuant to a Contribution Agreement. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. On January 1, 2023, the assets, liabilities, and equity that had been recorded in the books of PGS were transferred from TEC to the newly formed PGSI at book value in a tax-free transaction. PGSI issued 100 shares of common stock to TEC related to the transfer of PGS, which were subsequently distributed to TECO Energy, Inc. and then contributed to TECO Gas Operations, Inc. This is a transaction between entities under common control; therefore, TEC did not recognize a gain or loss on the transaction. TEC is not required to recast its prior period financial statements and disclosures to exclude PGS prior to January 1, 2023. The TEC Consolidated Statement of Cash Flows for the year ended December 31, 2023 does not include the non-cash impact of separating the PGS assets, liabilities and equity from TEC on January 1, 2023 and excludes PGS’s opening cash balance.

The impact of the separation of PGS from TEC on the Consolidated Statements of Capital for the year ended December 31, 2023 was $992 million, which represents the net assets of PGS transferred as of January 1, 2023. TEC recorded $121 million to

retained earnings, which was the retained earnings of PGS as of January 1, 2023, and the remainder of $871 million was recorded to additional paid in capital, which is presented with common stock.

Prior to the separation, as a division of TEC, PGS had received an allocation of outstanding unsecured notes and outstanding short-term borrowings issued by TEC. The obligations related to these combined borrowings were reflected in an affiliate loan agreement between TEC and PGS. The initial obligation of PGS under the loan agreement at January 1, 2023 was a term loan in the principal amount of $670 million and a revolving loan in the principal amount of $66 million. The maturity date for both was December 29, 2023. On December 20, 2023, PGS repaid Tampa Electric the outstanding principal amount of the term loan and revolving loan of $670 million and $286 million, respectively, plus outstanding interest. The repayment terminates the affiliate loan agreement and Tampa Electric will no longer provide capital for the operations of PGS. See Note 6 for further information.

See Note 11 for certain financial information related to PGS. In addition, the following table presents the assets and liabilities of PGS in TEC’s Consolidated Balance Sheet as of December 31, 2022:

	December 31,
(millions)	2022
Property, plant and equipment
Utility plant	$	2,938
Accumulated depreciation		(687	)
Total property, plant and equipment, net		2,251
Current assets
Cash and cash equivalents		4
Receivables, less allowance for credit losses of $1 at December 31, 2022		62
Due from affiliates		4
Inventories, at average cost
Materials and supplies		5
Regulatory assets		9
Prepayments and other current assets		4
Total current assets		88
Other assets
Regulatory assets		53
Deferred charges and other assets		79
Total other assets		132
Total assets	$	2,471
Capitalization
Common stock	$	871
Retained earnings		121
Total capital		992
Long-term debt		564
Total capital		1,556
Current liabilities
Notes payable		166
Accounts payable		78
Due to affiliates		27
Customer deposits		30
Regulatory liabilities		11
Accrued interest		4
Accrued taxes		5
Other		4
Total current liabilities		325
Other liabilities
Deferred income taxes		238
Regulatory liabilities		277
Deferred credits and other liabilities		75
Total other liabilities		590

Total liabilities and capital $ 2,471

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New Accounting Pronouncements

12 Months Ended

Dec. 31, 2023

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. TEC was not required to and did not adopt any new ASUs in 2023. The following update has been issued by FASB, but have not yet been adopted by TEC. Any ASUs not included below were assessed and determined to be either not applicable to TEC or have insignificant impact on the consolidated financial statements.

Reportable Segment Disclosures

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. TEC is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

Income Tax Disclosures

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard enhances the transparency, decision usefulness and effectiveness of income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (benefit) in accordance with U.S. Securities and Exchange Commission (SEC) Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax Expense, and the removal of disclosures no longer considered cost beneficial or relevant. The guidance will be effective for annual reporting periods beginning after December 15, 2024, and interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. TEC is currently evaluating the impact of adoption of the standard on its consolidated financial statements.

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Regulatory

12 Months Ended

Dec. 31, 2023

Regulated Operations [Abstract]

Regulatory

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. The FPSC sets rates based on a cost of service methodology which allows utilities to collect total revenues (revenue requirements) equal to their prudently incurred cost of providing service or products, plus a reasonable return on equity invested or assets. As a result, Tampa Electric and PGS qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between U.S. GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred. In addition to regulatory assets and regulatory liabilities, rate regulation impacts other financial statement balances and activity, including, but not limited to, property, plant, and equipment, revenues, and expenses.

Tampa Electric Base Rates

Tampa Electric’s results for 2021 reflected an amended and restated settlement agreement, approved by the FPSC on November 6, 2017, that replaced the previous 2013 base rate settlement agreement and extended it another four years through 2021. The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. Under the agreement, the allowed equity in the capital structure was 54% from investor sources of capital. The amended agreement provided for SoBRAs for Tampa Electric’s substantial investments in solar generation. Tampa Electric invested approximately $850 million in these solar projects during 2017 to 2021 and accrued AFUDC during construction. The agreement included a sharing provision that allowed customers to benefit from 75% of any cost savings for projects below $1,500/kWac. The 2017 settlement agreement further contained a provision related to tax reform. An asset optimization provision that allows Tampa Electric to share in

the savings for optimization of its system once certain thresholds are achieved is also included. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make no investments in gas reserves.

On August 6, 2021, Tampa Electric 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 Tampa Electric and the intervenors in Tampa Electric’s rate case filed with the FPSC in April 2021. The Settlement Agreement agreed 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 included 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 continued to be 54% from investor sources of capital. The Settlement Agreement included 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 Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contained a provision whereby Tampa Electric 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 created 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 that agreement. The Settlement Agreement set new depreciation and dismantlement rates effective January 1, 2022 and contained the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2024. On October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting such approval, was issued on November 10, 2021.

Tampa Electric's 2021 settlement agreement provision allowed Tampa Electric to request a revenue and ROE increase due to increases in the 30-year U.S. Treasury bond yield rate. On July 1, 2022, Tampa Electric requested to adjust its base rates to collect an additional $10 million annually (prorated in the first year) effective September 1, 2022 and increase its mid-point ROE and upper and lower allowed ranges. On August 16, 2022, the FPSC approved the change. The new mid-point ROE is 10.20%, and the range is 9.25% to 11.25% effective July 1, 2022.

On August 16, 2023, Tampa Electric filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 Settlement Agreement. Inclusive of Tampa Electric’s ROE adjustment, the increase of $22 million was approved by the FPSC and the order reflecting such approval was issued on November 17, 2023, effective in January 2024.

On February 1, 2024, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting a revenue requirement increase of approximately $290 to $320 million, effective in January 2025, and additional adjustments of approximately $100 million and $70 million for 2026 and 2027, respectively. Tampa Electric’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until Tampa Electric completes its analysis and files the case in April 2024. The FPSC will hear the case in the third quarter of 2024 with a decision expected by the end of 2024.

Tampa Electric Big Bend Modernization Project

Tampa Electric invested $876 million, including $91 million of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The Big Bend modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the Big Bend modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric retired Big Bend Unit 3 in 2023 as it is in the best interest of customers from economic, environmental risk and operational perspectives.

At December 31, 2020, Tampa Electric’s balance sheet included $636 million in electric utility plant and $267 million in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric continued to account for its investment in Units 1, 2 and 3 in electric utility plant and depreciated the assets using the current depreciation rates until December 31, 2021, at which point they were reclassified to a regulatory asset on the balance sheet.

Tampa Electric’s Settlement Agreement provided recovery for the Big Bend modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs was recovered as part of the 2023 subsequent year adjustment. The Settlement Agreement also included 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 term of the Settlement Agreement. The special capital recovery schedule for all three units was 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.

In January 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million beginning April 1, 2022 through December 2022 due to an increase in fuel commodity and capacity costs. On March 1, 2022, the FPSC voted to approve the mid-course adjustment, and the order reflecting such approval was issued on March 18, 2022.

On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the $518 million final 2022 fuel under-recovery over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The changes were approved by the FPSC on March 7, 2023, effective April 1, 2023.

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 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. A settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in January 2021. The current approved plan addresses the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022.

Tampa Electric Storm Restoration Cost Recovery

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. Once the storm reserve regulatory liability is exhausted, TEC may petition the FPSC for recovery. This provision was also included in Tampa Electric’s subsequent 2017 amended and restated settlement agreement and in Tampa Electric’s 2021 rate case settlement agreement. In 2021, 2020 and 2019, Tampa Electric incurred total storm restoration costs for multiple hurricanes of approximately $10 million, which was charged to the storm reserve regulatory liability.

In September 2022, Tampa Electric was impacted by Hurricane Ian. Total storm restoration costs were $129 million, with $121 million charged to the storm reserve. Restoration costs charged to the storm reserve exceeded the storm reserve balance and this amount was deferred to be collected from customers in subsequent periods. In November 2022, Tampa Electric incurred costs of approximately $2 million related to Hurricane Nicole. In January 2023, Tampa Electric petitioned the FPSC for recovery of costs associated with Hurricanes Ian and Nicole that exceeded the reserve, $10 million of storm restoration costs charged to the reserve since 2018, and the replenishment of the balance in the reserve to the $56 million level that existed as of October 31, 2013 for a total of approximately $131 million. The storm cost recovery surcharge was approved by the FPSC on March 7, 2023, and Tampa Electric began applying the surcharge on April 2023 bills. Subsequently, on November 9, 2023, the FPSC approved Tampa Electric’s petition filed on August 16, 2023 to update the total storm cost collection from $129 million to approximately $134 million and change the collection of the expected remaining balance of approximately $29 million as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC and issuance of an order by the FPSC is expected to occur by the third quarter of 2024.

In September 2023, Tampa Electric was impacted by Hurricane Idalia. The related storm restoration costs were approximately $35 million, which were charged to the storm reserve regulatory asset and not included in the petition above. Tampa Electric will determine the timing of the request for recovery of Hurricane Idalia costs at a future time.

PGS Base Rates

PGS’s results for 2022 and 2021 reflected a rate case settlement agreement filed by PGS and OPC and approved by the FPSC on November 19, 2020. 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, including the ability to reverse a total of $34 million of accumulated depreciation through 2023. During 2022, PGS reversed $14 million of the $34 million accumulated depreciation. No amounts were reversed prior to 2022.

Regulatory Assets and Liabilities

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

Regulatory Assets and Liabilities

	December 31,		December 31,
(millions)	2023		2022
Regulatory assets:
Regulatory tax asset (1)	$	112	$	124
Cost-recovery clauses (2)		94		525
Capital cost recovery for early retired assets (3)		507		497
Environmental remediation (4)		0		20
Postretirement benefits (5)		236		272
Storm reserve (6)		7		76
Other		32		38
Total regulatory assets		988		1,552
Less: Current portion		161		361
Long-term regulatory assets	$	827	$	1,191
Regulatory liabilities:
Regulatory tax liability (7)	$	477	$	601
Cost-recovery clauses - deferred balances (2)		20		30
Accumulated reserve—cost of removal (8)		271		498
Other		27		11
Total regulatory liabilities		795		1,140
Less: Current portion		94		85
Long-term regulatory liabilities	$	701	$	1,055

(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.

(2)These assets and liabilities are related to FPSC clauses and riders, primarily related to the fuel clause and the increase in natural gas prices experienced in 2022. 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 regulatory asset is related to the remaining net book value of Big Bend Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years. See “Tampa Electric Big Bend Modernization Project” above for further information.

(4)This asset was related to PGS costs associated with environmental remediation primarily at MGP sites. See Note 1 for information regarding the separation of PGS from TEC.

(5)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.

(6)See "Tampa Electric Storm Restoration Cost Recovery" above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC.

(7)The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower corporate 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.

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

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

4. Income Taxes

Change in Florida Corporate Income Tax Rate

On September 14, 2021, the state of Florida issued a corporate tax rate reduction from 4.46% to 3.53% effective January 1, 2021 through December 31, 2021. In 2021, TEC recorded a $4 million regulatory liability in recognition of its obligation to pass the tax rate reduction expense benefit to customers per the 2017 settlement agreement. Effective January 1, 2022, the Florida corporate income tax rate is 5.5%.

Inflation Reduction Act

On August 16, 2022, the Inflation Reduction Act was signed into legislation and includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024, the expansion of ITC for energy storage technology beginning 2023 and introduces new technology-neutral clean energy related credits beginning in 2025. TEC has determined that electing production tax credits for its solar plants placed in service in 2022 and 2023 will be more beneficial for customers compared to ITCs and has recorded a regulatory liability in recognition of its obligation to pass the tax benefits to customers of $23 million and $7 million as of December 31, 2023 and 2022, respectively.

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 of TECO Energy and EUSHI. To the extent that TEC’s cash tax positions are settled differently than the amount reported as realized under the tax sharing agreement, the difference is accounted for as either a capital contribution or a distribution.

In 2023, 2022 and 2021, TEC recorded net tax provisions of $87 million, $121 million and $80 million, respectively.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2023			2022			2021
Current income taxes
Federal	$	84		$	(13	)	$	48
State		25			(3	)		4
Deferred income taxes
Federal		(19	)		105			24
State		5			38			13
Investment tax credits amortization		(8	)		(6	)		(9	)
Total income tax expense	$	87		$	121		$	80

During 2022, TEC increased its net operating loss carryforward. Total current income tax expense for the year ended December 31, 2022, was reduced by $59 million to reflect the benefits of operating loss carryforwards.

For the three years presented, the overall effective tax rate differs from the U.S. federal statutory rate as presented below:

Effective Income Tax Rate

(millions)
For the year ended December 31,	2023			2022			2021
Income before provision for income taxes	$	553		$	661		$	526
Federal statutory income tax rates		21	%		21	%		21	%
Income taxes, at statutory income tax rate		116			139			110
Increase (decrease) due to
State income tax, net of federal income tax		23			27			13
Excess deferred tax amortization		(25	)		(25	)		(26	)
ITC amortization		(8	)		(6	)		(9	)
AFUDC-equity		(4	)		(7	)		(9	)
Production Tax Credits		(15	)		(6	)		0
Other Tax credits		(4	)		(3	)		(3	)
Other		4			2			4
Total income tax expense on consolidated statements of income	$	87		$	121		$	80
Income tax expense as a percent of income before income taxes		15.7	%		18.3	%		15.2	%

Deferred Income Taxes

Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

(millions)
As of December 31,	2023		2022
Deferred tax liabilities (1)
Property related	$	1,227	$	1,318
Deferred fuel		23		133
Pension and postretirement benefits		100		111
Insurance reserves		0		15
Total deferred tax liabilities		1,350		1,577
Deferred tax assets (1)
Loss and credit carryforwards (2)		383		408
Medical benefits		19		24
Insurance reserves		1		0
Pension and postretirement benefits		49		57
Capitalized energy conservation assistance costs		0		23
Other		18		20
Total deferred tax assets		470		532
Total deferred tax liability, net	$	880	$	1,045

(1)Certain property related assets and liabilities have been netted. At December 31, 2022, PGS total deferred tax liabilities and deferred tax assets were $213 million and $37 million, respectively, with the majority of the balances related to property and capitalized energy conservation assistance costs.

(2)Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $10 million and $9 million at December 31, 2023 and 2022, respectively.

The expiration of TEC's tax credits and NOL carryforwards are as follows:

(millions)	December 31, 2023		Expiration Year
General business credits	$	324	2027-2043
Federal NOL carryforwards		135	2037
Federal NOL carryforwards (1)		199	indefinite
State NOL carryforwards (1)		305	indefinite
Total tax credits and NOL carryforwards	$	963

(1)Indefinite carryforward for Federal NOLs and NOLs for states that have adopted the U.S. Tax Cuts and Jobs Act of 2017 provisions, generated in tax years beginning after December 31, 2017.

TEC has unused general business credits of $324 million expiring between 2027 and 2043, of which $266 million relate to ITCs expiring between 2034 and 2043. As a result of TECO Energy's merger with Emera in 2016, TECs NOLs and credits will be utilized by EUSHI, in accordance with the benefits-for-loss allocation which provide that tax attributes are utilized by the consolidated tax return group of EUSHI.

Unrecognized Tax Benefits

TEC accounts for uncertain tax positions as required by U.S. GAAP. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.

The following table provides details of the change in unrecognized tax benefits as follows:

(millions)	2023		2022		2021
Balance at January 1,	$	9	$	6	$	9
Increases due to tax positions related to prior year	0		2		1
Increases due to tax positions related to current year	1		1		1
Decreases due to settlements with tax authorities	0		0			(5	)
Balance at December 31,	$	10	$	9	$	6

As of December 31, 2023 and 2022, TEC’s uncertain tax positions for federal R&D tax credits were $10 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 2021 by approximately $5 million due to the resolution of its 2016 federal tax credits issue with IRS Appeals. The settlement of the federal R&D credits audit did not impact the effective tax rate during 2021. The unrecognized tax benefits, if recognized, would reduce TEC’s effective tax rate.

TEC recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance expense” in the Consolidated Statements of Income. In 2023, 2022 and 2021, TEC did not recognize any pre-tax charges (benefits) for interest. Additionally, TEC did not have any accrued interest or amounts recorded for penalties at December 31, 2023, 2022 and 2021.

The U.S. federal statute of limitations remains open for the year 2017 and forward. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized.

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Employee Postretirement Benefits

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Pension Benefits

TEC is a participant in the retirement plans of TECO Energy, including a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.

Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP and the unfunded obligations of the Restoration Plan. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. The Restoration Plan is a non-qualified, non-contributory defined benefit retirement plan that allows certain members of senior management to receive contributions as if no IRS limits were in place.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (other benefits) for most employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.

TECO Energy has made a change to the postretirement health plan to replace the pharmacy services provider. The change was treated as a plan amendment and the plan was remeasured as of September 30, 2023. See "Plan Amendments" line item in the "Obligations and Plan Assets" table below.

Obligations and Funded Status

TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted.

The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and TECO Energy’s Florida-based other postretirement benefit plan (other benefits).

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2023			2022			2023			2022
Change in benefit obligation
Benefit obligation at beginning of year	$	666		$	850		$	142		$	200
Service cost		15			18			1			2
Interest cost		35			23			7			5
Plan participants’ contributions		0			0			4			4
Benefits paid		(59	)		(79	)		(19	)		(19	)
Actuarial loss (gain)		27			(142	)		7			(50	)
Plan amendments		0			0			(10	)		0
Plan settlements (3)		(6	)		(4	)		0			0
Benefit obligation at end of year	$	678		$	666		$	132		$	142

Change in plan assets
Fair value of plan assets at beginning of year	$	650		$	924		$	0		$	0
Actual gain (loss) return on plan assets		78			(214	)		0			0
Employer contributions		16			18			0			0
Employer direct benefit payments		7			5			15			15
Plan participants’ contributions		0			0			4			4
Benefits paid		(58	)		(78	)		0			0
Direct benefit payments		(1	)		(1	)		(19	)		(19	)
Plan settlements (3)		(6	)		(4	)		0			0
Fair value of plan assets at end of year (1)	$	686		$	650		$	0		$	0

(1)The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

(2)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

(3)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

Increases in the benefit obligation for the period ended December 31, 2023 are the result of decreases in the discount rate used to calculate the benefit obligation and the updating of the salary assumption as the result of an experience study performed during the year.

At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with projected benefit obligations and accumulated projected benefit obligations in excess of plan assets was as follows:

TECO Energy	Pension Benefits					Other Benefits (1)
Funded Status
(millions)	2023		2022			2023			2022
Benefit obligation (PBO/APBO)	$	678	$	666		$	132		$	142
Less: Fair value of plan assets		686		650			0			0
Funded status at end of year	$	8	$	(16	)	$	(132	)	$	(142	)

(1)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $642 million at December 31, 2023 and $634 million at December 31, 2022.

The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations and plan assets at December 31 were as follows:

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2023			2022			2023			2022
Noncurrent assets	$	10		$	0		$	0		$	0
Accrued benefit costs and other current liabilities		0			(7	)		(10	)		(12	)
Deferred credits and other liabilities		(1	)		(9	)		(99	)		(121	)
	$	9		$	(16	)	$	(109	)	$	(133	)

Unrecognized gains and losses and prior service credits and costs are recorded in regulatory assets for TEC. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2023		2022		2023		2022
Net actuarial loss	$	207	$	242	$	29	$	30
Amount recognized	$	207	$	242	$	29	$	30

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2023			2022			2023			2022
Discount rate		5.27	%		5.55	%		5.28	%		5.53	%
Rate of compensation increase		4.42	%		3.79	%		4.42	%		3.79	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.09	%		6.39	%
Ultimate rate	n/a			n/a				4.00	%		4.00	%
Year rate reaches ultimate trend rate	n/a			n/a			2047			2047

The discount rate assumption used to determine the December 31, 2023 and 2022 benefit obligation was based on a cash flow matching technique that matches yields from high-quality (AA-rated, non-callable) corporate bonds to TECO Energy’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption.

Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets

TECO Energy	Pension Benefits									Other Benefits (1)
	2023			2022			2021			2023			2022			2021
(millions)
Service cost	$	15		$	18		$	19		$	1		$	2		$	2
Interest cost		35			23			21			7			5			5
Expected return on plan assets		(54	)		(51	)		(52	)		0			0			0
Amortization of:
Actuarial loss		5			17			24			0			3			4
Prior service cost		0			0			0			(2	)		(2	)		(2	)
Settlement loss (2)		2			2		0				0			0			0
Net periodic benefit cost	$	3		$	9		$	12		$	6		$	8		$	9

Net loss (gain) arising during the year (includes curtailment gain)		2			123			(56	)		7			(50	)		(5	)
Prior service cost	$	0		$	0		$	0		$	(11	)	$	0		$	0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service credit		0			0			0			3			2			2
Amortization or settlement of actuarial loss		(7	)		(19	)		(23	)		0			(3	)		(4	)
Total recognized in OCI and regulatory assets	$	(5	)	$	104		$	(79	)	$	(1	)	$	(51	)	$	(7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(2	)	$	113		$	(67	)	$	5		$	(43	)	$	2

(1)Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

(2)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

TEC’s portion of the net periodic benefit costs for pension benefits was $1 million, $8 million and $10 million for 2023, 2022 and 2021, respectively. Tampa Electric’s portion of the net periodic benefit costs for pension benefits was $1 million, $4 million and $7 million for 2023, 2022 and 2021, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $5 million, $9 million and $11 million for 2023, 2022 and 2021, respectively. Tampa Electric’s portion of the net periodic benefit costs for other benefits was $5 million, $8 million and $9 million for 2023, 2022 and 2021, respectively. Net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Statements of Income in “Operations & maintenance”.

Assumptions used to determine net periodic benefit cost for years ended December 31:

	Pension Benefits									Other Benefits
	2023			2022			2021			2023			2022			2021
Discount rate (1)	4.19%-5.55%				2.77	%		2.37	%	5.53%-6.14%				2.84	%		2.47	%
Expected long-term return on plan assets		7.05	%		6.50	%		6.70	%	n/a			n/a			n/a
Rate of compensation increase		3.79	%		3.05	%		3.08	%		3.79	%		3.04	%		3.07	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.39	%		5.61	%		5.74	%
Ultimate rate	n/a			n/a			n/a				4.00	%		4.00	%		4.50	%
Year rate reaches ultimate trend rate	n/a			n/a			n/a			2047			2045			2038

(1)Discount rate range is the result of remeasurements that occurred in 2023.

The discount rate assumption used to determine the benefit cost for 2023, 2022 and 2021 was based on the same technique that was used to determine the December 31, 2023 and 2022 benefit obligation as discussed above.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended December 31, 2023, TECO Energy’s pension plan’s actual return was approximately 14.7%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

Pension Plan Assets

Pension plan assets are invested in a mix of equity and fixed-income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

TECO Energy	2023 Target Allocation			2022 Target Allocation			Actual Allocation, End of Year
Asset Category							2023			2022
Cash and cash equivalents	0%-10%			n/a				3	%	n/a
Equity securities	48%-68%			50%-70%				57	%		58	%
Fixed income securities	29%-49%			30%-50%				40	%		42	%
Total		100	%		100	%		100	%		100	%

TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy will continue to monitor the matching of plan assets with plan liabilities over the long term.

The plan’s investments are held by a trust fund administered by The Bank of New York Mellon. Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments.

Pension Plan Investments

TECO Energy	At Fair Value as of December 31, 2023
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	(1	)	$	0		$	0	$	0	$	(1	)
Accounts receivable		3			0			0		0		3
Accounts payable		(10	)		0			0		0		(10	)
Short-term investment funds (STIFs)		24			0			0		0		24
Common stock		1			0			0		0		1
Real estate investment trusts (REITs)		3			0			0		0		3
Mutual funds		38			0			0		0		38
Municipal bonds		0			2			0		0		2
Government bonds		0			108			0		0		108
Corporate bonds		0			57			0		0		57
Long futures		5			0			0		0		5
Short Sales		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		63			166			0		0		229
Common and collective trusts (1)		0			0			0		443		443
Mutual fund (1)		0			0			0		14		14
Total investments	$	63		$	166		$	0	$	457	$	686

(1)In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

TECO Energy	At Fair Value as of December 31, 2022
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	5		$	0		$	0	$	0	$	5
Accounts receivable		10			0			0		0		10
Accounts payable		(62	)		0			0		0		(62	)
Short-term investment funds (STIFs)		32			0			0		0		32
Real estate investment trusts (REITs)		2			0			0		0		2
Mutual funds		50			0			0		0		50
Municipal bonds		0			1			0		0		1
Government bonds		0			58			0		0		58
Corporate bonds		0			50			0		0		50
Mortgage backed securities (MBS)		0			5			0		0		5
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Short Sales		0			(3	)		0		0		(3	)
Written Options		0			2			0		0		2
Swaps		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		37			113			0		0		150
Common and collective trusts (1)		0			0			0		444		444
Mutual fund (1)		0			0			0		56		56
Total investments	$	37		$	113		$	0	$	500	$	650

(1)In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

•Cash collateral is valued at cash posted due to its short-term nature.

•The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset.

•The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets.

•The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-end mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets.

•The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

•Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

•The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-end mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is an open-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. The redemption frequency is daily. The redemption notice period is the same day. There were no unfunded commitments as of December 31, 2023.

•The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days. There were no unfunded commitments as of December 31, 2023.

•Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

•Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

Additionally, the non-qualified SERP had $4 million and $8 million of assets as of December 31, 2023 and 2022, respectively. Since the plan is non-qualified, its assets are included in the “Deferred charges and other assets” line item in the Consolidated Balance Sheets rather than being netted with the related liability. The non-qualified trust holds investments in a money market fund. The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make it a level 1 asset. The SERP was fully funded as of December 31, 2023 and 2022.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s Florida-based other postretirement benefits plan.

Contributions

The qualified pension plan’s actuarial value of assets, including credit balance, was 107.24% of the Pension Protection Act funded target as of January 1, 2023 and is estimated at 111.50% of the Pension Protection Act funded target as of January 1, 2024.

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions. TEC’s contribution is first set equal to its service cost. If a contribution in excess of service cost for the year is made, TEC’s portion is based on TEC’s proportion of the TECO Energy unfunded liability. TECO Energy made contributions to this plan in 2023, 2022 and 2021, which met the minimum funding requirements for 2023, 2022 and 2021. TEC’s portion of the contribution in 2023 was $10 million, in 2022 was $15 million and in 2021 was $17 million. Tampa Electric’s portion of the contribution was $10 million in 2023, $12 million in 2022 and $14 million 2021. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. Tampa Electric estimates its portion of the 2024 contribution to be $10 million. The amount TECO Energy expects to contribute is in excess of the minimum funding required under ERISA guidelines.

TEC’s portion of the contributions to the SERP in 2023, 2022 and 2021 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2024. TEC made SERP payments of approximately $5 million, $2 million and $1 million from the trust in 2023, 2022 and 2021, respectively.

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between January 1, 1990 and June 30, 2001 is limited to a defined

dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2024, Tampa Electric expects to make a contribution of approximately $10 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2024	$	76	$	12
2025		67		12
2026		66		12
2027		66		12
2028		65		11
2029-2033		295		51

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match 75% of the first 6% of the participant’s payroll savings deductions. Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended December 31, 2023, 2022 and 2021, TEC’s portion of expense totaled $18 million, $22 million and $22 million, respectively, related to the matching contributions made to this plan. Tampa Electric’s portion of expense totaled $18 million, $19 million and $18 million, respectively, related to the matching contributions made to this plan. The expense related to the matching contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.

Effective October 21, 2019, TECO Energy amended the defined contribution plan such that certain participants covered by the IBEW collective bargaining agreement shall not be eligible to participate in the plan for purposes of receiving the fixed matching contribution. This has been replaced with a non-elective employer contribution on a bi-weekly basis equal to a percentage of the member’s compensation for that period based on years of tenure of employment. For the years ended December 31, 2023, 2022 and 2021, Tampa Electric recognized expense totaling $10 million, $10 million and $10 million, respectively, related to the contributions made to this plan. The expense related to this contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.

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Short-Term Debt

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Short-Term Debt

6. Short-Term Debt

Credit Facilities

	December 31, 2023								December 31, 2022
			Borrowings		Borrowings		Letters				Borrowings		Borrowings		Letters
	Credit		Outstanding -		Outstanding -		of Credit		Credit		Outstanding -		Outstanding -		of Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding
5-year facility (2)	$	800	$	0	$	706	$	1	$	800	$	0	$	619	$	1
1-year term facility (3)		0		0		0		0		400		400		0		0
1-year term facility (4)		200		0		0		0		0		0		0		0
1-year term facility (5)		200		0		0		0		0		0		0		0
Total	$	1,200	$	0	$	706	$	1	$	1,200	$	400	$	619	$	1

(1)Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets.

(2)This 5-year facility matures on December 17, 2026. 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. On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029. TEC used the net proceeds from this offering for the repayment of a portion of the borrowings outstanding under the 5-year credit facility. Therefore, $497 million of borrowings outstanding under the 5-year credit facility were reclassified as long-term debt on the Consolidated Balance Sheet as of December 31, 2023.

(3)This 1-year term facility was set to mature on December 16, 2022. On December 13, 2022, TEC extended the maturity date to December 13, 2023, at which time the facility terminated.

(4)On March 1, 2023, TEC entered into a 1-year term facility that matures on February 28, 2024.

(5)On April 3, 2023, TEC entered into a 1-year term facility that matures on April 1, 2024.

At December 31, 2023, these credit facilities required a commitment fee of 12.5 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities and commercial paper at December 31, 2023 and 2022 was 5.68% and 5.00%, respectively.

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called PGSI pursuant to a Contribution Agreement. Prior to the separation, as a division of TEC, PGS had received an allocation of outstanding unsecured notes and outstanding short-term borrowings issued by TEC. The obligations related to these combined borrowings were reflected in an affiliate loan agreement between Tampa Electric and PGS. The initial obligation of PGS under the loan agreement at January 1, 2023 was a term loan in the principal amount of $670 million and a revolving loan in the principal amount of $66 million. The maturity date for both was December 29, 2023. On December 20, 2023, PGS repaid Tampa Electric the outstanding principal amount of the term loan and revolving loan of $670 million and $286 million, respectively, plus outstanding interest. The repayment terminates the affiliate loan agreement and Tampa Electric will no longer provide capital for the operations of PGS.

In December 2023, Tampa Electric used the proceeds of the PGS repayment in part to repay $400 million in credit facility borrowings, the $195 million note payable to TECO Energy and $149 million of the commercial paper borrowed under the 5-year term facility.

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 cannot issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

TEC Term Loan

On April 3, 2023, TEC entered into a 364-day, $200 million senior unsecured revolving loan credit facility with a group of banks. The credit facility has a maturity date of April 1, 2024. The credit agreement contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term SOFR, Wells Fargo’s prime rate, the federal funds rate or the one-month secured overnight financing rate, plus a margin.

TEC Term Loan

On March 1, 2023, TEC entered into a 364-day, $200 million senior unsecured revolving loan credit facility with a maturity date of February 28, 2024. The credit agreement contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term secured overnight financing rate (SOFR), The Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month secured overnight financing rate, plus a margin.

TEC Term Loan

On December 13, 2022, TEC extended the maturity date of its $500 million credit agreement that was set to mature on December 16, 2022 and reduced the amount of the loan to $400 million. The credit agreement has a maturity date of December 13, 2023; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term secured overnight financing rate (SOFR), Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. On November 24, 2023, TEC repaid the facility. On December 13, 2023, the facility terminated.

5-Year Credit Facility

On December 17, 2021, TEC amended and restated its $800 million bank credit facility, entering into a Seventh Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2023 to December 17, 2026 (subject to further extension with the consent of each lender); 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; and made other technical changes. On April 3, 2023, TEC amended the agreement to replace the London interbank deposit rate with the SOFR.

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Long-Term Debt

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Long-Term Debt

7. Long-Term Debt

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time.

TEC 4.90% Notes due 2029

On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029 (the 2029 Notes). Prior to February 1, 2029, in the case of the 2029 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) the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the redemption date on a semi-annual basis at the Treasury Rate plus 15 basis points less interest accrued to the date of redemption or (ii) 100% of the principal amount of the notes to be redeemed, plus, in either case, accrued and unpaid interest thereon to the redemption date. On or after February 1, 2029, TEC may redeem the 2029 Notes, in whole or in part, at any time and from time to time, at a redemption price equal to 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to the redemption date. TEC used the net proceeds from this offering for the repayment of a portion of the borrowings outstanding under the 5-year credit facility. Therefore, $497 million of borrowings outstanding under the 5-year credit facility were reclassified from notes payable to long-term debt on the Consolidated Balance Sheet as of December 31, 2023.

TEC 3.875% Notes due 2024 and 5.00% Notes due 2052

On July 12, 2022, TEC completed a sale of (i) $300 million aggregate principal amount of 3.875% Notes due July 12, 2024 (the 2024 Notes) and (ii) $300 million aggregate principal amount of 5.00% Notes due July 15, 2052 (the 2052 Notes, and collectively, the Notes). Until July 12, 2024, in the case of the 2024 Notes, or January 15, 2052, in the case of the 2052 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) July 12, 2024, in the case of the 2024 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) July 15, 2052, in the case of the 2052 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, plus 30 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after January 15, 2052, in the case of the 2052 Notes, TEC may, at its option, redeem the 2052 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.

TEC 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

12 Months Ended

Dec. 31, 2023

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

As of December 31, 2023, TEC, through its Tampa Electric division and former PGS division, was a PRP for certain superfund sites and, through its former PGS division, for certain former MGP sites. As a result of the separation of the PGS division, PGS is now the responsible party for those sites (in addition to third party PRPs for certain sites). See Note 1 to the 2023 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC.

Long-Term Commitments

TEC has commitments for various purchases as disclosed below, including payment obligations for capital projects, such as Tampa Electric’s solar projects (see Note 3), and 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 minimum lease payments with non-cancelable lease terms in excess of one year and other net purchase obligations/commitments at December 31, 2023:

	Purchased				Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Power		Transportation		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2024	$	4	$	135	$	533	$	194	$	34	$	3	$	5	$	908
2025		0		128		81		60		22		3		5		299
2026		0		125		53		17		23		1		1		220
2027		0		125		1		4		22		1		1		154
2028		0		97		0		1		17		1		0		116
Thereafter		0		833		0		0		33		75		0		941
Total future minimum payments	$	4	$	1,443	$	668	$	276	$	151	$	84	$	12	$	2,638

Financial Covenants

TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable debt agreements. TEC has certain restrictive covenants in specific agreements and debt instruments. At December 31, 2023 and 2022, TEC was in compliance with all required financial covenants.

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Revenue

12 Months Ended

Dec. 31, 2023

Revenues [Abstract]

Revenue

9. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
For the year ended December 31, 2023	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,711							$	1,711
Commercial		803								803
Industrial		203								203
Regulatory deferrals		(387	)							(387	)
Unbilled revenue		(2	)							(2	)
Other (1)		309								309
Total electric revenue		2,637								2,637
Total revenue	$	2,637							$	2,637
For the year ended December 31, 2022
Electric revenue
Residential	$	1,381		$	0	$	0		$	1,381
Commercial		666			0		0			666
Industrial		176			0		0			176
Regulatory deferrals		(21	)		0		0			(21	)
Unbilled revenue		9			0		0			9
Other (1)		312			0		(4	)		308
Total electric revenue		2,523			0		(4	)		2,519
Gas revenue
Residential		0			229		0			229
Commercial		0			200		0			200
Industrial (2)		0			31		0			31
Other (3)		0			196		(6	)		190
Total gas revenue		0			656		(6	)		650
Total revenue	$	2,523		$	656	$	(10	)	$	3,169
For the year ended December 31, 2021
Electric revenue
Residential	$	1,156		$	0	$	0		$	1,156
Commercial		602			0		0			602
Industrial		172			0		0			172
Regulatory deferrals		(6	)		0		0			(6	)
Unbilled revenue		(2	)		0		0			(2	)
Other (1)		252			0		(4	)		248
Total electric revenue		2,174			0		(4	)		2,170
Gas revenue
Residential		0			212		0			212
Commercial		0			191		0			191
Industrial (2)		0			25		0			25
Other (3)		0			100		(3	)		97
Total gas revenue		0			528		(3	)		525
Total revenue	$	2,174		$	528	$	(7	)	$	2,695

(1)Other includes sales to public authorities, off-system sales to other utilities and various other items.

(2)Industrial includes sales to power generation customers.

(3)Other includes off-system sales to other utilities and various other items.

Remaining Performance Obligations

Remaining performance obligations primarily represent lighting contracts and, prior to January 1, 2023, gas transportation contracts with fixed contract terms. As of December 31, 2023 and 2022, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $78 million and $140 million, respectively. The decrease is due to TEC's January 1, 2023 separation from its former PGS division. See Note 1 for further information regarding the separation of PGS from TEC. As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2043.

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2023		2022			2021
Natural gas purchases (net of sales) from affiliates	$	65	$	232		$	236
Services to/(from) affiliates		28		(4	)		(7	)
Interest income from affiliate		38		0			0
Interest expense to affiliate		11		0			0
Dividends to TECO Energy		472		517			450
Equity contributions from TECO Energy		300		605			580

Amounts due from or to affiliates at December 31,

(millions)	2023		2022
Accounts receivable related to asset management agreements with Emera Energy Services Inc. (1)	$	4	$	7
Accounts receivable excluding asset management agreements (1)		12		5
Taxes receivable (2)		3		10
Accounts payable (1)		10		31
Note payable to TECO Energy (3)		0		195

(1)Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2)Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.

(3)The note payable with TECO Energy bears interest at a rate approximating the market rate of TEC's commercial paper.

See Note 6 for further information regarding related party transactions between TEC and PGS as a result of financing activities due to the separation of PGS from TEC on January 1, 2023..

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Segment Information

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Segment Information

11. Segment Information

Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. Management reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TEC but are included in determining reportable segments.

TEC is a public utility operating within the State of Florida. Due to the separation of PGS from TEC, TEC operates under a single operating and reportable segment effective January 1, 2023 because the operations of TEC only include the operations of the Electric division. See "Separation of PGS from TEC" in Note 1 for further information regarding the separation of PGS from TEC. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 840,000 customers in West Central Florida.

	Tampa				Eliminations/
(millions)	Electric		PGS		Reclassifications				TEC
2023
Revenues - external	$	2,637							$	2,637
Intracompany sales		0								0
Total revenues		2,637								2,637
Depreciation and amortization		422								422
Interest income from affiliates		38								38
Total interest charges		239								239
Provision for income taxes		87								87
Net income		466								466
Total assets		11,831								11,831
Capital expenditures		1,294								1,294
2022
Revenues - external	$	2,519	$	650	$	0			$	3,169
Intracompany sales		4		6		(10	)			0
Total revenues		2,523		656		(10	)			3,169
Depreciation and amortization		389		47		0				436
Total interest charges		142		25		0				167
Provision for income taxes		94		27		0				121
Net income		458		82		0				540
Total assets		12,064		2,471		(732	)	(1)		13,803
Capital expenditures		1,099		328		0				1,427
2021
Revenues - external	$	2,170	$	525	$	0			$	2,695
Intracompany sales		4		3		(7	)			0
Total revenues		2,174		528		(7	)			2,695
Depreciation and amortization		374		56		0				430
Total interest charges		110		20		0				130
Provision for income taxes		57		23		0				80
Net income		369		77		0				446
Total assets		10,650		2,209		(663	)	(1)		12,196
Capital expenditures		1,081		316		0				1,397

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

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

12. Asset Retirement Obligations

Tampa Electric accounts for AROs at fair value at inception of the obligation if there is a legal obligation under applicable law, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. When the liability is initially recorded in “Deferred credits and other liabilities” in the Consolidated Balance Sheets, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The ARO estimates are reviewed quarterly. Any updates are revalued based on current market prices.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:

	December 31,
(millions)	2023			2022
Beginning balance	$	35		$	31
Additional liabilities		1			1
Liabilities settled		(4	)		0
Other		0			3
Ending balance	$	32		$	35

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Leases

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Leases

13. Leases

TEC determines whether a contract contains a lease at inception by evaluating if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

Operating lease ROU assets and operating lease liabilities are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of TEC’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operations and maintenance expenses” on the Consolidated Statements of Income.

TEC has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component for all leases in which TEC is the lessee.

Lessee

Tampa Electric has operating leases for buildings, land, telecommunication services and rail cars. Tampa Electric’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to an additional 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.

(millions)	Classification	2023		2022
Right-of-use asset	Deferred charges and other assets	$	21	$	23
Lease liabilities
Current	Other current liabilities	$	2	$	2
Long-term	Deferred credits and other liabilities		20		22
Total lease liabilities		$	22	$	24

Tampa Electric has recorded operating lease expense for the year ended December 31, 2023, 2022 and 2021 of $4 million, $4 million and $5 million, respectively.

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at December 31, 2023:

(millions)
Year ended December 31:	2024		2025		2026		2027		2028		Thereafter		Total
Minimum lease payments	$	3	$	2	$	1	$	1	$	1	$	46	$	54
Less imputed interest														(32	)
Total future minimum payments													$	22

Additional information related to Tampa Electric’s leases is as follows:

Year ended December 31,	2023			2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	4		$	4
Weighted average remaining lease term (years)		45			44
Weighted average discount rate - operating leases		4.4	%		4.4	%

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Fair Value Measurements

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

14. 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 December 31, 2023 and 2022, the fair value of TEC’s short-term debt was not materially different from the carrying 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 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively.

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Stock-Based Compensation

15. Stock-Based Compensation

Emera has a performance share unit (PSU) plan and a restricted share unit (RSU) plan. The PSU and RSU liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA.

Performance Share Unit Plan

Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and are paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the Emera Management Resources and Compensation Committee (MRCC) early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to TEC employee PSUs is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2022		176			56.21		9
Granted including DRIP		73			52.83		4
Exercised		(70	)		54.62		4
Forfeited		(5	)		54.72		0
Transferred (1)		(31	)		56.17		2
Outstanding as of December 31, 2023		143			55.32		7

(1)This amount includes 38,197 units transferred to PGS upon their separation from TEC on January 1, 2023.

Compensation cost recognized for the PSU plan for the years ended December 31, 2023, 2022 and 2021 was $2 million, $4 million and $3 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2023, 2022 and 2021 were $1 million, $1 million and $1 million, respectively. Cash payments made during the year ended December 31, 2023, 2022 and 2021 associated with the PSU plan were $3 million, $7 million and $10 million, respectively. As of December 31, 2023 and 2022, there was $2 million and $3 million, respectively, of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years.

Restricted Share Unit Plan

Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.

RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement.

A summary of the activity related to TEC employee RSUs is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2022		173			56.23		9
Granted including DRIP		60			52.11		3
Exercised		(49	)		54.62		3
Forfeited		(5	)		54.72		0
Transferred (1)		(29	)		56.30		1
Outstanding as of December 31, 2023		150			55.15		8

(1)This amount includes 35,774 units transferred to PGS upon their separation from TEC on January 1, 2023.

Compensation cost recognized for the RSU plan for the years ended December 31, 2023, 2022 and 2021 was $2 million, $3 million and $2 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2023, 2022 and 2021 were $1 million, $1 million and zero, respectively. Cash payments made during the year ended December 31, 2023, 2022 and 2021 associated with the RSU plan were $3 million, none and none, respectively. As of December 31, 2023 and 2022, there was $2 million and $3 million, respectively, of unrecognized compensation cost related to non-vested RSUs that is expected to be recognized over a weighted-average period of two years.

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Long-Term PPAs

12 Months Ended

Dec. 31, 2023

Contractors [Abstract]

Long-Term PPAs

16. Long-Term PPAs

In 2019, Tampa Electric entered into a long-term PPA with a wholesale energy provider in Florida with up to 515 MW of available capacity, which expires in 2024. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric reviewed these risks and determined that the owners of these entities retain the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric was not the primary beneficiary and was not required to consolidate any of these entities. Tampa Electric purchased $35 million, $70 million and $46 million under this long-term PPA for the three years ended December 31, 2023, 2022 and 2021, respectively.

TEC does not provide any material financial or other support to any of the variable interests it is involved with, nor is TEC under any obligation to absorb losses associated with these variable interests. Excluding the payments for energy under these contracts, TEC’s involvement with these variable interests does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows.

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Schedule II - Valuation and Qualifying Accounts and Reserves

12 Months Ended

Dec. 31, 2023

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts and Reserves

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended December 31, 2023, 2022 and 2021

(millions)

	Balance at		Additions							Balance at
	Beginning		Charged to		Other			Payments &		End of
	of Period		Income		Charges			Deductions (1)		Period
Allowance for Credit Losses:
2023	$	4	$	9	$	(1	)	$	10	$	2
2022	$	7	$	5	$	0		$	8	$	4
2021	$	7	$	8	$	0		$	8	$	7

Write-off of individual bad debt accounts

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Subsequent Events

12 Months Ended

Dec. 31, 2023

Subsequent Events [Abstract]

Subsequent Events

17. Subsequent Events

On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029. See Note 7 for additional information.

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. 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.

TEC is a wholly owned subsidiary of TECO Energy, Inc. TEC contains the electric division, and prior to January 1, 2023, also included the natural gas division. Prior to January 1, 2023, intercompany balances and transactions within the divisions have been eliminated in consolidation. TECO Energy is a wholly owned indirect subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera.

Cash Equivalents

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

As a regulated utility, TEC must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation. The original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2023			December 31, 2022
Electric generation	10-60 years	$	6,732		$	6,300
Electric transmission	10-75 years		1,182			1,109
Electric distribution	10-60 years		3,609			3,296
Gas transmission and distribution	15-75 years	0				2,567
General plant and other	4-60 years		997			1,020
Total cost			12,520			14,292
Less Tampa Electric accumulated depreciation			(3,443	)		(3,158	)
Less PGS accumulated depreciation		0				(687	)
Tampa Electric construction work in progress			1,151			949
PGS construction work in progress		0				248
Total property, plant and equipment, net		$	10,228		$	11,644

Depreciation

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.5%, 3.2% and 3.5% for 2023, 2022 and 2021, respectively. Construction work in progress is not depreciated until the asset is placed in service. TEC's total depreciation expense for the years ended December 31, 2023, 2022 and 2021 was $390 million, $402 million and $408 million, respectively. For the year ended December 31, 2023, 2022 and 2021, Tampa Electric's depreciation expense was $390 million, $359 million and $357 million, respectively.

TEC computes depreciation and amortization using the following methods:

•the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

•the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rates used to calculate AFUDC are revised periodically to reflect significant changes in cost of capital. In 2023, 2022 and 2021, Tampa Electric’s rate was 6.07%, 6.00% and 6.46%, respectively. PGS’s rate used to calculate its AFUDC in 2022 and 2021 was 6.00%. Total AFUDC for the years ended December 31, 2023, 2022 and 2021 was $25 million, $46 million and $66 million, respectively.

Inventory

Inventory

TEC values materials, supplies and fossil fuel inventory (natural gas and coal) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or net realizable value.

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3).

Deferred Income Taxes

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details.

Investment and Production Tax Credits (PTCs)

Investment and Production Tax Credits (PTCs)

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense as required by regulatory practices. TEC recognizes a reduction of income tax expense for PTCs earned by its eligible solar assets. The PTCs are based on per kwH rate prescribed by applicable federal statutes.

Stranded Tax Effects in Accumulated Other Comprehensive Income

Stranded Tax Effects in Accumulated Other Comprehensive Income

TEC utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released.

Revenue Recognition

Revenue Recognition

Regulated electric revenue

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied. This occurs primarily when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. Tampa Electric’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of MWH delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, timing of meter reads and line losses.

Regulated gas revenue

Prior to January 1, 2023, gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, were recognized when obligations under the terms of a contract were satisfied. This occurred primarily when gas was delivered to customers over time as the customer simultaneously received and consumed the benefits of the gas. Gas revenues were recognized on an accrual basis and included billed and unbilled revenues. Revenues related to the distribution and sale of gas were recognized at rates approved by the regulator and recorded based on metered usage, which occurred on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, was estimated and the corresponding unbilled revenue was recognized. PGS’s estimate of unbilled revenue at the end of the reporting period was calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate included assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

Other

See Accounting for Franchise Fees and Gross Receipts below for the accounting for gross receipts taxes. Sales and other taxes TEC collects concurrent with revenue-producing activities are excluded from revenue.

Revenues and Cost Recovery

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation, environmental and storm protection plan costs for Tampa Electric and, prior to January 1, 2023, purchased gas, interstate pipeline capacity, replacement of cast iron/bare steel pipe and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are recognized.

Receivables and Allowance for Credit Losses

Receivables and Allowance for Credit Losses

Receivables on the Consolidated Balance Sheets include receivables from contracts with customers, which consist of services to residential, commercial, industrial and other customers, totaling $284 million and $295 million as of December 31, 2023 and 2022, 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 impact estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

TEC accrues base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2023 and 2022, unbilled revenues of $63 million and $82 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Accounting for Franchise Fees and Gross Receipts Taxes

Accounting for Franchise Fees and Gross Receipts Taxes

TEC is allowed to recover certain costs incurred on a dollar-for-dollar basis from customers 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 Statements of Income. Franchise fees and gross receipt taxes payable are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $139 million, $145 million and $129 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Deferred Charges and Other Assets

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of pension assets net of accrued pension liabilities (see Note 5) and right-of-use assets related to operating leases (see Note 13).

Deferred Credits and Other Liabilities

Deferred Credits and Other Liabilities

Other deferred credits primarily include accrued other postretirement benefits (see Note 5), MGP environmental remediation liability prior to January 1, 2023 (see Note 8), asset retirement obligations (see Note 12), lease liabilities (see Note 13) and a reserve for auto, general and workers’ compensation liability claims.

TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at December 31, 2023 and 2022 ranged from 4.00% to 5.99% and 4.00% to 5.78%, respectively.

Derivatives and Hedging Activities

Derivatives and Hedging Activities

TEC had $1 million and $5 million derivative assets as of December 31, 2023 and 2022, respectively, and $0 and $1 million derivative liabilities as of December 31, 2023 and December 31, 2022, respectively.

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2023 and 2022, all of TEC’s physical contracts qualified for the NPNS exception, which was elected.

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Separation of PGS from TEC

Separation of PGS from TEC

PGS became an operating division of TEC in 1997 when TECO Energy purchased PGS and merged that corporation into TEC. Since then, PGS has operated as a stand-alone regulated utility, including having its own tariff and its own books and records.

On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. (PGSI) pursuant to a Contribution Agreement. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. On January 1, 2023, the assets, liabilities, and equity that had been recorded in the books of PGS were transferred from TEC to the newly formed PGSI at book value in a tax-free transaction. PGSI issued 100 shares of common stock to TEC related to the transfer of PGS, which were subsequently distributed to TECO Energy, Inc. and then contributed to TECO Gas Operations, Inc. This is a transaction between entities under common control; therefore, TEC did not recognize a gain or loss on the transaction. TEC is not required to recast its prior period financial statements and disclosures to exclude PGS prior to January 1, 2023. The TEC Consolidated Statement of Cash Flows for the year ended December 31, 2023 does not include the non-cash impact of separating the PGS assets, liabilities and equity from TEC on January 1, 2023 and excludes PGS’s opening cash balance.

The impact of the separation of PGS from TEC on the Consolidated Statements of Capital for the year ended December 31, 2023 was $992 million, which represents the net assets of PGS transferred as of January 1, 2023. TEC recorded $121 million to

retained earnings, which was the retained earnings of PGS as of January 1, 2023, and the remainder of $871 million was recorded to additional paid in capital, which is presented with common stock.

Prior to the separation, as a division of TEC, PGS had received an allocation of outstanding unsecured notes and outstanding short-term borrowings issued by TEC. The obligations related to these combined borrowings were reflected in an affiliate loan agreement between TEC and PGS. The initial obligation of PGS under the loan agreement at January 1, 2023 was a term loan in the principal amount of $670 million and a revolving loan in the principal amount of $66 million. The maturity date for both was December 29, 2023. On December 20, 2023, PGS repaid Tampa Electric the outstanding principal amount of the term loan and revolving loan of $670 million and $286 million, respectively, plus outstanding interest. The repayment terminates the affiliate loan agreement and Tampa Electric will no longer provide capital for the operations of PGS. See Note 6 for further information.

he following table presents the assets and liabilities of PGS in TEC’s Consolidated Balance Sheet as of December 31, 2022:

	December 31,
(millions)	2022
Property, plant and equipment
Utility plant	$	2,938
Accumulated depreciation		(687	)
Total property, plant and equipment, net		2,251
Current assets
Cash and cash equivalents		4
Receivables, less allowance for credit losses of $1 at December 31, 2022		62
Due from affiliates		4
Inventories, at average cost
Materials and supplies		5
Regulatory assets		9
Prepayments and other current assets		4
Total current assets		88
Other assets
Regulatory assets		53
Deferred charges and other assets		79
Total other assets		132
Total assets	$	2,471
Capitalization
Common stock	$	871
Retained earnings		121
Total capital		992
Long-term debt		564
Total capital		1,556
Current liabilities
Notes payable		166
Accounts payable		78
Due to affiliates		27
Customer deposits		30
Regulatory liabilities		11
Accrued interest		4
Accrued taxes		5
Other		4
Total current liabilities		325
Other liabilities
Deferred income taxes		238
Regulatory liabilities		277
Deferred credits and other liabilities		75
Total other liabilities		590

Total liabilities and capital $ 2,471

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule of Property, Plant and Equipment

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2023			December 31, 2022
Electric generation	10-60 years	$	6,732		$	6,300
Electric transmission	10-75 years		1,182			1,109
Electric distribution	10-60 years		3,609			3,296
Gas transmission and distribution	15-75 years	0				2,567
General plant and other	4-60 years		997			1,020
Total cost			12,520			14,292
Less Tampa Electric accumulated depreciation			(3,443	)		(3,158	)
Less PGS accumulated depreciation		0				(687	)
Tampa Electric construction work in progress			1,151			949
PGS construction work in progress		0				248
Total property, plant and equipment, net		$	10,228		$	11,644

Summary of Assets and Liabilities of PGS in TEC's Consolidated Balance Sheets

he following table presents the assets and liabilities of PGS in TEC’s Consolidated Balance Sheet as of December 31, 2022:

	December 31,
(millions)	2022
Property, plant and equipment
Utility plant	$	2,938
Accumulated depreciation		(687	)
Total property, plant and equipment, net		2,251
Current assets
Cash and cash equivalents		4
Receivables, less allowance for credit losses of $1 at December 31, 2022		62
Due from affiliates		4
Inventories, at average cost
Materials and supplies		5
Regulatory assets		9
Prepayments and other current assets		4
Total current assets		88
Other assets
Regulatory assets		53
Deferred charges and other assets		79
Total other assets		132
Total assets	$	2,471
Capitalization
Common stock	$	871
Retained earnings		121
Total capital		992
Long-term debt		564
Total capital		1,556
Current liabilities
Notes payable		166
Accounts payable		78
Due to affiliates		27
Customer deposits		30
Regulatory liabilities		11
Accrued interest		4
Accrued taxes		5
Other		4
Total current liabilities		325
Other liabilities
Deferred income taxes		238
Regulatory liabilities		277
Deferred credits and other liabilities		75
Total other liabilities		590

Total liabilities and capital $ 2,471

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Regulatory (Tables)

12 Months Ended

Dec. 31, 2023

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

	December 31,		December 31,
(millions)	2023		2022
Regulatory assets:
Regulatory tax asset (1)	$	112	$	124
Cost-recovery clauses (2)		94		525
Capital cost recovery for early retired assets (3)		507		497
Environmental remediation (4)		0		20
Postretirement benefits (5)		236		272
Storm reserve (6)		7		76
Other		32		38
Total regulatory assets		988		1,552
Less: Current portion		161		361
Long-term regulatory assets	$	827	$	1,191
Regulatory liabilities:
Regulatory tax liability (7)	$	477	$	601
Cost-recovery clauses - deferred balances (2)		20		30
Accumulated reserve—cost of removal (8)		271		498
Other		27		11
Total regulatory liabilities		795		1,140
Less: Current portion		94		85
Long-term regulatory liabilities	$	701	$	1,055

(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.

(2)These assets and liabilities are related to FPSC clauses and riders, primarily related to the fuel clause and the increase in natural gas prices experienced in 2022. 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 regulatory asset is related to the remaining net book value of Big Bend Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years. See “Tampa Electric Big Bend Modernization Project” above for further information.

(4)This asset was related to PGS costs associated with environmental remediation primarily at MGP sites. See Note 1 for information regarding the separation of PGS from TEC.

(5)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.

(6)See "Tampa Electric Storm Restoration Cost Recovery" above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC.

(7)The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower corporate 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.

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

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2023			2022			2021
Current income taxes
Federal	$	84		$	(13	)	$	48
State		25			(3	)		4
Deferred income taxes
Federal		(19	)		105			24
State		5			38			13
Investment tax credits amortization		(8	)		(6	)		(9	)
Total income tax expense	$	87		$	121		$	80

Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes

For the three years presented, the overall effective tax rate differs from the U.S. federal statutory rate as presented below:

(millions)
For the year ended December 31,	2023			2022			2021
Income before provision for income taxes	$	553		$	661		$	526
Federal statutory income tax rates		21	%		21	%		21	%
Income taxes, at statutory income tax rate		116			139			110
Increase (decrease) due to
State income tax, net of federal income tax		23			27			13
Excess deferred tax amortization		(25	)		(25	)		(26	)
ITC amortization		(8	)		(6	)		(9	)
AFUDC-equity		(4	)		(7	)		(9	)
Production Tax Credits		(15	)		(6	)		0
Other Tax credits		(4	)		(3	)		(3	)
Other		4			2			4
Total income tax expense on consolidated statements of income	$	87		$	121		$	80
Income tax expense as a percent of income before income taxes		15.7	%		18.3	%		15.2	%

Schedule of Deferred Tax Assets and Liabilities

The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

(millions)
As of December 31,	2023		2022
Deferred tax liabilities (1)
Property related	$	1,227	$	1,318
Deferred fuel		23		133
Pension and postretirement benefits		100		111
Insurance reserves		0		15
Total deferred tax liabilities		1,350		1,577
Deferred tax assets (1)
Loss and credit carryforwards (2)		383		408
Medical benefits		19		24
Insurance reserves		1		0
Pension and postretirement benefits		49		57
Capitalized energy conservation assistance costs		0		23
Other		18		20
Total deferred tax assets		470		532
Total deferred tax liability, net	$	880	$	1,045

(1)Certain property related assets and liabilities have been netted. At December 31, 2022, PGS total deferred tax liabilities and deferred tax assets were $213 million and $37 million, respectively, with the majority of the balances related to property and capitalized energy conservation assistance costs.

(2)Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $10 million and $9 million at December 31, 2023 and 2022, respectively.

Schedule of Unrecognized Tax Benefits

The following table provides details of the change in unrecognized tax benefits as follows:

(millions)	2023		2022		2021
Balance at January 1,	$	9	$	6	$	9
Increases due to tax positions related to prior year	0		2		1
Increases due to tax positions related to current year	1		1		1
Decreases due to settlements with tax authorities	0		0			(5	)
Balance at December 31,	$	10	$	9	$	6

Summary of expiration of TEC's tax credits and NOL carryforwards

The expiration of TEC's tax credits and NOL carryforwards are as follows:

(millions)	December 31, 2023		Expiration Year
General business credits	$	324	2027-2043
Federal NOL carryforwards		135	2037
Federal NOL carryforwards (1)		199	indefinite
State NOL carryforwards (1)		305	indefinite
Total tax credits and NOL carryforwards	$	963

(1)Indefinite carryforward for Federal NOLs and NOLs for states that have adopted the U.S. Tax Cuts and Jobs Act of 2017 provisions, generated in tax years beginning after December 31, 2017.

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Employee Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2023

Schedule of Amount Recognized in Balance Sheet

The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations and plan assets at December 31 were as follows:

TEC	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2023			2022			2023			2022
Noncurrent assets	$	10		$	0		$	0		$	0
Accrued benefit costs and other current liabilities		0			(7	)		(10	)		(12	)
Deferred credits and other liabilities		(1	)		(9	)		(99	)		(121	)
	$	9		$	(16	)	$	(109	)	$	(133	)

Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets

The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

TEC	Pension Benefits				Other Benefits
Amounts recognized in regulatory assets
(millions)	2023		2022		2023		2022
Net actuarial loss	$	207	$	242	$	29	$	30
Amount recognized	$	207	$	242	$	29	$	30

Benefit Obligations [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2023			2022			2023			2022
Discount rate		5.27	%		5.55	%		5.28	%		5.53	%
Rate of compensation increase		4.42	%		3.79	%		4.42	%		3.79	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				6.09	%		6.39	%
Ultimate rate	n/a			n/a				4.00	%		4.00	%
Year rate reaches ultimate trend rate	n/a			n/a			2047			2047

Net Periodic Benefit Cost [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine net periodic benefit cost for years ended December 31:

	Pension Benefits									Other Benefits
	2023			2022			2021			2023			2022			2021
Discount rate (1)	4.19%-5.55%				2.77	%		2.37	%	5.53%-6.14%				2.84	%		2.47	%
Expected long-term return on plan assets		7.05	%		6.50	%		6.70	%	n/a			n/a			n/a
Rate of compensation increase		3.79	%		3.05	%		3.08	%		3.79	%		3.04	%		3.07	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				6.39	%		5.61	%		5.74	%
Ultimate rate	n/a			n/a			n/a				4.00	%		4.00	%		4.50	%
Year rate reaches ultimate trend rate	n/a			n/a			n/a			2047			2045			2038

(1)Discount rate range is the result of remeasurements that occurred in 2023.

TECO Energy [Member]

Schedule of Change in Plan Assets

Change in plan assets
Fair value of plan assets at beginning of year	$	650		$	924		$	0		$	0
Actual gain (loss) return on plan assets		78			(214	)		0			0
Employer contributions		16			18			0			0
Employer direct benefit payments		7			5			15			15
Plan participants’ contributions		0			0			4			4
Benefits paid		(58	)		(78	)		0			0
Direct benefit payments		(1	)		(1	)		(19	)		(19	)
Plan settlements (3)		(6	)		(4	)		0			0
Fair value of plan assets at end of year (1)	$	686		$	650		$	0		$	0

(1)The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

(2)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

(3)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

Schedule of Net Periodic Benefit Cost

TECO Energy	Pension Benefits									Other Benefits (1)
	2023			2022			2021			2023			2022			2021
(millions)
Service cost	$	15		$	18		$	19		$	1		$	2		$	2
Interest cost		35			23			21			7			5			5
Expected return on plan assets		(54	)		(51	)		(52	)		0			0			0
Amortization of:
Actuarial loss		5			17			24			0			3			4
Prior service cost		0			0			0			(2	)		(2	)		(2	)
Settlement loss (2)		2			2		0				0			0			0
Net periodic benefit cost	$	3		$	9		$	12		$	6		$	8		$	9

Schedule of Amounts Recognized in OCI and Regulatory Assets

Net loss (gain) arising during the year (includes curtailment gain)		2			123			(56	)		7			(50	)		(5	)
Prior service cost	$	0		$	0		$	0		$	(11	)	$	0		$	0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service credit		0			0			0			3			2			2
Amortization or settlement of actuarial loss		(7	)		(19	)		(23	)		0			(3	)		(4	)
Total recognized in OCI and regulatory assets	$	(5	)	$	104		$	(79	)	$	(1	)	$	(51	)	$	(7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(2	)	$	113		$	(67	)	$	5		$	(43	)	$	2

(1)Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

(2)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

Schedule of Pension Plan Assets

TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

TECO Energy	2023 Target Allocation			2022 Target Allocation			Actual Allocation, End of Year
Asset Category							2023			2022
Cash and cash equivalents	0%-10%			n/a				3	%	n/a
Equity securities	48%-68%			50%-70%				57	%		58	%
Fixed income securities	29%-49%			30%-50%				40	%		42	%
Total		100	%		100	%		100	%		100	%

Schedule of Fair Value Hierarchy Plan's Investments

The following table sets forth by level within the fair value hierarchy the plan’s investments.

Pension Plan Investments

TECO Energy	At Fair Value as of December 31, 2023
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	(1	)	$	0		$	0	$	0	$	(1	)
Accounts receivable		3			0			0		0		3
Accounts payable		(10	)		0			0		0		(10	)
Short-term investment funds (STIFs)		24			0			0		0		24
Common stock		1			0			0		0		1
Real estate investment trusts (REITs)		3			0			0		0		3
Mutual funds		38			0			0		0		38
Municipal bonds		0			2			0		0		2
Government bonds		0			108			0		0		108
Corporate bonds		0			57			0		0		57
Long futures		5			0			0		0		5
Short Sales		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		63			166			0		0		229
Common and collective trusts (1)		0			0			0		443		443
Mutual fund (1)		0			0			0		14		14
Total investments	$	63		$	166		$	0	$	457	$	686

(1)In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

TECO Energy	At Fair Value as of December 31, 2022
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	5		$	0		$	0	$	0	$	5
Accounts receivable		10			0			0		0		10
Accounts payable		(62	)		0			0		0		(62	)
Short-term investment funds (STIFs)		32			0			0		0		32
Real estate investment trusts (REITs)		2			0			0		0		2
Mutual funds		50			0			0		0		50
Municipal bonds		0			1			0		0		1
Government bonds		0			58			0		0		58
Corporate bonds		0			50			0		0		50
Mortgage backed securities (MBS)		0			5			0		0		5
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Short Sales		0			(3	)		0		0		(3	)
Written Options		0			2			0		0		2
Swaps		0			(1	)		0		0		(1	)
Investments not utilizing the practical expedient		37			113			0		0		150
Common and collective trusts (1)		0			0			0		444		444
Mutual fund (1)		0			0			0		56		56
Total investments	$	37		$	113		$	0	$	500	$	650

(1)In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

•Cash collateral is valued at cash posted due to its short-term nature.

•The STIF is valued at net asset value (NAV). The fund is an open-end investment, resulting in a readily-determinable fair value. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV. These factors make the STIF a level 1 asset.

•The primary pricing inputs in determining the fair value of the Common stocks and REITs are closing quoted prices in active markets.

•The primary pricing inputs in determining the level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-end mutual funds and the NAVs are validated with purchases and sales at NAV. Since the fair values are determined and published, they are considered readily-determinable fair values and therefore Level 1 assets.

•The primary pricing inputs in determining the fair value of Municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of Government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of Corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. CMOs are priced using to-be-announced (TBA) prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

•Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

•The primary pricing input in determining the fair value of the mutual fund utilizing the practical expedient is its NAV. It is an unregistered open-end mutual fund. The fund holds primarily corporate bonds, debt securities and other similar instruments issued by U.S. and non-U.S. public- or private-sector entities. The fund may purchase or sell securities on a when-issued basis. These transactions are made conditionally because a security has not yet been issued in the market, although it is authorized. A commitment is made regarding these transactions to purchase or sell securities for a predetermined price or yield, with payment and delivery taking place beyond the customary settlement period. Since this mutual fund is an open-end mutual fund and the prices are not published to an external source, it uses NAV as a practical expedient. The redemption frequency is daily. The redemption notice period is the same day. There were no unfunded commitments as of December 31, 2023.

•The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days. There were no unfunded commitments as of December 31, 2023.

•Treasury bills are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

•Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

Schedule of Benefit Payments

Expected Benefit Payments

TECO Energy			Other
(including projected service and net of employee contributions)	Pension		Postretirement
	Benefits		Benefits
(millions)
2024	$	76	$	12
2025		67		12
2026		66		12
2027		66		12
2028		65		11
2029-2033		295		51

TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member]

Schedule of Change in Benefit Obligation

The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and TECO Energy’s Florida-based other postretirement benefit plan (other benefits).

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2023			2022			2023			2022
Change in benefit obligation
Benefit obligation at beginning of year	$	666		$	850		$	142		$	200
Service cost		15			18			1			2
Interest cost		35			23			7			5
Plan participants’ contributions		0			0			4			4
Benefits paid		(59	)		(79	)		(19	)		(19	)
Actuarial loss (gain)		27			(142	)		7			(50	)
Plan amendments		0			0			(10	)		0
Plan settlements (3)		(6	)		(4	)		0			0
Benefit obligation at end of year	$	678		$	666		$	132		$	142

Schedule of Funded status

At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with projected benefit obligations and accumulated projected benefit obligations in excess of plan assets was as follows:

TECO Energy	Pension Benefits					Other Benefits (1)
Funded Status
(millions)	2023		2022			2023			2022
Benefit obligation (PBO/APBO)	$	678	$	666		$	132		$	142
Less: Fair value of plan assets		686		650			0			0
Funded status at end of year	$	8	$	(16	)	$	(132	)	$	(142	)

(1)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

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Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Short-Term Debt Credit Facilities

Credit Facilities

	December 31, 2023								December 31, 2022
			Borrowings		Borrowings		Letters				Borrowings		Borrowings		Letters
	Credit		Outstanding -		Outstanding -		of Credit		Credit		Outstanding -		Outstanding -		of Credit
(millions)	Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding		Facilities		Credit Facilities (1)		Commercial Paper (1)		Outstanding
5-year facility (2)	$	800	$	0	$	706	$	1	$	800	$	0	$	619	$	1
1-year term facility (3)		0		0		0		0		400		400		0		0
1-year term facility (4)		200		0		0		0		0		0		0		0
1-year term facility (5)		200		0		0		0		0		0		0		0
Total	$	1,200	$	0	$	706	$	1	$	1,200	$	400	$	619	$	1

(1)Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets.

(2)This 5-year facility matures on December 17, 2026. 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. On January 30, 2024, TEC completed a sale of $500 million aggregate principal amount of 4.90% Notes due March 1, 2029. TEC used the net proceeds from this offering for the repayment of a portion of the borrowings outstanding under the 5-year credit facility. Therefore, $497 million of borrowings outstanding under the 5-year credit facility were reclassified as long-term debt on the Consolidated Balance Sheet as of December 31, 2023.

(3)This 1-year term facility was set to mature on December 16, 2022. On December 13, 2022, TEC extended the maturity date to December 13, 2023, at which time the facility terminated.

(4)On March 1, 2023, TEC entered into a 1-year term facility that matures on February 28, 2024.

(5)On April 3, 2023, TEC entered into a 1-year term facility that matures on April 1, 2024.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Long-term Commitments

The following is a schedule of future payments under minimum lease payments with non-cancelable lease terms in excess of one year and other net purchase obligations/commitments at December 31, 2023:

	Purchased				Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Power		Transportation		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2024	$	4	$	135	$	533	$	194	$	34	$	3	$	5	$	908
2025		0		128		81		60		22		3		5		299
2026		0		125		53		17		23		1		1		220
2027		0		125		1		4		22		1		1		154
2028		0		97		0		1		17		1		0		116
Thereafter		0		833		0		0		33		75		0		941
Total future minimum payments	$	4	$	1,443	$	668	$	276	$	151	$	84	$	12	$	2,638

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Revenue (Tables)

12 Months Ended

Dec. 31, 2023

Revenue Recognition [Abstract]

Summary of Disaggregates TEC Revenue by Major Source

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
For the year ended December 31, 2023	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,711							$	1,711
Commercial		803								803
Industrial		203								203
Regulatory deferrals		(387	)							(387	)
Unbilled revenue		(2	)							(2	)
Other (1)		309								309
Total electric revenue		2,637								2,637
Total revenue	$	2,637							$	2,637
For the year ended December 31, 2022
Electric revenue
Residential	$	1,381		$	0	$	0		$	1,381
Commercial		666			0		0			666
Industrial		176			0		0			176
Regulatory deferrals		(21	)		0		0			(21	)
Unbilled revenue		9			0		0			9
Other (1)		312			0		(4	)		308
Total electric revenue		2,523			0		(4	)		2,519
Gas revenue
Residential		0			229		0			229
Commercial		0			200		0			200
Industrial (2)		0			31		0			31
Other (3)		0			196		(6	)		190
Total gas revenue		0			656		(6	)		650
Total revenue	$	2,523		$	656	$	(10	)	$	3,169
For the year ended December 31, 2021
Electric revenue
Residential	$	1,156		$	0	$	0		$	1,156
Commercial		602			0		0			602
Industrial		172			0		0			172
Regulatory deferrals		(6	)		0		0			(6	)
Unbilled revenue		(2	)		0		0			(2	)
Other (1)		252			0		(4	)		248
Total electric revenue		2,174			0		(4	)		2,170
Gas revenue
Residential		0			212		0			212
Commercial		0			191		0			191
Industrial (2)		0			25		0			25
Other (3)		0			100		(3	)		97
Total gas revenue		0			528		(3	)		525
Total revenue	$	2,174		$	528	$	(7	)	$	2,695

(1)Other includes sales to public authorities, off-system sales to other utilities and various other items.

(2)Industrial includes sales to power generation customers.

(3)Other includes off-system sales to other utilities and various other items.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2023		2022			2021
Natural gas purchases (net of sales) from affiliates	$	65	$	232		$	236
Services to/(from) affiliates		28		(4	)		(7	)
Interest income from affiliate		38		0			0
Interest expense to affiliate		11		0			0
Dividends to TECO Energy		472		517			450
Equity contributions from TECO Energy		300		605			580

Amounts due from or to affiliates at December 31,

(millions)	2023		2022
Accounts receivable related to asset management agreements with Emera Energy Services Inc. (1)	$	4	$	7
Accounts receivable excluding asset management agreements (1)		12		5
Taxes receivable (2)		3		10
Accounts payable (1)		10		31
Note payable to TECO Energy (3)		0		195

(1)Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2)Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.

(3)The note payable with TECO Energy bears interest at a rate approximating the market rate of TEC's commercial paper.

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Schedule of Segment Information

	Tampa				Eliminations/
(millions)	Electric		PGS		Reclassifications				TEC
2023
Revenues - external	$	2,637							$	2,637
Intracompany sales		0								0
Total revenues		2,637								2,637
Depreciation and amortization		422								422
Interest income from affiliates		38								38
Total interest charges		239								239
Provision for income taxes		87								87
Net income		466								466
Total assets		11,831								11,831
Capital expenditures		1,294								1,294
2022
Revenues - external	$	2,519	$	650	$	0			$	3,169
Intracompany sales		4		6		(10	)			0
Total revenues		2,523		656		(10	)			3,169
Depreciation and amortization		389		47		0				436
Total interest charges		142		25		0				167
Provision for income taxes		94		27		0				121
Net income		458		82		0				540
Total assets		12,064		2,471		(732	)	(1)		13,803
Capital expenditures		1,099		328		0				1,427
2021
Revenues - external	$	2,170	$	525	$	0			$	2,695
Intracompany sales		4		3		(7	)			0
Total revenues		2,174		528		(7	)			2,695
Depreciation and amortization		374		56		0				430
Total interest charges		110		20		0				130
Provision for income taxes		57		23		0				80
Net income		369		77		0				446
Total assets		10,650		2,209		(663	)	(1)		12,196
Capital expenditures		1,081		316		0				1,397

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

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

Reconciliation of beginning and ending carrying amount of asset retirement obligations:

	December 31,
(millions)	2023			2022
Beginning balance	$	35		$	31
Additional liabilities		1			1
Liabilities settled		(4	)		0
Other		0			3
Ending balance	$	32		$	35

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Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Summary of Lease Assets and Liabilities

(millions)	Classification	2023		2022
Right-of-use asset	Deferred charges and other assets	$	21	$	23
Lease liabilities
Current	Other current liabilities	$	2	$	2
Long-term	Deferred credits and other liabilities		20		22
Total lease liabilities		$	22	$	24

Future Minimum Lease Payments

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at December 31, 2023:

(millions)
Year ended December 31:	2024		2025		2026		2027		2028		Thereafter		Total
Minimum lease payments	$	3	$	2	$	1	$	1	$	1	$	46	$	54
Less imputed interest														(32	)
Total future minimum payments													$	22

Additional Information Related to Leases

Additional information related to Tampa Electric’s leases is as follows:

Year ended December 31,	2023			2022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	4		$	4
Weighted average remaining lease term (years)		45			44
Weighted average discount rate - operating leases		4.4	%		4.4	%

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Summary of Activity Related to TEC Employee PSUs

A summary of the activity related to TEC employee PSUs is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2022		176			56.21		9
Granted including DRIP		73			52.83		4
Exercised		(70	)		54.62		4
Forfeited		(5	)		54.72		0
Transferred (1)		(31	)		56.17		2
Outstanding as of December 31, 2023		143			55.32		7

This amount includes 38,197 units transferred to PGS upon their separation from TEC on January 1, 2023.

Summary of Activity Related to Employee RSUs

A summary of the activity related to TEC employee RSUs is presented in the following table:

				Weighted		Aggregate
	Number of			Average Grant		Intrinsic
	Units			Date Fair Value		Value
	(Thousands)			(Per Unit)		(Millions)
Outstanding as of December 31, 2022		173			56.23		9
Granted including DRIP		60			52.11		3
Exercised		(49	)		54.62		3
Forfeited		(5	)		54.72		0
Transferred (1)		(29	)		56.30		1
Outstanding as of December 31, 2023		150			55.15		8

(1)This amount includes 35,774 units transferred to PGS upon their separation from TEC on January 1, 2023.

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Significant Accounting Policies - Additional Information (Detail) - USD ($)			1 Months Ended	12 Months Ended
	Dec. 20, 2023	Jan. 01, 2023	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 30, 2024
Summary Of Significant Accounting Policies [Line Items]
Percentage of original cost of depreciable property				3.50%	3.20%	3.50%
Depreciation expense				$ 390,000,000	$ 402,000,000	$ 408,000,000
Allowance for funds used during construction rate				6.07%	6.00%	6.46%
Allowance for funds used during construction				$ 25,000,000	$ 46,000,000	$ 66,000,000
Receivables from contracts with customers			$ 284,000,000	284,000,000	295,000,000
Unbilled revenues			63,000,000	63,000,000	82,000,000
Franchise fees and gross receipts taxes				139,000,000	145,000,000	$ 129,000,000
Derivative Liabilities			$ 0	$ 0	$ 1,000,000
Derivative Liability, Statement of Financial Position [Extensible Enumeration]			Other Liabilities, Current	Other Liabilities, Current	Other Liabilities, Current
Derivative Assets			$ 1,000,000	$ 1,000,000	$ 5,000,000
Derivative Asset, Statement of Financial Position [Extensible Enumeration]			Prepaid Expense and Other Assets, Current	Prepaid Expense and Other Assets, Current	Prepaid Expense and Other Assets, Current
Issuance of common stock on transfer of assets		100
Gain (loss) from transaction		$ 0
Separation of PGS equity from TEC				$ (992,000,000)
Repayment of short term debt			$ 400,000,000
Common Stock [Member]
Summary Of Significant Accounting Policies [Line Items]
Separation of PGS equity from TEC				(871,000,000)
Retained Earnings [Member]
Summary Of Significant Accounting Policies [Line Items]
Separation of PGS equity from TEC				$ (121,000,000)
Term Loan [Member]
Summary Of Significant Accounting Policies [Line Items]
Principal amount		670,000,000
Repayment of short term debt	$ 670,000,000
Revolving Loan [Member]
Summary Of Significant Accounting Policies [Line Items]
Principal amount		$ 66,000,000
Repayment of short term debt	$ 286,000,000
Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Principal amount							$ 500,000,000
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities				4.00%	4.00%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities				5.99%	5.78%
PGS [Member]
Summary Of Significant Accounting Policies [Line Items]
Allowance for funds used during construction rate					6.00%	6.00%
Tampa Electric [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciation expense				$ 390,000,000	$ 359,000,000	$ 357,000,000

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Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property Plant And Equipment [Line Items]
Total cost	$ 12,520	$ 14,292
Total property, plant and equipment, net	10,228	11,644
Tampa Electric [Member]
Property Plant And Equipment [Line Items]
Less accumulated depreciation	(3,443)	(3,158)
Construction work in progress	1,151	949
PGS [Member]
Property Plant And Equipment [Line Items]
Less accumulated depreciation	0	(687)
Construction work in progress	0	248
Total property, plant and equipment, net		2,251
Electric Generation [Member]
Property Plant And Equipment [Line Items]
Total cost	6,732	6,300
Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	0	2,567
General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 997	1,020
Minimum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	10 years
Minimum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	15 years
Minimum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	4 years
Maximum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	60 years
Maximum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	75 years
Maximum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	60 years
Electric Transmission [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 1,182	1,109
Electric Transmission [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	10 years
Electric Transmission [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	75 years
Electric Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 3,609	$ 3,296
Electric Distribution [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	10 years
Electric Distribution [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	60 years

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Significant Accounting Policies - Summary of Assets and Liabilities of PGS in TEC's Consolidated Balance Sheets (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, plant and equipment
Utility plant	$ 13,655	$ 15,474
Accumulated depreciation	3,443	3,845
Total property, plant and equipment, net	10,228	11,644
Current assets
Cash and cash equivalents	5	14
Receivables, less allowance for credit losses of $1 at December 31, 2022	286	295
Inventories, at average cost
Regulatory assets	161	361
Prepayments and other current assets	32	35
Total current assets	720	909
Other assets
Regulatory assets	827	1,191
Deferred charges and other assets	56	59
Total other assets	883	1,250
Total assets	11,831	13,803	$ 12,196
Capitalization
Common stock	4,505	5,075
Accumulated other comprehensive loss	(1)	(1)
Retained earnings	219	346
Total capital	4,723	5,420	$ 4,792	$ 4,216
Long-term debt	3,933	3,734
Total capital	8,656	9,154
Current liabilities
Long-term debt due within one year	300	0
Notes payable	209	1,019
Accounts payable	354	472
Customer deposits	121	145
Regulatory liabilities	94	85
Accrued interest	28	30
Accrued taxes	14	15
Other	43	45
Total current liabilities	1,173	2,037
Other liabilities
Deferred income taxes	880	1,045
Regulatory liabilities	701	1,055
Deferred credits and other liabilities	184	269
Total Other liabilities	2,002	2,612
Total liabilities and capital	11,831	13,803
PGS [Member]
Property, plant and equipment
Utility plant		2,938
Accumulated depreciation		(687)
Total property, plant and equipment, net		2,251
Current assets
Cash and cash equivalents		4
Receivables, less allowance for credit losses of $1 at December 31, 2022		62
Due from affiliates		4
Inventories, at average cost
Regulatory assets		53
Prepayments and other current assets		4
Total current assets		88
Other assets
Regulatory assets		9
Deferred charges and other assets		79
Total other assets		132
Total assets		2,471
Capitalization
Common stock		871
Retained earnings		121
Total capital		1,556
Long-term debt		564
Total capital		992
Current liabilities
Notes payable		166
Accounts payable		78
Due to affiliates		27
Customer deposits		30
Regulatory liabilities		277
Accrued interest		4
Accrued taxes		5
Other		4
Total current liabilities		325
Other liabilities
Deferred income taxes		238
Regulatory liabilities		11
Deferred credits and other liabilities		75
Total Other liabilities		590
Total liabilities and capital		2,471
Fuel [Member]
Inventories, at average cost
Utility inventories	36	23
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	$ 181	159
Materials and Supplies [Member] | PGS [Member]
Inventories, at average cost
Utility inventories		$ 5

XML

Significant Accounting Policies - Summary of Assets and Liabilities of PGS in TEC's Consolidated Balance Sheets (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Allowance for credit losses	$ 2	$ 4
PGS [Member]
Allowance for credit losses		$ 1

XML

Regulatory - Additional Information (Detail)												1 Months Ended					12 Months Ended
	Jan. 31, 2027 USD ($)	Jan. 31, 2026 USD ($)	Jan. 31, 2025 USD ($)	Nov. 09, 2023 USD ($)	Jan. 23, 2023 USD ($)	Jul. 01, 2022 USD ($)	Aug. 06, 2021 USD ($)	Aug. 03, 2021 USD ($)	Nov. 19, 2020 USD ($)	Oct. 31, 2013 USD ($)	Sep. 06, 2013	Jan. 31, 2024 USD ($)	Sep. 30, 2023 USD ($)	Jan. 31, 2023 USD ($)	Sep. 30, 2022 USD ($)	Jan. 31, 2022 USD ($)	Dec. 31, 2023 USD ($) Unit $ / kWh	Dec. 31, 2021 USD ($)	Dec. 31, 2019 USD ($)	Nov. 17, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2020 USD ($)
Public Utilities General Disclosures [Line Items]
Percentage of ROE																	10.25%
Return on equity range																	range of plus or minus 1%
Allowed equity in the capital structure											54.00%
Base rate adjustment amount						$ 10,000,000														$ 22,000,000
Changes in base rate under agreement																		$ 0
Utility plant, at original costs																	$ 13,655,000,000				$ 15,474,000,000
Accumulated depreciation																	$ 3,443,000,000				3,845,000,000
Number of units applied for recovery | Unit																	3
Adjustment to fuel and capacity charges recovery								$ 83,000,000
Adjustment to fuel and capacity charges recovery																$ 169,000,000
Adjustments to fuel charges recovery					$ 518,000,000
Adjustments to fuel charges recovery projected reduction					$ 170,000,000
Storm restoration preparation costs																			$ 10,000,000
Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs																					2,938,000,000
Accumulated depreciation																					(687,000,000)
PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Increase in revenue									$ 34,000,000
Accumulated depreciation									34,000,000								$ 34,000,000
Increase in annual base rate									58,000,000
Peoples Gas [Member]
Public Utilities General Disclosures [Line Items]
Accumulated depreciation reversed amount																	14,000,000
Hurricane Ian [Member]
Public Utilities General Disclosures [Line Items]
Storm Reserve Expected to Charge															$ 121,000,000
Storm restoration costs charged to reserve															10,000,000
Replenishment of balance in reserve										$ 131,000,000							56,000,000
Storm restoration costs															129,000,000
Storm restoration costs balance				$ 29,000,000
Hurricane Nicole [Member]
Public Utilities General Disclosures [Line Items]
Restoration costs															$ 2,000,000
Hurricane Idalia [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs													$ 35,000,000
Electric Utility Plant [Member]
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs																	$ 13,655,000,000				$ 12,536,000,000
Cast Iron and Bare Steel Replacement Rider [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Increase in revenue									$ 24,000,000
Scenario Forecast [Member]
Public Utilities General Disclosures [Line Items]
Effect of base rate adjustment on revenue	$ 70,000,000	$ 100,000,000
Settlement Agreement [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement, approval date							Aug. 06, 2021
Allowed equity in the capital structure							54.00%
Base rate adjustment amount							$ 123,000,000
Increase in revenue							$ 191,000,000
Settlement agreement number of subsequent years adjustments							2 years
Settlement agreement adjustment amount														$ 90,000,000
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
Settlement Agreement [Member] | US Treasury Bond [Member]
Public Utilities General Disclosures [Line Items]
Calculating period							30 years
Determining period							6 months
Minimum [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE						9.25%
Minimum [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE									8.90%
Minimum [Member] | Hurricane Ian [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs				129,000,000
Minimum [Member] | Scenario Forecast [Member]
Public Utilities General Disclosures [Line Items]
Effect of base rate adjustment on revenue			$ 290,000,000
Minimum [Member] | Settlement Agreement [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]
Public Utilities General Disclosures [Line Items]
ROE revenue basis point on yield rate							0.50%
Maximum [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE						11.25%
Maximum [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE									11.00%
Maximum [Member] | Hurricane Ian [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs				$ 134,000,000
Maximum [Member] | Scenario Forecast [Member]
Public Utilities General Disclosures [Line Items]
Effect of base rate adjustment on revenue			$ 320,000,000
Maximum [Member] | Settlement Agreement [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE							11.00%
Base rate agreement frozen period							Dec. 31, 2024
Mid Point [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE						10.20%
Mid Point [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE									9.90%
Mid Point [Member] | Settlement Agreement [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 2021
Settlement agreement, approval date																	Nov. 06, 2017
Cost cap of project | $ / kWh																	1,500
Cost savings benefit percentage for projects below cost cap																	75.00%
Solar generation capacity investments																	$ 850,000,000
Investments in gas reserves																	$ 0
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]
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]
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																	$ 876,000,000
AFUDC included in energy project investment																	$ 91,000,000
Accumulated depreciation																						$ 267,000,000
Settlement agreement recovery description																	Tampa Electric’s Settlement Agreement provided recovery for the Big Bend modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs was 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																						$ 636,000,000
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																	2022
Big Bend Coal Generation Assets [Member]
Public Utilities General Disclosures [Line Items]
Settlement agreement cost recovery period																	15 years
Storm Restoration Cost Recovery [Member]
Public Utilities General Disclosures [Line Items]
Minimum cost recovery period																	12 months
Replenishment reserve for recovery of cost																	$ 56,000,000

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Regulatory assets:
Regulatory assets	$ 988	$ 1,552
Less: Current portion	161	361
Long-term regulatory assets	827	1,191
Regulatory liabilities:
Regulatory liabilities	795	1,140
Less: Current portion	94	85
Long-term regulatory liabilities	701	1,055
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	112	124
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	94	525
Capital Cost Recovery for Early Retired Assets [Member]
Regulatory assets:
Regulatory assets	507	497
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	0	20
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	236	272
Storm Reserve [Member]
Regulatory assets:
Regulatory assets	7	76
Other [Member]
Regulatory assets:
Regulatory assets	32	38
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	477	601
Cost-recovery Clauses - Deferred Balances [Member]
Regulatory liabilities:
Regulatory liabilities	20	30
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	271	498
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 27	$ 11

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2023
Capital Cost Recovery for Early Retired Assets [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Settlement agreement cost recovery period	15 years

XML

Income Taxes - Additional Information (Detail) - USD ($)		12 Months Ended
	Sep. 14, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Line Items]
Federal statutory tax rate		21.00%	21.00%	21.00%
Regulatory liability due to obligation to transfer tax rate reduction expense benefit		$ 23,000,000	$ 7,000,000
Provision for income taxes		87,000,000	121,000,000	$ 80,000,000
General business credit		$ 324,000,000
Deferred tax general business credits expiration date		2027-2043
Investment tax credits		$ 266,000,000
Investment tax credit expiration date		2034 and 2043
Uncertain tax positions		$ 10,000,000	9,000,000	6,000,000	$ 9,000,000
Unrecognized tax benefits decreased				0
Pre-tax charges (benefits)		0	0	0
Interest accrued		0	0	0
Penalties		$ 0	0	0
Statutes of limitations		3 years
Income tax examination period		1 year
Decrease in current income tax expense			(59,000,000)
Federal [Member] | R&D Tax Credits [Member]
Income Taxes [Line Items]
Uncertain tax positions		$ 10,000,000	$ 9,000,000
Unrecognized tax benefits decreased				$ 5,000,000
Florida [Member]
Income Taxes [Line Items]
Florida corporate income tax rate	4.46%	5.50%		3.53%
Regulatory liability due to obligation to transfer tax rate reduction expense benefit				$ 4,000,000

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Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Current income taxes, Federal	$ 84	$ (13)	$ 48
Current income taxes, State	(25)	(3)	4
Deferred income taxes, Federal	19	105	24
Deferred income taxes, State	5	38	13
Investment tax credits amortization	(8)	(6)	(9)
Total income tax expense	$ 87	$ 121	$ 80

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Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income before provision for income taxes	$ 553	$ 661	$ 526
Federal statutory income tax rates	21.00%	21.00%	21.00%
Income taxes, at statutory income tax rate	$ 116	$ 139	$ 110
State income tax, net of federal income tax	23	27	13
Excess deferred tax amortization	(25)	(25)	(26)
ITC amortization	(8)	(6)	(9)
AFUDC-equity	(4)	(7)	(9)
Production Tax Credits	(15)	(6)	0
Other Tax credits	(4)	(3)	(3)
Other	4	2	4
Total income tax expense	$ 87	$ 121	$ 80
Income tax expense as a percent of income before income taxes	15.70%	18.30%	15.20%

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Deferred tax liabilities
Property related		$ 1,227	$ 1,318
Deferred fuel		23	133
Pension and postretirement benefits		100	111
Insurance reserves		0	15
Total deferred tax liabilities		1,350	1,577
Deferred tax assets
Loss and credit carryforwards	[1]	383	408
Medical benefits		19	24
Insurance reserves		1	0
Pension and postretirement benefits		49	57
Capitalized energy conservation assistance costs		0	23
Other		18	20
Total deferred tax assets		470	532
Total deferred tax liability, net		$ 880	$ 1,045

[1] Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $10 million and $9 million at December 31, 2023 and 2022, respectively.

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Line Items]
Unrecognized tax benefits	$ 10	$ 9	$ 6	$ 9
Total deferred tax liabilities	1,350	1,577
Total deferred tax assets	$ 470	532
PGS [Member]
Income Taxes [Line Items]
Total deferred tax liabilities		213
Total deferred tax assets		$ 37

XML

Income Taxes - Summary of Expiration of Tax Credits and Net Operating Loss Carryforwards (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Income Taxes [Line Items]
General business credit	$ 324
Total tax credits and NOL carryforwards	$ 963
Deferred tax general business credits expiration date	2027-2043
Domestic Tax Authority [Member]
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward expiration	$ 135
Deferred tax general business credits expiration date	2037
Domestic Tax Authority [Member] | Tax Cuts and Jobs Act of 2017 Provisions
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward Not subject to expiration	$ 199	[1]
Deferred tax general business credits expiration date	indefinite	[1]
State and Local Jurisdiction [Member] | Tax Cuts and Jobs Act of 2017 Provisions
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward Not subject to expiration	$ 305	[1]
Deferred tax general business credits expiration date	indefinite	[1]

[1] Indefinite carryforward for Federal NOLs and NOLs for states that have adopted the U.S. Tax Cuts and Jobs Act of 2017 provisions, generated in tax years beginning after December 31, 2017.

XML

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Beginning Balance	$ 9	$ 6	$ 9
Increases due to tax positions related to prior year	0	2	1
Increases due to tax positions related to current year	1	1	1
Decreases due to settlements with tax authorities	0	0	(5)
Ending Balance	$ 10	$ 9	$ 6

XML

Employee Postretirement Benefits - Additional Information (Detail) - USD ($)			12 Months Ended
		Jan. 02, 2017	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Redemption frequency description			The redemption frequency of the funds ranges from daily to weekly and the redemption notice period ranges from 1 business day to 30 business days.
Percentage of qualified pension plan's actuarial value of assets			111.50%	107.24%
Employer contributions			$ 10,000,000	$ 15,000,000	$ 17,000,000
Employer matching contribution percentage of eligible participant contribution		75.00%				70.00%
Description of defined contribution plan			Effective January 1, 2017, the employer matching contributions increased from 70% to 75% with an additional incentive match of up to 25% of eligible participant contributions based on the achievement of certain operating company financial goals.
Defined contribution plan cost recognized			$ 18,000,000	22,000,000	22,000,000
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer			25.00%
Non-qualified SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, assets			$ 4,000,000	8,000,000
Unfunded [Member]
Defined Benefit Plan Disclosure [Line Items]
Commitments			0
Tampa Electric [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			1,000,000	4,000,000	7,000,000
Employer contributions			10,000,000	12,000,000	14,000,000
Employer contributions in next fiscal year			10,000,000
Defined contribution plan cost recognized			18,000,000	19,000,000	18,000,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			1,000,000	8,000,000	10,000,000
Defined benefit plan, assets			10,000,000	0
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			5,000,000	9,000,000	11,000,000
Defined benefit plan, assets			0	0
Other Postretirement Benefits [Member] | Tampa Electric [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			5,000,000	8,000,000	9,000,000
Employer contributions in next fiscal year			10,000,000
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions			0	0	0
Benefits paid			5,000,000	2,000,000	1,000,000
Non Elective Employer Contribution [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan cost recognized			10,000,000	10,000,000	10,000,000
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation of defined benefit pension plans			$ 642,000,000	634,000,000
Percentage of defined benefit plan's actual return			14.70%
Defined contribution plan, employer match percentage			6.00%
Employer matching contribution percentage of eligible participant contribution			75.00%
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			$ 3,000,000	9,000,000	12,000,000
Settlement charge	[1]		(2,000,000)	(2,000,000)	0
Commitments			678,000,000	666,000,000	850,000,000
Employer contributions			16,000,000	18,000,000
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	[2]		6,000,000	8,000,000	9,000,000
Settlement charge	[1],[2]		0	0	0
Commitments	[3]		132,000,000	142,000,000	$ 200,000,000
Employer contributions	[3]		0	$ 0
TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit plans service benefit to be amortized from regulatory assets in next fiscal year			$ 0

[1] Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

[2] Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

[3] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) - TECO Energy [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Pension Benefits [Member]
Change in benefit obligation
Benefit obligation at beginning of year		$ 666		$ 850
Service cost		15		18		$ 19
Interest cost		35		23		21
Plan participants’ contributions		0		0
Benefits paid		(59)		(79)
Actuarial loss (gain)		27		(142)
Plan amendments		0		0
Plan settlement	[1]	(6)		(4)
Benefit obligation at end of year		678		666		850
Other Postretirement Benefits [Member]
Change in benefit obligation
Benefit obligation at beginning of year	[2]	142		200
Service cost	[3]	1	[2]	2	[2]	2
Interest cost	[3]	7	[2]	5	[2]	5
Plan participants’ contributions	[2]	4		4
Benefits paid	[2]	(19)		(19)
Actuarial loss (gain)	[2]	7		(50)
Plan amendments	[2]	(10)		0
Plan settlement	[1],[2]	0		0
Benefit obligation at end of year	[2]	$ 132		$ 142		$ 200

[1] Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

[2] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

[3] Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

XML

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Change in plan assets
Employer contributions		$ 10		$ 15		$ 17
TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year		650
Fair value of plan assets at end of year		686		650
TECO Energy [Member] | Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year		650	[1]	924
Actual gain (loss) return on plan assets		78		(214)
Employer contributions		16		18
Employer direct benefit payments		7		5
Plan participants’ contributions		0		0
Benefits paid		(58)		(78)
Direct benefit payments		(1)		(1)
Plan settlement	[2]	(6)		(4)
Fair value of plan assets at end of year		686	[1]	650	[1]	924
TECO Energy [Member] | Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	[3]	0	[1]	0
Actual gain (loss) return on plan assets	[3]	0		0
Employer contributions	[3]	0		0
Employer direct benefit payments	[3]	15		15
Plan participants’ contributions	[3]	4		4
Benefits paid	[3]	0		0
Direct benefit payments	[3]	(19)		(19)
Plan settlement	[2],[3]	0		0
Fair value of plan assets at end of year	[3]	$ 0	[1]	$ 0	[1]	$ 0

[1] The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

[2] Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

[3] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member]	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses		5 years

XML

Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 686		$ 650
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)		678		666		$ 850
Fair value of plan assets		686	[1]	650	[1]	924
Funded status at end of year		8		(16)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	[2]	132		142		200
Fair value of plan assets	[2]	0	[1]	0	[1]	$ 0
Funded status at end of year	[3]	$ (132)		$ (142)

[1] The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

[2] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

[3] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

XML

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	$ 10	$ 0
Accrued benefit costs and other current liabilities	0	(7)
Deferred credits and other liabilities	(1)	(9)
Net amount recognized at end of year	9	(16)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	0	0
Accrued benefit costs and other current liabilities	(10)	(12)
Deferred credits and other liabilities	(99)	(121)
Net amount recognized at end of year	$ (109)	$ (133)

XML

Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income, Pretax and Regulatory Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 207	$ 242
Amount recognized	207	242
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	29	30
Amount recognized	$ 29	$ 30

XML

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		5.27%	5.55%
Rate of compensation increase		4.42%	3.79%
Discount rate	[1]		2.77%	2.37%
Expected long-term return on plan assets		7.05%	6.50%	6.70%
Rate of compensation increase		3.79%	3.05%	3.08%
Pension Benefits [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	[1]	5.55%
Pension Benefits [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	[1]	4.19%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		5.28%	5.53%
Rate of compensation increase		4.42%	3.79%
Discount rate	[1]		2.84%	2.47%
Rate of compensation increase		3.79%	3.04%	3.07%
Healthcare cost trend rate
Ultimate rate		4.00%	4.00%	4.50%
Year rate reaches ultimate trend rate		2047	2045	2038
Other Postretirement Benefits [Member] | Immediate Rate [Member]
Healthcare cost trend rate
Immediate rate		6.09%	6.39%
Other Postretirement Benefits [Member] | Initial Rate [Member]
Healthcare cost trend rate
Immediate rate		6.39%	5.61%	5.74%
Other Postretirement Benefits [Member] | Ultimate Trend Rate Per Actuary [Member]
Healthcare cost trend rate
Ultimate rate		4.00%	4.00%
Year rate reaches ultimate trend rate		2047	2047
Other Postretirement Benefits [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	[1]	6.14%
Other Postretirement Benefits [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	[1]	5.53%

[1] Discount rate range is the result of remeasurements that occurred in 2023.

XML

Employee Postretirement Benefits - Schedule of Amounts Recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost		$ 1		$ 8		$ 10
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost		5		9		11
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		15		18		19
Interest cost		35		23		21
Expected return on plan assets		(54)		(51)		(52)
Amortization of:
Actuarial loss		5		17		24
Prior service cost		$ 0		$ 0		$ 0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]		Nonoperating Income (Expense)		Nonoperating Income (Expense)		Nonoperating Income (Expense)
Settlement loss	[1]	$ 2		$ 2		$ 0
Net periodic benefit cost		3		9		12
Net loss (gain) arising during the year (includes curtailment gain)		2		123		(56)
Prior service cost		0		0		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service credit		0		0		0
Amortization or settlement of actuarial loss		(7)		(19)		(23)
Total recognized in OCI and regulatory assets		(5)		104		(79)
Total recognized in net periodic benefit cost, OCI and regulatory assets		(2)		113		(67)
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	[3]	1	[2]	2	[2]	2
Interest cost	[3]	7	[2]	5	[2]	5
Expected return on plan assets	[3]	0		0		0
Amortization of:
Actuarial loss	[3]	0		3		4
Prior service cost	[3]	$ (2)		$ (2)		$ (2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]		Nonoperating Income (Expense)		Nonoperating Income (Expense)		Nonoperating Income (Expense)
Settlement loss	[1],[3]	$ 0		$ 0		$ 0
Net periodic benefit cost	[3]	6		8		9
Net loss (gain) arising during the year (includes curtailment gain)	[3]	7		(50)		(5)
Prior service cost	[3]	(11)		0		0
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service credit	[3]	3		2		2
Amortization or settlement of actuarial loss	[3]	0		(3)		(4)
Total recognized in OCI and regulatory assets	[3]	(1)		(51)		(7)
Total recognized in net periodic benefit cost, OCI and regulatory assets	[3]	$ 5		$ (43)		$ 2

[1] Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.

[2] Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.

[3] Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan

XML

Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member]	Dec. 31, 2023	Dec. 31, 2022
Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	100.00%	100.00%
Actual Asset Allocation [Member] | Cash and Cash Equivalents [Member]
Asset Category
Actual Allocation, End of Year	3.00%
Actual Asset Allocation [Member] | Equity Securities [Member]
Asset Category
Actual Allocation, End of Year	57.00%	58.00%
Actual Asset Allocation [Member] | Fixed Income Securities [Member]
Asset Category
Actual Allocation, End of Year	40.00%	42.00%
Target Allocation [Member]
Asset Category
Target Allocation	100.00%	100.00%
Target Allocation [Member] | Cash and Cash Equivalents [Member] | Minimum [Member]
Asset Category
Target Allocation	0.00%
Target Allocation [Member] | Cash and Cash Equivalents [Member] | Maximum [Member]
Asset Category
Target Allocation	10.00%
Target Allocation [Member] | Equity Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	48.00%	50.00%
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	68.00%	70.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	29.00%	30.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	49.00%	50.00%

XML

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 686		$ 650
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)		5
Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24		32
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3		2
Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	38		50
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2		1
Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	108		58
Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	57		50
Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5
Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)		(3)
Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			2
Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	229		150
Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			1
Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	443	[1]	444	[2]
Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	[1]	56	[2]
Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			5
Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			(1)
NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	457		500
NAV [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
NAV [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
NAV [Member] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
NAV [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
NAV [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	443	[1]	444	[2]
NAV [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14	[1]	56	[2]
NAV [Member] | Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
NAV [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	63		37
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)		5
Level 1 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24		32
Level 1 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3		2
Level 1 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	38		50
Level 1 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 1 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 1 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 1 [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5
Level 1 [Member] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 1 [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 1 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	63		37
Level 1 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 1 [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[1]	0	[2]
Level 1 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[1]	0	[2]
Level 1 [Member] | Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 1 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	166		113
Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 2 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 2 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 2 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 2 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 2 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2		1
Level 2 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	108		58
Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	57		50
Level 2 [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 2 [Member] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(1)		(3)
Level 2 [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			2
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	166		113
Level 2 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			1
Level 2 [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[1]	0	[2]
Level 2 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[1]	0	[2]
Level 2 [Member] | Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			5
Level 2 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			(1)
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 3 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 3 [Member] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 3 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 3 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 3 [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[1]	0	[2]
Level 3 [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	[1]	0	[2]
Level 3 [Member] | Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Level 3 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			0
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3		10
Accounts Receivable [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Accounts Receivable [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3		10
Accounts Receivable [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Accounts Receivable [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(10)		(62)
Accounts Payable [Member] | NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Accounts Payable [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(10)		(62)
Accounts Payable [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Accounts Payable [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0		$ 0

[1] In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

[2] In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the TECO Energy fair value of plan assets.

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Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions	Dec. 31, 2023 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2024	$ 76
Expected Benefit Payments - 2025	67
Expected Benefit Payments - 2026	66
Expected Benefit Payments - 2027	66
Expected Benefit Payments - 2028	65
Expected Benefit Payments - 2029-2033	295
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2024	12
Expected Benefit Payments - 2025	12
Expected Benefit Payments - 2026	12
Expected Benefit Payments - 2027	12
Expected Benefit Payments - 2028	11
Expected Benefit Payments - 2029-2033	$ 51

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Short-Term Debt - Credit Facilities (Detail) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 17, 2021
Line Of Credit Facility [Line Items]
Credit Facilities	$ 1,200,000,000	$ 1,200,000,000
Borrowings Outstanding	209,000,000	1,019,000,000
Letters of Credit Outstanding	1,000,000	1,000,000
Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
Letters of Credit Outstanding		400,000,000
Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	706,000,000	619,000,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities			$ 800,000,000
5-year Facility [Member] | December 17, 2026 [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	800,000,000	800,000,000
Letters of Credit Outstanding	1,000,000	1,000,000
5-year Facility [Member] | December 17, 2026 [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
Letters of Credit Outstanding		0
5-year Facility [Member] | December 17, 2026 [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	706,000,000	619,000,000
1-year Term Facility [Member] | December 13, 2023 [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	0	400,000,000
Letters of Credit Outstanding	0	0
1-year Term Facility [Member] | December 13, 2023 [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
Letters of Credit Outstanding		400,000,000
1-year Term Facility [Member] | December 13, 2023 [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0	0
1-year Term Facility [Member] | February 28, 2024 [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	200,000,000	0
Letters of Credit Outstanding	0	0
1-year Term Facility [Member] | February 28, 2024 [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
Letters of Credit Outstanding		0
1-year Term Facility [Member] | February 28, 2024 [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0	0
1-year Term Facility [Member] | April 1, 2024 [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	200,000,000	0
Letters of Credit Outstanding	0	0
1-year Term Facility [Member] | April 1, 2024 [Member] | Credit Facilities [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	0
Letters of Credit Outstanding		0
1-year Term Facility [Member] | April 1, 2024 [Member] | Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Borrowings Outstanding	$ 0	$ 0

XML

Short-Term Debt - Credit Facilities (Parenthetical) (Detail) - USD ($)				12 Months Ended
	Jan. 30, 2024	Apr. 03, 2023	Mar. 01, 2023	Dec. 31, 2023	Dec. 31, 2022	May 25, 2021
4.90% Notes [Member]
Line Of Credit Facility [Line Items]
Debt instrument, offering date				Jan. 30, 2024
Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Debt instrument, offering date	Jan. 30, 2024
Aggregate principal amount issued	$ 500,000,000
Stated interest rate	4.90%
Debt instrument maturity date	Mar. 01, 2029
Subsequent Event [Member] | 4.90% Notes [Member]
Line Of Credit Facility [Line Items]
Debt instrument, offering date	Jan. 30, 2024
Aggregate principal amount issued	$ 500,000,000
Stated interest rate	4.90%
Debt instrument maturity date	Mar. 01, 2029
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date				Dec. 17, 2026	Dec. 17, 2026
5-year Facility [Member] | Subsequent Event [Member] | Long-Term Debt [Member] | 4.90% Notes [Member]
Line Of Credit Facility [Line Items]
Borrowings outstanding	$ 497,000,000
5-year Facility [Member] | Subsequent Event [Member] | Long-Term Debt [Member]
Line Of Credit Facility [Line Items]
Borrowings outstanding	$ 497,000,000
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Apr. 01, 2024	Feb. 28, 2024	Dec. 13, 2022	Dec. 13, 2022
Maximum [Member] | Commercial Paper Program [Member]
Line Of Credit Facility [Line Items]
Commercial paper issued				$ 800,000,000		$ 800,000,000

XML

Short-Term Debt - Additional Information (Detail) - USD ($)							1 Months Ended	12 Months Ended
	Dec. 20, 2023	Nov. 24, 2023	Apr. 03, 2023	Mar. 01, 2023	Dec. 13, 2022	Dec. 17, 2021	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Jan. 01, 2023	Dec. 14, 2022	May 25, 2021
Line Of Credit Facility [Line Items]
Commitment fees, percentage								0.125%
Weighted-average interest rate							5.68%	5.68%	5.00%
Repayment of short term debt							$ 400,000,000
Line of credit facility maximum borrowing capacity							1,200,000,000	$ 1,200,000,000	$ 1,200,000,000
Increase of credit facility						$ 100,000,000
Affiliate [Member]
Line Of Credit Facility [Line Items]
Repayment of note payable							$ 195,000,000
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.
Debt instrument term							5 years
Repayment of note payable							$ 149,000,000
364-day Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity			$ 200,000,000	$ 200,000,000
Credit facility maturity date			Apr. 01, 2024	Feb. 28, 2024
TEC Term Loan [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity					$ 500,000,000						$ 400,000,000
Credit facility maturity date		Dec. 13, 2023			Dec. 16, 2022			Dec. 13, 2023
Term Loan [Member]
Line Of Credit Facility [Line Items]
Principal amount										$ 670,000,000
Repayment of short term debt	$ 670,000,000
Proceeds from short term debt	670,000,000
Revolving Loan [Member]
Line Of Credit Facility [Line Items]
Principal amount										$ 66,000,000
Repayment of short term debt	286,000,000
Proceeds from short term debt	$ 286,000,000
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date			Apr. 01, 2024	Feb. 28, 2024				Dec. 13, 2022	Dec. 13, 2022
Minimum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date						Mar. 22, 2023
Maximum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date						Dec. 17, 2026
Maximum [Member] | Commercial Paper Program [Member]
Line Of Credit Facility [Line Items]
Commercial paper issued							$ 800,000,000	$ 800,000,000				$ 800,000,000

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions				12 Months Ended
	Jan. 30, 2024	Jul. 12, 2022	Mar. 18, 2021	Dec. 31, 2023
Subsequent Event [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 500
Stated interest rate	4.90%
Debt instrument maturity date	Mar. 01, 2029
Debt instrument, offering date	Jan. 30, 2024
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
5.00% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year		2052
Aggregate principal amount issued		$ 300
Stated interest rate		5.00%
Debt instrument maturity date		Jul. 15, 2052
Redeemable principal amount percentage		100.00%
Basis spread on federal funds rate		30.00%
Redeemable principal amount percentage		100.00%
Debt instrument, start date of redemption		Jan. 15, 2052
Debt instrument, offering date		Jul. 12, 2022
3.875% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year		2024
Aggregate principal amount issued		$ 300
Stated interest rate		3.875%
Debt instrument maturity date		Jul. 12, 2024
Basis spread on federal funds rate		15.00%
Debt instrument, offering date		Jul. 12, 2022
4.90% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, offering date				Jan. 30, 2024
4.90% Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2029
Aggregate principal amount issued	$ 500
Stated interest rate	4.90%
Debt instrument maturity date	Mar. 01, 2029
Redeemable principal amount percentage	100.00%
Basis spread on federal funds rate	15.00%
Redeemable principal amount percentage	100.00%
Debt instrument, offering date	Jan. 30, 2024
4.90% Notes [Member] | Long-Term Debt [Member] | Subsequent Event [Member] | 5-year Facility [Member]
Debt Instrument [Line Items]
Borrowings outstanding	$ 497

XML

Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Other Commitments [Line Items]
2024	$ 908
2025	299
2026	220
2027	154
2028	116
Thereafter	941
Total future minimum payments	2,638
Purchased Power [Member]
Other Commitments [Line Items]
2024	4
2025	0
2026	0
2027	0
2028	0
Thereafter	0
Total future minimum payments	4
Transportation [Member]
Other Commitments [Line Items]
2024	135
2025	128
2026	125
2027	125
2028	97
Thereafter	833
Total future minimum payments	1,443
Capital Projects [Member]
Other Commitments [Line Items]
2024	533
2025	81
2026	53
2027	1
2028	0
Thereafter	0
Total future minimum payments	668
Fuel and Gas Supply [Member]
Other Commitments [Line Items]
2024	194
2025	60
2026	17
2027	4
2028	1
Thereafter	0
Total future minimum payments	276
Long-term Service Agreements [Member]
Other Commitments [Line Items]
2024	34
2025	22
2026	23
2027	22
2028	17
Thereafter	33
Total future minimum payments	151
Operating Leases [Member]
Other Commitments [Line Items]
2024	3
2025	3
2026	1
2027	1
2028	1
Thereafter	75
Total future minimum payments	84
Demand Side Management [Member]
Other Commitments [Line Items]
2024	5
2025	5
2026	1
2027	1
2028	0
Thereafter	0
Total future minimum payments	$ 12

XML

Commitments and Contingencies - Schedule of Long-term Commitments (Parenthetical) (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Other Commitments [Line Items]
Total future minimum payments	$ 2,638
Fuel and Gas Supply [Member]
Other Commitments [Line Items]
Total future minimum payments	276
Transportation [Member]
Other Commitments [Line Items]
Total future minimum payments	$ 1,443

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Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 2,637	$ 2,519	$ 2,170
Total gas revenue	0	650	525
Total revenue	2,637	3,169	2,695
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	1,711	1,381	1,156
Total gas revenue		229	212
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	803	666	602
Total gas revenue		200	191
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	203	176	172
Total gas revenue		31	25
Regulatory Deferrals [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(387)	(21)	(6)
Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(2)	9	(2)
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	309	308	248
Total gas revenue		190	97
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		(4)	(4)
Total gas revenue		(6)	(3)
Total revenue		(10)	(7)
Eliminations [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		0	0
Eliminations [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		0	0
Eliminations [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		0	0
Eliminations [Member] | Regulatory Deferrals [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Eliminations [Member] | Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Eliminations [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		(4)	(4)
Total gas revenue		(6)	(3)
Tampa Electric [Member] | Operating Segments [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	2,637	2,523	2,174
Total gas revenue		0	0
Total revenue	2,637	2,523	2,174
Tampa Electric [Member] | Operating Segments [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	1,711	1,381	1,156
Total gas revenue		0	0
Tampa Electric [Member] | Operating Segments [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	803	666	602
Total gas revenue		0	0
Tampa Electric [Member] | Operating Segments [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	203	176	172
Total gas revenue		0	0
Tampa Electric [Member] | Operating Segments [Member] | Regulatory Deferrals [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(387)	(21)	(6)
Tampa Electric [Member] | Operating Segments [Member] | Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(2)	9	(2)
Tampa Electric [Member] | Operating Segments [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 309	312	252
Total gas revenue		0	0
PGS [Member] | Operating Segments [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		656	528
Total revenue		656	528
PGS [Member] | Operating Segments [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		229	212
PGS [Member] | Operating Segments [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		200	191
PGS [Member] | Operating Segments [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		31	25
PGS [Member] | Operating Segments [Member] | Regulatory Deferrals [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
PGS [Member] | Operating Segments [Member] | Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
PGS [Member] | Operating Segments [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue		0	0
Total gas revenue		$ 196	$ 100

XML

Revenue - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Remaining performance obligations, transaction price	$ 78	$ 140
Remaining performance obligations, expected year of revenue recognition	2043

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Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Natural gas purchases (net of sales) from affiliates	$ 65	$ 232	$ 236
Services to/(from) affiliates	28	(4)	(7)
Interest expense to affiliates	239	167	130
Dividends to TECO Energy	472	517	450
Equity contributions from TECO Energy	300	605	580
Affiliate [Member]
Related Party Transaction [Line Items]
Accounts receivable excluding asset management agreements	12	5
Taxes receivable	3	10
Accounts payable	10	31
Note payable to TECO Energy	0	195
Related Party [Member]
Related Party Transaction [Line Items]
Interest income from affiliates	38	0	0
Interest expense to affiliates	11	0	0
Emera Energy Services Inc [Member]
Related Party Transaction [Line Items]
Accounts receivable related to asset management agreements	4	7
TECO Energy [Member]
Related Party Transaction [Line Items]
Dividends to TECO Energy	472	517	450
Equity contributions from TECO Energy	$ 300	$ 605	$ 580

XML

Segment Information - Additional Information (Detail)	Dec. 31, 2023 Customer
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	840,000

XML

Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Total revenues	$ 2,637	$ 3,169	$ 2,695
Depreciation and amortization	422	436	430
Interest income from affiliates	38	0	0
Total interest charges	239	167	130
Provision for income taxes	87	121	80
Net income	466	540	446
Total assets	11,831	13,803	12,196
Capital expenditures	1,294	1,427	1,397
Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,637	3,169	2,695
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues		(10)	(7)
Depreciation and amortization		0	0
Total interest charges		0	0
Provision for income taxes		0	0
Net income		0	0
Total assets		(732)	(663)
Capital expenditures		0	0
Eliminations [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Total revenues		(10)	(7)
Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues		0	0
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	2,637	2,523	2,174
Depreciation and amortization	422	389	374
Interest income from affiliates	38
Total interest charges	239	142	110
Provision for income taxes	87	94	57
Net income	466	458	369
Total assets	11,831	12,064	10,650
Capital expenditures	1,294	1,099	1,081
Tampa Electric [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Total revenues	0	4	4
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	$ 2,637	2,519	2,170
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues		656	528
Depreciation and amortization		47	56
Total interest charges		25	20
Provision for income taxes		27	23
Net income		82	77
Total assets		2,471	2,209
Capital expenditures		328	316
PGS [Member] | Operating Segments [Member] | Intracompany Sales [Member]
Segment Reporting Information [Line Items]
Total revenues		6	3
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues		$ 650	$ 525

XML

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 35	$ 31
Additional liabilities	1	1
Liabilities settled	(4)	0
Other	0	3
Ending balance	$ 32	$ 35

XML

Leases - Additional Information (Detail) - Tampa Electric [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Leased Assets [Line Items]
Operating lease, description	Tampa Electric has operating leases for buildings, land, telecommunication services and rail cars.
Operating lease, existence of option to extend	true
Operating lease options to extend	options to extend the leases for up to an additional 65 years.
Operating lease expense	$ 4	$ 4	$ 5
Maximum [Member]
Operating Leased Assets [Line Items]
Operating lease renewal term	62 years
Minimum [Member]
Operating Leased Assets [Line Items]
Operating lease renewal term	1 year

XML

Leases - Summary of Lease Assets and Liabilities (Detail) - Tampa Electric [Member] - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Schedule Of Assets And Liabilities Lessee [Line Items]
Right-of-use asset	$ 21	$ 23
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Deferred Costs and Other Assets	Deferred Costs and Other Assets
Current	$ 2	$ 2
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Current	Other Liabilities, Current
Long-term	$ 20	$ 22
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Deferred Credits and Other Liabilities, Noncurrent	Deferred Credits and Other Liabilities, Noncurrent
Total lease liabilities	$ 22	$ 24

XML

Leases - Future Minimum Lease Payments (Detail) - Tampa Electric [Member] - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Minimum lease payments, 2024	$ 3
Minimum lease payments, 2025	2
Minimum lease payments, 2026	1
Minimum lease payments, 2027	1
Minimum lease payments, 2028	1
Minimum lease payments, Thereafter	46
Minimum lease payments, Total	54
Less imputed interest	(32)
Total lease liabilities	$ 22	$ 24

XML

Leases - Additional Information Related to Leases (Detail) - Tampa Electric [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating cash flows for operating leases (millions)	$ 4	$ 4
Weighted average remaining lease term (years)	45 years	44 years
Weighted average discount rate - operating leases	4.40%	4.40%

XML

Stock-Based Compensation - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Performance Share Unit Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
PSU/RSU performance cycles	3 years
Number of trading days	50 days
Compensation cost recognized	$ 2,000,000	$ 4,000,000	$ 3,000,000
Tax benefits related to compensation cost	1,000,000	1,000,000	1,000,000
Cash payments	3,000,000	7,000,000	10,000,000
Unrecognized compensation cost	$ 2,000,000	3,000,000
Weighted-average period expected to be recognized	2 years
Restricted Share Unit Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
PSU/RSU performance cycles	3 years
Number of trading days	50 days
Vesting period	3 years
Compensation cost recognized	$ 2,000,000	3,000,000	2,000,000
Tax benefits related to compensation cost	1,000,000	1,000,000	0
Cash payments	3,000,000	0	$ 0
Unrecognized compensation cost	$ 2,000,000	$ 3,000,000
Weighted-average period expected to be recognized	2 years

XML

Stock-Based Compensation - Summary of Activity Related to Employee PSUs (Detail) - Performance Share Unit Plan [Member] $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Outstanding as of December 31, 2022 | shares	176
Number of Units, Granted including DRIP | shares	73
Number of Units, Exercised | shares	(70)
Number of Units, Forfeited | shares	(5)
Number of Units, Transferred | shares	(31)	[1]
Number of Units, Outstanding as of December 31, 2023 | shares	143
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2022 | $ / shares	$ 56.21
Weighted Average Grant Date Fair Value, Granted including DRIP | $ / shares	52.83
Weighted Average Grant Date Fair Value, Exercised | $ / shares	54.62
Weighted Average Grant Date Fair Value, Forfeited | $ / shares	54.72
Weighted Average Grant Date Fair Value, Transferred | $ / shares	56.17	[1]
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2023 | $ / shares	$ 55.32
Aggregate Intrinsic Value, Outstanding as of December 31, 2022 | $	$ 9
Aggregate Intrinsic Value, Granted including DRIP | $	4
Aggregate Intrinsic Value, Exercised | $	4
Aggregate Intrinsic Value, Forfeited | $	0
Aggregate Intrinsic Value, Transferred | $	2	[1]
Aggregate Intrinsic Value, Outstanding as of December 31, 2023 | $	$ 7

[1] This amount includes 38,197 units transferred to PGS upon their separation from TEC on January 1, 2023.

XML

Stock-Based Compensation - Summary of Activity Related to Employee PSUs (Parenthetical) (Details) - Performance Share Unit Plan [Member] - shares			12 Months Ended
		Jan. 01, 2023	Dec. 31, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of Units, Transferred	[1]		31,000
PGS [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of Units, Transferred		38,197

[1] This amount includes 38,197 units transferred to PGS upon their separation from TEC on January 1, 2023.

XML

Stock-Based Compensation - Summary of Activity Related to Employee RSUs (Detail) - Restricted Share Unit Plan [Member] $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of Units, Outstanding as of December 31, 2022 | shares	173
Number of Units, Granted including DRIP | shares	60
Number of Units, Exercised | shares	(49)
Number of Units, Forfeited | shares	(5)
Number of Units, Transferred | shares	(29)	[1]
Number of Units, Outstanding as of December 31, 2023 | shares	150
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2022 | $ / shares	$ 56.23
Weighted Average Grant Date Fair Value, Granted including DRIP | $ / shares	52.11
Weighted Average Grant Date Fair Value, Exercised | $ / shares	54.62
Weighted Average Grant Date Fair Value, Forfeited | $ / shares	54.72
Weighted Average Grant Date Fair Value, Transferred | $ / shares	56.3	[1]
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2023 | $ / shares	$ 55.15
Aggregate Intrinsic Value, Outstanding as of December 31, 2022 | $	$ 9
Aggregate Intrinsic Value, Granted including DRIP | $	3
Aggregate Intrinsic Value, Exercised | $	3
Aggregate Intrinsic Value, Forfeited | $	0
Aggregate Intrinsic Value, Transferred | $	1	[1]
Aggregate Intrinsic Value, Outstanding as of December 31, 2023 | $	$ 8

[1] This amount includes 35,774 units transferred to PGS upon their separation from TEC on January 1, 2023.

XML

Stock-Based Compensation - Summary of Activity Related to Employee RSUs (Parenthetical) (Details) - Restricted Share Unit Plan [Member] - shares			12 Months Ended
		Jan. 01, 2023	Dec. 31, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of Units, Transferred	[1]		29,000
PGS [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of Units, Transferred		35,774

[1] This amount includes 35,774 units transferred to PGS upon their separation from TEC on January 1, 2023.

XML

Long-Term PPAs - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2019 MW
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	$ 78	$ 151	$ 106
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power	$ 35	$ 70	$ 46
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
PPAs range | MW				515

XML

Subsequent Events - Additional Information (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 30, 2024	Dec. 31, 2023
Subsequent Event [Member]
Subsequent Event [Line Items]
Aggregate principal amount issued	$ 500
Stated interest rate	4.90%
Debt instrument maturity date	Mar. 01, 2029
Debt instrument, offering date	Jan. 30, 2024
4.90% Notes [Member]
Subsequent Event [Line Items]
Debt instrument, offering date		Jan. 30, 2024
4.90% Notes [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Aggregate principal amount issued	$ 500
Stated interest rate	4.90%
Debt instrument maturity date	Mar. 01, 2029
Debt instrument, offering date	Jan. 30, 2024

XML

Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - Allowance for Credit Losses - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		$ 4	$ 7	$ 7
Charged to Income		9	5	8
Other Charges		(1)	0	0
Payments & Deductions	[1]	10	8	8
Balance at End of Period		$ 2	$ 4	$ 7

[1] Write-off of individual bad debt accounts