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, 2020

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

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.  

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 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, 2020 was zero.

As of February 12, 2021, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc., 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
BCF	billion cubic feet
CAIR	Clean Air Interstate Rule
CCRs	coal combustion residuals
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CO2	carbon dioxide
COVID-19	coronavirus disease 2019
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CT	combustion turbine
ECRC	environmental cost recovery clause
Emera	Emera Inc., a geographically diverse energy and services company headquartered in Nova Scotia, Canada
EPA	U.S. Environmental Protection Agency
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
EUSHI	Emera US Holdings Inc., a wholly owned subsidiary of Emera, which is the sole shareholder of TECO Energy’s common stock
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FPSC	Florida Public Service Commission
GHG	greenhouse gas
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ITCs	investment tax credits
kWac	kilowatt on an alternating current basis
LNG	liquefied natural gas
MBS	mortgage-backed securities
MD&A	the section of this report entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger	Merger of Merger Sub Company with and into TECO Energy, with TECO Energy as the surviving corporation
MGP	manufactured gas plant
MMBTU	one million British Thermal Units
MRV	market-related value
MW	megawatt(s)
MWH	megawatt-hour(s)
NAV	net asset value
Note	Note to consolidated financial statements
NPNS	normal purchase normal sale
O&M expenses	operations and maintenance expenses
OCI	other comprehensive income
OPC	Office of Public Counsel
OPEB	other postemployment benefits
Parent	TECO Energy, Inc., the direct parent company of Tampa Electric Company
PBGC	Pension Benefit Guarantee Corporation
PBO	projected benefit obligation
PGA	purchased gas adjustment

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Term	Meaning
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PRP	potentially responsible party
R&D	research and development
REIT	real estate investment trust
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SoBRAs	solar base rate adjustments
SPP	storm protection plan
STIF	short-term investment fund
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TEC	Tampa Electric Company
TECO Energy	TECO Energy, Inc., the direct parent company of Tampa Electric Company
TSI	TECO Services, Inc.
U.S. GAAP	generally accepted accounting principles in the United States

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. TEC is a public utility operating within the State of Florida. TEC has two operating segments. Its electric division, referred to as Tampa Electric, provides retail electric service to approximately 792,500 customers in West Central Florida with a net winter system generating capacity of 5,790 MW at December 31, 2020. The gas division of TEC, referred to as PGS, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With approximately 426,000 customers, PGS has operations in Florida’s major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2020 was approximately 2.1 billion therms. 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 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 2020 Annual TEC Consolidated Financial Statements.

TEC Human Capital

TEC had approximately 3,100 employees as of December 31, 2020, substantially all of whom are located in Florida.

Tampa Electric had approximately 2,420 employees as of December 31, 2020, of which 710 were represented by the International Brotherhood of Electrical Workers and 190 were represented by the Office and Professional Employees International Union. In December 2019, 370 TSI employees were transferred to Tampa Electric. The transfer of these employees to Tampa Electric created operational synergies in the organization but did not materially impact shared service costs or the TEC Consolidated Statement of Income.

PGS had approximately 680 employees as of December 31, 2020. Approximately 90 employees in four of PGS’s 14 service areas and call center are represented by various union organizations.

TEC initiated a plan in March 2020 to manage the critical safety, operational and business risks associated with the COVID-19 pandemic. On March 19, 2020 TEC launched a work-from-home plan for approximately 70% of the workforce and implemented policies and revised work practices to promote safe operations for the remaining field-based employees.

In alignment with our efforts to promote inclusion and diversity, TEC has in place a company-wide I&D initiative, which provides the organizational blueprint for achieving greater diversity and uniqueness of individuals and cultures and the varied perspectives they provide. 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

TEC’s Tampa Electric division 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

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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. It has two generating stations in or near Tampa, one generating station in southwestern Polk County, and fourteen photovoltaic power stations, eight in Hillsborough County and six in Polk County (one of which was completed in 2021).

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

Tampa Electric Operating Revenue

(millions)	2020			2019			2018
Residential	$	1,018		$	1,046		$	1,067
Commercial		506			562			582
Industrial		133			156			161
Other sales of electricity		165			183			187
Regulatory deferrals and unbilled revenue		(25	)		(49	)		(2	)
Total energy sales		1,797			1,898			1,995
Off system sales		3			6			11
Other		49			61			60
Total revenues	$	1,849		$	1,965		$	2,066

Megawatt-hour Sales

(thousands)	2020		2019		2018
Residential		10,122		9,584		9,418
Commercial		6,058		6,240		6,266
Industrial		1,891		2,021		2,014
Other sales of electricity		1,883		1,939		1,933
Total retail		19,954		19,784		19,631
Off system sales		75		155		286
Total energy sold		20,029		19,939		19,917

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 more 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, fewer daylight hours and colder temperatures.

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 2020, 2019 and 2018 results reflect an amended and restated settlement agreement approved by the FPSC on November 6, 2017. See Note 3 to the 2020 Annual TEC Consolidated Financial Statements for information regarding Tampa Electric’s base rates, ROE and other regulatory matters.

Other Cost Recovery

Tampa Electric has five cost recovery clauses.

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(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 November 2020, the FPSC approved cost-recovery rates for the above clauses for 2021. See Note 3 to the 2020 Annual TEC Consolidated Financial Statements for further information.

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.

Unlike in the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including approximately 30 other utilities and other power generators. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a long-term basis. Tampa Electric is not a major participant in the wholesale market because it uses its lower-cost generation primarily to serve its retail customers rather than the wholesale market.

FPSC rules promote cost-competitiveness in the building of new steam generating capacity or solar capacity by requiring IOUs, such as Tampa Electric, to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle or solar capacity greater than 75 MWs. These rules allow independent power producers and others to bid to supply the new generating capacity.

In many areas of the country, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, known as distributed generation, by individual residential, commercial and industrial customers, or by third-party developers. Distributed generation is encouraged and supported by special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Developers offer attractive financing and leasing arrangements to encourage project development. In Florida, third parties that are not subject to regulation by the FPSC are currently not permitted to make direct sales of electricity to end-use customers.

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Generation Sources

In 2020 and 2019, approximately 89% and 90%, respectively, of Tampa Electric’s generation of electricity was natural gas-fired, with solar representing 6% and 4%, respectively, and coal representing 5% and 6%, respectively. In 2020 and 2019, Tampa Electric used its generating units to meet approximately 88% and 93%, respectively, of the total system load requirements, with the remaining 12% and 7%, 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. See MD&A - Capital Investments for information regarding TEC’s forecasted capital investments in generation sources, including solar projects and the modernization of the Big Bend Power Station.

The table below presents Tampa Electric’s average delivered fuel cost per MMBTU, excluding solar production which has no fuel cost.

Average cost per MMBTU	2020		2019		2018
Natural Gas (1)	$	3.31	$	3.40	$	4.07
Coal (2)		3.69		3.66		3.37
Oil/petroleum coke (3)		25.16		22.01		3.10
Average generation cost per MWh (4)		20.27		27.81		30.40

(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.

(3) In 2020 and 2019, the cost per MMBTU represents 100% oil.

(4) 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, 2020, approximately 84% of Tampa Electric’s 2.0 million BCF of gas storage capacity was full. Tampa Electric has contracted for 70% of its expected gas needs for the January through December 2021 period. Tampa Electric expects to issue RFPs to meet its remaining 2021 gas needs and begin contracting for its 2022 requirements. Additional volume requirements are purchased in the short-term spot market.

Coal. Tampa Electric burned under 0.5 million tons of coal during 2020 and estimates that its coal consumption will be similar in 2021. Consistent with 2020, Tampa Electric will be purchasing its coal in 2021 under a contract with two different commodity suppliers. Tampa Electric takes coal deliveries primarily by water and uses transportation agreements with a rail provider if spot coal supplies are needed.   

Oil. Tampa Electric purchases low sulfur No. 2 fuel oil and petroleum coke for its Polk Power station on a spot basis.

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. The franchises are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture. 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. These agreements have various expiration dates ranging through 2049 and are expected to be renewed under similar terms and conditions.

Franchise fees expense totaled $42 million and $45 million in 2020 and 2019, respectively. Franchise fees are calculated using a formula based primarily on electric revenues and are recovered from customers.

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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 and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. See Environmental Compliance section of the MD&A for additional information.

PEOPLES GAS SYSTEM – Gas Operations

PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the state of Florida.

Gas is delivered to the PGS distribution system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that serves approximately 426,000 customers. The system includes approximately 13,800 miles of gas mains and 7,800 miles of service lines (see PGS’s Franchises and Other Rights section below).

In 2020, the total throughput for PGS was approximately 2.1 billion therms. Of this total throughput, 5% was gas purchased and resold to customers by PGS, 89% was third-party supplied gas that was delivered to transportation-only customers and 6% was gas sold off-system (i.e., to customers not connected to PGS’s distribution system).

PGS provides transportation service to customers utilizing gas-fired technology in the production of electric power. In addition, PGS provides gas transportation service to large LNG facilities located in Jacksonville, Florida. PGS has seen continuing interest and development in natural gas vehicles. There are 53 compressed natural gas filling stations connected to the PGS distribution system. See the PGS Operating Results section of the MD&A for information on the impact of natural gas vehicles on PGS’s operations.

Revenues and therms for PGS for the years ended December 31 were as follows:

	Revenues						Therms
(millions)	2020		2019		2018		2020		2019		2018
Residential	$	158	$	154	$	157		91		85		87
Commercial		135		146		151		476		517		510
Industrial		17		16		16		460		430		361
Off-system sales		30		55		78		126		188		217
Power generation		6		5		5		955		853		791
Other revenues		75		72		69		-		-		-
Total	$	421	$	448	$	476		2,108		2,073		1,966

No significant part of PGS’s business is dependent upon a single or limited number of customers where the loss of any one customer would have a significant adverse effect on PGS. PGS experiences winter peak throughputs due to higher therm usage for heating during colder temperatures.

Regulation

Base Rates

The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC seeks to set rates at a level that provides an opportunity for a 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 providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’s weighted cost of capital, primarily includes its cost 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 irregular intervals at the initiative of PGS, the FPSC or other parties.

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See Note 3 to the 2020 Annual TEC Consolidated Financial Statements for further information regarding PGS’s base rates, ROE and other regulatory matters.

  Cost Recovery Clauses and Riders

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through a PGA clause. This clause is designed to recover the actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. The current PGA cap rate, effective January 2021, was approved by the FPSC in November 2020.

In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm charge for energy conservation and pipeline replacement programs. The conservation charge is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are mandated by Florida law and approved and monitored by the FPSC. PGS is also permitted to recover the return on, depreciation expenses and applicable taxes associated with the replacement of cast iron/bare steel infrastructure. The FPSC approved a replacement program of approximately 5%, or 500 miles, of the PGS system over a 10-year period beginning in 2013. In February 2017, the FPSC approved an amendment to the cast iron bare steel rider to include certain plastic materials and pipe deemed obsolete by Pipeline and Hazardous Materials Safety Administration, totaling approximately 550 miles. PGS estimates that all cast iron and bare steel pipe will be removed from its system by 2022, with the replacement of obsolete plastic pipe continuing under the rider until 2028.

FPSC and Other Regulation

The FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers. In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’s distribution system.

PGS is subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section of the MD&A).

Competition

Although PGS is not in direct competition with any other regulated local distributors of natural gas for customers within its service areas, there are other forms of competition. The principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. There is also competition from other local distributors of natural gas to establish service territories in unserved areas of Florida. 

Competition is most prevalent in the large commercial and industrial markets. These classes of customers have the option to contract with companies that sell gas directly by transporting gas through other facilities and thereby bypassing the PGS system. In response to this competition, PGS has developed various programs, including the provision of transportation-only services at discounted rates.

In Florida, gas service is unbundled for all non-residential customers. PGS offers unbundled transportation service to all non-residential customers, and residential customers consuming in excess of 1,999 therms annually, allowing these customers to purchase commodity gas from a third party but continue to pay PGS for the transportation. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings effect when a customer shifts to transportation-only sales. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. As of December 31, 2020, PGS had approximately 26,000 transportation-only customers out of approximately 40,100 eligible customers.

Gas Supplies

PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers. In addition, PGS has reserved firm transportation capacity through intrastate pipelines owned by PGS’s affiliate,SeaCoast Gas Transmission, LLC.

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Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to meet the gas requirements of its system commodity customers, except during certain weather events and localized emergencies affecting the PGS distribution system.

Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by the FERC. PGS actively markets any excess capacity available to partially offset costs recovered through the PGA clause.

PGS procures natural gas supplies using base-load contracts and swing-supply contracts (i.e., short-term contracts without a specified volume) with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices or a fixed price for the contract term.

Franchises and Other Rights

PGS holds franchise and other rights with 117 municipalities and districts throughout Florida. These franchises govern the placement of PGS’s facilities on the public rights-of-way as it carries on its retail business in the localities it serves. The franchises are irrevocable and are not subject to amendment without the consent of PGS.

Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’s property located in the franchise area, if the franchise is not renewed. Otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.

PGS’s franchise agreements have various expiration dates through 2050. PGS expects to negotiate up to 17 franchise renewals in 2021 under similar terms, in addition to those franchise agreements that have auto renewals effective during 2021. Franchise fees expense totaled $10 million in 2020 and 2019. Franchise fees are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are recovered on a dollar-for-dollar basis from the respective customers within each franchise area.

Utility operations in areas outside of incorporated municipalities and districts are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commission of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates, and these rights are, therefore, considered perpetual.

Environmental Matters

PGS’s operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures. TEC is one of several PRPs for certain superfund sites and, through PGS, for former MGP sites. See Note 8 to the 2020 Annual TEC Consolidated Financial Statements and the Environmental Compliance section of the MD&A for additional information.

Item 1A. RISK FACTORS

Risks Relating to TEC’s Business and Strategy

Regulatory, Legislative, and Legal Risks

TEC’s electric and gas utilities are regulated; changes in regulation or the regulatory environment could reduce revenues, increase costs or competition.

TEC’s electric and gas utilities operate in regulated industries. Retail operations, including the rates charged, 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.

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If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, indicating a trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged returns above their allowed ranges 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 businesses could increase TEC’s costs or curtail its activities.

TEC’s businesses are 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. In addition, environmental and land use laws and regulations may curtail sales of natural gas to new customers, which could reduce PGS’s customer growth in the future.

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, establishes emission guidelines for states to address GHG emissions from existing coal-fired electric generating units.  Tampa Electric has emission units that are subject to the ACE rule and is preparing to engage in the development of a state plan that could be finalized by the end of 2021.

The outcome of expected litigation and the EPA rulemaking process and its impact on Tampa Electric’s business is currently uncertain. Tampa Electric is continuing to evaluate the potential impact of the rule, but currently expects prudently incurred related costs for compliance to be recovered through rates. 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 2020 Annual TEC Consolidated Financial Statements for further information regarding TEC’s income taxes.

Tampa Electric and PGS may not be able to secure adequate rights-of-way to construct transmission lines, gas interconnection 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 and PGS rely on federal, state and local governmental agencies to secure rights-of-way and siting permits to construct transmission lines, gas interconnection 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 and PGS:

• 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 their customers;

• May not be able to maintain reliability in their service areas;

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

• May experience a negative impact on their ability to provide electric or gas service to new customers.

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

Tampa Electric and PGS hold franchise agreements with counterparties throughout their service areas. 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. Some agreements contain provisions allowing municipalities to purchase the portion of the applicable utility’s system located within a given municipality’s boundaries under certain conditions.

Operational and Construction Risks

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TEC’s businesses are sensitive to variations in weather and the effects of extreme weather and have seasonal variations.

TEC’s utility businesses are affected by variations in general weather conditions including severe weather. Energy sales by its electric and gas utilities 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. PGS typically has a short but significant winter peak period that is dependent on cold weather; Tampa Electric has both summer and winter peak periods that are dependent on weather conditions. Tampa Electric and PGS forecast 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 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 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 territories. Refer to “variations in weather” above for further information.

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.

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 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 gas leaks, 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.

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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, such as COVID-19, 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 “Public Health Risk” section below. 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.

Continued effects of the ongoing COVID-19 pandemic, or an outbreak of infectious disease, another pandemic or a similar public health threat could have a negative impact on TEC’s operations.

An outbreak of infectious disease, a pandemic or a similar public health threat, such as the ongoing COVID-19 pandemic, 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 and natural gas, 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 start to 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

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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.

The gas distribution industry has been subject to competitive forces for several years. Gas services provided by PGS are unbundled for all non-residential customers. Because PGS earns on the distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS’s results. However, future structural changes could adversely affect PGS.

TEC relies on some natural gas transmission assets that it does not own or control to deliver natural gas.

TEC depends on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas it sells to the wholesale and retail markets. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver products and satisfy its contractual and service obligations could be adversely affected.

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

Tampa Electric and PGS depend on third parties to supply fuel, including natural gas, oil 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 electricity and gas 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 businesses.

TEC’s businesses are sensitive to changes in gas, coal, oil 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.

In the case of PGS, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of PGS as compared to electricity, other forms of energy and other gas suppliers.

Developments in technology could reduce demand for electricity and gas.

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 appliances and equipment. Advances in these or other technologies could reduce the cost of producing electricity or transporting gas, or otherwise make Tampa Electric’s existing generating facilities uneconomic. Advances in such technologies could reduce demand for electricity or natural gas, 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.

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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.

Potential state or local law and regulation changes may adversely affect PGS.

Recently state and local policies in certain jurisdictions in the United States have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas. Changes in applicable state or local laws and regulations could adversely impact PGS.

Liquidity, Capital Requirements, and Common Stock 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; 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.

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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 used to determine benefit 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, 2021 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. For 2021, Tampa Electric is forecasting capital expenditures to support the current levels of customer growth, harden transmission and distribution facilities against storm damage, maintain transmission and distribution system reliability, modernize the Big Bend Power Station, invest in solar generation and maintain generating unit reliability and efficiency. For 2021, PGS is forecasting capital expenditures to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel, cast iron and obsolete plastic pipe.

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.

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 $120 million. Credit facilities or debt agreements do not have ratings downgrade covenants that would require immediate repayment.

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.

TAMPA ELECTRIC

Tampa Electric has electric generating stations in service, with a December 2020 net winter generating capability of 5,790 MWs. Tampa Electric assets include the Big Bend Power Station (1,693 MWs capacity), the Bayside Power Station (2,083 capacity) and the Polk Power Station (1,420 MWs capacity). Also included in Tampa Electric’s assets at December 31, 2020 are thirteen solar arrays (594 MWs). In addition, solar arrays totaling 60 MWs were placed in service in early 2021.

Tampa Electric owns 189 substations having an aggregate transformer capacity of 23,900 mega volts amps. The transmission system consists of approximately 1,344 total circuit miles of high voltage transmission lines, including underground and double-circuit lines. The distribution system consists of approximately 6,246 circuit miles of overhead lines and approximately 5,715 circuit miles of underground lines. As of December 31, 2020, there were 809,570 meters in service. All of this property is located in Florida.

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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.

PEOPLES GAS SYSTEM

PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 21,600 miles of pipe, including approximately 13,800 miles of mains and 7,800 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

PGS’s operations are located in 14 service areas throughout Florida. Most of the operations and administrative facilities are owned.

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 2020 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. SELECTED FINANCIAL DATA OF TAMPA ELECTRIC COMPANY

Information required by Item 6 is omitted pursuant to General Instruction I(2) of Form 10-K.

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

OVERVIEW

TEC has regulated electric and gas utility operations in Florida. At December 31, 2020, Tampa Electric served approximately 792,500 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 5,790 MW. PGS, Florida’s largest gas distribution utility, served approximately 426,000 residential, commercial, industrial and electric power generating customers at December 31, 2020 in all major metropolitan areas of the state, with a total natural gas throughput of approximately 2.1 billion therms in 2020.

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 2020 Annual TEC Consolidated Financial Statements for information regarding related party transactions.

2020 PERFORMANCE

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

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In 2020, TEC’s net income was $424 million, compared with $370 million in 2019. 2020 results were impacted by higher base revenues and higher AFUDC, partially offset by higher O&M expense excluding all FPSC-approved cost-recovery clauses,depreciation expense, income taxes and interest expense. See Operating Results below for further detail regarding 2020 results as compared to 2019. For information regarding 2019 results as compared to 2018, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” ofTEC’s Annual Report on Form 10-K for the year ended December 31, 2019.

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.

Due to continued growth in rate base, Tampa Electric anticipates earning near or below the bottom of the allowed ROE range in 2021. Tampa Electric sales volumes are expected to be slightly lower than in 2020, which benefited from weather that was warmer than in recent years (see Customer and Energy Sales Growth Outlook for further details). As a result, Tampa Electric anticipates earnings to be slightly lower than in 2020. Tampa Electric expects customer growth rates in 2021 to be consistent with 2020, reflective of current expected economic growth in Florida.

On February 1, 2021, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting revenue requirements of approximately $280 million to $295 million, effective in January 2022. Tampa Electric’s proposed 2022 rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investment, and accelerated recovery of the remaining net book value of retiring assets. Tampa Electric also intends to seek approval for Generation Base Rate Adjustments of $130 million to recover the costs of the second phase of the Big Bend modernization project and additional utility-scale solar projects in subsequent years. These filing amounts are estimates until Tampa Electric completes its analysis and files the case. Tampa Electric expects to file its detailed case on or after April 2, 2021, and the FPSC is expected to decide the case by the end of the year. See Note 3 to the 2020 Annual TEC Consolidated Financial Statements for further information.

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million base rate reduction for SPP program costs previously recovered in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million of costs removed from base rates. This settlement agreement was approved on August 10, 2020, and Tampa Electric’s cost recovery began in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.

On November 19, 2020, the FPSC approved a settlement agreement that allows PGS to increase base rates $58 million annually effective January 2021. The $58 million increase includes $24 million previously recovered through the cast iron and bare steel replacement rider. The settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint.  In 2021, PGS anticipates earning within its allowed ROE range and expects rate base and earnings to be higher than in 2020. PGS also expects customer growth rates in 2021 to exceed population growth, reflecting expectations of continued strong housing demand in Florida and commercial activity trending back towards normal levels. PGS sales volumes in 2021 are expected to increase at a level slightly above customer growth as 2020 energy sales to commercial customers were negatively impacted by the COVID-19 pandemic and unfavorable winter weather.

In addition to the base rate increase, the PGS settlement agreement also provides PGS the ability to reverse a total of $34 million of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.90% before that time with an allowed equity in the capital structure of 54.7% from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If, on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024.

In 2021, TEC expects to invest approximately $1.4 billion, excluding AFUDC, in capital projects compared to $1.4 billion in 2020. Capital projects support normal system reliability and growth at the utilities. AFUDC will be earned on eligible capital projects during the construction periods. Tampa Electric investments include continuation of the modernization of the Big Bend Power Station, solar investments, storm hardening investments and an AMI (Advanced Meter Infrastructure) project, which includes the installation of smart meters. 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 by the end of 2023. PGS will make investments to expand its system and support customer growth, including expected investments related to compressed natural gas fueling stations, renewable natural gas and

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liquefied natural gas facilities, and continued replacement of obsolete plastic, cast iron and bare steel pipe. 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).

COVID-19 PANDEMIC

During 2020, the ongoing COVID-19 pandemic affected the service territories in which TEC operates. To date, the COVID-19 pandemic has not had a material financial impact on TEC’s earnings. TEC provides essential services and continues to operate and meet customer demand. TEC’s top priority continues to be the health and safety of its customers and employees. Management continues to closely monitor developments related to the COVID-19 pandemic.

In March 2020, TEC activated its company-wide pandemic and business continuity plans, including travel restrictions, directing employees to work remotely whenever possible, restricting access to operating facilities, physical distancing and implementing additional protocols (including the expanded use of personal protective equipment) for work within customers’ premises. TEC is monitoring recommendations by local and national public health authorities related to the COVID-19 pandemic and continues to adjust operational requirements as needed.

TEC is working with customers on relief initiatives in response to the effect of the pandemic on customers’ ability to make payments and the need for continued service. These initiatives included the temporary suspension of disconnection for non-payment of bills in the second and a portion of the third quarters of 2020 and the continued development of payment arrangements where necessary. In 2020, TEC experienced an increase in the aging of customer receivables resulting from the temporary suspension of disconnections. This trend has begun to reverse as disconnection processes resumed on September 14, 2020. To date, customer defaults as a result of bankruptcies have not been material. As of the year ended December 31, 2020, adjustments to the allowance for credit losses have increased but have not had a material impact on the financial statements. TEC is continuing to monitor customer accounts and to work with customers on payment arrangements.

The extent of the future impact of the COVID-19 pandemic on TEC’s financial results and business operations is uncertain at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions, timing and effectiveness of vaccinations, future economic activity and energy usage. Please see Risk Factors for further information. TEC plans to complete its capital investment plans and continue to reliably and safely serve its customers. Capital project delays and supply chain disruptions have been immaterial to date but, depending on the duration of the COVID-19 pandemic, forecasted capital expenditures may be delayed due to supply chain disruptions, travel restrictions for contractors or the deferral of non-essential capital work. TEC currently expects to continue to have adequate liquidity given its cash position, existing bank facilities and access to capital but will continue to monitor the impact of the COVID-19 pandemic on future cash flows. Refer to Liquidity and Capital Resources for further details.  

OPERATING RESULTS

This MD&A utilizes TEC’s consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Our 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 2020 Annual TEC Consolidated Financial Statements).  

(millions)		2020			2019			2018
Revenues
	Tampa Electric	$	1,849		$	1,965		$	2,066
	PGS		433			461			488
	Eliminations		(10	)		(22	)		(30	)
	TEC	$	2,272		$	2,404		$	2,524
Net income
	Tampa Electric	$	372		$	316		$	294
	PGS		52			54			47
	TEC	$	424		$	370		$	341

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TAMPA ELECTRIC

Electric Operations Results

Tampa Electric’s net income in 2020 was $372 million, compared with $316 million in 2019. Results primarily reflected higher base revenues and higher AFUDC earnings, partially offset by higher O&M excluding all FPSC-approved cost-recovery clauses, income taxes and interest 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.

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)	2020		% Change			2019		% Change			2018
Revenues	$	1,849		(6	)	$	1,965		(5	)	$	2,066
O&M expense		401		(2	)		408		(19	)		504
Depreciation and amortization expense		339		1			336		8			312
Taxes, other than income		161		(2	)		165		(2	)		168
Non-fuel operating expenses		901		(1	)		909		(8	)		984
Fuel expense		345		(35	)		533		(8	)		578
Purchased power expense		83		69			49		(17	)		59
Total fuel & purchased power expense		428		(26	)		582		(9	)		637
Total operating expenses		1,329		(11	)		1,491		(8	)		1,621
Operating income	$	520		10		$	474		7		$	445
AFUDC-equity	$	27		145		$	11		10		$	10
Provision for income taxes	$	66		12		$	59		(9	)	$	65
Net income	$	372		18		$	316		7		$	294
Megawatt-Hour Sales (thousands)
Residential		10,122		6			9,584		2			9,418
Commercial		6,058		(3	)		6,240		(0	)		6,266
Industrial		1,891		(6	)		2,021		0			2,014
Other		1,883		(3	)		1,939		0			1,933
Total retail		19,954		1			19,784		1			19,631
Off system sales		75		(52	)		155		(46	)		286
Total energy sold		20,029		0			19,939		0			19,917
Retail customers—(thousands)
At December 31		793		2			779		2			764
Retail net energy for load		21,055		1			20,770		1			20,663
Total degree days		4,807		5			4,568		(3	)		4,711

Operating Revenues

Revenues were $116 million lower than in 2019 driven by lower clause revenue, partially offset by increased base revenue from in-service of additional solar generation projects, favorable weather, higher residential sales, and customer growth. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in 2020 were 12% above normal (a 20-year statistical degree day average) and 5% above 2019. Total net energy for load, which is a calendar measurement of energy output, increased 1% in 2020 compared with 2019.

Customer and Energy Sales Growth Outlook

The Tampa labor market continues to outperform the state and U.S. labor markets. Due to the business closures caused by the COVID-19 pandemic, the Tampa area unemployment rate increased to 7.2% in 2020 from 3.1% in 2019. Similarly, Florida’s unemployment rate increased to 8.0% in 2020 from 3.1% in 2019 and the U.S. rate rose to 8.2% from 3.7% in 2019. The unemployment rate in the Tampa area is expected to decline over the next few years.  

Population growth is forecasted to continue to be a major driver of customer growth. Tampa Electric expects customer growth to be 1.5% to 2.0% annually over the next few years, assuming continued economic recovery from COVID-19 and business expansion.

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For the past several years, weather-normalized energy consumption per customer declined due to the combined effects of voluntary conservation efforts, improvements in lighting and equipment efficiency. It is expected to continue to decline annually at an average annual rate of 0.6% over the next few years.

In 2021, retail energy sales are expected to be slightly lower than 2020 levels. In 2020, energy sales benefitted from favorable weather while 2021 projections are based on normal weather. Normalizing 2020 for weather, 2021 energy sales are projected to increase over 2020 primarily due to customer growth and recovery from the COVID-19 pandemic. Over the longer term, energy sales growth is expected to be around 1.0%.

Operating Expenses

In 2020, operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $10 million higher than in 2019 primarily reflecting increased costs related to safety, benefits and higher insurance costs for solar assets. Depreciation and amortization expense increased $2 million in 2020 from normal additions to facilities to reliably serve customers and the in-service of solar generation projects, partially offset by a one-time $16 million software amortization settlement.

Excluding all FPSC-approved cost-recovery clause-related expense, O&M expense in 2021 is expected to be lower than in 2020 as SPP-related costs will be recovered through the SPP cost recovery clause (see Note 3), partially offset byhigher costs to safely and reliably serve customers. In 2021, depreciation expense is expected to increase due to normal plant additions, the in-service of solar projects and the one-time software amortization settlement in 2020.

Fuel Prices and Fuel Cost Recovery

In November 2020, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental, conservation and storm protection costs for 2021. The rates include the expected cost for natural gas and coal in 2021, and a net prior period under-recovery true-up of fuel, purchased power and capacity clause expense. These rates are typically set annually, based on information provided in September of the year prior to the year the rates take effect.

In March 2020, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges, effective with June 2020 customer bills, due to a decline in expected fuel commodity and capacity costs in 2020. The FPSC approved the request on April 28, 2020. This resulted in lower fuel and capacity clause rates to customers for the remainder of 2020 and included an acceleration of the return of these savings in the three months starting June 2020 through customer bill credits.

Total fuel expense decreased in 2020 from 2019 primarily due to lower natural gas prices. Delivered natural gas prices decreased 15% in 2020 as a mild winter and impacts from the COVID-19 pandemic impacted demand.

Total 2021 fuel and purchased power costs are expected to be greater than in 2020, due to increased prices for natural gas.

PGS

Operating Results

In 2020, PGS reported net income of $52 million, compared with $54 million in 2019. Results reflect a 5.0% increase in the number of customers in 2020 compared to 2019. Revenues were $28 million lower than in the prior year primarily due to lower PGA clause-related revenues and lower off-system sales, partially offset by higher cast iron and bare steel replacement rider revenue. Base revenues were $1 million lower than in 2019 primarily due to the COVID-19 pandemic impacts lowering commercial sales, which was partially offset by customer growth. Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was $4 million higher than in 2019 primarily due to higher labor, contractor and technology related costs to safely and reliably operate and maintain the growing distribution system. Depreciation and amortization increased $4 million due to asset growth to reliably serve customers (see Note 3 to the TEC Consolidated Financial Statements). Return on investment in the cast iron and bare steel replacement rider and AFUDC earnings were each $4 million higher in the 2020 period. 

In both 2020 and 2019, total throughput for PGS was approximately 2.1 billion therms. See Business - Peoples Gas System- Gas Operations for information regarding therms by type of customer.

PGS provides transportation service to customers utilizing gas-fired technology in the production of electric power. In addition, PGS provides gas transportation service to large LNG facilities located in Jacksonville, Florida. PGS has also experienced interest in the usage of CNG as an alternative fuel for vehicles, especially refuse trucks and buses. Therms sold to CNG stations were 36 million therms sold in both 2020 and 2019. Currently, there are 53 CNG fueling stations connected to the PGS system, with more in progress. PGS owns three CNG filling stations, and the cost of these stations is recovered over time through a special rate approved by the FPSC. CNG conversions add therm sales to the gas system without requiring significant capital investment by PGS.

The table below provides a summary of PGS’s revenue and expenses and therm sales by customer type.

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Summary of Operating Results

(millions, except customers)	2020		% Change			2019		% Change			2018
Revenues	$	433		(6	)	$	461		(6	)	$	488
Cost of gas sold		121		(20	)		152		(16	)		180
Operating expenses		231		4			222		(4	)		231
Operating income	$	81		(7	)	$	87		13		$	77
Net income	$	52		(4	)	$	54		15		$	47
Therms sold – by customer segment
Residential		91		7			85		(2	)		87
Commercial		476		(8	)		517		1			510
Industrial		460		7			430		19			361
Off-system sales		126		(33	)		188		(13	)		217
Power generation		955		12			853		8			791
Total		2,108		2			2,073		5			1,966
Therms sold – by sales type
System supply		241		(19	)		296		(10	)		328
Transportation		1,867		5			1,777		8			1,638
Total		2,108		2			2,073		5			1,966
Customer (thousands) – at December 31		426		5			406		4			392

See Business-Peoples Gas System-Competition for information regarding PGS’s transportation-only customers.

PGS Outlook

In 2021, PGS anticipates earning within its allowed ROE range and expects rate base and earnings to be higher than in 2020. PGS expects customer growth in 2021 to be higher than Florida’s population growth rates, reflecting expectations of continued strong housing demand in Florida and commercial activity trending back towards normal levels. Assuming normal weather, PGS sales volumes are expected to increase above customer growth, as the COVID-19 pandemic impact on 2021 commercial energy sales is expected to be less than 2020. In January 2021, a base rate increase went into effect in accordance with the FPSC-approved rate case settlement and is expected to result in a $34 million revenue increase.

Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense in 2021 is expected to be higher than in 2020, driven by initiatives to enhance customer experience, and expenses necessary to safely and reliably operate and maintain a growing distribution system. Depreciation and amortization expense is expected to increase in 2021 due to plant additions, partially offset by the potential reversal of accumulated depreciation as provided for in PGS’s 2020 settlement agreement.

Complementing the strong residential construction market is PGS’s focus on extending the system to serve large commercial and industrial customers that are currently using petroleum or propane as fuel. The current relatively low natural gas prices and the lower emissions levels from using natural gas compared to other fuels make it attractive for these customers to convert.

OTHER ITEMS IMPACTING NET INCOME

Other Income, Net

Other income, net was $36 million and $20 million in 2020 and 2019, respectively, and included AFUDC-equity. AFUDC-equity was $30 million and $11 million in 2020 and 2019, respectively. The increase in AFUDC-equity is primarily due to the timing of Tampa Electric’s solar projects and the modernization of its Big Bend Power Station as discussed in the Capital Investments section below. AFUDC is expected to increase in 2021 due to the timing of construction of the Big Bend modernization, solar generation, AMI and PGS expansion projects.

Interest Expense

In 2020, interest expense, excluding AFUDC-debt, was $144 million compared to $139 million in 2019. The increase is due to an increase in borrowings to support TEC’s ongoing capital investments program.

Interest expense is expected to increase in 2021, reflecting higher balances and interest rates.

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Income Taxes

The provision for income taxes increased in 2020 primarily due to higher pre-tax income, partially offset by higher tax benefits due to AFUDC and R&D credits and higher ITC amortization related to solar projects. Income tax expense as a percentage of income before taxes was 16.2% in 2020 and 17.2% in 2019. TEC expects the 2021 annual effective tax rate to be consistent with 2020.

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 $14 million and $63 million in 2020 and 2019, respectively. The cash payments mainly differ year over year due to the timing of tax depreciation deductions.    

For more information on our 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 2020 Annual TEC Consolidated Financial Statements.

LIQUIDITY, CAPITAL RESOURCES

Balances as of December 31, 2020

(millions)
Credit facilities	$	1,250
Drawn amounts/LCs		776
Available credit facilities		474
Cash and short-term investments		10
Total liquidity	$	484

Cash from Operating Activities

Cash flows from operating activities in 2020 were $829 million, a decrease of $12 million compared to 2019. The decrease is primarily due to higher fuel under-recoveries and storm settlement customer refunds, partially offset by the timing of invoice payments.

Cash from Investing Activities

Cash flows from investing activities in 2020 resulted in a net use of cash of $1.4 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 2020 resulted in net cash inflows of $522 million. TEC received $505 million of equity contributions from Parent, $300 million proceeds from the 1-year term credit agreement, and $127 million from the net increase in short-term debt with maturities of less than 90 days. These increases in cash flows were partially offset by dividend payments to Parent of $408 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 and credit facility borrowings to support normal operations and capital 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 2021 as it invests in solar projects, the modernization of the Big Bend power plant, smart meters, gas distribution system expansion and other projects. See Capital Investments section below for further detail on TEC’s projected capital expenditures. TEC intends to fund those capital expenditures with available cash on hand, cash generated from operating activities, cash from equity contributions and debt issuances so that Tampa Electric and PGS maintain their capital structures consistent with the regulatory arrangements. Debt raised is subject to applicable regulatory approvals. Future financial market conditions could increase TEC’s interest costs which could reduce earnings and cash flows.

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As noted earlier, cash from operating activities and short-term borrowings are used to fund capital expenditures, which may result in periodic working capital deficits. The working capital deficit as of December 31, 2020 was primarily caused by short-term borrowings and periodic fluctuations in assets and liabilities related to FPSC clauses and riders. At December 31, 2020, TEC’s unused capacity under its credit facilities was $474 million.  

TEC has credit facilities that provide $1,250 million of credit, including $450 million maturing in 2021 and $800 million maturing in 2023. See Note 6 to the 2020 Annual TEC Consolidated Financial Statements for additional information regarding the credit facilities. TEC expects that its liquidity is 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 2021 to be lower than in 2020 primarily due to decreased revenues as a result of weather favorability experienced in 2020 partially offset by increased revenues due to customer growth and solar investments at Tampa Electric (see Note 3 to the 2020 Annual TEC Consolidated Financial Statements), combined with higher cash inflows from fuel and cost of gas sold. TEC plans to use cash in 2021 to fund capital spending and to pay dividends to its shareholder. Dividends are declared and 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 2021 and remain within the covenant restrictions.

Short-Term Borrowings

At December 31, 2020 and 2019, the following credit facilities and related borrowings existed.

	December 31, 2020						December 31, 2019
					Letters of						Letters of
	Credit		Borrowings		Credit		Credit		Borrowings		Credit
(millions)	Facilities		Outstanding(1)		Outstanding		Facilities		Outstanding(1)		Outstanding
5-year facility (2)	$	800	$	345	$	1	$	400	$	295	$	1
3-year accounts receivable facility (3)		150		130		0		150		53		0
1-year term facility (4)		300		300	0		0		0		0
Total	$	1,250	$	775	$	1	$	550	$	348	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023.

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

(4) This 1-year term facility matures on April 29, 2021.

These credit facilities require commitment fees ranging from 12.5 to 35.0 basis points.  The weighted average interest rate on outstanding amounts payable under the credit facilities at December 31, 2020 and 2019 was 0.89% and 2.56%, respectively. For a complete description of the credit facilities see Note 6 to the 2020 Annual TEC Consolidated Financial Statements.

	Maximum		Minimum		Average		Average
	drawn		drawn		drawn		interest
(millions)	amount		amount		amount		rate
2020 credit facility utilization	$	775	$	300	$	478		1.13	%

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, 2020, 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, 2020. Reference is made to the specific agreements and instruments for more details.  

			Calculation
Instrument	Financial Covenant (1)	Requirement/Restriction	at December 31, 2020
Credit facility- $800 million (2)	Debt/capital	Cannot exceed 65%	46%
Accounts receivable credit facility- $150 million (2)	Debt/capital	Cannot exceed 65%	46%
Term facility- $300 million (2)	Debt/capital	Cannot exceed 65%	46%

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(1) As defined in each applicable instrument.

(2) See Note 6 to the 2020 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	Stable	Positive	Stable

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 ratings 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 (see Note 14 to the 2020 Annual TEC Consolidated Financial Statements).

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, 2020

	Payments Due by Period
(millions)	Total		2021		2022		2023		2024		2025		After 2025
Long-term debt (1)	$	2,903	$	278	$	250	$	0	$	0	$	0	$	2,375
Interest payment obligations(2)		2,567		125		117		110		110		110		1,995
Transportation(3)		3,071		232		232		213		207		189		1,998
Pension plan(4)		0		0		0		0		0		0		0
Capital projects(5)		373		237		76		60		0		0		0
Fuel and gas supply(3)		280		238		41		1		0		0		0
Purchased power		10		10		0		0		0		0		0
Long-term service agreements(6)		127		11		13		16		16		17		54
Operating leases		62		3		3		3		3		2		48
Demand side management(3)		7		4		3		0		0		0		0
Total contractual obligations	$	9,400	$	1,138	$	735	$	403	$	336	$	318	$	6,470

(1) Includes debt at Tampa Electric and PGS (see the Consolidated Statements of Capitalization and Note 7 to the 2020 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, 2020.

(3) These payment obligations under contractual agreements of Tampa Electric and PGS 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, 2021 measurement date, the pension plan was fully funded. Under ERISA guidelines, TEC is not required to make additional cash contributions; 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 2020 Annual TEC Consolidated Financial Statements).

(5) Represents outstanding commitments for major capital projects, including solar projects, the modernization of the Big Bend power plant and smart meters.

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

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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, 2020.

Capital Investments

(millions)	Actual 2020		Forecasted 2021
Tampa Electric (1)
Renewable generation	$	196	$	235
Transmission		72		55
Distribution		274		350
Generation		377		335
Facilities, equipment, vehicles and other		89		115
Tampa Electric total		1,008		1,090
PGS		344		315
Net cash effect of accruals, retentions and AFUDC		9
Total	$	1,361	$	1,405

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

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 by the end of 2023. As of December 31, 2020, Tampa Electric has invested approximately $213 million in these new projects. AFUDC is being earned on these projects during construction.

Tampa Electric expects to invest approximately $850 million through 2023 to modernize the Big Bend Power Station. This modernization project includes conversion of Unit 1 from coal-fired to natural gas combined-cycle technology and the early retirement of Unit 2. As of December 31, 2020, Tampa Electric has invested approximately $526 million in this modernization project. AFUDC is being earned on this project during construction.

Tampa Electric’s 2020 capital expenditures included solar generation projects, the Big Bend modernization, storm hardening for the transmission and distribution systems, smart meters and the maintenance and refurbishment of existing generating facilities. In 2021, Tampa Electric expects capital expenditures to include solar generation projects, the Big Bend modernization, storm hardening for the transmission and distribution systems, new technology for distribution system modernization, smart meters and the maintenance and refurbishment of existing generating facilities.

Capital expenditures in 2020 for PGS included maintenance of the existing system, expansion of the system and replacement of cast iron, bare steel and obsolete plastic pipe. In addition, PGS expects to invest in 2021 for projects associated with customer growth, system expansion to serve large commercial and industrial customers, including continued interest in the conversion of vehicle fleets to CNG, LNG facilities, renewable natural gas facilities and information technology investments. The remainder of PGS’s capital expenditure forecast for 2021 includes amounts related to ongoing renewal, replacement and system safety, including the replacement of cast iron, bare steel and obsolete plastic pipe, which is recovered through a rider clause (see the Business–PGS-Regulation section).

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

Tampa Electric and PGS maintained capital structures consistent with their regulatory arrangements. At December 31, 2020, TEC’s year-end capital structure was 46% debt and 54% common equity. At December 31, 2019, 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 2020 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 2020 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 2020 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, 2020, TEC does not have a valuation allowance. At December 31, 2020, TEC had a net deferred income tax liability of $783 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 2020 Annual TEC Consolidated Financial Statements.

Unbilled Revenue

Electric and gas revenues are billed on a systematic basis over a one-month period. At the end of each month, TEC must make an estimate of energy delivered to customers for related revenues earned but not yet billed. TEC’s unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses, timing of meter reads and applicable customer rates. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate.

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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 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 7.00% as of January 1, 2020. The expected return on assets was 7.35% as of January 1, 2019 and 7.00% as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment. The expected return on assets was 6.85% in 2018. Given recent strong capital market returns and market expectations for long-term interest rates, TECO Energy expects the expected return on assets to be 6.70% for 2021. Actual earned returns in 2020 were 18.9%.

The discount rate assumption used to measure the 2020, 2019 and 2018 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.

For the December 31, 2018 measurement, TECO Energy used a discount rate of 4.34% for pension benefits under its qualified plan and 4.38% for its other postretirement benefits. For the October 31, 2019 remeasurement that occurred as a result of a plan curtailment, TECO Energy used a discount rate of 3.13% for pension benefits under its qualified plan. For the December 31, 2019 measurement, TECO Energy used a discount rate of 3.22% for pension benefits under its qualified plan and 3.32% for its other postretirement benefits. For the December 31, 2020 measurement, TECO Energy used a discount rate of 2.38% for pension benefits under its qualified plan and 2.47% for its other postretirement benefits.

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 2020 and is anticipated to have in 2021 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
2020	$5 million increase	$2 million increase
2021	$7 million increase	$3 million increase

In October 2019, the Society of Actuaries (SOA) released its final report of the Pri-2012 Private Retirement Plans Mortality Tables. The SOA tables incorporate the results of the SOA’s study of actuarial mortality in pension plans from 2010-2014. TECO Energy has determined that these base mortality tables are appropriate for valuing the postretirement plans. In 2018, 2019 and 2020, the SOA updated the mortality projection scale. For mortality improvements reflected in the 2018, 2019 and 2020 year-end measurements, TECO Energy used an updated projection scale based on the SOA’s scale but modified with a shorter grade-down period and lower ultimate rates of mortality improvement at the older ages. TECO Energy believes these tables are more appropriate and reflective of its population.

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Unrecognized actuarial gains and losses for the pension plan are being recognized over a period of approximately 12 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. TECO Energy assumes that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industrywide cost-containment initiatives.

The actuarial assumptions used in determining TECO Energy’s pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations.

See the discussion of employee postretirement benefits in Note 5 to the 2020 Annual TEC Consolidated Financial Statements.

RECENTLY ISSUED ACCOUNTING STANDARDS

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2020, are described as follows:

  Measurement of Credit Losses on Financial Instruments

TEC adopted Accounting Standard Update (ASU) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

  Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 related to the approach for intraperiod tax allocation. It also simplifies aspects of accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2020, with early adoption permitted. The standard is applied on both a prospective and retrospective basis. TEC early adopted the standard effective January 1, 2020. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

     Facilitation of the Effects of Reference Rate Reform on Financial Reporting

TEC adopted ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting in the fourth quarter of 2020. The standard provides options and exceptions for applying U.S. GAAP to contract modifications and hedging relationships that reference LIBOR or another reference rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The transition from reference rates will not have a material impact on the consolidated financial statements. In November 2020, the Federal Reserve extended the phase-out of LIBOR until June 2023. TEC will continue to monitor the impact this may have on application of the standard.

 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

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environmental matters. TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites.

CAIR/CSAPR

Based on updated EPA modeling, Florida is no longer subject to Cross-State Air Pollution Rule (CSAPR) requirements.  On May 13, 2019, the EPA finalized the determination that Florida is meeting its “good neighbor” obligation to prohibit emissions from contributing significantly to nonattainment or interfering with maintenance status in another state. This confirms that Florida is meeting its cross-state air transport obligations under the Clean Air Act.

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 U.S. District of Columbia Circuit Court (the D.C. Circuit Court) 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 acts.

All of Tampa Electric’s conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the MATS standards without considerable impacts, compared to others who had not taken similar early actions. 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 1998, Tampa Electric has reduced its system wide emissions of CO₂ by approximately 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 is also substantially reducing CO₂ emissions by significantly expanding the use of solar power, repowering Big Bend Unit 1 steam turbine, and retiring Big Bend Unit 2. See Capital Investments above for information regarding Tampa Electric’s solar projects. By 2023, the Big Bend Unit 1 modernization project, capable of producing 1,090 megawatts of power, will lead to system-wide emissions that are expected to be less than half of 1998-level emissions.

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 (EGUs).  The rule provides emission guidelines to replace the Clean Power Plan and inform the development of state plans to reduce GHG emissions from certain coal-fired EGUs. In the guidelines, the EPA determined that heat rate improvement measures are the best system of emission reduction for existing coal-fired EGUs. This action also provides implementing regulations for emission guidelines issued under Section 111(d) of the Clean Air Act. Tampa Electric has emission units that are subject to this rule and has engaged in the development of a state plan that could be finalized by the end of 2021.

The outcome of expected litigation and the rule-making process and its impact on TEC’s businesses is uncertain at this time; however, it could result in increased operating costs, and/or decreased operations at Tampa Electric’s coal-fired plants. Depending on how the state plan could be developed and implemented, the ACE rule could cause an increase in costs or rates charged to customers, which could curtail sales. See Item 1A - Risk Factors.

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.

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Ozone

On September 30, 2015 in response to a court order, the EPA published a final rule revising the ground level ozone standard to 70 parts per billion from the previous level of 75 parts per billion. On September 30, 2016, the Florida Department of Environmental Protection submitted its recommendation that the entire State of Florida be designated as “attainment” for the 2015 standard.  On May 6, 2020, the EPA published final approval of the Florida Infrastructure State Implementation Plan (SIP) but did not act on the interstate transport requirements related to attainment and maintenance of the National Ambient Air Quality Standards (NAAQS). The EPA will consider these requirements for Florida for the 2015 8-hour ozone NAAQS separately.

On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise them. A future review of the standard 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 outcome of 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 both 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 U.S. 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 will ultimately be used by FDEP to determine the necessity of cooling water system retrofits. Big Bend is negotiating an alternative schedule (as allowed by the rule) and will be completing a portion of the compliance requirements with the Big Bend modernization project with the remainder to be 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.  

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. 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 June 2015, the U.S. Army Corps of Engineers (the Corps) and the EPA issued a rule defining “Waters of the United States” (WOTUS) for purposes of federal Clean Water Act (CWA) jurisdiction. The final rule took effect on August 28, 2015. The rule has the effect of defining the scope of agency jurisdiction under the CWA very broadly. In August 2015, a federal judge in North Dakota issued an injunction against the implementation of the rule in certain states. In October 2015, the Sixth Circuit Court of Appeals issued a nationwide stay of WOTUS, effectively ending the implementation of the rule in the 37 states that were not subject to the prior injunction.  This stay is temporary, pending the outcome of litigation. On February 28, 2017, President Trump issued an Executive Order directing the EPA and the Corps to review the rule. In June 2018, the EPA and the Corps issued a draft prepublication notice to clarify, supplement and seek additional comment to the July 27, 2017 proposal to repeal the 2015 WOTUS Rule and restore the regulatory text that existed prior to the 2015 rule. On August 16, 2018, a federal court in South Carolina restored the 2015 rule, putting it back into effect in 26 states but not in the other 24 states with federal court injunctions against it. Both Florida and New Mexico remain under the federal court injunctions. On February 14, 2019, the EPA and the Corps published their proposed new “Revised Definition of WOTUS” in the Federal Register. On October 22, 2019, the Corps and the EPA published in the Federal Register the final rule repealing the 2015 Rule and restoring the regulatory text that existed prior to the 2015 Rule. The agencies will implement the pre-2015 Rule regulations informed by applicable agency guidance documents and consistent with Supreme Court decisions and prior agency practice. This final rule became effective on December 23, 2019.

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On January 23, 2020, the U.S. EPA and the Corps finalized a rule, called the “Navigable Waters Protection Rule”,  to define “Waters of the United States” and thereby establish federal regulatory authority under the Clean Water Act. This final rule became effective on June 20, 2020 (60 days after publication in the Federal Register) and replaced the rule published in October 2019. The impact of this potential new standard on the operations of Tampa Electric will depend on the outcome of litigation or other developments.

Superfund and Former Manufactured Gas Plant Sites

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

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

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

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. See Note 3 to the 2020 Annual TEC Consolidated Financial Statements for information regarding an agreement approved by the FPSC to accelerate the amortization of the regulated asset associated with this liability.

Coal Combustion Residuals Recycling and Regulation

Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk Power stations. An annual average of 95% of all CCRs produced at these facilities is 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. On February 2, 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for recovery of certain capital and O&M expenses through the ECRC. On December 12, 2017, the FPSC approved an additional petition for recovery of expenses associated with the closure of Tampa Electric’s Big Bend Economizer Ash and Pyrite Ponds which began in late November 2018. The O&M expenses for disposal of CCRs from this project began in 2019 and will continue through 2021. Closure of Tampa Electric’s West Slag Dewatering Pond and improvements to Tampa Electric’s North Gypsum Stackout Area were completed in 2020. In June 2018, the EPA finalized Phase I revisions to the rule which provide clarifications and additional flexibility for certain rule requirements. In August 2019, the EPA proposed Phase II revisions to the rule and solicited public comments on these revisions. These included a revised beneficial use definition and restrictions on offsite beneficial use storage piles, both of which could negatively affect management and recycling of CCRs by TEC customers. On November 4, 2019, the EPA proposed an additional rule to establish deadlines for unlined impoundments to cease receiving CCRs and initiate closure.  The EPA revised the rule that now establishes April 11, 2021 as the deadline, with a provision for an extension up to 2023 if a company can substantiate a lack of CCR disposal capacity or associated wastewater. In 2020, the EPA published the draft Federal CCR Permitting Rule, which would cover facilities in states which do not apply for their own permit programs. However, FDEP has proposed a Florida CCR permitting program to be incorporated into the existing state solid waste regulation, so the Federal regulation would not apply in Florida. Nevertheless, TEC is already in the process of closing its regulated CCR Units by October 2021 so the above regulatory actions will have limited impact to TEC. See Note 12 to the 2020 Annual TEC Consolidated Financial Statements for information regarding the estimated impact on Tampa Electric’s AROs.

Conservation

In 2020, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial Demand Side Management (DSM) programs. On July 2020, the FPSC approved TEC’s 2020-2029 DSM Plan to support achieving the newly FPSC approved annual DSM goals. In November 2020, Tampa Electric transitioned into the new 2020-2029 DSM Plan by discontinuing nine existing DSM programs, created seven new DSM programs, and modified 14 of the existing DSM programs. One of the new DSM

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Programs is a five-year pilot program that will involve the installation, testing and showcasing of a fully integrated renewable energy system that will utilize a large solar array integrated with battery storage and electric vehicle and large commercial vehicle battery charging.  

In 2020, Tampa Electric achieved all of the commercial annual energy and demand goals, the annual residential energy goal and achieved the total combined annual energy and demand goals. To achieve these DSM goals, Tampa Electric offered 39 cost-effective DSM programs and then with the new DSM plan transitioned to 36 cost-effective DSM programs in November. 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, Tampa Electric’s conservation programs have contributed to reducing the summer peak demand by 779 MWs and the winter peak demand by 1,289 MWs.

In 2020, PGS implemented an online energy audit program for residential customers. PGS expects to implement a walkthrough energy audit for commercial customers in 2021. Both programs were approved by the FPSC as part of its DSM goals in 2019. PGS also developed and filed its DSM plan in November 2019, which will support the achievement of these DSM goals on an annual basis. This filing is pending review and approval from the FPSC. Starting in 2019, PGS initiated the reporting of annual energy reduction achievements as part of meeting the requirements of Florida Energy Efficiency and Conservation Act. In 2020, PGS’ conservation programs saved 731,300 therms. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause rate on the customer’s gas bill.

REGULATION

See the Business section (Tampa Electric – Electric Operations and Peoples Gas System – Gas Operations sections)and Note 3 to the 2020 Annual TEC Consolidated Financial Statements for a description of the utilities’ base rates, cost-recovery clauses and competition.

CHANGE IN EXECUTIVE OFFICERS

On February 9, 2021, Emera announced that Archie Collins was appointed President and Chief Executive Officer of Tampa Electric Company effective May 3, 2021. Until that time, Mr. Collins will serve as President and Chief Operating Officer and was most recently the Chief Operating Officer of Tampa Electric Company. Mr. Collins will succeed Nancy Tower who is retiring in June 2021.

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).

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.

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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:

● Price fluctuations for physical purchases and sales of natural gas in the course of normal operations; and

● Interest rate fluctuations on debt.

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 (see Note 3 to the 2020 Annual TEC Consolidated Financial Statements). As of December 31, 2020, 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 on any high-risk accounts.  

Certain of TEC’s derivative instruments, including NPNS agreements as disclosed in Note 14 to the 2020 Annual TEC Consolidated Financial Statements, 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 as a result of borrowing activities. TEC may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt. As of December 31, 2020 and 2019, TEC had no hedges of interest rates in place. As of December 31, 2020 and 2019, a hypothetical 10% increase in TEC’s weighted-average interest rate on its variable rate debt during the subsequent year would not have resulted in a material impact on pre-tax earnings. This is driven by the low amounts of variable rate debt at TEC. A hypothetical 10% increase in interest rates would have decreased the fair market value of our long-term debt by 3.6% at December 31, 2020 and 4.4% at December 31, 2019. See the Financing Activity section and Notes 6 and 7 to the 2020 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 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, fuel oil, petcoke 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 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, oil and petcoke. Tampa Electric’s use of natural gas, with its more volatile pricing, for generation of electricity was 89% in 2020 and 90% in 2019 (see the Business section). PGS has exposure related to the price of purchased gas and pipeline capacity.

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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 and natural gas to consumers. TEC manages commodity price risk by entering into long-term fuel supply agreements, prudently operating plant facilities to optimize cost and,prior to the moratorium mentioned above, entering into derivative transactions designated as cash flow hedges of anticipated purchases of wholesale natural gas. At December 31, 2020 and 2019, a change in commodity prices would not have had a material impact on earnings for Tampa Electric or PGS, but could have 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, 2020 and 2019, the related consolidated statements of income and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2020, the related consolidated statements of capitalization as of and for each of the two years in the period ended December 31, 2020 and 2019, and the related notes and schedule of valuation and qualifying accounts and reserves for the year ended December 31, 2020, 2019 and 2018 (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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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 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 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 audit committee 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 $485 million in regulatory assets and $1,261 million in regulatory liabilities. As disclosed in Note 3, Tampa Electric’s retail business and the Peoples Gas System are regulated separately 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 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 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 recovery on costs incurred, of the disallowance of part of the cost of recently completed property, plant, and equipment and construction work in progress, or of the probable refund to customers through future rates.

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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, property, plant and equipment, 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 16, 2021

38

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets

Assets	December 31,			December 31,
(millions)	2020			2019
Property, plant and equipment
Utility plant
Electric	$	11,486		$	10,578
Gas		2,332			2,012
Utility plant, at original costs		13,818			12,590
Accumulated depreciation		(3,712	)		(3,472	)
Utility plant, net		10,106			9,118
Other property		14			13
Total property, plant and equipment, net		10,120			9,131
Current assets
Cash and cash equivalents		10			14
Receivables, less allowance for credit losses of $7 and $2 at December 31, 2020 and 2019, respectively		219			206
Due from affiliates		11			14
Inventories, at average cost
Fuel		26			36
Materials and supplies		107			104
Regulatory assets		79			41
Prepayments and other current assets		10			10
Total current assets		462			425
Deferred debits
Regulatory assets		406			396
Other		60			55
Total deferred debits		466			451
Total assets	$	11,048		$	10,007

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

39

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets—continued

Liabilities and Capital	December 31,			December 31,
(millions)	2020			2019
Capitalization
Common stock	$	3,890		$	3,385
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		327			311
Total capital		4,216			3,695
Long-term debt		2,594			2,869
Total capital		6,810			6,564
Current liabilities
Long-term debt due within one year		278			0
Notes payable		775			348
Accounts payable		321			296
Due to affiliates		46			20
Customer deposits		130			132
Regulatory liabilities		67			93
Accrued interest		13			13
Accrued taxes		22			14
Other		57			44
Total current liabilities		1,709			960
Long-term liabilities
Deferred income taxes		783			758
Regulatory liabilities		1,194			1,210
Investment tax credits		216			164
Deferred credits and other liabilities		336			351
Total deferred credits		2,529			2,483
Commitments and Contingencies (see Note 8)
Total liabilities and capital	$	11,048		$	10,007

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

40

TAMPA ELECTRIC COMPANY

Consolidated Statements of Income and Comprehensive Income

(millions)
For the years ended December 31,	2020			2019			2018
Revenues
Electric	$	1,845		$	1,961		$	2,063
Gas		427			443			461
Total revenues		2,272			2,404			2,524
Expenses
Fuel		340			516			551
Purchased power		83			49			59
Cost of natural gas sold		121			152			180
Operations & maintenance		542			543			632
Depreciation and amortization		384			377			372
Taxes, other than income		202			206			208
Total expenses		1,672			1,843			2,002
Income from operations		600			561			522
Other income
Allowance for other funds used during construction		30			11			10
Other income, net		6			9			8
Total other income		36			20			18
Interest charges
Interest expense		144			139			123
Allowance for borrowed funds used during construction		(14	)		(5	)		(5	)
Total interest charges		130			134			118
Income before provision for income taxes		506			447			422
Provision for income taxes		82			77			81
Net income		424			370			341
Other comprehensive income, net of tax
Gain on cash flow hedges		0			0			1
Total other comprehensive income, net of tax		0			0			1
Comprehensive income	$	424		$	370		$	342

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

41

TAMPA ELECTRIC COMPANY

Consolidated Statements of Cash Flows

(millions)
For the years ended December 31,	2020			2019			2018
Cash flows from operating activities
Net income	$	424		$	370		$	341
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		384			377			372
Deferred income taxes and investment tax credits		54			15			(1	)
Allowance for equity funds used during construction		(30	)		(11	)		(10	)
Deferred recovery clauses		(40	)		63			(55	)
Receivables, less allowance for credit losses		(10	)		52			(2	)
Inventories		7			6			4
Taxes accrued		23			1			6
Accounts payable		34			(4	)		11
Regulatory assets and liabilities		(18	)		1			98
Other		1			(29	)		38
Cash flows from operating activities		829			841			802
Cash flows used in investing activities
Capital expenditures		(1,361	)		(1,283	)		(1,109	)
Net proceeds from sale of assets		6			0			1
Cash flows used in investing activities		(1,355	)		(1,283	)		(1,108	)
Cash flows from or used in financing activities
Equity contributions from TECO Energy		505			395			345
Proceeds from long-term debt issuance		0			292			714
Repayment of long-term debt		0			0			(304	)
Net change in short-term debt (maturities of 90 days or less)		127			127			216
Proceeds from other short-term debt (maturities over 90 days)		300			0			0
Repayment of other short-term debt (maturities over 90 days)		0			0			(300	)
Dividends to TECO Energy		(408	)		(373	)		(362	)
Other financing activities		(2	)		0			(1	)
Cash flows from financing activities		522			441			308
Net increase (decrease) in cash and cash equivalents		(4	)		(1	)		2
Cash and cash equivalents at beginning of the year		14			15			13
Cash and cash equivalents at end of the year	$	10		$	14		$	15
Supplemental disclosure of cash paid (received):
Interest	$	126		$	134		$	112
Income taxes	$	14		$	63		$	77
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	1		$	17		$	40

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

42

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, 2017		10		2,645	$	335		$	(2	)	$	2,978
Net income						341						341
Other comprehensive income, after tax									1			1
Equity contributions from Parent			345									345
Dividends to Parent (2)						(362	)					(362	)
Balance, December 31, 2018		10	$	2,990	$	314		$	(1	)	$	3,303
Net income						370						370
Equity contributions from Parent			395									395
Dividends to Parent (2)						(373	)					(373	)
Balance, December 31, 2019		10	$	3,385	$	311		$	(1	)	$	3,695
Net income						424						424
Equity contributions from Parent			505									505
Dividends to Parent (2)						(408	)					(408	)
Balance, December 31, 2020		10	$	3,890	$	327		$	(1	)	$	4,216

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

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.

43

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization – continued

At December 31, 2020 and 2019, TEC had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2020			2019
Tampa Electric	Notes (1)(2)(3) : 5.40%	2021		231			232
	2.60%	2022		225			225
	6.55%	2036		250			250
	6.15%	2037		190			190
	4.10%	2042		250			250
	4.35%	2044		290			290
	4.20%	2045		230			230
	4.30%	2048		275			275
	4.45%	2049		350			350
	3.63%	2050		275			275
	Total long-term debt of Tampa Electric			2,566			2,567
PGS	Notes (1)(2)(3) : 5.40%	2021		47			47
	2.60%	2022		25			25
	6.15%	2037		60			60
	4.10%	2042		50			50
	4.35%	2044		10			10
	4.20%	2045		20			20
	4.30%	2048		75			75
	4.45%	2049		25			25
	3.63%	2050		25			25
	Total long-term debt of PGS			337			337
Total long-term debt				2,903			2,904
Unamortized debt discount, net				(10	)		(10	)
Debt issuance costs				(21	)		(25	)
Total carrying amount of long-term debt				2,872			2,869
Less amount due within one year			278			0
Total long-term debt			$	2,594		$	2,869

(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)  The amounts shown are allocations to Tampa Electric and PGS of TEC Notes.

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

44

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization—continued

At December 31, 2020, long-term debt had a carrying amount of $2,872 million and an estimated fair market value of $3,597 million. At December 31, 2019, total long-term debt had a carrying amount of $2,869 million and an estimated fair market value of $3,335 million. The fair value of the debt securities is determined using Level 2 measurements(see Note 15 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, 2020													Long-Term
(millions)	2021		2022		2023		2024		2025		Thereafter		Debt
Tampa Electric	$	231	$	225	$	0	$	0	$	0	$	2,110	$	2,566
PGS		47		25		0		0		0		265		337
Total long-term debt maturities	$	278	$	250	$	0	$	0	$	0	$	2,375	$	2,903

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

45

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.Significant Accounting Policies

Description of the Business

TEC has two operating segments. Its Tampa Electricdivision provides retail electric services in West Central Florida, and PGS, its natural gas division, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. 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. and contains electric and natural gas divisions. 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.

In 2020, the outbreak of the novel strain of coronavirus, specifically identified as COVID-19, has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of and for the year ended December 31, 2020 were not materially impacted by the COVID-19 pandemic. However, it is not possible to reliably estimate the length and severity of the COVID-19 pandemic and the impact on the financial results and condition of TEC in future periods.

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 regulated utilities, Tampa Electric and PGS 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.

46

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2020			December 31, 2019
Electric generation	21-56 years	$	5,694		$	5,370
Electric transmission	28-77 years		1,008			940
Electric distribution	14-56 years		2,859			2,732
Gas transmission and distribution	16-77 years		2,076			1,848
General plant and other	8-43 years		723			675
Total cost			12,360			11,565
Less accumulated depreciation			(3,712	)		(3,472	)
Construction work in progress			1,472			1,038
Total property, plant and equipment, net		$	10,120		$	9,131

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.2%, 3.4% and 3.5% for 2020, 2019 and 2018, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2020, 2019 and 2018 was $381 million, $359 million and $345 million, respectively. See Note 3 for information regarding agreements approved by the FPSC that, among other things, allow Tampa Electric to continue to depreciate certain retired assets until the FPSC approves Tampa Electric’s next depreciation and dismantlement study and allowed Tampa Electric to eliminate its $16 million accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020.

Tampa Electric and PGS compute 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. Tampa Electric’s FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2020, 2019 and 2018, Tampa Electric’s rate was 6.46%. In July 2019, the FPSC approved a petition filed by PGS for authority to record AFUDC at an annual rate of 5.97% as part of its plans to develop three expansion projects in 2019 and 2020. Total AFUDC for the years ended December 31, 2020, 2019 and 2018 was $44 million, $16 million and $15 million, respectively. The increase in 2020 is primarily a result of the construction of solar projects and the repowering of Big Bend Unit 1 with natural gas combined-cycle technology.

Inventory

TEC values materials, supplies and fossil fuel inventory (natural gas, coal, petcoke and oil) 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.

47

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

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

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

Other

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

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 and environmental costs for Tampa Electric and 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 from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $214 million and $205 million as of December 31, 2020 and 2019, 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 Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

48

The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2020 and 2019, unbilled revenues of $73 million and $61 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Accounting for Franchise Fees and Gross Receipts Taxes

Tampa Electric and PGS are 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 by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $109 million, $117 million and $120 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Deferred Credits and Other Liabilities

Other deferred credits primarily include accrued pension and other postretirement benefits (see Note 5), MGP environmental remediation liability (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, 2020 and 2019 ranged from 2.43% to 4.00% and 2.66% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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. See Note 14 for further information regarding derivatives.

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2020, are described as follows:

  Measurement of Credit Losses on Financial Instruments

TEC adopted Accounting Standard Update (ASU) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

  Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 related to the approach for intraperiod tax allocation. It also simplifies aspects of accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2020, with early adoption permitted. The standard is applied on both a prospective and retrospective basis. TEC early adopted the standard effective January 1, 2020. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

     Facilitation of the Effects of Reference Rate Reform on Financial Reporting

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TEC adopted ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting in the fourth quarter of 2020. The standard provides options and exceptions for applying U.S. GAAP to contract modifications and hedging relationships that reference LIBOR or another reference rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The transition from reference rates will not have a material impact on the consolidated financial statements. In November 2020, the Federal Reserve extended the phase-out of LIBOR until June 2023. TEC will continue to monitor the impact this may have on application of the standard.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately 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 2020, 2019 and 2018 reflect 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%. The agreement stated that Tampa Electric could not file for additional base rate increases to be effective sooner than December 31, 2021, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital. The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. Tampa Electric expects to invest approximately $850 million in these solar projects during the period from 2017 to 2021, of which approximately $820 million has been invested through December 31, 2020, and is accruing AFUDC during construction. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac.   

On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018 and TEC began receiving these revenues in January 2019. On June 28, 2019, TEC filed its third SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2020 tranche representing 149 MW and $26 million annually in estimated revenue requirements. The FPSC approved the tariffs on this SoBRA filing, including an adjustment to reflect the reduction in the state corporate income tax discussed below, on December 10, 2019 and TEC began receiving these revenues in January 2020.On July 31, 2020, TEC filed its fourth and final SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2021 tranche representing 46 MW and $8 million annually in estimated revenues. The FPSC approved the tariffs on this SoBRA filing on November 3, 2020 and TEC began receiving these revenues in January 2021.

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

   The 2017 settlement agreement further contains a provision related to tax reform.  See “Tampa Electric Storm Restoration Cost Recovery” below for information regarding the impact of 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 November 13, 2019, as required by the 2017 settlement agreement, TEC filed its petition to reduce base rates and charges to

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reflect the impact of the temporary reduction of the state corporate income tax from 5.5% to 4.5%. The tax rate reduction was issued on September 12, 2019 and is effective retroactive from January 1, 2019 through December 31, 2021. The estimated base rate reduction due to customers of $5 million is subject to true-up, and the actual rate reduction may vary from year to year. The base rate reduction was approved on December 10, 2019 for rates effective January 2020.

On February 1, 2021, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting revenue requirements of approximately $280 million to $295 million, effective in January 2022. Tampa Electric’s proposed 2022 rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investment, and accelerated recovery of the remaining net book value of retiring assets. Tampa Electric also intends to seek approval for Generation Base Rate Adjustments of $130 million to recover the costs of the second phase of the Big Bend modernization project and additional utility-scale solar projects in subsequent years. These filing amounts are estimates until Tampa Electric completes its analysis and files the case. Tampa Electric expects to file its detailed case on or after April 2, 2021, and the FPSC is expected to decide the case by the end of the year.

Tampa Electric Big Bend Power Station

Tampa Electric expects to invest approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $526 million has been invested through December 31, 2020. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the Big Bend modernization project, on June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At June 1, 2020 and December 31, 2020, Tampa Electric’s balance sheet included $223 million and $200 million, respectively, in electric utility plant and $90 million and $88 million, respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 as part of the Big Bend modernization project. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric was not required to request an asset recovery schedule for retired assets until the next depreciation study. On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedule with the FPSC.    

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

Tampa Electric Storm Protection Cost Recovery Clause and Settlement Agreement

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million base rate reduction for SPP program costs previously recovered in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million of costs removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.

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

Tampa Electric Storm Restoration Cost Recovery

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million, of which $90 million was charged to the storm reserve, $3 million was charged to O&M expense and $9 million was charged to capital expenditures. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated Hurricane Irma storm costs plus approximately $10 million in restoration costs from prior named storms and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013.

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

On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $12 million to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income.

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

PGS Base Rates

PGS’s base rates for 2020, 2019 and 2018 were originally established in May 2009. The allowed equity in its capital structure was 54.7% from all investor sources of capital.

On February 7, 2017, the FPSC approved a settlement agreement filed by PGS and the OPC agreeing to new depreciation rates, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and establish an ROE range of  9.25% to 11.75%. The settlement agreement provided that the bottom of the range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020 and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders.

As part of the 2017 settlement, PGS and the OPC agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million of that amount will be amortized over a two-year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million and $16 million, respectively, of this amortization expense.

In 2018, the FPSC approved a settlement agreement authorizing PGS to accelerate in 2018 the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS recorded amortization expense and a regulatory asset reduction of $11 million in 2018. In January 2019, PGS reduced its base rates by $12 million for the impact of tax reform and reduced depreciation rates by $10 million in accordance with the settlement agreement.

PGS was permitted to initiate a general base rate proceeding during 2020 regardless of its earned ROE at the time, provided the new rates do not become effective before January 1, 2021. On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase in base rates by $58 million annually effective January 2021, which is a $34 million increase in revenue and $24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint. It provides PGS the ability to reverse a total of $34 million of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.90% before that time with an allowed equity in the capital structure of 54.7% from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024.

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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)	2020		2019
Regulatory assets:
Regulatory tax asset (1)	$	90	$	74
Cost-recovery clauses (2)		38		12
Environmental remediation (3)		22		20
Postretirement benefits (4)		309		295
Asset retirement obligation (5)		13		25
Other		13		11
Total regulatory assets		485		437
Less: Current portion		79		41
Long-term regulatory assets	$	406	$	396
Regulatory liabilities:
Regulatory tax liability (6)	$	691	$	699
Cost-recovery clauses (2)		23		37
Accumulated reserve—cost of removal (7)		498		506
Storm reserve (8)		48		48
Other		1		13
Total regulatory liabilities		1,261		1,303
Less: Current portion		67		93
Long-term regulatory liabilities	$	1,194	$	1,210

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction.  

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in a subsequent period.

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

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

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

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

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

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

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4. Income Taxes

   CARES Act

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

Change in Florida Corporate Income Tax Rate

On September 12, 2019, the state of Florida issued a corporate tax rate reduction from 5.5% to 4.46% effective January 1, 2019 through December 31, 2021. The impact to TEC earnings and revaluation of TEC state deferred income tax balance was not material.

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 2020, 2019 and 2018, TEC recorded net tax provisions of $82 million, $77 million and $81 million, respectively.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2020			2019			2018
Current income taxes
Federal	$	35		$	56		$	72
State		(7	)		6			10
Deferred income taxes
Federal		32			7			(13	)
State		29			13			13
Investment tax credits amortization		(7	)		(5	)		(1	)
Total income tax expense	$	82		$	77		$	81

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,	2020			2019			2018
Income before provision for income taxes	$	506		$	447		$	422
Federal statutory income tax rates		21	%		21	%		21	%
Income taxes, at statutory income tax rate		106			94			89
Increase (decrease) due to
State income tax, net of federal income tax		17			15			19
Excess deferred tax amortization		(26	)		(25	)		(24	)
ITC amortization		(7	)		(5	)		(1	)
AFUDC-equity		(6	)		(2	)		(2	)
Tax credits		(8	)		(1	)		(2	)
Other		6			1			2
Total income tax expense on consolidated statements of income	$	82		$	77		$	81
Income tax expense as a percent of income before income taxes		16.2	%		17.2	%		19.2	%

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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,	2020		2019
Deferred tax liabilities (1)
Property related	$	1,121	$	1,036
Pension and postretirement benefits		116		111
Total deferred tax liabilities		1,237		1,147
Deferred tax assets (1)
Loss and credit carryforwards (2)		301		243
Medical benefits		27		27
Insurance reserves		16		16
Pension and postretirement benefits		66		63
Capitalized energy conservation assistance costs		18		17
Other		26		23
Total deferred tax assets		454		389
Total deferred tax liability, net	$	783	$	758

(1) Certain property related assets and liabilities have been netted.

(2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $9 million.

At December 31, 2020, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $340 million and $88 million, respectively, expiring between 2032 and 2037. TEC has unused general business credits of $242 million expiring between 2027 and 2040, of which $222 million relate to ITCs expiring between 2034 and 2040. As a result of the Merger with Emera, 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)	2020			2019		2018
Balance at January 1,	$	9		$	8	$	8
Decreases due to tax positions related to prior year		(2	)	0		0
Increases due to tax positions related to prior year	1			1		0
Increases due to tax positions related to current year	1			0		0
Balance at December 31,	$	9		$	9	$	8

As of December 31, 2020 and 2019, TEC’s uncertain tax positions for federal R&D tax credits were $9 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC’s unrecognized federal tax benefits decreased in the fourth quarter of 2020 by approximately $2 million due to an adjustment related to its 2016 federal R&D credits issue with IRS Appeals. The recognition of these tax benefits decreased the effective tax rate resulting in an income tax benefit of approximately $2 million. TEC expects to be effectively settled with this issue early 2021. TEC had $9 million of unrecognized tax benefits at December 31, 2020 and 2019 that, 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 2020, 2019 and 2018, 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, 2020, 2019 and 2018.

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The short tax year ending June 30, 2016 is currently under examination by the IRS under its Compliance Assurance Program (CAP). EUSHI’s 2016 consolidated federal income tax return, which includes TEC’s short tax year ending December 31, 2016, is also currently under examination by the IRS. The U.S. federal statute of limitations remains open for the year 2016 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 comprehensive 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.

Effective October 21, 2019, the defined benefit retirement plan was amended to freeze further crediting of service and earnings for certain participants covered by the International Brotherhood of Electrical Workers (the IBEW) collective bargaining agreement. As of December 31, 2019, 24% of TEC’s employees were represented by the IBEW. As a result, a curtailment and a remeasurement of the plan occurred in the fourth quarter of 2019. See curtailment-related line items in tables below.

As the result of a reorganization of shared services functions, certain employees and their associated pension benefits were transferred from TSI to TEC effective December 2019. Deferred costs related to pension benefits that were recognized by TSI in AOCI are now recognized in TEC as regulatory assets. The balances at December 31, 2020 and 2019 are reflective of this transfer.

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.  

As the result of a reorganization of shared services functions, certain employees and their associated other postretirement benefits were transferred from TSI to TEC effective December 2019. Deferred costs related to other postretirement benefits that were recognized by TSI in AOCI are now recognized in TEC as regulatory assets. The balances at December 31, 2020 and 2019 are reflective of this transfer.

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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)	2020			2019			2020			2019
Change in benefit obligation
Benefit obligation at beginning of year	$	843		$	750		$	180		$	173
Service cost		20			20			2			1
Interest cost		26			31			6			7
Plan participants’ contributions		0			0			4			4
Plan curtailment		0			(10	)		0			0
Plan settlement		0			(5	)		0			0
Benefits paid		(54	)		(49	)		(17	)		(14	)
Actuarial loss		84			106			37			9
Benefit obligation at end of year	$	919		$	843		$	212		$	180

Change in plan assets
Fair value of plan assets at beginning of year	$	796		$	659		$	0		$	0
Actual return on plan assets		142			165			0			0
Employer contributions		19			20			0			0
Employer direct benefit payments		1			6			13			10
Plan participants’ contributions		0			0			4			4
Plan settlement		0			(5	)		0			0
Benefits paid		(54	)		(48	)		0			0
Direct benefit payments		(1	)		(1	)		(17	)		(14	)
Fair value of plan assets at end of year (1)	$	903		$	796		$	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.

Gains in the benefit obligation for the year ended December 31, 2020 relate to decreases in the discount rate used to calculate the benefit obligation, the incorporation of new census data as of January 1, 2020 and the updating of the withdrawal, retirement rate and form of payment assumptions as the result of an experience study performed during the year. In addition, participation and persistency assumptions were updated for the other postretirement benefit plan.

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)	2020			2019			2020			2019
Benefit obligation (PBO/APBO)	$	919		$	843		$	212		$	180
Less: Fair value of plan assets		903			796			0			0
Funded status at end of year	$	(16	)	$	(47	)	$	(212	)	$	(180	)

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

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The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $876 million at December 31, 2020 and $801 million at December 31, 2019.

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)	2020			2019			2020			2019
Accrued benefit costs and other current liabilities	$	(1	)	$	(1	)	$	(12	)	$	(11	)
Deferred credits and other liabilities		(15	)		(42	)		(186	)		(156	)
	$	(16	)	$	(43	)	$	(198	)	$	(167	)

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)	2020		2019		2020		2019
Net actuarial loss (gain)	$	221	$	244	$	88	$	51
Amount recognized	$	221	$	244	$	88	$	51

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2020			2019			2020			2019
Discount rate		2.37	%		3.21	%		2.47	%		3.32	%
Rate of compensation increase		3.07	%		3.79	%		3.07	%		3.79	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				5.74	%		6.03	%
Ultimate rate	n/a			n/a				4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			2038			2038

 The discount rate assumption used to determine the December 31, 2020 and 2019 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)
	2020			2019					2018					2020			2019			2018
(millions)
Service cost	$	20		$	20				$	21				$	2		$	1		$	2
Interest cost		26			31					29					6			7			7
Expected return on plan assets		(50	)		(51	)				(49	)				0			0			0
Amortization of:
Actuarial loss		20			16					19					1			1			1
Prior service (benefit) cost		0			0					0					(3	)		(2	)		(2	)
Settlement loss	0				1		(3	)		2		(2	)		0			0			0
Net periodic benefit cost	$	16		$	17				$	22				$	6		$	7		$	8

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Net loss (gain) arising during the year (includes curtailment gain)	$	(8	)	$	(17	)	$	62		$	38		$	9		$	(14	)
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2			2			2
Amortization or settlement of actuarial loss		(20	)		(17	)		(20	)		(1	)		(1	)		(1	)
Total recognized in OCI and regulatory assets	$	(28	)	$	(34	)	$	42		$	39		$	10		$	(13	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(12	)	$	(17	)	$	64		$	45		$	17		$	(5	)

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

(2) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

(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.

TEC’s portion of the net periodic benefit costs for pension benefits was $12 million, $12 million and $16 million for 2020, 2019 and 2018, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $7 million, $7 million and $8 million for 2020, 2019 and 2018, respectively. TEC’s portion of net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Statements of Income in “Operations & maintenance”.

   TEC recognized a settlement charge of $1 million in 2018 relating to the retirement of an executive in the SERP plan. TEC recognized a settlement charge of approximately $1 million in 2019 related to the retirement of a SERP participant. TEC recognized settlement charges of approximately $1 million in 2019 related to the retirement of Restoration plan participants.

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

	Pension Benefits										Other Benefits
	2020			2019				2018			2020			2019			2018
Discount rate		3.21	%		4.33	%			3.62	%		3.32	%		4.38	%		3.70	%
Expected long-term return on plan assets		7.00	%	7.35%/7.00%			(1)		6.85	%	n/a			n/a			n/a
Rate of compensation increase		3.79	%		3.75	%			3.32	%		3.79	%		3.75	%		3.31	%
Healthcare cost trend rate
Initial rate	n/a			n/a				n/a				6.03	%		6.31	%		6.58	%
Ultimate rate	n/a			n/a				n/a				4.50	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a				n/a			2038			2038			2038

(1) The expected return on assets was 7.35% as of January 1, 2019 and 7.00% as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment.

The discount rate assumption used to determine the benefit cost for 2020, 2019 and 2018 was based on the same technique that was used to determine the December 31, 2020 and 2019 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, 2020, TECO Energy’s pension plan’s actual earned returns were approximately 19%.

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.

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Pension Plan Assets

Pension plan assets (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							ActualAllocation, End of Year
Asset Category	2020 Target Allocation			2019 Target Allocation			2020			2019
Equity securities	50%-70%			57%-63%				60	%		58	%
Fixed income securities	30%-50%			37%-43%				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 expects to take additional steps to more closely match 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.

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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, 2020
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	9		$	0		$	0	$	0	$	9
Accounts receivable		10			0			0		0		10
Accounts payable		(88	)		0			0		0		(88	)
Short-term investment funds (STIFs)		35			0			0		0		35
Common stocks		66			0			0		0		66
Real estate investment trusts (REITs)		8			0			0		0		8
Mutual funds		69		0				0		0		69
Municipal bonds		0			1			0		0		1
Government bonds		0			90			0		0		90
Corporate bonds		0			79			0		0		79
Mortgage backed securities (MBS)		0			1			0		0		1
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Short Sales		0			(4	)		0		0		(4	)
Long Futures		(2	)		0			0		0		(2	)
Swaps		0			1			0		0		1
Investments not utilizing the practical expedient		107			169			0		0		276
Common and collective trusts (1)		0			0			0		553		553
Mutual fund (1)		0			0			0		74		74
Total investments	$	107		$	169		$	0	$	627	$	903

(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 Consolidated Balance Sheet of TECO Energy.

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TECO Energy	At Fair Value as of December 31, 2019
(millions)
	Level 1			Level 2		Level 3		Using NAV (1)		Total
Cash	$	7		$	0	$	0	$	0	$	7
Accounts receivable		27			0		0		0		27
Accounts payable		(64	)		0		0		0		(64	)
Cash collateral		1			0		0		0		1
Short-term investment funds (STIFs)		22			0		0		0		22
Common stocks		50			0		0		0		50
Real estate investment trusts (REITs)		4			0		0		0		4
Mutual funds		153			0		0		0		153
Municipal bonds		0			1		0		0		1
Government bonds		0			51		0		0		51
Corporate bonds		0			70		0		0		70
Mortgage backed securities (MBS)		0			5		0		0		5
Collateralized mortgage obligations (CMOs)		0			2		0		0		2
Long Futures		(4	)		0		0		0		(4	)
Swaps		0			1		0		0		1
Investments not utilizing the practical expedient		196			130		0		0		326
Common and collective trusts (1)		0			0		0		412		412
Mutual fund (1)		0			0		0		58		58
Total investments	$	196		$	130	$	0	$	470	$	796

(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 Consolidated Balance Sheet of TECO Energy.

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.

• Options are valued using the bid-ask spread and the last price.

• 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, 2020.

● 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  

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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, 2020.

● 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 $10 million and $10 million of assets as of December 31, 2020 and 2019, 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, 2020 and 2019.

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 111.66% of the Pension Protection Act funded target as of January 1, 2020 and is estimated at 109.67% of the Pension Protection Act funded target as of January 1, 2021.

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 and minimize PBGC premiums paid by the plan. 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 2020, 2019 and 2018, which met the minimum funding requirements for 2020, 2019 and 2018. TEC’s portion of the contribution in 2020 was $16 million and in 2019 was $15 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2021 contribution to be $17 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 2020, 2019 and 2018 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2021. TEC made SERP payments of approximately $1 million and $5 million from the trust in 2020 and 2019, respectively, and expects to make a SERP payment of approximately $1 million from the trust in 2021.    

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 2021, TEC expects to make a contribution of about $12 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)
2021	$	58	$	13
2022		66		13
2023		62		13
2024		64		13
2025		66		13
2026-2030		331		61

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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, 2020, 2019 and 2018, TEC’s portion of expense totaled $21 million, $11 million and $11 million, respectively, related to the matching contributions made to this plan. TEC’s portion of 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, 2020 and 2019, TEC recognized expense totaling $9 million and $1 million, respectively, related to the contributions made to this plan. TEC’s portion of the expense related to this contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.

COVID-19

The COVID-19 pandemic could impact key actuarial assumptions used to account for employee postretirement benefits including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements. The extent of the future impact of the COVID-19 pandemic on TEC’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions, future economic activity and energy usage. Actual results may differ significantly from these estimates.

6. Short-Term Debt

Credit Facilities

	December 31, 2020						December 31, 2019
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	800	$	345	$	1	$	400	$	295	$	1
3-year accounts receivable facility (3)		150		130		0		150		53		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	1,250	$	775	$	1	$	550	$	348	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023.

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

(4) This 1-year term facility matures on April 29, 2021.

At December 31, 2020, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2020 and 2019 was 0.89% and 2.56%, respectively.

Tampa Electric Company Non-Revolving Term Loan

On February 6, 2020, TEC entered into a 364-day, $300 million credit agreement with a group of banks. The credit agreement had a maturity date of February 4, 2021; 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 London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. On January 29, 2021, TEC extended the maturity date of the agreement to April 29, 2021.

Tampa Electric Company Accounts Receivable Facility

On March 23, 2018, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a Second Amended Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). Throughout the term of the facility, TEC will pay program and liquidity

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fees, which total 70 basis points at December 31, 2020. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin.  In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. On July 14, 2020 and October 30, 2020, TEC amended the agreement in order to change performance ratios. As of December 31, 2020, TEC was in compliance with the requirements of the Loan Agreement.  

Tampa Electric Company 5-Year Credit Facility

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); provides 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. On December 19, 2019, TEC increased the amount by $75 million to $400 million with no other changes from the prior agreement.  

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

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.

Tampa Electric Company 3.625% Notes due 2050

On July 24, 2019, TEC completed a sale of $300 million aggregate principal amount of 3.625% unsecured notes due June 15, 2050. Until December 15, 2049, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after December 15, 2049, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

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Tampa Electric Company 4.45% Notes due 2049

On October 4, 2018, TEC completed a sale of $375 million aggregate principal amount of 4.45% unsecured notes due June 15, 2049. Until December 15, 2048, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2048, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

Tampa Electric Company 4.3% Notes due 2048

On June 7, 2018, TEC completed a sale of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048. Until December 15, 2047, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after December 15, 2047, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

8. Commitments and Contingencies

Legal Contingencies

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 2020 and 2019, TEC has estimated its ultimate financial liability to be $17 million and $21 million, respectively, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

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

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

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

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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 the modernization of the Big Bend power station, 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, 2020:

	Purchased				Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Power		Transportation(1)		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2021	$	10	$	232	$	237	$	238	$	11	$	3	$	4	$	735
2022		0		232		76		41		13		3		3		368
2023		0		213		60		1		16		3		0		293
2024		0		207		0		0		16		3		0		226
2025		0		189		0		0		17		2		0		208
Thereafter		0		1,998		0		0		54		48		0		2,100
Total future minimum payments	$	10	$	3,071	$	373	$	280	$	127	$	62	$	7	$	3,930

(1) As of December 31, 2020, $117 million is related to a gas transportation contract through 2040 between PGS and SeaCoast, a related party.

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, 2020 and 2019, TEC was in compliance with all required financial covenants.

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9. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
For the year ended December 31, 2020	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,018		$	0	$	0		$	1,018
Commercial		506			0		0			506
Industrial		133			0		0			133
Regulatory deferrals and unbilled revenue		(25	)		0		0			(25	)
Other (1)		217			0		(4	)		213
Total electric revenue		1,849			0		(4	)		1,845
Gas revenue
Residential		0			158		0			158
Commercial		0			135		0			135
Industrial (2)		0			23		0			23
Other (3)		0			117		(6	)		111
Total gas revenue		0			433		(6	)		427
Total revenue	$	1,849		$	433	$	(10	)	$	2,272
For the year ended December 31, 2019
Electric revenue
Residential	$	1,046		$	0	$	0		$	1,046
Commercial		562			0		0			562
Industrial		156			0		0			156
Regulatory deferrals and unbilled revenue		(49	)		0		0			(49	)
Other (1)		250			0		(4	)		246
Total electric revenue		1,965			0		(4	)		1,961
Gas revenue
Residential		0			154		0			154
Commercial		0			146		0			146
Industrial (2)		0			21		0			21
Other (3)		0			140		(18	)		122
Total gas revenue		0			461		(18	)		443
Total revenue	$	1,965		$	461	$	(22	)	$	2,404
For the year ended December 31, 2018
Electric revenue
Residential	$	1,067		$	0	$	0		$	1,067
Commercial		582			0		0			582
Industrial		161			0		0			161
Regulatory deferrals and unbilled revenue		(2	)		0		0			(2	)
Other (1)		258			0		(3	)		255
Total electric revenue		2,066			0		(3	)		2,063
Gas revenue
Residential		0			157		0			157
Commercial		0			151		0			151
Industrial (2)		0			21		0			21
Other (3)		0			159		(27	)		132
Total gas revenue		0			488		(27	)		461
Total revenue	$	2,066		$	488	$	(30	)	$	2,524

(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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Remaining Performance Obligations

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms.  As of December 31, 2020 and 2019, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $135 million and $140 million, respectively. As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2033. 

10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2020		2019			2018
Natural gas sales to/(from) affiliates	$	(139)	$	(111	)	$	(38	)
Services received from affiliates		6		65			65
Dividends to TECO Energy		408		373			362
Equity contributions from TECO Energy		505		395			345

In 2019 and 2018, services received from affiliates primarily included shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary. In December 2019, most TSI employees were transferred to Tampa Electric. The transfer of these employees to Tampa Electric did not materially impact shared service costs or the TEC Consolidated Statement of Income. In 2020, the shared service costs were not recorded through TSI but rather directly recorded in TEC’s O&M expenses on the TEC Consolidated Statement of Income.

Amounts due from or to affiliates at December 31,

(millions)	2020		2019
Accounts receivable related to asset management agreements to Emera Energy Services Inc. (1)	$	4	$	4
Accounts receivable excluding asset management agreements (1)		7		10
Accounts payable (1)		27		16
Taxes payable (2)		19		4

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

(2) Taxes payable were due to EUSHI. See Note 4 for additional 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 and has two segments, Tampa Electric and PGS. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 792,500 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 426,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

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	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2020
Revenues - external	$	1,845	$	427	$	0			$	2,272
Sales to affiliates		4		6		(10	)			0
Total revenues		1,849		433		(10	)			2,272
Depreciation and amortization		339		45		0				384
Total interest charges		113		17		0				130
Provision for income taxes		66		16		0				82
Net income		372		52		0				424
Total assets		9,800		1,901		(653	)	(1)		11,048
Capital expenditures		1,028		333		0				1,361
2019
Revenues - external	$	1,961	$	443	$	0			$	2,404
Sales to affiliates		4		18		(22	)			0
Total revenues		1,965		461		(22	)			2,404
Depreciation and amortization		336		41		0				377
Total interest charges		117		17		0				134
Provision for income taxes		59		18		0				77
Net income		316		54		0				370
Total assets		9,007		1,593		(593	)	(1)		10,007
Capital expenditures		1,055		228		0				1,283
2018
Revenues - external	$	2,063	$	461	$	0			$	2,524
Sales to affiliates		3		27		(30	)			0
Total revenues		2,066		488		(30	)			2,524
Depreciation and amortization		312		60		0				372
Total interest charges		102		16		0				118
Provision for income taxes		65		16		0				81
Net income		294		47		0				341
Total assets		8,235		1,407		(487	)	(1)		9,155
Capital expenditures		940		169		0				1,109

(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

TEC 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)	2020			2019
Beginning balance	$	49		$	64
Additional liabilities		8			0
Liabilities settled (1)		(19	)		(18	)
Other (2)		1			3
Ending balance	$	39		$	49

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(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The decreases in the ARO in 2020 and 2019 are due to the closure of CCR management facilities.

(2) Includes accretion recorded as a deferred regulatory asset.  

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.

Where TEC is the lessor, a lease is a sales-type lease if certain criteria is met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

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

Lessee

TEC has operating leases for buildings, land, telecommunication services and rail cars. TEC’s leases have remaining lease terms of 1 year to 65years, 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	December 31, 2020		December 31, 2019
Right-of-use asset	Other deferred debits	$	26	$	28
Lease liabilities
Current	Other current liabilities	$	2	$	2
Long-term	Deferred credits and other liabilities		25		27
Total lease liabilities		$	27	$	29

TEC has recorded operating lease expense for the year ended December 31, 2020 and 2019 of $4 million and $4 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, 2020: 

(millions)
Year ended December 31:	2021		2022		2023		2024		2025		Thereafter		Total
Minimum lease payments	$	3	$	3	$	3	$	3	$	2	$	48	$	62
Less imputed interest														(35	)
Total future minimum payments													$	27

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

Year ended December 31,	2020			2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	5		$	3
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions)	$	0		$	11
Weighted average remaining lease term (years)		43			43
Weighted average discount rate - operating leases		4.3	%		4.3	%

Lessor

TEC leases CNG stations to other companies, which are classified as direct finance leases. The net investment in direct finance leases consists of the following:

(millions)	December 31, 2020			December 31, 2019
Total minimum lease payments to be received	$	31		$	33
Less amounts representing estimated executory costs		(12	)		(13	)
Minimum lease payments receivable	$	19		$	20
Less unearned finance lease income		(10	)		(11	)
Net investment in direct finance and sales-type leases	$	9		$	9
Principal due within one year (included in "Receivables")		(2	)		(2	)
Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits")	$	7		$	7

The unearned income related to these direct finance leases is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Gas revenues” on the Consolidated Statements of Income. Customers have the option to purchase the assets related to the CNG stations at any time after year five of the agreements, which is in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. Alternatively, the customer may take possession of the CNG station asset at the end of the lease term for no cost.

As of December 31, 2020, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following:

(millions)
Year ended December 31:	2021		2022		2023		2024		2025		Thereafter		Total
Minimum lease payments to be received	$	2	$	2	$	2	$	2	$	2	$	21	$	31
Less executory costs														(12	)
Total minimum lease payments receivable													$	19

14. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

• To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

• To optimize the utilization of Tampa Electric’s physical natural gas storage capacity and PGS’s firm transportation capacity on interstate pipelines.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers and to optimize the utilization of its physical natural gas storage capacity and firm transportation capacity on interstate pipelines.

The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

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On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which included a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022 (see Note 3).TEC was hedging its exposure to the variability in future cash flows untilNovember 30, 2018 for financial natural gas contracts. TEC hadzeroand $1million of derivative liabilities related to natural gas storage optimization as of December 31, 2020 and 2019, respectively, and zero derivative assets on its Consolidated Balance Sheets as of December 31, 2020 and 2019.

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements and to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage capacity for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income (see Note 3).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2020, all of TEC’s physical contracts qualified for the NPNS exception, which was elected.

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of December 31, 2020, substantially all of the counterparties with transaction amounts outstanding in TEC’s derivative positions were either rated investment grade by the major rating agencies or held with affiliates. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.  

15. 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.

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As of December 31, 2020 and 2019, 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.

16. Stock-Based Compensation

Performance Share Unit Plan

Emera has a performance share unit (PSU) plan.  The PSU liability is 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.

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.

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, 2019		504		$	45.45	$	28
Granted including DRIP		78			52.68		4
Exercised		(162	)		45.41		9
Forfeited		(27	)		46.08		0
Transferred		(3	)		44.85		0
Outstanding as of December 31, 2020		390			46.87		21

Compensation cost recognized for the PSU plan for the years ended December 31, 2020, 2019 and 2018 was $8 million, $8 million and $4 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2020, 2019 and 2018were $2 million, $2 million and $1 million, respectively. Cash payments made during the year ended December 31, 2020, 2019 and 2018 associated with the PSU plan were $9 million, zero and zero, respectively. As of December 31, 2020 and 2019, there was $5 million and $4 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.

17. Long-Term PPAs

In 2018, Tampa Electric had long-term PPAs with wholesale energy providers in Florida, which expired in December 2018. These agreements ranged in size from 121 MW to 250 MW of available capacity, were with similar entities and contained similar provisions. 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 2021. 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 $36 million, $25 million and $15 million under these long-term PPAs for the three years ended December 31, 2020, 2019 and 2018, 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

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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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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, 2020 (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, 2020 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, 2020.

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.

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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 EY for the audit of TEC’s annual financial statements and other services for the years ended December 31, 2020 and 2019, respectively.

	2020		2019
Audit fees	$	403,300	$	550,300
Tax fees
Tax compliance fees		0		15,000
Total	$	403,300	$	565,300

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 and (iii) services that are normally provided in connection with statutory and regulatory filings or engagements.

Tax fees consist of tax compliance fees for tax return review and income tax provision review, and tax planning fees, including tax audit advice.

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.

76

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

Consolidated Balance Sheets at December 31, 2020 and 2019

Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018

Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018

Consolidated Statements of Capitalization for the Years Ended December 31, 2020 and 2019

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.

77

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended December 31, 2020, 2019 and 2018

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions  (1)		Period
Allowance for Credit Losses:
2020	$	2	$	9	$	0	$	4	$	7
2019	$	2	$	5	$	0	$	5	$	2
2018	$	1	$	7	$	0	$	6	$	2

(1) Write-off of individual bad debt accounts

78

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).	*

79

Exhibit No.	Description
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).	*
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).	*

80

Exhibit No.	Description
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.
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)
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

(1) This certification accompanies the 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.

81

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.

82

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 16, 2021	By:	/s/ Nancy Tower
		Nancy Tower
		President and Chief Executive Officer
		(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 16, 2021:

	Title
/s/ Nancy Tower	President and Chief Executive Officer
Nancy Tower	(Principal Executive Officer)
/s/ Gregory W. Blunden	Senior Vice President-Finance and Accounting 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/ Ana-Marie Codina Barlick	Director
Scott Balfour				Ana-Marie Codina Barlick
/s/ Robert R. Bennett	Director		/s/ Jacqueline Bradley		Director
Robert R. Bennett			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/ Ralph Tedesco	Director		/s/ Rasesh Thakkar		Director
Ralph Tedesco			Rasesh Thakkar
/s/ Nancy Tower	Director		/s/ Will Weatherford		Director
Nancy Tower			Will Weatherford

83

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.

84

EX-10.15

Exhibit 10.15

AMENDMENT NO. 1

AMENDMENT NO. 1 dated as of January 29, 2021 (this “Amendment No. 1”) to the Credit Agreement referred to below, among TAMPA ELECTRIC COMPANY, a Florida corporation (the “Borrower”), the Lenders and WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

The Borrower, the Lenders and the Administrative Agent are parties to a Credit Agreement dated as of February 6, 2020 (the “Credit Agreement”).  The Borrower and the Lenders wish to amend the Credit Agreement in certain respects, and accordingly, the parties hereto hereby agree as follows:

Section 1.  Definitions.  Capitalized terms used in this Amendment No. 1 and not otherwise defined are used herein as defined in the Credit Agreement.

Section 2.  Amendments.  Subject to the satisfaction of the conditions precedent specified in Section 4 hereof, but effective as of the date hereof, the Credit Agreement shall be amended as follows:

(a)  References in the Credit Agreement (including references to the Credit Agreement as amended hereby) to “this Agreement” and “the Credit Agreement” (and indirect references such as “hereunder”, “hereby”, “herein” and “hereof”) shall be deemed to be references to the Credit Agreement as amended hereby.

(b)  The below definition as set forth in Exhibit A to the Credit Agreement is hereby amended and restated in its entirety as follows:

““Maturity Date” means April 29, 2021.”

Section 3.  Representations and Warranties.  The Borrower represents and warrants to the Lenders that (a) its representations and warranties set forth in Article IV of the Credit Agreement are true and complete on the date hereof as if made on and as of the date hereof and as if each reference in said Article IV to “this Agreement” included reference to this Amendment No. 1 (unless such representation and warranty relates solely to another time, in which event such representation or warranty is true and correct as of such other time) and (b) no Event of Default or Inchoate Default shall have occurred and be continuing.

Section 4.  Conditions Precedent to Effectiveness.  This Amendment No. 1 including the amendments set forth in Section 2 hereof shall become effective, as of the date hereof, upon the occurrence of the following conditions precedent (such date, the “Amendment No. 1 Effective Date”):

(a) Amendment.  Delivery to Administrative Agent of one or more counterparts of this Amendment No. 1 duly executed by the Borrower and each of the Lenders (or written evidence satisfactory to Administrative Agent of the execution thereof by the parties thereto).

(b) Payment of Fees.  All amounts required to be paid by the Borrower to the Lenders and the Administrative Agent under Section 8.4 of the Credit Agreement (including the fees and expenses of Milbank LLP) in connection with the execution and delivery of the Amendment No. 1, and all fees and other costs payable in connection with the execution and delivery of the documents and instruments referred to in this Section 4 (or incorporated herein by reference) shall have been paid in full.

1

(c) Representations and Warranties. (i) Each representation and warranty set forth in Article IV of the Credit Agreement shall be true and correct as if made on and as of the Amendment No. 1 Effective Date, before and after giving effect thereto, unless such representation or warranty relates solely to another time, in which event such representation or warranty shall be true and correct as of such other time, and (ii) no Event of Default or Inchoate Default shall have occurred and is continuing or will result from the occurrence of the Amendment No. 1 Effective Date.

(d) Certificate of the Borrower.  Administrative Agent shall have received (i) a certificate, dated as of the Amendment No. 1 Effective Date, signed by a Responsible Officer of the Borrower, in substantially the form of Exhibit G but modified to reflect Amendment No. 1 and the transactions contemplated hereby and (ii) secretary certificates of the Borrower, substantially consistent with the one delivered on the Closing Date, in form and substance reasonably satisfactory to the Administrative Agent.

(e) Beneficial Ownership Certification.  To the extent the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, at least four days prior to the Amendment No. 1 Effective Date, any Lender that has requested, in a written notice to the Borrower at least 8 days prior to the Amendment No. 1 Effective Date, a Beneficial Ownership Certification in relation to the Borrower shall have received such Beneficial Ownership Certification (provided that, upon the execution and delivery by such Lender of its signature page to this Agreement, the condition set forth in this Section 4(e) shall be deemed to be satisfied).

Section 5.  Miscellaneous.  Except as herein provided, the Credit Agreement shall remain unchanged and in full force and effect.  This Amendment No. 1 may be executed in any number of counterparts, all of which taken together shall constitute one and the same agreement and any of the parties hereto may execute this Amendment No. 1 by signing any such counterpart.  This Amendment No. 1 shall be governed by, and construed in accordance with, the law of the State of New York.

Section 6.  Credit Facility Document.  The execution, delivery and effectiveness of this Amendment No. 1 shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Credit Facility Documents, nor constitute a waiver or novation of any provision of any of the Credit Facility Documents. On and after the effectiveness of this Amendment No. 1, this Amendment No. 1 shall for all purposes constitute a Credit Facility Document.

[Signature pages follow]

2

IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 1 to be duly executed and delivered as of the day and year first above written.

TAMPA ELECTRIC COMPANY

By: /s/ Gregory W. Blunden

  Name: Gregory W. Blunden

Title:  Treasurer and Chief Financial Officer

By: /s/ Jeffrey S. Chronister

  Name: Jeffrey S. Chronister

Title:  Vice President – Finance and Controller

[Signature Page – Amendment No. 1]

LENDERS

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Administrative Agent and Lender

By:  /s/ Gregory R. GredvigName: Gregory R. Gredvig
Title:  Director

[Signature Page – Amendment No. 1]

JPMORGAN CHASE BANK, N.A.

as Lender

By:  /s/ Nancy R. BarwigName:  Nancy R. Barwig
Title: Executive Director

[Signature Page – Amendment No. 1]

ROYAL BANK OF CANADA,
as Lender

By:  /s/ David Gazley

Name: David Gazley 
Title: Authorized Signatory

‎[Signature Page – Amendment No. 1]‎

MUFG BANK, LTD., CANADA BRANCH,

as Lender

By:  /s/ Nirushan ThambirajahName: Nirushan Thambirajah
Title: Director

‎[Signature Page – Amendment No. 1]‎

THE BANK OF NOVA SCOTIA,
as Lender

By:  /s/ David DewarName:  David Dewar
Title: Director

‎[Signature Page – Amendment No. 1]‎

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.333-233336) of Tampa Electric Company and in the related Prospectus of our report dated February 16, 2021, with respectto the consolidated financial statements of Tampa Electric Company included in this Annual Report (Form 10-K) for the year ended December 31, 2020.

/s/ Ernst & Young LLP

Tampa, Florida

February 16, 2021

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Nancy Tower, 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 16, 2021	/s/ NANCY TOWER
	NANCY TOWER
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Gregory W. Blunden, certify that:

1. I have reviewed this 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 16, 2021	/s/ GREGORY W. BLUNDEN
	GREGORY W. BLUNDEN
	Senior Vice President-Finance and Accounting 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, 2020 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 16, 2021	/s/	NANCY TOWER
		NANCY TOWER
		President and Chief Executive Officer
		(Principal Executive Officer)

Dated: February 16, 2021	/s/	GREGORY W. BLUNDEN
		GREGORY W. BLUNDEN
		Senior Vice President-Finance and Accounting 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, 2020	Feb. 12, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
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
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

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, plant and equipment
Utility plant, at original costs	$ 13,818	$ 12,590
Accumulated depreciation	(3,712)	(3,472)
Utility plant, net	10,106	9,118
Other property	14	13
Total property, plant and equipment, net	10,120	9,131
Current assets
Cash and cash equivalents	10	14
Receivables, less allowance for credit losses of $7 and $2 at December 31, 2020 and 2019, respectively	219	206
Due from affiliates	11	14
Inventories, at average cost
Regulatory assets	79	41
Prepayments and other current assets	10	10
Total current assets	462	425
Deferred debits
Regulatory assets	406	396
Other	60	55
Total deferred debits	466	451
Total assets	11,048	10,007
Capitalization
Common stock	3,890	3,385
Accumulated other comprehensive loss	(1)	(1)
Retained earnings	327	311
Total capital	4,216	3,695
Long-term debt	2,594	2,869
Total capital	6,810	6,564
Current liabilities
Long-term debt due within one year	278	0
Notes payable	775	348
Accounts payable	321	296
Due to affiliates	46	20
Customer deposits	130	132
Regulatory liabilities	67	93
Accrued interest	13	13
Accrued taxes	22	14
Other	57	44
Total current liabilities	1,709	960
Long-term liabilities
Deferred income taxes	783	758
Regulatory liabilities	1,194	1,210
Investment tax credits	216	164
Deferred credits and other liabilities	336	351
Total deferred credits	2,529	2,483
Commitments and Contingencies (see Note 8)
Total liabilities and capital	11,048	10,007
Fuel [Member]
Inventories, at average cost
Utility inventories	26	36
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	107	104
Electric [Member]
Property, plant and equipment
Utility plant, at original costs	11,486	10,578
Gas [Member]
Property, plant and equipment
Utility plant, at original costs	$ 2,332	$ 2,012

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Statement Of Financial Position [Abstract]
Allowance for credit losses	$ 7	$ 2

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Consolidated Statements of Income and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues
Electric	$ 1,845	$ 1,961	$ 2,063
Gas	427	443	461
Total revenues	2,272	2,404	2,524
Expenses
Fuel	340	516	551
Purchased power	83	49	59
Cost of natural gas sold	121	152	180
Operations & maintenance	542	543	632
Depreciation and amortization	384	377	372
Taxes, other than income	202	206	208
Total expenses	1,672	1,843	2,002
Income from operations	600	561	522
Other income
Allowance for other funds used during construction	30	11	10
Other income, net	6	9	8
Total other income	36	20	18
Interest charges
Interest expense	144	139	123
Allowance for borrowed funds used during construction	(14)	(5)	(5)
Total interest charges	130	134	118
Income before provision for income taxes	506	447	422
Provision for income taxes	82	77	81
Net income	424	370	341
Other comprehensive income, net of tax
Gain on cash flow hedges	0	0	1
Total other comprehensive income, net of tax	0	0	1
Comprehensive income	$ 424	$ 370	$ 342

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net income	$ 424	$ 370	$ 341
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	384	377	372
Deferred income taxes and investment tax credits	54	15	(1)
Allowance for equity funds used during construction	(30)	(11)	(10)
Deferred recovery clauses	(40)	63	(55)
Receivables, less allowance for credit losses	(10)	52	(2)
Inventories	7	6	4
Taxes accrued	23	1	6
Accounts payable	34	(4)	11
Regulatory assets and liabilities	(18)	1	98
Other	1	(29)	38
Cash flows from operating activities	829	841	802
Cash flows used in investing activities
Capital expenditures	(1,361)	(1,283)	(1,109)
Net proceeds from sale of assets	6	0	1
Cash flows used in investing activities	(1,355)	(1,283)	(1,108)
Cash flows from or used in financing activities
Proceeds from long-term debt issuance	0	292	714
Repayment of long-term debt	0	0	(304)
Net change in short-term debt (maturities of 90 days or less)	127	127	216
Proceeds from other short-term debt (maturities over 90 days)	300	0	0
Repayment of other short-term debt (maturities over 90 days)	0	0	(300)
Other financing activities	(2)	0	(1)
Cash flows from financing activities	522	441	308
Net increase (decrease) in cash and cash equivalents	(4)	(1)	2
Cash and cash equivalents at beginning of the year	14	15	13
Cash and cash equivalents at end of the year	10	14	15
Supplemental disclosure of cash paid (received):
Interest	126	134	112
Income taxes	14	63	77
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	1	17	40
TECO Energy [Member]
Cash flows from or used in financing activities
Equity contributions from TECO Energy	505	395	345
Dividends to TECO Energy	$ (408)	$ (373)	$ (362)

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Consolidated Statements of Capitalization - Capital Stock - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Beginning balance	$ 3,695	$ 3,303	$ 2,978
Net income	424	370	341
Other comprehensive income, after tax	0	0	1
Equity contributions from Parent	505	395	345
Dividends to Parent	(408)	(373)	(362)
Ending balance	4,216	3,695	3,303
Common Stock [Member]
Beginning balance	$ 3,385	$ 2,990	$ 2,645
Beginning balance	10	10	10
Equity contributions from Parent	$ 505	$ 395	$ 345
Ending balance	$ 3,890	$ 3,385	$ 2,990
Ending balance	10	10	10
Retained Earnings [Member]
Beginning balance	$ 311	$ 314	$ 335
Net income	424	370	341
Dividends to Parent	(408)	(373)	(362)
Ending balance	327	311	314
Accumulated Other Comprehensive Loss [Member]
Beginning balance	(1)	(1)	(2)
Other comprehensive income, after tax			1
Ending balance	$ (1)	$ (1)	$ (1)

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Consolidated Statements of Capitalization - Capital Stock (Parenthetical)	Dec. 31, 2020 $ / shares shares
Preferred stock - par value | $ / shares	$ 100
Preferred stock, no par value | $ / shares
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
Preference Stock No Par Value
Preferred stock, shares authorized	2,500,000
Preferred stock, shares outstanding	0

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Consolidated Statements of Capitalization - Long-Term Debt - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Long-term debt, total	$ 2,903	$ 2,904
Unamortized debt discount, net	(10)	(10)
Debt issuance costs	(21)	(25)
Long-term debt, carrying amount	2,872	2,869
Less amount due within one year	278	0
Total long-term debt	2,594	2,869
Long-term debt, fair value	3,597	3,335
Tampa Electric [Member]
Debt Instrument [Line Items]
Long-term debt, total	2,566	2,567
Long-term debt, carrying amount	$ 2,566
Tampa Electric [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	$ 231	232
Tampa Electric [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	$ 225	225
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	$ 190	190
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 250	250
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$ 290	290
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2045
Long-term debt, total	$ 230	230
Tampa Electric [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Due	2048
Long-term debt, total	$ 275	275
Tampa Electric [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Due	2049
Long-term debt, total	$ 350	350
Tampa Electric [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Due	2050
Long-term debt, total	$ 275	275
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	337	337
Long-term debt, carrying amount	$ 337
PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	$ 47	47
PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	$ 25	25
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	$ 60	60
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 50	50
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Due	2044
Long-term debt, total	$ 10	10
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Due	2045
Long-term debt, total	$ 20	20
PGS [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Due	2048
Long-term debt, total	$ 75	75
PGS [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Due	2049
Long-term debt, total	$ 25	25
PGS [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Due	2050
Long-term debt, total	$ 25	$ 25

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Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical)	Dec. 31, 2020
Tampa Electric [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
Tampa Electric [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
Tampa Electric [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.55%
Tampa Electric [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
Tampa Electric [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
Tampa Electric [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
Tampa Electric [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
Tampa Electric [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.30%
Tampa Electric [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.45%
Tampa Electric [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.63%
PGS [Member] | 5.40% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	5.40%
PGS [Member] | 2.60% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	2.60%
PGS [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.15%
PGS [Member] | 4.10% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.10%
PGS [Member] | 4.35% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.35%
PGS [Member] | 4.20% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.20%
PGS [Member] | 4.30% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.30%
PGS [Member] | 4.45% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	4.45%
PGS [Member] | 3.63% Notes [Member]
Debt Instrument [Line Items]
Stated interest rate	3.63%

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Consolidated Statements of Capitalization - Long-term Debt Maturities $ in Millions	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Total long-term debt maturities	$ 2,872
Long Term Debt Maturities
Debt Instrument [Line Items]
2021	278
2022	250
2023	0
2024	0
2025	0
Thereafter	2,375
Total long-term debt maturities	2,903
Tampa Electric [Member]
Debt Instrument [Line Items]
2021	231
2022	225
2023	0
2024	0
2025	0
Thereafter	2,110
Total long-term debt maturities	2,566
PGS [Member]
Debt Instrument [Line Items]
2021	47
2022	25
2023	0
2024	0
2025	0
Thereafter	265
Total long-term debt maturities	$ 337

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Significant Accounting Policies

1.Significant Accounting Policies

Description of the Business

TEC has two operating segments. Its Tampa Electricdivision provides retail electric services in West Central Florida, and PGS, its natural gas division, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. 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. and contains electric and natural gas divisions. 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.

In 2020, the outbreak of the novel strain of coronavirus, specifically identified as COVID-19, has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of and for the year ended December 31, 2020 were not materially impacted by the COVID-19 pandemic. However, it is not possible to reliably estimate the length and severity of the COVID-19 pandemic and the impact on the financial results and condition of TEC in future periods.

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 regulated utilities, Tampa Electric and PGS 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, 2020			December 31, 2019
Electric generation	21-56 years	$	5,694		$	5,370
Electric transmission	28-77 years		1,008			940
Electric distribution	14-56 years		2,859			2,732
Gas transmission and distribution	16-77 years		2,076			1,848
General plant and other	8-43 years		723			675
Total cost			12,360			11,565
Less accumulated depreciation			(3,712	)		(3,472	)
Construction work in progress			1,472			1,038
Total property, plant and equipment, net		$	10,120		$	9,131

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.2%, 3.4% and 3.5% for 2020, 2019 and 2018, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2020, 2019 and 2018 was $381 million, $359 million and $345 million, respectively. See Note 3 for information regarding agreements approved by the FPSC that, among other things, allow Tampa Electric to continue to depreciate certain retired assets until the FPSC approves Tampa Electric’s next depreciation and dismantlement study and allowed Tampa Electric to eliminate its $16 million accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020.

Tampa Electric and PGS compute 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. Tampa Electric’s FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2020, 2019 and 2018, Tampa Electric’s rate was 6.46%. In July 2019, the FPSC approved a petition filed by PGS for authority to record AFUDC at an annual rate of 5.97% as part of its plans to develop three expansion projects in 2019 and 2020. Total AFUDC for the years ended December 31, 2020, 2019 and 2018 was $44 million, $16 million and $15 million, respectively. The increase in 2020 is primarily a result of the construction of solar projects and the repowering of Big Bend Unit 1 with natural gas combined-cycle technology.

Inventory

TEC values materials, supplies and fossil fuel inventory (natural gas, coal, petcoke and oil) 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 Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

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

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

Other

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

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 and environmental costs for Tampa Electric and 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 from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $214 million and $205 million as of December 31, 2020 and 2019, 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 Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2020 and 2019, unbilled revenues of $73 million and $61 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Accounting for Franchise Fees and Gross Receipts Taxes

Tampa Electric and PGS are 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 by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $109 million, $117 million and $120 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Deferred Credits and Other Liabilities

Other deferred credits primarily include accrued pension and other postretirement benefits (see Note 5), MGP environmental remediation liability (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, 2020 and 2019 ranged from 2.43% to 4.00% and 2.66% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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. See Note 14 for further information regarding derivatives.

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New Accounting Pronouncements

12 Months Ended

Dec. 31, 2020

Accounting Changes And Error Corrections [Abstract]

New Accounting Pronouncements

2. New Accounting Pronouncements

Change in Accounting Policy

The new U.S. GAAP accounting policies that are applicable to, and adopted by TEC in 2020, are described as follows:

  Measurement of Credit Losses on Financial Instruments

TEC adopted Accounting Standard Update (ASU) 2016-13, Measurement of Credit Losses on Financial Instruments effective January 1, 2020. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. There was no material impact on the consolidated financial statements as a result of the adoption of this standard.

  Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in ASC 740 related to the approach for intraperiod tax allocation. It also simplifies aspects of accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2020, with early adoption permitted. The standard is applied on both a prospective and retrospective basis. TEC early adopted the standard effective January 1, 2020. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

     Facilitation of the Effects of Reference Rate Reform on Financial Reporting

TEC adopted ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting in the fourth quarter of 2020. The standard provides options and exceptions for applying U.S. GAAP to contract modifications and hedging relationships that reference LIBOR or another reference rate that is expected to be discontinued. The guidance was effective as of the date of issuance and entities may elect to apply the guidance prospectively through December 31, 2022. The transition from reference rates will not have a material impact on the consolidated financial statements. In November 2020, the Federal Reserve extended the phase-out of LIBOR until June 2023. TEC will continue to monitor the impact this may have on application of the standard.

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Regulatory

12 Months Ended

Dec. 31, 2020

Regulated Operations [Abstract]

Regulatory

3. Regulatory

Tampa Electric’s retail business and PGS are regulated separately 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 2020, 2019 and 2018 reflect 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%. The agreement stated that Tampa Electric could not file for additional base rate increases to be effective sooner than December 31, 2021, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital. The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. Tampa Electric expects to invest approximately $850 million in these solar projects during the period from 2017 to 2021, of which approximately $820 million has been invested through December 31, 2020, and is accruing AFUDC during construction. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac.   

On December 12, 2017, TEC filed its first petition regarding the SoBRAs along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 tranche representing 145 MW and $24 million annually in estimated revenue requirements. The FPSC approved the tariffs on the first SoBRA filing on May 8, 2018 and TEC began receiving these revenues in September 2018. On June 29, 2018, TEC filed its second SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2019 tranche representing 260 MW and $46 million annually in estimated revenue requirements. The FPSC approved the tariffs on the second SoBRA filing on October 29, 2018 and TEC began receiving these revenues in January 2019. On June 28, 2019, TEC filed its third SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2020 tranche representing 149 MW and $26 million annually in estimated revenue requirements. The FPSC approved the tariffs on this SoBRA filing, including an adjustment to reflect the reduction in the state corporate income tax discussed below, on December 10, 2019 and TEC began receiving these revenues in January 2020.On July 31, 2020, TEC filed its fourth and final SoBRA petition along with supporting tariffs demonstrating the cost-effectiveness of the January 1, 2021 tranche representing 46 MW and $8 million annually in estimated revenues. The FPSC approved the tariffs on this SoBRA filing on November 3, 2020 and TEC began receiving these revenues in January 2021.

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

   The 2017 settlement agreement further contains a provision related to tax reform.  See “Tampa Electric Storm Restoration Cost Recovery” below for information regarding the impact of 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 November 13, 2019, as required by the 2017 settlement agreement, TEC filed its petition to reduce base rates and charges to reflect the impact of the temporary reduction of the state corporate income tax from 5.5% to 4.5%. The tax rate reduction was issued on September 12, 2019 and is effective retroactive from January 1, 2019 through December 31, 2021. The estimated base rate reduction due to customers of $5 million is subject to true-up, and the actual rate reduction may vary from year to year. The base rate reduction was approved on December 10, 2019 for rates effective January 2020.

On February 1, 2021, Tampa Electric notified the FPSC of its intent to seek a base rate increase, reflecting revenue requirements of approximately $280 million to $295 million, effective in January 2022. Tampa Electric’s proposed 2022 rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investment, and accelerated recovery of the remaining net book value of retiring assets. Tampa Electric also intends to seek approval for Generation Base Rate Adjustments of $130 million to recover the costs of the second phase of the Big Bend modernization project and additional utility-scale solar projects in subsequent years. These filing amounts are estimates until Tampa Electric completes its analysis and files the case. Tampa Electric expects to file its detailed case on or after April 2, 2021, and the FPSC is expected to decide the case by the end of the year.

Tampa Electric Big Bend Power Station

Tampa Electric expects to invest approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $526 million has been invested through December 31, 2020. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the Big Bend modernization project, on June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At June 1, 2020 and December 31, 2020, Tampa Electric’s balance sheet included $223 million and $200 million, respectively, in electric utility plant and $90 million and $88 million, respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 as part of the Big Bend modernization project. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric was not required to request an asset recovery schedule for retired assets until the next depreciation study. On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedule with the FPSC.    

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

Tampa Electric Storm Protection Cost Recovery Clause and Settlement Agreement

On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This new clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Tampa Electric submitted its storm protection plan with the FPSC on April 10, 2020. On April 27, 2020, Tampa Electric submitted a settlement agreement with the FPSC which specified a $15 million base rate reduction for SPP program costs previously recovered in base rates beginning January 1, 2021. On June 9, 2020, the FPSC approved this settlement agreement. On August 3, 2020, Tampa Electric submitted another settlement agreement to the FPSC for approval, including cost recovery of approximately $39 million in proposed storm protection project costs for 2020 and 2021. This cost recovery includes the $15 million of costs removed from base rates. This settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in January 2021. The current approved plan will apply for the years 2020, 2021 and 2022, and Tampa Electric will file a new plan in 2022 to determine cost recovery in 2023, 2024, and 2025.

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

Tampa Electric Storm Restoration Cost Recovery

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million, of which $90 million was charged to the storm reserve, $3 million was charged to O&M expense and $9 million was charged to capital expenditures. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated Hurricane Irma storm costs plus approximately $10 million in restoration costs from prior named storms and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013.

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

On April 9, 2019, Tampa Electric reached a settlement agreement with consumer parties regarding eligible storm costs, which was approved by the FPSC on May 21, 2019. As a result, Tampa Electric refunded $12 million to customers in January 2020, resulting in minimal impact to the Consolidated Statements of Income.

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

PGS Base Rates

PGS’s base rates for 2020, 2019 and 2018 were originally established in May 2009. The allowed equity in its capital structure was 54.7% from all investor sources of capital.

On February 7, 2017, the FPSC approved a settlement agreement filed by PGS and the OPC agreeing to new depreciation rates, accelerate the amortization of the regulatory asset associated with environmental remediation costs as described below, include obsolete plastic pipe replacements through the existing cast iron and bare steel replacement rider, and establish an ROE range of  9.25% to 11.75%. The settlement agreement provided that the bottom of the range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020 and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders.

As part of the 2017 settlement, PGS and the OPC agreedthat at least $32 million of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites, to the extent expenses are reasonably and prudently incurred, will be amortized over the period 2016 through 2020. At least $21 million of that amount will be amortized over a two-year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million and $16 million, respectively, of this amortization expense.

In 2018, the FPSC approved a settlement agreement authorizing PGS to accelerate in 2018 the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS recorded amortization expense and a regulatory asset reduction of $11 million in 2018. In January 2019, PGS reduced its base rates by $12 million for the impact of tax reform and reduced depreciation rates by $10 million in accordance with the settlement agreement.

PGS was permitted to initiate a general base rate proceeding during 2020 regardless of its earned ROE at the time, provided the new rates do not become effective before January 1, 2021. On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase in base rates by $58 million annually effective January 2021, which is a $34 million increase in revenue and $24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint. It provides PGS the ability to reverse a total of $34 million of accumulated depreciation through 2023 and sets new depreciation rates going into effect January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.90% before that time with an allowed equity in the capital structure of 54.7% from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024.

Regulatory Assets and Liabilities

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

Regulatory Assets and Liabilities

	December 31,		December 31,
(millions)	2020		2019
Regulatory assets:
Regulatory tax asset (1)	$	90	$	74
Cost-recovery clauses (2)		38		12
Environmental remediation (3)		22		20
Postretirement benefits (4)		309		295
Asset retirement obligation (5)		13		25
Other		13		11
Total regulatory assets		485		437
Less: Current portion		79		41
Long-term regulatory assets	$	406	$	396
Regulatory liabilities:
Regulatory tax liability (6)	$	691	$	699
Cost-recovery clauses (2)		23		37
Accumulated reserve—cost of removal (7)		498		506
Storm reserve (8)		48		48
Other		1		13
Total regulatory liabilities		1,261		1,303
Less: Current portion		67		93
Long-term regulatory liabilities	$	1,194	$	1,210

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction.  

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in a subsequent period.

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

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

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

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

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

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

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Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Taxes

4. Income Taxes

   CARES Act

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

Change in Florida Corporate Income Tax Rate

On September 12, 2019, the state of Florida issued a corporate tax rate reduction from 5.5% to 4.46% effective January 1, 2019 through December 31, 2021. The impact to TEC earnings and revaluation of TEC state deferred income tax balance was not material.

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 2020, 2019 and 2018, TEC recorded net tax provisions of $82 million, $77 million and $81 million, respectively.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ended December 31,	2020			2019			2018
Current income taxes
Federal	$	35		$	56		$	72
State		(7	)		6			10
Deferred income taxes
Federal		32			7			(13	)
State		29			13			13
Investment tax credits amortization		(7	)		(5	)		(1	)
Total income tax expense	$	82		$	77		$	81

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,	2020			2019			2018
Income before provision for income taxes	$	506		$	447		$	422
Federal statutory income tax rates		21	%		21	%		21	%
Income taxes, at statutory income tax rate		106			94			89
Increase (decrease) due to
State income tax, net of federal income tax		17			15			19
Excess deferred tax amortization		(26	)		(25	)		(24	)
ITC amortization		(7	)		(5	)		(1	)
AFUDC-equity		(6	)		(2	)		(2	)
Tax credits		(8	)		(1	)		(2	)
Other		6			1			2
Total income tax expense on consolidated statements of income	$	82		$	77		$	81
Income tax expense as a percent of income before income taxes		16.2	%		17.2	%		19.2	%

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,	2020		2019
Deferred tax liabilities (1)
Property related	$	1,121	$	1,036
Pension and postretirement benefits		116		111
Total deferred tax liabilities		1,237		1,147
Deferred tax assets (1)
Loss and credit carryforwards (2)		301		243
Medical benefits		27		27
Insurance reserves		16		16
Pension and postretirement benefits		66		63
Capitalized energy conservation assistance costs		18		17
Other		26		23
Total deferred tax assets		454		389
Total deferred tax liability, net	$	783	$	758

(1) Certain property related assets and liabilities have been netted.

(2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $9 million.

At December 31, 2020, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $340 million and $88 million, respectively, expiring between 2032 and 2037. TEC has unused general business credits of $242 million expiring between 2027 and 2040, of which $222 million relate to ITCs expiring between 2034 and 2040. As a result of the Merger with Emera, 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)	2020			2019		2018
Balance at January 1,	$	9		$	8	$	8
Decreases due to tax positions related to prior year		(2	)	0		0
Increases due to tax positions related to prior year	1			1		0
Increases due to tax positions related to current year	1			0		0
Balance at December 31,	$	9		$	9	$	8

As of December 31, 2020 and 2019, TEC’s uncertain tax positions for federal R&D tax credits were $9 million, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC’s unrecognized federal tax benefits decreased in the fourth quarter of 2020 by approximately $2 million due to an adjustment related to its 2016 federal R&D credits issue with IRS Appeals. The recognition of these tax benefits decreased the effective tax rate resulting in an income tax benefit of approximately $2 million. TEC expects to be effectively settled with this issue early 2021. TEC had $9 million of unrecognized tax benefits at December 31, 2020 and 2019 that, 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 2020, 2019 and 2018, 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, 2020, 2019 and 2018.

The short tax year ending June 30, 2016 is currently under examination by the IRS under its Compliance Assurance Program (CAP). EUSHI’s 2016 consolidated federal income tax return, which includes TEC’s short tax year ending December 31, 2016, is also currently under examination by the IRS. The U.S. federal statute of limitations remains open for the year 2016 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, 2020

Compensation And Retirement Disclosure [Abstract]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Pension Benefits

TEC is a participant in the comprehensive 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.

Effective October 21, 2019, the defined benefit retirement plan was amended to freeze further crediting of service and earnings for certain participants covered by the International Brotherhood of Electrical Workers (the IBEW) collective bargaining agreement. As of December 31, 2019, 24% of TEC’s employees were represented by the IBEW. As a result, a curtailment and a remeasurement of the plan occurred in the fourth quarter of 2019. See curtailment-related line items in tables below.

As the result of a reorganization of shared services functions, certain employees and their associated pension benefits were transferred from TSI to TEC effective December 2019. Deferred costs related to pension benefits that were recognized by TSI in AOCI are now recognized in TEC as regulatory assets. The balances at December 31, 2020 and 2019 are reflective of this transfer.

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.  

As the result of a reorganization of shared services functions, certain employees and their associated other postretirement benefits were transferred from TSI to TEC effective December 2019. Deferred costs related to other postretirement benefits that were recognized by TSI in AOCI are now recognized in TEC as regulatory assets. The balances at December 31, 2020 and 2019 are reflective of this transfer.

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)	2020			2019			2020			2019
Change in benefit obligation
Benefit obligation at beginning of year	$	843		$	750		$	180		$	173
Service cost		20			20			2			1
Interest cost		26			31			6			7
Plan participants’ contributions		0			0			4			4
Plan curtailment		0			(10	)		0			0
Plan settlement		0			(5	)		0			0
Benefits paid		(54	)		(49	)		(17	)		(14	)
Actuarial loss		84			106			37			9
Benefit obligation at end of year	$	919		$	843		$	212		$	180

Change in plan assets
Fair value of plan assets at beginning of year	$	796		$	659		$	0		$	0
Actual return on plan assets		142			165			0			0
Employer contributions		19			20			0			0
Employer direct benefit payments		1			6			13			10
Plan participants’ contributions		0			0			4			4
Plan settlement		0			(5	)		0			0
Benefits paid		(54	)		(48	)		0			0
Direct benefit payments		(1	)		(1	)		(17	)		(14	)
Fair value of plan assets at end of year (1)	$	903		$	796		$	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.

Gains in the benefit obligation for the year ended December 31, 2020 relate to decreases in the discount rate used to calculate the benefit obligation, the incorporation of new census data as of January 1, 2020 and the updating of the withdrawal, retirement rate and form of payment assumptions as the result of an experience study performed during the year. In addition, participation and persistency assumptions were updated for the other postretirement benefit plan.

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)	2020			2019			2020			2019
Benefit obligation (PBO/APBO)	$	919		$	843		$	212		$	180
Less: Fair value of plan assets		903			796			0			0
Funded status at end of year	$	(16	)	$	(47	)	$	(212	)	$	(180	)

(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 $876 million at December 31, 2020 and $801 million at December 31, 2019.

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)	2020			2019			2020			2019
Accrued benefit costs and other current liabilities	$	(1	)	$	(1	)	$	(12	)	$	(11	)
Deferred credits and other liabilities		(15	)		(42	)		(186	)		(156	)
	$	(16	)	$	(43	)	$	(198	)	$	(167	)

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)	2020		2019		2020		2019
Net actuarial loss (gain)	$	221	$	244	$	88	$	51
Amount recognized	$	221	$	244	$	88	$	51

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2020			2019			2020			2019
Discount rate		2.37	%		3.21	%		2.47	%		3.32	%
Rate of compensation increase		3.07	%		3.79	%		3.07	%		3.79	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				5.74	%		6.03	%
Ultimate rate	n/a			n/a				4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			2038			2038

 The discount rate assumption used to determine the December 31, 2020 and 2019 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)
	2020			2019					2018					2020			2019			2018
(millions)
Service cost	$	20		$	20				$	21				$	2		$	1		$	2
Interest cost		26			31					29					6			7			7
Expected return on plan assets		(50	)		(51	)				(49	)				0			0			0
Amortization of:
Actuarial loss		20			16					19					1			1			1
Prior service (benefit) cost		0			0					0					(3	)		(2	)		(2	)
Settlement loss	0				1		(3	)		2		(2	)		0			0			0
Net periodic benefit cost	$	16		$	17				$	22				$	6		$	7		$	8

Net loss (gain) arising during the year (includes curtailment gain)	$	(8	)	$	(17	)	$	62		$	38		$	9		$	(14	)
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2			2			2
Amortization or settlement of actuarial loss		(20	)		(17	)		(20	)		(1	)		(1	)		(1	)
Total recognized in OCI and regulatory assets	$	(28	)	$	(34	)	$	42		$	39		$	10		$	(13	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(12	)	$	(17	)	$	64		$	45		$	17		$	(5	)

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

(2) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

(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.

TEC’s portion of the net periodic benefit costs for pension benefits was $12 million, $12 million and $16 million for 2020, 2019 and 2018, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $7 million, $7 million and $8 million for 2020, 2019 and 2018, respectively. TEC’s portion of net periodic benefit costs for pension and other benefits is included as an expense on the Consolidated Statements of Income in “Operations & maintenance”.

   TEC recognized a settlement charge of $1 million in 2018 relating to the retirement of an executive in the SERP plan. TEC recognized a settlement charge of approximately $1 million in 2019 related to the retirement of a SERP participant. TEC recognized settlement charges of approximately $1 million in 2019 related to the retirement of Restoration plan participants.

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

	Pension Benefits										Other Benefits
	2020			2019				2018			2020			2019			2018
Discount rate		3.21	%		4.33	%			3.62	%		3.32	%		4.38	%		3.70	%
Expected long-term return on plan assets		7.00	%	7.35%/7.00%			(1)		6.85	%	n/a			n/a			n/a
Rate of compensation increase		3.79	%		3.75	%			3.32	%		3.79	%		3.75	%		3.31	%
Healthcare cost trend rate
Initial rate	n/a			n/a				n/a				6.03	%		6.31	%		6.58	%
Ultimate rate	n/a			n/a				n/a				4.50	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a				n/a			2038			2038			2038

(1) The expected return on assets was 7.35% as of January 1, 2019 and 7.00% as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment.

The discount rate assumption used to determine the benefit cost for 2020, 2019 and 2018 was based on the same technique that was used to determine the December 31, 2020 and 2019 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, 2020, TECO Energy’s pension plan’s actual earned returns were approximately 19%.

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 (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							ActualAllocation, End of Year
Asset Category	2020 Target Allocation			2019 Target Allocation			2020			2019
Equity securities	50%-70%			57%-63%				60	%		58	%
Fixed income securities	30%-50%			37%-43%				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 expects to take additional steps to more closely match 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, 2020
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	9		$	0		$	0	$	0	$	9
Accounts receivable		10			0			0		0		10
Accounts payable		(88	)		0			0		0		(88	)
Short-term investment funds (STIFs)		35			0			0		0		35
Common stocks		66			0			0		0		66
Real estate investment trusts (REITs)		8			0			0		0		8
Mutual funds		69		0				0		0		69
Municipal bonds		0			1			0		0		1
Government bonds		0			90			0		0		90
Corporate bonds		0			79			0		0		79
Mortgage backed securities (MBS)		0			1			0		0		1
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Short Sales		0			(4	)		0		0		(4	)
Long Futures		(2	)		0			0		0		(2	)
Swaps		0			1			0		0		1
Investments not utilizing the practical expedient		107			169			0		0		276
Common and collective trusts (1)		0			0			0		553		553
Mutual fund (1)		0			0			0		74		74
Total investments	$	107		$	169		$	0	$	627	$	903

(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 Consolidated Balance Sheet of TECO Energy.

TECO Energy	At Fair Value as of December 31, 2019
(millions)
	Level 1			Level 2		Level 3		Using NAV (1)		Total
Cash	$	7		$	0	$	0	$	0	$	7
Accounts receivable		27			0		0		0		27
Accounts payable		(64	)		0		0		0		(64	)
Cash collateral		1			0		0		0		1
Short-term investment funds (STIFs)		22			0		0		0		22
Common stocks		50			0		0		0		50
Real estate investment trusts (REITs)		4			0		0		0		4
Mutual funds		153			0		0		0		153
Municipal bonds		0			1		0		0		1
Government bonds		0			51		0		0		51
Corporate bonds		0			70		0		0		70
Mortgage backed securities (MBS)		0			5		0		0		5
Collateralized mortgage obligations (CMOs)		0			2		0		0		2
Long Futures		(4	)		0		0		0		(4	)
Swaps		0			1		0		0		1
Investments not utilizing the practical expedient		196			130		0		0		326
Common and collective trusts (1)		0			0		0		412		412
Mutual fund (1)		0			0		0		58		58
Total investments	$	196		$	130	$	0	$	470	$	796

(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 Consolidated Balance Sheet of TECO Energy.

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.

• Options are valued using the bid-ask spread and the last price.

• 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, 2020.

• 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, 2020.

• 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 $10 million and $10 million of assets as of December 31, 2020 and 2019, 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, 2020 and 2019.

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 111.66% of the Pension Protection Act funded target as of January 1, 2020 and is estimated at 109.67% of the Pension Protection Act funded target as of January 1, 2021.

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 and minimize PBGC premiums paid by the plan. 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 2020, 2019 and 2018, which met the minimum funding requirements for 2020, 2019 and 2018. TEC’s portion of the contribution in 2020 was $16 million and in 2019 was $15 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2021 contribution to be $17 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 2020, 2019 and 2018 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2021. TEC made SERP payments of approximately $1 million and $5 million from the trust in 2020 and 2019, respectively, and expects to make a SERP payment of approximately $1 million from the trust in 2021.    

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 2021, TEC expects to make a contribution of about $12 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)
2021	$	58	$	13
2022		66		13
2023		62		13
2024		64		13
2025		66		13
2026-2030		331		61

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, 2020, 2019 and 2018, TEC’s portion of expense totaled $21 million, $11 million and $11 million, respectively, related to the matching contributions made to this plan. TEC’s portion of 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, 2020 and 2019, TEC recognized expense totaling $9 million and $1 million, respectively, related to the contributions made to this plan. TEC’s portion of the expense related to this contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.

COVID-19

The COVID-19 pandemic could impact key actuarial assumptions used to account for employee postretirement benefits including the anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation, benefit costs and annual pension funding requirements. The extent of the future impact of the COVID-19 pandemic on TEC’s financial results and business operations cannot be predicted at this time and will depend on future developments, including the duration and severity of the pandemic, further potential government actions, future economic activity and energy usage. Actual results may differ significantly from these estimates.

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Short-Term Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Short-Term Debt

6. Short-Term Debt

Credit Facilities

	December 31, 2020						December 31, 2019
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	800	$	345	$	1	$	400	$	295	$	1
3-year accounts receivable facility (3)		150		130		0		150		53		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	1,250	$	775	$	1	$	550	$	348	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023.

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

(4) This 1-year term facility matures on April 29, 2021.

At December 31, 2020, these credit facilities required commitment fees ranging from 12.5 to 35.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at December 31, 2020 and 2019 was 0.89% and 2.56%, respectively.

Tampa Electric Company Non-Revolving Term Loan

On February 6, 2020, TEC entered into a 364-day, $300 million credit agreement with a group of banks. The credit agreement had a maturity date of February 4, 2021; 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 London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin. On January 29, 2021, TEC extended the maturity date of the agreement to April 29, 2021.

Tampa Electric Company Accounts Receivable Facility

On March 23, 2018, TEC amended its $150 million accounts receivable collateralized borrowing facility in order to extend the scheduled termination date to March 22, 2021, by entering into a Second Amended Loan and Servicing Agreement, among TEC, certain lenders and the program agent (the Loan Agreement). Throughout the term of the facility, TEC will pay program and liquidity fees, which total 70 basis points at December 31, 2020. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin.  In the case of default, as defined under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. On July 14, 2020 and October 30, 2020, TEC amended the agreement in order to change performance ratios. As of December 31, 2020, TEC was in compliance with the requirements of the Loan Agreement.  

Tampa Electric Company 5-Year Credit Facility

On March 22, 2017, TEC amended its $325 million bank credit facility, entering into a Fifth Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from December 17, 2018 to March 22, 2022 (subject to further extension with the consent of each lender); provides 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. On December 19, 2019, TEC increased the amount by $75 million to $400 million with no other changes from the prior agreement.  

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

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Long-Term Debt

12 Months Ended

Dec. 31, 2020

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.

Tampa Electric Company 3.625% Notes due 2050

On July 24, 2019, TEC completed a sale of $300 million aggregate principal amount of 3.625% unsecured notes due June 15, 2050. Until December 15, 2049, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after December 15, 2049, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Tampa Electric Company 4.45% Notes due 2049

On October 4, 2018, TEC completed a sale of $375 million aggregate principal amount of 4.45% unsecured notes due June 15, 2049. Until December 15, 2048, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2048, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

Tampa Electric Company 4.3% Notes due 2048

On June 7, 2018, TEC completed a sale of $350 million aggregate principal amount of 4.3% unsecured notes due June 15, 2048. Until December 15, 2047, TEC may redeem all or any part of the Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after December 15, 2047, TEC may, at its option, redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2020

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

8. Commitments and Contingencies

Legal Contingencies

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 2020 and 2019, TEC has estimated its ultimate financial liability to be $17 million and $21 million, respectively, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

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

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

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

Long-Term Commitments

TEC has commitments for various purchases as disclosed below, including payment obligations for capital projects, such as Tampa Electric’s solar projects (see Note 3) and the modernization of the Big Bend power station, 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, 2020:

	Purchased				Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Power		Transportation(1)		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2021	$	10	$	232	$	237	$	238	$	11	$	3	$	4	$	735
2022		0		232		76		41		13		3		3		368
2023		0		213		60		1		16		3		0		293
2024		0		207		0		0		16		3		0		226
2025		0		189		0		0		17		2		0		208
Thereafter		0		1,998		0		0		54		48		0		2,100
Total future minimum payments	$	10	$	3,071	$	373	$	280	$	127	$	62	$	7	$	3,930

(1) As of December 31, 2020, $117 million is related to a gas transportation contract through 2040 between PGS and SeaCoast, a related party.

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, 2020 and 2019, TEC was in compliance with all required financial covenants.

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Revenue

12 Months Ended

Dec. 31, 2020

Revenues [Abstract]

Revenue

9. Revenue

The following disaggregates TEC’s revenue by major source:

(millions)	Tampa								Tampa Electric
For the year ended December 31, 2020	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,018		$	0	$	0		$	1,018
Commercial		506			0		0			506
Industrial		133			0		0			133
Regulatory deferrals and unbilled revenue		(25	)		0		0			(25	)
Other (1)		217			0		(4	)		213
Total electric revenue		1,849			0		(4	)		1,845
Gas revenue
Residential		0			158		0			158
Commercial		0			135		0			135
Industrial (2)		0			23		0			23
Other (3)		0			117		(6	)		111
Total gas revenue		0			433		(6	)		427
Total revenue	$	1,849		$	433	$	(10	)	$	2,272
For the year ended December 31, 2019
Electric revenue
Residential	$	1,046		$	0	$	0		$	1,046
Commercial		562			0		0			562
Industrial		156			0		0			156
Regulatory deferrals and unbilled revenue		(49	)		0		0			(49	)
Other (1)		250			0		(4	)		246
Total electric revenue		1,965			0		(4	)		1,961
Gas revenue
Residential		0			154		0			154
Commercial		0			146		0			146
Industrial (2)		0			21		0			21
Other (3)		0			140		(18	)		122
Total gas revenue		0			461		(18	)		443
Total revenue	$	1,965		$	461	$	(22	)	$	2,404
For the year ended December 31, 2018
Electric revenue
Residential	$	1,067		$	0	$	0		$	1,067
Commercial		582			0		0			582
Industrial		161			0		0			161
Regulatory deferrals and unbilled revenue		(2	)		0		0			(2	)
Other (1)		258			0		(3	)		255
Total electric revenue		2,066			0		(3	)		2,063
Gas revenue
Residential		0			157		0			157
Commercial		0			151		0			151
Industrial (2)		0			21		0			21
Other (3)		0			159		(27	)		132
Total gas revenue		0			488		(27	)		461
Total revenue	$	2,066		$	488	$	(30	)	$	2,524

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

(2)    Industrial includes sales to power generation customers.

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

Remaining Performance Obligations

Remaining performance obligations primarily represent lighting contracts and gas transportation contracts with fixed contract terms.  As of December 31, 2020 and 2019, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $135 million and $140 million, respectively. As allowed under ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which TEC recognizes revenue at the amount to which it has the right to invoice for services performed. TEC expects to recognize revenue for the remaining performance obligations through 2033. 

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Related Party Transactions

12 Months Ended

Dec. 31, 2020

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)	2020		2019			2018
Natural gas sales to/(from) affiliates	$	(139)	$	(111	)	$	(38	)
Services received from affiliates		6		65			65
Dividends to TECO Energy		408		373			362
Equity contributions from TECO Energy		505		395			345

In 2019 and 2018, services received from affiliates primarily included shared services provided to TEC from TSI, TECO Energy’s centralized services company subsidiary. In December 2019, most TSI employees were transferred to Tampa Electric. The transfer of these employees to Tampa Electric did not materially impact shared service costs or the TEC Consolidated Statement of Income. In 2020, the shared service costs were not recorded through TSI but rather directly recorded in TEC’s O&M expenses on the TEC Consolidated Statement of Income.

Amounts due from or to affiliates at December 31,

(millions)	2020		2019
Accounts receivable related to asset management agreements to Emera Energy Services Inc. (1)	$	4	$	4
Accounts receivable excluding asset management agreements (1)		7		10
Accounts payable (1)		27		16
Taxes payable (2)		19		4

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

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

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Segment Information

12 Months Ended

Dec. 31, 2020

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 and has two segments, Tampa Electric and PGS. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to approximately 792,500 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 426,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2020
Revenues - external	$	1,845	$	427	$	0			$	2,272
Sales to affiliates		4		6		(10	)			0
Total revenues		1,849		433		(10	)			2,272
Depreciation and amortization		339		45		0				384
Total interest charges		113		17		0				130
Provision for income taxes		66		16		0				82
Net income		372		52		0				424
Total assets		9,800		1,901		(653	)	(1)		11,048
Capital expenditures		1,028		333		0				1,361
2019
Revenues - external	$	1,961	$	443	$	0			$	2,404
Sales to affiliates		4		18		(22	)			0
Total revenues		1,965		461		(22	)			2,404
Depreciation and amortization		336		41		0				377
Total interest charges		117		17		0				134
Provision for income taxes		59		18		0				77
Net income		316		54		0				370
Total assets		9,007		1,593		(593	)	(1)		10,007
Capital expenditures		1,055		228		0				1,283
2018
Revenues - external	$	2,063	$	461	$	0			$	2,524
Sales to affiliates		3		27		(30	)			0
Total revenues		2,066		488		(30	)			2,524
Depreciation and amortization		312		60		0				372
Total interest charges		102		16		0				118
Provision for income taxes		65		16		0				81
Net income		294		47		0				341
Total assets		8,235		1,407		(487	)	(1)		9,155
Capital expenditures		940		169		0				1,109

(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, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

12. Asset Retirement Obligations

TEC 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)	2020			2019
Beginning balance	$	49		$	64
Additional liabilities		8			0
Liabilities settled (1)		(19	)		(18	)
Other (2)		1			3
Ending balance	$	39		$	49

(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The decreases in the ARO in 2020 and 2019 are due to the closure of CCR management facilities.

(2) Includes accretion recorded as a deferred regulatory asset.  

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Leases

12 Months Ended

Dec. 31, 2020

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.

Where TEC is the lessor, a lease is a sales-type lease if certain criteria is met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease.

For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value (net of estimated executory costs and unearned income). The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

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

Lessee

TEC has operating leases for buildings, land, telecommunication services and rail cars. TEC’s leases have remaining lease terms of 1 year to 65years, 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	December 31, 2020		December 31, 2019
Right-of-use asset	Other deferred debits	$	26	$	28
Lease liabilities
Current	Other current liabilities	$	2	$	2
Long-term	Deferred credits and other liabilities		25		27
Total lease liabilities		$	27	$	29

TEC has recorded operating lease expense for the year ended December 31, 2020 and 2019 of $4 million and $4 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, 2020: 

(millions)
Year ended December 31:	2021		2022		2023		2024		2025		Thereafter		Total
Minimum lease payments	$	3	$	3	$	3	$	3	$	2	$	48	$	62
Less imputed interest														(35	)
Total future minimum payments													$	27

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

Year ended December 31,	2020			2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	5		$	3
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions)	$	0		$	11
Weighted average remaining lease term (years)		43			43
Weighted average discount rate - operating leases		4.3	%		4.3	%

Lessor

TEC leases CNG stations to other companies, which are classified as direct finance leases. The net investment in direct finance leases consists of the following:

(millions)	December 31, 2020			December 31, 2019
Total minimum lease payments to be received	$	31		$	33
Less amounts representing estimated executory costs		(12	)		(13	)
Minimum lease payments receivable	$	19		$	20
Less unearned finance lease income		(10	)		(11	)
Net investment in direct finance and sales-type leases	$	9		$	9
Principal due within one year (included in "Receivables")		(2	)		(2	)
Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits")	$	7		$	7

The unearned income related to these direct finance leases is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Gas revenues” on the Consolidated Statements of Income. Customers have the option to purchase the assets related to the CNG stations at any time after year five of the agreements, which is in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. Alternatively, the customer may take possession of the CNG station asset at the end of the lease term for no cost.

As of December 31, 2020, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following:

(millions)
Year ended December 31:	2021		2022		2023		2024		2025		Thereafter		Total
Minimum lease payments to be received	$	2	$	2	$	2	$	2	$	2	$	21	$	31
Less executory costs														(12	)
Total minimum lease payments receivable													$	19

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Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2020

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

14. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

• To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

• To optimize the utilization of Tampa Electric’s physical natural gas storage capacity and PGS’s firm transportation capacity on interstate pipelines.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers and to optimize the utilization of its physical natural gas storage capacity and firm transportation capacity on interstate pipelines.

The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which included a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022 (see Note 3). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had zero and $1 million of derivative liabilities related to natural gas storage optimization as of December 31, 2020 and 2019, respectively, and zero derivative assets on its Consolidated Balance Sheets as of December 31, 2020 and 2019.

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements and to measure those instruments at fair value. TEC also applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas and optimize natural gas storage capacity for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of these activities on the fuel recovery clause. As a result, these changes are not recorded in OCI or net income (see Note 3).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2020, all of TEC’s physical contracts qualified for the NPNS exception, which was elected.

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas and to optimize the value of natural gas storage capacity. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of December 31, 2020, substantially all of the counterparties with transaction amounts outstanding in TEC’s derivative positions were either rated investment grade by the major rating agencies or held with affiliates. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into standardized master arrangements in the electric and gas industry. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.  

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Fair Value Measurements

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

15. 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, 2020 and 2019, 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, 2020

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation

16. Stock-Based Compensation

Performance Share Unit Plan

Emera has a performance share unit (PSU) plan.  The PSU liability is 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.

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.

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, 2019		504		$	45.45	$	28
Granted including DRIP		78			52.68		4
Exercised		(162	)		45.41		9
Forfeited		(27	)		46.08		0
Transferred		(3	)		44.85		0
Outstanding as of December 31, 2020		390			46.87		21

Compensation cost recognized for the PSU plan for the years ended December 31, 2020, 2019 and 2018 was $8 million, $8 million and $4 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2020, 2019 and 2018were $2 million, $2 million and $1 million, respectively. Cash payments made during the year ended December 31, 2020, 2019 and 2018 associated with the PSU plan were $9 million, zero and zero, respectively. As of December 31, 2020 and 2019, there was $5 million and $4 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.

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Long-Term PPAs

12 Months Ended

Dec. 31, 2020

Contractors [Abstract]

Long-Term PPAs

17. Long-Term PPAs

In 2018, Tampa Electric had long-term PPAs with wholesale energy providers in Florida, which expired in December 2018. These agreements ranged in size from 121 MW to 250 MW of available capacity, were with similar entities and contained similar provisions. 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 2021. 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 $36 million, $25 million and $15 million under these long-term PPAs for the three years ended December 31, 2020, 2019 and 2018, 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, 2020

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, 2020, 2019 and 2018

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions  (1)		Period
Allowance for Credit Losses:
2020	$	2	$	9	$	0	$	4	$	7
2019	$	2	$	5	$	0	$	5	$	2
2018	$	1	$	7	$	0	$	6	$	2

(1) Write-off of individual bad debt accounts

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

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. and contains electric and natural gas divisions. 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.

In 2020, the outbreak of the novel strain of coronavirus, specifically identified as COVID-19, has resulted in governments worldwide enacting emergency measures to combat the spread of the virus. While management considered the impact of the COVID-19 pandemic in TEC’s estimates and results, the financial statements as of and for the year ended December 31, 2020 were not materially impacted by the COVID-19 pandemic. However, it is not possible to reliably estimate the length and severity of the COVID-19 pandemic and the impact on the financial results and condition of TEC in future periods.

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 regulated utilities, Tampa Electric and PGS 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, 2020			December 31, 2019
Electric generation	21-56 years	$	5,694		$	5,370
Electric transmission	28-77 years		1,008			940
Electric distribution	14-56 years		2,859			2,732
Gas transmission and distribution	16-77 years		2,076			1,848
General plant and other	8-43 years		723			675
Total cost			12,360			11,565
Less accumulated depreciation			(3,712	)		(3,472	)
Construction work in progress			1,472			1,038
Total property, plant and equipment, net		$	10,120		$	9,131

Depreciation

Depreciation

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.2%, 3.4% and 3.5% for 2020, 2019 and 2018, respectively. Construction work in progress is not depreciated until the asset is placed in service. Total depreciation expense for the years ended December 31, 2020, 2019 and 2018 was $381 million, $359 million and $345 million, respectively. See Note 3 for information regarding agreements approved by the FPSC that, among other things, allow Tampa Electric to continue to depreciate certain retired assets until the FPSC approves Tampa Electric’s next depreciation and dismantlement study and allowed Tampa Electric to eliminate its $16 million accumulated amortization reserve surplus for intangible software assets through a credit to amortization expense in 2020.

Tampa Electric and PGS compute 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. Tampa Electric’s FPSC-approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. In 2020, 2019 and 2018, Tampa Electric’s rate was 6.46%. In July 2019, the FPSC approved a petition filed by PGS for authority to record AFUDC at an annual rate of 5.97% as part of its plans to develop three expansion projects in 2019 and 2020. Total AFUDC for the years ended December 31, 2020, 2019 and 2018 was $44 million, $16 million and $15 million, respectively. The increase in 2020 is primarily a result of the construction of solar projects and the repowering of Big Bend Unit 1 with natural gas combined-cycle technology.

Inventory

Inventory

TEC values materials, supplies and fossil fuel inventory (natural gas, coal, petcoke and oil) 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 Tax Credits

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

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

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

Other

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

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 and environmental costs for Tampa Electric and 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 from contracts with customers, which consist of services to residential, commercial, industrial and other customers, were $214 million and $205 million as of December 31, 2020 and 2019, 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 Tampa Electric’s and PGS’s estimates of credit losses include, but are not limited to, customer credit issues, fuel prices, customer deposits and general economic conditions, including the impacts of the COVID-19 pandemic. Accounts are reserved in the allowance or written off once they are deemed to be uncollectible.

The regulated utilities accrue base revenues for services rendered but unbilled to provide for matching of revenues and expenses (see Note 3). As of December 31, 2020 and 2019, unbilled revenues of $73 million and $61 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

Tampa Electric and PGS are 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 by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $109 million, $117 million and $120 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Deferred Credits and Other Liabilities

Deferred Credits and Other Liabilities

Other deferred credits primarily include accrued pension and other postretirement benefits (see Note 5), MGP environmental remediation liability (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, 2020 and 2019 ranged from 2.43% to 4.00% and 2.66% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

Cash Flows Related to Derivatives and Hedging Activities

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. See Note 14 for further information regarding derivatives.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Schedule of Property, Plant and Equipment

Property, plant and equipment consisted of the following assets:

(millions)	Estimated Useful Lives	December 31, 2020			December 31, 2019
Electric generation	21-56 years	$	5,694		$	5,370
Electric transmission	28-77 years		1,008			940
Electric distribution	14-56 years		2,859			2,732
Gas transmission and distribution	16-77 years		2,076			1,848
General plant and other	8-43 years		723			675
Total cost			12,360			11,565
Less accumulated depreciation			(3,712	)		(3,472	)
Construction work in progress			1,472			1,038
Total property, plant and equipment, net		$	10,120		$	9,131

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Regulatory (Tables)

12 Months Ended

Dec. 31, 2020

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)	2020		2019
Regulatory assets:
Regulatory tax asset (1)	$	90	$	74
Cost-recovery clauses (2)		38		12
Environmental remediation (3)		22		20
Postretirement benefits (4)		309		295
Asset retirement obligation (5)		13		25
Other		13		11
Total regulatory assets		485		437
Less: Current portion		79		41
Long-term regulatory assets	$	406	$	396
Regulatory liabilities:
Regulatory tax liability (6)	$	691	$	699
Cost-recovery clauses (2)		23		37
Accumulated reserve—cost of removal (7)		498		506
Storm reserve (8)		48		48
Other		1		13
Total regulatory liabilities		1,261		1,303
Less: Current portion		67		93
Long-term regulatory liabilities	$	1,194	$	1,210

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in the capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets. The regulatory tax asset balance reflects the impact of the federal tax rate reduction.  

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in a subsequent period.

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

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

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

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

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

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

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

Income tax expense consists of the following components:

(millions)
For the year ended December 31,	2020			2019			2018
Current income taxes
Federal	$	35		$	56		$	72
State		(7	)		6			10
Deferred income taxes
Federal		32			7			(13	)
State		29			13			13
Investment tax credits amortization		(7	)		(5	)		(1	)
Total income tax expense	$	82		$	77		$	81

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,	2020			2019			2018
Income before provision for income taxes	$	506		$	447		$	422
Federal statutory income tax rates		21	%		21	%		21	%
Income taxes, at statutory income tax rate		106			94			89
Increase (decrease) due to
State income tax, net of federal income tax		17			15			19
Excess deferred tax amortization		(26	)		(25	)		(24	)
ITC amortization		(7	)		(5	)		(1	)
AFUDC-equity		(6	)		(2	)		(2	)
Tax credits		(8	)		(1	)		(2	)
Other		6			1			2
Total income tax expense on consolidated statements of income	$	82		$	77		$	81
Income tax expense as a percent of income before income taxes		16.2	%		17.2	%		19.2	%

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,	2020		2019
Deferred tax liabilities (1)
Property related	$	1,121	$	1,036
Pension and postretirement benefits		116		111
Total deferred tax liabilities		1,237		1,147
Deferred tax assets (1)
Loss and credit carryforwards (2)		301		243
Medical benefits		27		27
Insurance reserves		16		16
Pension and postretirement benefits		66		63
Capitalized energy conservation assistance costs		18		17
Other		26		23
Total deferred tax assets		454		389
Total deferred tax liability, net	$	783	$	758

(1) Certain property related assets and liabilities have been netted.

(2) Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $9 million.

Schedule of Unrecognized Tax Benefits

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

(millions)	2020			2019		2018
Balance at January 1,	$	9		$	8	$	8
Decreases due to tax positions related to prior year		(2	)	0		0
Increases due to tax positions related to prior year	1			1		0
Increases due to tax positions related to current year	1			0		0
Balance at December 31,	$	9		$	9	$	8

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Employee Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2020

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)	2020			2019			2020			2019
Accrued benefit costs and other current liabilities	$	(1	)	$	(1	)	$	(12	)	$	(11	)
Deferred credits and other liabilities		(15	)		(42	)		(186	)		(156	)
	$	(16	)	$	(43	)	$	(198	)	$	(167	)

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)	2020		2019		2020		2019
Net actuarial loss (gain)	$	221	$	244	$	88	$	51
Amount recognized	$	221	$	244	$	88	$	51

Benefit Obligations [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine benefit obligations at December 31:

	Pension Benefits						Other Benefits
	2020			2019			2020			2019
Discount rate		2.37	%		3.21	%		2.47	%		3.32	%
Rate of compensation increase		3.07	%		3.79	%		3.07	%		3.79	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				5.74	%		6.03	%
Ultimate rate	n/a			n/a				4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			2038			2038

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
	2020			2019				2018			2020			2019			2018
Discount rate		3.21	%		4.33	%			3.62	%		3.32	%		4.38	%		3.70	%
Expected long-term return on plan assets		7.00	%	7.35%/7.00%			(1)		6.85	%	n/a			n/a			n/a
Rate of compensation increase		3.79	%		3.75	%			3.32	%		3.79	%		3.75	%		3.31	%
Healthcare cost trend rate
Initial rate	n/a			n/a				n/a				6.03	%		6.31	%		6.58	%
Ultimate rate	n/a			n/a				n/a				4.50	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a				n/a			2038			2038			2038

TECO Energy [Member]

Schedule of Change in Plan Assets

Change in plan assets
Fair value of plan assets at beginning of year	$	796		$	659		$	0		$	0
Actual return on plan assets		142			165			0			0
Employer contributions		19			20			0			0
Employer direct benefit payments		1			6			13			10
Plan participants’ contributions		0			0			4			4
Plan settlement		0			(5	)		0			0
Benefits paid		(54	)		(48	)		0			0
Direct benefit payments		(1	)		(1	)		(17	)		(14	)
Fair value of plan assets at end of year (1)	$	903		$	796		$	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.

Schedule of Net Periodic Benefit Cost

TECO Energy	Pension Benefits													Other Benefits (1)
	2020			2019					2018					2020			2019			2018
(millions)
Service cost	$	20		$	20				$	21				$	2		$	1		$	2
Interest cost		26			31					29					6			7			7
Expected return on plan assets		(50	)		(51	)				(49	)				0			0			0
Amortization of:
Actuarial loss		20			16					19					1			1			1
Prior service (benefit) cost		0			0					0					(3	)		(2	)		(2	)
Settlement loss	0				1		(3	)		2		(2	)		0			0			0
Net periodic benefit cost	$	16		$	17				$	22				$	6		$	7		$	8

Schedule of Amounts Recognized in OCI and Regulatory Assets

Net loss (gain) arising during the year (includes curtailment gain)	$	(8	)	$	(17	)	$	62		$	38		$	9		$	(14	)
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost		0			0			0			2			2			2
Amortization or settlement of actuarial loss		(20	)		(17	)		(20	)		(1	)		(1	)		(1	)
Total recognized in OCI and regulatory assets	$	(28	)	$	(34	)	$	42		$	39		$	10		$	(13	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(12	)	$	(17	)	$	64		$	45		$	17		$	(5	)

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

(2) Represents TECO Energy’s SERP settlement charge as a result of retirements that occurred subsequent to the Merger with Emera. The charge did not impact TEC’s financial statements.

(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 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							ActualAllocation, End of Year
Asset Category	2020 Target Allocation			2019 Target Allocation			2020			2019
Equity securities	50%-70%			57%-63%				60	%		58	%
Fixed income securities	30%-50%			37%-43%				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, 2020
(millions)
	Level 1			Level 2			Level 3		Using NAV (1)		Total
Cash	$	9		$	0		$	0	$	0	$	9
Accounts receivable		10			0			0		0		10
Accounts payable		(88	)		0			0		0		(88	)
Short-term investment funds (STIFs)		35			0			0		0		35
Common stocks		66			0			0		0		66
Real estate investment trusts (REITs)		8			0			0		0		8
Mutual funds		69		0				0		0		69
Municipal bonds		0			1			0		0		1
Government bonds		0			90			0		0		90
Corporate bonds		0			79			0		0		79
Mortgage backed securities (MBS)		0			1			0		0		1
Collateralized mortgage obligations (CMOs)		0			1			0		0		1
Short Sales		0			(4	)		0		0		(4	)
Long Futures		(2	)		0			0		0		(2	)
Swaps		0			1			0		0		1
Investments not utilizing the practical expedient		107			169			0		0		276
Common and collective trusts (1)		0			0			0		553		553
Mutual fund (1)		0			0			0		74		74
Total investments	$	107		$	169		$	0	$	627	$	903

(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 Consolidated Balance Sheet of TECO Energy.

TECO Energy	At Fair Value as of December 31, 2019
(millions)
	Level 1			Level 2		Level 3		Using NAV (1)		Total
Cash	$	7		$	0	$	0	$	0	$	7
Accounts receivable		27			0		0		0		27
Accounts payable		(64	)		0		0		0		(64	)
Cash collateral		1			0		0		0		1
Short-term investment funds (STIFs)		22			0		0		0		22
Common stocks		50			0		0		0		50
Real estate investment trusts (REITs)		4			0		0		0		4
Mutual funds		153			0		0		0		153
Municipal bonds		0			1		0		0		1
Government bonds		0			51		0		0		51
Corporate bonds		0			70		0		0		70
Mortgage backed securities (MBS)		0			5		0		0		5
Collateralized mortgage obligations (CMOs)		0			2		0		0		2
Long Futures		(4	)		0		0		0		(4	)
Swaps		0			1		0		0		1
Investments not utilizing the practical expedient		196			130		0		0		326
Common and collective trusts (1)		0			0		0		412		412
Mutual fund (1)		0			0		0		58		58
Total investments	$	196		$	130	$	0	$	470	$	796

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.

• Options are valued using the bid-ask spread and the last price.

• 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, 2020.

• 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, 2020.

• 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)
2021	$	58	$	13
2022		66		13
2023		62		13
2024		64		13
2025		66		13
2026-2030		331		61

TECO Energy [Member] | Other Postretirement Benefits Florida-Based Plan [Member]

Schedule of Change in Benefit Obligation

TECO Energy	Pension Benefits						Other Benefits (2)
Obligations and Funded Status
(millions)	2020			2019			2020			2019
Change in benefit obligation
Benefit obligation at beginning of year	$	843		$	750		$	180		$	173
Service cost		20			20			2			1
Interest cost		26			31			6			7
Plan participants’ contributions		0			0			4			4
Plan curtailment		0			(10	)		0			0
Plan settlement		0			(5	)		0			0
Benefits paid		(54	)		(49	)		(17	)		(14	)
Actuarial loss		84			106			37			9
Benefit obligation at end of year	$	919		$	843		$	212		$	180

Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan

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)	2020			2019			2020			2019
Benefit obligation (PBO/APBO)	$	919		$	843		$	212		$	180
Less: Fair value of plan assets		903			796			0			0
Funded status at end of year	$	(16	)	$	(47	)	$	(212	)	$	(180	)

(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, 2020

Debt Disclosure [Abstract]

Short-Term Debt Credit Facilities

Credit Facilities

	December 31, 2020						December 31, 2019
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
5-year facility (2)	$	800	$	345	$	1	$	400	$	295	$	1
3-year accounts receivable facility (3)		150		130		0		150		53		0
1-year term facility (4)		300		300		0		0		0		0
Total	$	1,250	$	775	$	1	$	550	$	348	$	1

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures March 22, 2023.

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

(4) This 1-year term facility matures on April 29, 2021.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020:

	Purchased				Capital		Fuel and Gas		Long-term Service		Operating		Demand Side
(millions)	Power		Transportation(1)		Projects		Supply		Agreements		Leases		Management		Total
Year ended December 31:
2021	$	10	$	232	$	237	$	238	$	11	$	3	$	4	$	735
2022		0		232		76		41		13		3		3		368
2023		0		213		60		1		16		3		0		293
2024		0		207		0		0		16		3		0		226
2025		0		189		0		0		17		2		0		208
Thereafter		0		1,998		0		0		54		48		0		2,100
Total future minimum payments	$	10	$	3,071	$	373	$	280	$	127	$	62	$	7	$	3,930

(1) As of December 31, 2020, $117 million is related to a gas transportation contract through 2040 between PGS and SeaCoast, a related party.

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Revenue (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020	Electric			PGS		Eliminations			Company
Electric revenue
Residential	$	1,018		$	0	$	0		$	1,018
Commercial		506			0		0			506
Industrial		133			0		0			133
Regulatory deferrals and unbilled revenue		(25	)		0		0			(25	)
Other (1)		217			0		(4	)		213
Total electric revenue		1,849			0		(4	)		1,845
Gas revenue
Residential		0			158		0			158
Commercial		0			135		0			135
Industrial (2)		0			23		0			23
Other (3)		0			117		(6	)		111
Total gas revenue		0			433		(6	)		427
Total revenue	$	1,849		$	433	$	(10	)	$	2,272
For the year ended December 31, 2019
Electric revenue
Residential	$	1,046		$	0	$	0		$	1,046
Commercial		562			0		0			562
Industrial		156			0		0			156
Regulatory deferrals and unbilled revenue		(49	)		0		0			(49	)
Other (1)		250			0		(4	)		246
Total electric revenue		1,965			0		(4	)		1,961
Gas revenue
Residential		0			154		0			154
Commercial		0			146		0			146
Industrial (2)		0			21		0			21
Other (3)		0			140		(18	)		122
Total gas revenue		0			461		(18	)		443
Total revenue	$	1,965		$	461	$	(22	)	$	2,404
For the year ended December 31, 2018
Electric revenue
Residential	$	1,067		$	0	$	0		$	1,067
Commercial		582			0		0			582
Industrial		161			0		0			161
Regulatory deferrals and unbilled revenue		(2	)		0		0			(2	)
Other (1)		258			0		(3	)		255
Total electric revenue		2,066			0		(3	)		2,063
Gas revenue
Residential		0			157		0			157
Commercial		0			151		0			151
Industrial (2)		0			21		0			21
Other (3)		0			159		(27	)		132
Total gas revenue		0			488		(27	)		461
Total revenue	$	2,066		$	488	$	(30	)	$	2,524

(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, 2020

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2020		2019			2018
Natural gas sales to/(from) affiliates	$	(139)	$	(111	)	$	(38	)
Services received from affiliates		6		65			65
Dividends to TECO Energy		408		373			362
Equity contributions from TECO Energy		505		395			345

Amounts due from or to affiliates at December 31,

(millions)	2020		2019
Accounts receivable related to asset management agreements to Emera Energy Services Inc. (1)	$	4	$	4
Accounts receivable excluding asset management agreements (1)		7		10
Accounts payable (1)		27		16
Taxes payable (2)		19		4

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

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

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of Segment Information

	Tampa
(millions)	Electric		PGS		Eliminations				TEC
2020
Revenues - external	$	1,845	$	427	$	0			$	2,272
Sales to affiliates		4		6		(10	)			0
Total revenues		1,849		433		(10	)			2,272
Depreciation and amortization		339		45		0				384
Total interest charges		113		17		0				130
Provision for income taxes		66		16		0				82
Net income		372		52		0				424
Total assets		9,800		1,901		(653	)	(1)		11,048
Capital expenditures		1,028		333		0				1,361
2019
Revenues - external	$	1,961	$	443	$	0			$	2,404
Sales to affiliates		4		18		(22	)			0
Total revenues		1,965		461		(22	)			2,404
Depreciation and amortization		336		41		0				377
Total interest charges		117		17		0				134
Provision for income taxes		59		18		0				77
Net income		316		54		0				370
Total assets		9,007		1,593		(593	)	(1)		10,007
Capital expenditures		1,055		228		0				1,283
2018
Revenues - external	$	2,063	$	461	$	0			$	2,524
Sales to affiliates		3		27		(30	)			0
Total revenues		2,066		488		(30	)			2,524
Depreciation and amortization		312		60		0				372
Total interest charges		102		16		0				118
Provision for income taxes		65		16		0				81
Net income		294		47		0				341
Total assets		8,235		1,407		(487	)	(1)		9,155
Capital expenditures		940		169		0				1,109

(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, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

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

	December 31,
(millions)	2020			2019
Beginning balance	$	49		$	64
Additional liabilities		8			0
Liabilities settled (1)		(19	)		(18	)
Other (2)		1			3
Ending balance	$	39		$	49

(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The decreases in the ARO in 2020 and 2019 are due to the closure of CCR management facilities.

(2) Includes accretion recorded as a deferred regulatory asset.  

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Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Summary of Lease Assets and Liabilities

(millions)	Classification	December 31, 2020		December 31, 2019
Right-of-use asset	Other deferred debits	$	26	$	28
Lease liabilities
Current	Other current liabilities	$	2	$	2
Long-term	Deferred credits and other liabilities		25		27
Total lease liabilities		$	27	$	29

Future Minimum Lease Payments

Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter consisted of the following at December 31, 2020: 

(millions)
Year ended December 31:	2021		2022		2023		2024		2025		Thereafter		Total
Minimum lease payments	$	3	$	3	$	3	$	3	$	2	$	48	$	62
Less imputed interest														(35	)
Total future minimum payments													$	27

Additional Information Related to Leases

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

Year ended December 31,	2020			2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)	$	5		$	3
Right-of-use assets obtained in exchange for lease obligations:
Operating leases (millions)	$	0		$	11
Weighted average remaining lease term (years)		43			43
Weighted average discount rate - operating leases		4.3	%		4.3	%

Net Investment in Direct Finance Leases

The net investment in direct finance leases consists of the following:

(millions)	December 31, 2020			December 31, 2019
Total minimum lease payments to be received	$	31		$	33
Less amounts representing estimated executory costs		(12	)		(13	)
Minimum lease payments receivable	$	19		$	20
Less unearned finance lease income		(10	)		(11	)
Net investment in direct finance and sales-type leases	$	9		$	9
Principal due within one year (included in "Receivables")		(2	)		(2	)
Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits")	$	7		$	7

Future Minimum Direct Finance Lease Payments to be Received

As of December 31, 2020, future minimum direct finance lease payments to be received for each of the next five years and in aggregate thereafter consisted of the following:

(millions)
Year ended December 31:	2021		2022		2023		2024		2025		Thereafter		Total
Minimum lease payments to be received	$	2	$	2	$	2	$	2	$	2	$	21	$	31
Less executory costs														(12	)
Total minimum lease payments receivable													$	19

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2020

Disclosure Of Compensation Related Costs Sharebased Payments [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, 2019		504		$	45.45	$	28
Granted including DRIP		78			52.68		4
Exercised		(162	)		45.41		9
Forfeited		(27	)		46.08		0
Transferred		(3	)		44.85		0
Outstanding as of December 31, 2020		390			46.87		21

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Significant Accounting Policies - Additional Information (Detail) $ in Millions		12 Months Ended
	Jul. 31, 2019	Dec. 31, 2020 USD ($) Segment	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Jun. 09, 2020 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of operating segments | Segment		2
Percentage of original cost of depreciable property		3.20%	3.40%	3.50%
Depreciation expense		$ 381	$ 359	$ 345
Allowance for funds used during construction rate	5.97%	6.46%	6.46%	6.46%
Allowance for funds used during construction		$ 44	$ 16	$ 15
Receivables from contracts with customers		214	205
Unbilled revenues		73	61
Franchise fees and gross receipts taxes		$ 109	$ 117	$ 120
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities		2.43%	2.66%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities		4.00%	4.00%
Intangible Software Assets [Member]
Summary Of Significant Accounting Policies [Line Items]
Accumulated amortization reserve surplus					$ 16

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Significant Accounting Policies - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property Plant And Equipment [Line Items]
Total cost	$ 12,360	$ 11,565
Less accumulated depreciation	(3,712)	(3,472)
Construction work in progress	1,472	1,038
Total property, plant and equipment, net	10,120	9,131
Electric Generation [Member]
Property Plant And Equipment [Line Items]
Total cost	5,694	5,370
Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	2,076	1,848
General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 723	675
Minimum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	21 years
Minimum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	16 years
Minimum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	8 years
Maximum [Member] | Electric Generation [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	56 years
Maximum [Member] | Gas Transmission and Distribution [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	77 years
Maximum [Member] | General Plant and Other [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	43 years
Electric Transmission [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 1,008	940
Electric Transmission [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	28 years
Electric Transmission [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	77 years
Electric Distribution [Member]
Property Plant And Equipment [Line Items]
Total cost	$ 2,859	$ 2,732
Electric Distribution [Member] | Minimum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	14 years
Electric Distribution [Member] | Maximum [Member]
Property Plant And Equipment [Line Items]
Estimated useful lives	56 years

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Regulatory - Additional Information (Detail)													1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 19, 2020 USD ($)	Aug. 18, 2020 USD ($)	Aug. 03, 2020 USD ($)	Apr. 27, 2020 USD ($)	Jun. 28, 2019 USD ($) MW	Apr. 09, 2019 USD ($)	Aug. 20, 2018 USD ($)	Jun. 29, 2018 USD ($) MW	Dec. 28, 2017 USD ($)	Dec. 12, 2017 USD ($) MW	Feb. 07, 2017	Sep. 06, 2013	May 31, 2009	Sep. 30, 2017 USD ($)	Dec. 31, 2020 USD ($) $ / kWac	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jan. 31, 2022 USD ($)	Feb. 01, 2021 USD ($)	Jun. 09, 2020 USD ($)	Jun. 01, 2020 USD ($)	Oct. 31, 2013 USD ($)
Public Utilities General Disclosures [Line Items]
Percentage of ROE															10.25%
Return on equity range															range of plus or minus 1%
Percentage change in ROE Percentage															1.00%
Allowed equity in the capital structure												54.00%
Federal statutory tax rate															4.50%	5.50%
Decrease in deferred income taxes offset to regulatory liability															$ 5,000,000
Utility plant, at original costs															13,818,000,000	$ 12,590,000,000
Accumulated depreciation															3,712,000,000	3,472,000,000
Storm restoration costs									$ 10,000,000
Regulatory assets															485,000,000	437,000,000
O&M expense															542,000,000	543,000,000	$ 632,000,000
Regulatory liability															1,261,000,000	1,303,000,000
Provision for income taxes															82,000,000	77,000,000	81,000,000
Amount refundable on settlement						$ 12,000,000
Reduction in regulatory asset for amortization															18,000,000	(1,000,000)	(98,000,000)
Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE											10.75%
Allowed equity in the capital structure	54.70%												54.70%
Accumulated depreciation	$ 34,000,000
Reduction in annual base rates																12,000,000
Reduction in regulatory asset for amortization																	(11,000,000)
Reduction in annual depreciation rates																10,000,000
Increase in annual base rate	58,000,000
Increase in revenue	$ 34,000,000
Impact of tax reform through reduction in base revenue days	120 days
PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Regulatory assets																		$ 32,000,000
Date new bottom of return on equity range will remain in effect																			Dec. 31, 2020
Amortization expenses																		$ 5,000,000	$ 16,000,000
Regulatory asset amortization beginning period																		2016
Regulatory asset amortization ending period																		2020
Hurricane Dorian [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration preparation costs																8,000,000
Storm Reserve [Member]
Public Utilities General Disclosures [Line Items]
Regulatory liability															48,000,000	48,000,000
Hurricane Irma [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs														$ 102,000,000
Hurricane Irma [Member] | Storm Reserve [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs														90,000,000
Hurricane Irma [Member] | O&M Expenses [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs														3,000,000
Hurricane Irma [Member] | Capital Expenditures [Member]
Public Utilities General Disclosures [Line Items]
Storm restoration costs														$ 9,000,000
Intangible Software Assets [Member]
Public Utilities General Disclosures [Line Items]
Accumulated amortization reserve surplus																						$ 16,000,000
Electric Utility Plant [Member]
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs															$ 11,486,000,000	10,578,000,000
Cast Iron and Bare Steel Replacement Rider [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Increase in revenue	$ 24,000,000
Scenario Forecast [Member]
Public Utilities General Disclosures [Line Items]
Revenue requirements																				$ 295,000,000
Subsequent Event [Member]
Public Utilities General Disclosures [Line Items]
Revenue requirements																					$ 280,000,000
Base rate adjustment amount																					$ 130,000,000
Minimum [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE	8.90%
Base rate agreement frozen period	Jan. 01, 2021
Minimum [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Decrease bottom return on equity											11.75%
Amortization expenses																			$ 21,000,000
Amortization period of Regulatory Asset																		2 years
Maximum [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE	11.00%
Base rate agreement frozen period	Dec. 31, 2023
Maximum [Member] | PGS and OPC [Member]
Public Utilities General Disclosures [Line Items]
Decrease bottom return on equity											9.25%
Mid Point [Member] | Peoples Gas System [Member]
Public Utilities General Disclosures [Line Items]
Percentage of ROE	9.90%
Condition One [Member]
Public Utilities General Disclosures [Line Items]
ROE lower range limit															9.25%
Condition Two [Member]
Public Utilities General Disclosures [Line Items]
ROE lower range limit															11.25%
Tax Reform and Storm Settlement Two [Member]
Public Utilities General Disclosures [Line Items]
O&M expense																	47,000,000
Reduction in regulatory asset																	47,000,000
Tax Reform and Storm Settlement Three [Member]
Public Utilities General Disclosures [Line Items]
O&M expense																	56,000,000
Regulatory liability																	$ 56,000,000
Tax Reform and Storm Settlement [Member]
Public Utilities General Disclosures [Line Items]
Annually approved lowering base rates, Amount							$ 103,000,000
Provision for income taxes															$ 103,000,000
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 | $ / kWac															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] | Solar Base Rate Adjustments [Member]
Public Utilities General Disclosures [Line Items]
True-up amount returned to customers		$ 5,000,000
Solar Project Cost Recovery [Member] | Minimum [Member]
Public Utilities General Disclosures [Line Items]
Solar project investment term															2017
Solar Project Cost Recovery [Member] | Maximum [Member]
Public Utilities General Disclosures [Line Items]
Solar project investment term															2021
Solar Project Cost Recovery [Member] | Invested Through December 31, 2019 [Member]
Public Utilities General Disclosures [Line Items]
Solar generation capacity investments																$ 820,000,000
Solar Project Cost Recovery [Member] | Effective January 1, 2021 [Member]
Public Utilities General Disclosures [Line Items]
Solar energy capacity | MW										46
Estimated annual revenue requirements										$ 8,000,000
Solar Project Cost Recovery [Member] | Effective September 1, 2018 [Member]
Public Utilities General Disclosures [Line Items]
Solar energy capacity | MW										145
Estimated annual revenue requirements										$ 24,000,000
Solar Project Cost Recovery [Member] | Effective January 1, 2019 [Member]
Public Utilities General Disclosures [Line Items]
Solar energy capacity | MW								260
Estimated annual revenue requirements								$ 46,000,000
Solar Project Cost Recovery [Member] | Effective January 1, 2020 [Member]
Public Utilities General Disclosures [Line Items]
Solar energy capacity | MW					149
Estimated annual revenue requirements					$ 26,000,000
Big Bend Modernization Project [Member]
Public Utilities General Disclosures [Line Items]
Energy generation capacity investments															$ 850,000,000
Investments in energy projects till date															526,000,000
Accumulated depreciation															88,000,000								$ 90,000,000
Big Bend Modernization Project [Member] | Electric Utility Plant [Member]
Public Utilities General Disclosures [Line Items]
Utility plant, at original costs															$ 200,000,000								$ 223,000,000
Big Bend Modernization Project [Member] | Minimum [Member]
Public Utilities General Disclosures [Line Items]
Energy project investment term															2018
Big Bend Modernization Project [Member] | Maximum [Member]
Public Utilities General Disclosures [Line Items]
Energy project investment term															2023
Storm Protection Plan [Member]
Public Utilities General Disclosures [Line Items]
Reduction in annual base rates				$ 15,000,000
Cost recovery from settlement agreement			$ 39,000,000
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
Storm Reserve [Member]
Public Utilities General Disclosures [Line Items]
Regulatory assets									$ 56,000,000

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Regulatory assets:
Regulatory assets	$ 485	$ 437
Less: Current portion	79	41
Long-term regulatory assets	406	396
Regulatory liabilities:
Regulatory liabilities	1,261	1,303
Less: Current portion	67	93
Long-term regulatory liabilities	1,194	1,210
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	90	74
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	38	12
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	22	20
Postretirement Benefits [Member]
Regulatory assets:
Regulatory assets	309	295
Asset Retirement Obligation [Member]
Regulatory assets:
Regulatory assets	13	25
Other [Member]
Regulatory assets:
Regulatory assets	13	11
Regulatory Tax Liability [Member] | Non-Current Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	691	699
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	23	37
Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	48	48
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	498	506
Other [Member]
Regulatory liabilities:
Regulatory liabilities	$ 1	$ 13

XML

Income Taxes - Additional Information (Detail) - USD ($)		3 Months Ended	12 Months Ended
	Sep. 12, 2019	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Federal statutory tax rate			21.00%	21.00%	21.00%
Federal statutory tax rate			4.50%	5.50%
Provision for income taxes			$ 82,000,000	$ 77,000,000	$ 81,000,000
Deferred tax assets expiration date			2032 and 2037
General business credit		$ 242,000,000	$ 242,000,000
Deferred tax general business credits expiration date			2027 and 2040
Investment tax credits		222,000,000	$ 222,000,000
Investment tax credit expiration date			2034 and 2040
Uncertain tax positions		9,000,000	$ 9,000,000	9,000,000	8,000,000	$ 8,000,000
Unrecognized tax benefits decreased			2,000,000
Pre-tax charges (benefits)			0	0	0
Interest accrued		0	0	0	0
Penalties			$ 0	0	$ 0
Statutes of limitations			3 years
Income tax examination period			1 year
Federal [Member]
Income Taxes [Line Items]
Federal and Florida net operating losses (NOL's) carryforward		340,000,000	$ 340,000,000
Federal [Member] | R&D Tax Credits [Member]
Income Taxes [Line Items]
Uncertain tax positions		9,000,000	$ 9,000,000	$ 9,000,000
Unrecognized tax benefits decreased		2,000,000
Florida [Member]
Income Taxes [Line Items]
Federal statutory tax rate	5.50%		4.46%
Federal and Florida net operating losses (NOL's) carryforward		$ 88,000,000	$ 88,000,000

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Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Current income taxes, Federal	$ 35	$ 56	$ 72
Current income taxes, State	(7)	6	10
Deferred income taxes, Federal	32	7	(13)
Deferred income taxes, State	29	13	13
Investment tax credits amortization	(7)	(5)	(1)
Total income tax expense	$ 82	$ 77	$ 81

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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, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income before provision for income taxes	$ 506	$ 447	$ 422
Federal statutory income tax rates	21.00%	21.00%	21.00%
Income taxes, at statutory income tax rate	$ 106	$ 94	$ 89
State income tax, net of federal income tax	17	15	19
Excess deferred tax amortization	(26)	(25)	(24)
ITC amortization	(7)	(5)	(1)
AFUDC-equity	(6)	(2)	(2)
Tax credits	(8)	(1)	(2)
Other	6	1	2
Total income tax expense	$ 82	$ 77	$ 81
Income tax expense as a percent of income before income taxes	16.20%	17.20%	19.20%

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred tax liabilities
Property related	$ 1,121	$ 1,036
Pension and postretirement benefits	116	111
Total deferred tax liabilities	1,237	1,147
Deferred tax assets
Loss and credit carryforwards	301	243
Medical benefits	27	27
Insurance reserves	16	16
Pension and postretirement benefits	66	63
Capitalized energy conservation assistance costs	18	17
Other	26	23
Total deferred tax assets	454	389
Total deferred tax liability, net	$ 783	$ 758

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Unrecognized tax benefits	$ 9	$ 9	$ 8	$ 8

XML

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Beginning Balance	$ 9	$ 8	$ 8
Decreases due to tax positions related to prior year	(2)	0	0
Increases due to tax positions related to prior year	1	1	0
Increases due to tax positions related to current year	1	0	0
Ending Balance	$ 9	$ 9	$ 8

XML

Employee Postretirement Benefits - Additional Information (Detail) - USD ($)			12 Months Ended
		Jan. 02, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	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			109.67%	111.66%
Employer contributions			$ 16,000,000	$ 15,000,000
Employer contributions in next fiscal year			$ 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			$ 21,000,000	11,000,000	$ 11,000,000
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			$ 10,000,000	10,000,000
Unfunded [Member]
Defined Benefit Plan Disclosure [Line Items]
Commitments			0
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			12,000,000	12,000,000	16,000,000
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			7,000,000	7,000,000	8,000,000
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected settlement charge				1,000,000
Employer contributions			0	0	0
Benefits paid			1,000,000	5,000,000
Expected payment in next twelve months			1,000,000
Restoration Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected settlement charge				1,000,000
Non Elective Employer Contribution [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan cost recognized			9,000,000	1,000,000
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation of defined benefit pension plans			$ 876,000,000	801,000,000
Percentage of defined benefit plan's actual earned returns			19.00%
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			$ 16,000,000	17,000,000	22,000,000
Settlement charge			0	(1,000,000)	(2,000,000)
Commitments			919,000,000	843,000,000	750,000,000
Employer contributions			19,000,000	20,000,000
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost			6,000,000	7,000,000	8,000,000
Settlement charge			0	0	0
Commitments	[1]		212,000,000	180,000,000	173,000,000
Employer contributions	[1]		0	$ 0
Employer contributions in next fiscal year			12,000,000
TECO Energy [Member] | SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Settlement charge					$ 1,000,000
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
International Brotherhood of Electrical Workers [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees represented				24.00%

[1] 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, 2020		Dec. 31, 2019		Dec. 31, 2018
Pension Benefits [Member]
Change in benefit obligation
Benefit obligation at beginning of year		$ 843		$ 750
Service cost		20		20		$ 21
Interest cost		26		31		29
Plan participants’ contributions		0		0
Plan curtailment		0		(10)
Plan settlement		0		(5)
Benefits paid		(54)		(49)
Actuarial loss		84		106
Benefit obligation at end of year		919		843		750
Other Postretirement Benefits [Member]
Change in benefit obligation
Benefit obligation at beginning of year	[1]	180		173
Service cost		2	[1]	1	[1]	2
Interest cost		6	[1]	7	[1]	7
Plan participants’ contributions	[1]	4		4
Plan curtailment	[1]	0		0
Plan settlement	[1]	0		0
Benefits paid	[1]	(17)		(14)
Actuarial loss	[1]	37		9
Benefit obligation at end of year	[1]	$ 212		$ 180		$ 173

[1] Represent 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, 2020		Dec. 31, 2019
Change in plan assets
Employer contributions		$ 16		$ 15
TECO Energy [Member]
Change in plan assets
Fair value of plan assets at beginning of year		796
Fair value of plan assets at end of year		903		796
TECO Energy [Member] | Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year		796	[1]	659
Actual return on plan assets		142		165
Employer contributions		19		20
Employer direct benefit payments		1		6
Plan participants’ contributions		0		0
Plan settlement		0		(5)
Benefits paid		(54)		(48)
Direct benefit payments		(1)		(1)
Fair value of plan assets at end of year	[1]	903		796
TECO Energy [Member] | Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	[2]	0	[1]	0
Actual return on plan assets	[2]	0		0
Employer contributions	[2]	0		0
Employer direct benefit payments	[2]	13		10
Plan participants’ contributions	[2]	4		4
Plan settlement	[2]	0		0
Benefits paid	[2]	0		0
Direct benefit payments	[2]	(17)		(14)
Fair value of plan assets at end of year	[1],[2]	$ 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.

XML

Employee Postretirement Benefits - Schedule of Change in Plan Assets (Parenthetical) (Detail) - TECO Energy [Member]	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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	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	5 years

XML

Employee Postretirement Benefits - Schedule of Funded Status (Detail) - TECO Energy [Member] - USD ($) $ in Millions		Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 903		$ 796
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)		919		843		$ 750
Fair value of plan assets		903	[1]	796	[1]	659
Funded status at end of year		(16)		(47)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	[2]	212		180		173
Fair value of plan assets	[2]	0	[1]	0	[1]	$ 0
Funded status at end of year	[2]	$ (212)
Other Postretirement Benefits [Member] | Florida [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation (PBO/APBO)	[2]			180
Fair value of plan assets	[2]			0
Funded status at end of year	[2]			$ (180)

[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.

XML

Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	$ (1)	$ (1)
Deferred credits and other liabilities	(15)	(42)
Net amount recognized at end of year	(16)	(43)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit costs and other current liabilities	(12)	(11)
Deferred credits and other liabilities	(186)	(156)
Net amount recognized at end of year	$ (198)	$ (167)

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, 2020	Dec. 31, 2019
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 221	$ 244
Amount recognized	221	244
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	88	51
Amount recognized	$ 88	$ 51

XML

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)			1 Months Ended		12 Months Ended
	Jan. 01, 2019	[1]	Oct. 31, 2019	[1]	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate					2.37%	3.21%
Rate of compensation increase					3.07%	3.79%
Discount rate					3.21%	4.33%	3.62%
Expected long-term return on plan assets	7.35%		7.00%		7.00%		6.85%
Rate of compensation increase					3.79%	3.75%	3.32%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate					2.47%	3.32%
Rate of compensation increase					3.07%	3.79%
Discount rate					3.32%	4.38%	3.70%
Rate of compensation increase					3.79%	3.75%	3.31%
Healthcare cost trend rate
Ultimate rate					4.50%	4.50%	4.50%
Year rate reaches ultimate					2038	2038	2038
Other Postretirement Benefits [Member] | Immediate Rate [Member]
Healthcare cost trend rate
Immediate rate					5.74%	6.03%
Other Postretirement Benefits [Member] | Initial Rate [Member]
Healthcare cost trend rate
Immediate rate					6.03%	6.31%	6.58%

[1] The expected return on assets was 7.35% as of January 1, 2019 and 7.00% as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment.

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, 2020		Dec. 31, 2019		Dec. 31, 2018
Pension Benefits [Member]
Amortization of:
Net periodic benefit cost	$ 12		$ 12		$ 16
Other Postretirement Benefits [Member]
Amortization of:
Net periodic benefit cost	7		7		8
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	20		20		21
Interest cost	26		31		29
Expected return on plan assets	(50)		(51)		(49)
Amortization of:
Actuarial loss	20		16		19
Prior service (benefit) cost	0		0		0
Settlement loss	0		1		2
Net periodic benefit cost	16		17		22
Net loss (gain) arising during the year (includes curtailment gain)	(8)		(17)		62
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	0		0		0
Amortization or settlement of actuarial loss	(20)		(17)		(20)
Total recognized in OCI and regulatory assets	(28)		(34)		42
Total recognized in net periodic benefit cost, OCI and regulatory assets	(12)		(17)		64
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	[1]	1	[1]	2
Interest cost	6	[1]	7	[1]	7
Expected return on plan assets	0		0		0
Amortization of:
Actuarial loss	1		1		1
Prior service (benefit) cost	(3)		(2)		(2)
Settlement loss	0		0		0
Net periodic benefit cost	6		7		8
Net loss (gain) arising during the year (includes curtailment gain)	38		9		(14)
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service (benefit) cost	2		2		2
Amortization or settlement of actuarial loss	(1)		(1)		(1)
Total recognized in OCI and regulatory assets	39		10		(13)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$ 45		$ 17		$ (5)

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

XML

Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Parenthetical) (Detail)			1 Months Ended		12 Months Ended
	Jan. 01, 2019		Oct. 31, 2019		Dec. 31, 2020	Dec. 31, 2018
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	7.35%	[1]	7.00%	[1]	7.00%	6.85%

[1] The expected return on assets was 7.35% as of January 1, 2019 and 7.00% as of October 31, 2019 when a plan remeasurement occurred as a result of a plan curtailment.

XML

Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) - TECO Energy [Member]	Dec. 31, 2020	Dec. 31, 2019
Actual Asset Allocation [Member]
Asset Category
Actual Allocation, End of Year	100.00%	100.00%
Actual Asset Allocation [Member] | Equity Securities [Member]
Asset Category
Actual Allocation, End of Year	60.00%	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] | Equity Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	50.00%	57.00%
Target Allocation [Member] | Equity Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	70.00%	63.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Minimum [Member]
Asset Category
Target Allocation	30.00%	37.00%
Target Allocation [Member] | Fixed Income Securities [Member] | Maximum [Member]
Asset Category
Target Allocation	50.00%	43.00%

XML

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) - TECO Energy [Member] - USD ($) $ in Millions	Dec. 31, 2020		Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 903		$ 796
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9		7
Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			1
Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35		22
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	66		50
Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(2)		(4)
Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8		4
Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(4)
Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	69		153
Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1		1
Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90		51
Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	79		70
Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	276		326
Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1		2
Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	553	[1]	412	[2]
Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	74	[1]	58	[2]
Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1		5
Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1		1
NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	627		470
NAV [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			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		0
NAV [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	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] | 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		0
NAV [Member] | Common and Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	553	[1]	412	[2]
NAV [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	74	[1]	58	[2]
NAV [Member] | Mortgage Backed Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
NAV [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	107		196
Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9		7
Level 1 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			1
Level 1 [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35		22
Level 1 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	66		50
Level 1 [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(2)		(4)
Level 1 [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8		4
Level 1 [Member] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 1 [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	69		153
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] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	107		196
Level 1 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		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		0
Level 1 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	169		130
Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Level 2 [Member] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			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		0
Level 2 [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		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] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(4)
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	1		1
Level 2 [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90		51
Level 2 [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	79		70
Level 2 [Member] | Investments Not Utilizing The Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	169		130
Level 2 [Member] | Collateralized Mortgage Obligations (CMOs) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1		2
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	1		5
Level 2 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1		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] | Cash Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			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		0
Level 3 [Member] | Long Futures [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		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] | Short Sales [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	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] | 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		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		0
Level 3 [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0		0
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10		27
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	10		27
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	(88)		(64)
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	(88)		(64)
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 Consolidated Balance Sheet of TECO Energy.

[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 Consolidated Balance Sheet of TECO Energy. 

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Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) - TECO Energy [Member] $ in Millions	Dec. 31, 2020 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2021	$ 58
Expected Benefit Payments - 2022	66
Expected Benefit Payments - 2023	62
Expected Benefit Payments - 2024	64
Expected Benefit Payments - 2025	66
Expected Benefit Payments - 2026-2030	331
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2021	13
Expected Benefit Payments - 2022	13
Expected Benefit Payments - 2023	13
Expected Benefit Payments - 2024	13
Expected Benefit Payments - 2025	13
Expected Benefit Payments - 2026-2030	$ 61

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Short-Term Debt - Credit Facilities (Detail) - USD ($)	Dec. 31, 2020	Dec. 18, 2020	Dec. 31, 2019	Dec. 19, 2019	Mar. 23, 2018
Line Of Credit Facility [Line Items]
Credit Facilities	$ 1,250,000,000	$ 80,000,000	$ 550,000,000	$ 400,000,000
Borrowings Outstanding	775,000,000		348,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	800,000,000		400,000,000
Borrowings Outstanding	345,000,000		295,000,000
Letters of Credit Outstanding	1,000,000		1,000,000
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	150,000,000		150,000,000		$ 150,000,000
Borrowings Outstanding	130,000,000		53,000,000
Letters of Credit Outstanding	0		0
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facilities	300,000,000		0
Borrowings Outstanding	300,000,000		0
Letters of Credit Outstanding	$ 0		$ 0

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Short-Term Debt - Credit Facilities (Parenthetical) (Detail)		12 Months Ended
	Mar. 23, 2018	Dec. 31, 2020	Dec. 31, 2019
5-year Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Mar. 22, 2023	Mar. 22, 2023
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date	Mar. 22, 2021	Mar. 22, 2021	Mar. 22, 2021
1-year Term Facility [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity date		Apr. 29, 2021	Apr. 29, 2021

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Short-Term Debt - Additional Information (Detail) - USD ($)							12 Months Ended
	Jan. 29, 2021	Dec. 18, 2020	Feb. 06, 2020	Dec. 19, 2019	Mar. 23, 2018	Mar. 22, 2017	Dec. 31, 2020	Dec. 31, 2019
Line Of Credit Facility [Line Items]
Weighted-average interest rate							0.89%	2.56%
Line of credit facility maximum borrowing capacity		$ 80,000,000		$ 400,000,000			$ 1,250,000,000	$ 550,000,000
Line of credit facility, increase amount				$ 75,000,000
Lenders commitment amount		800,000,000
Increase of credit facility		$ 100,000,000
Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity						$ 325,000,000
364-day Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Credit facility maturity period			364 days
Line of credit facility maximum borrowing capacity			$ 300,000,000
Credit facility maturity date			Feb. 04, 2021
364-day Credit Agreement [Member] | Subsequent Event [Member]
Line Of Credit Facility [Line Items]
Credit Facility extended maturity date	Apr. 29, 2021
3-year Accounts Receivable Facility [Member]
Line Of Credit Facility [Line Items]
Line of credit facility maximum borrowing capacity					$ 150,000,000		$ 150,000,000	$ 150,000,000
Credit facility maturity date					Mar. 22, 2021		Mar. 22, 2021	Mar. 22, 2021
Credit facility amendment date					Mar. 23, 2018
Loan agreement program and liquidity fees							0.70%
Interest rate description							TEC will pay program and liquidity fees, which total 70 basis points at December 31, 2020. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, the federal funds rate, or the London interbank deposit rate, plus a margin
Minimum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage							0.125%
Minimum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		Mar. 22, 2022				Dec. 17, 2018
Maximum [Member]
Line Of Credit Facility [Line Items]
Commitment fees, percentage							0.35%
Maximum [Member] | Amended And Restated Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt instrument maturity date		Mar. 22, 2023				Mar. 22, 2022

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Millions	Jul. 24, 2019	Oct. 04, 2018	Jun. 07, 2018
3.625% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year	2050
3.625% Notes [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 300
Stated interest rate	3.625%
Debt instrument maturity date	Jun. 15, 2050
Redeemable principal amount percentage	100.00%
Basis spread on federal funds rate	0.20%
Redeemable principal amount percentage	100.00%
Debt instrument, start date of redemption	Dec. 15, 2049
Debt instrument, offering date	Jul. 24, 2019
4.45% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year		2049
4.45% Notes [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		$ 375
Stated interest rate		4.45%
Debt instrument maturity date		Jun. 15, 2049
Redeemable principal amount percentage		100.00%
Basis spread on federal funds rate		0.20%
Redeemable principal amount percentage		100.00%
Debt instrument, start date of redemption		Dec. 15, 2048
Debt instrument, offering date		Oct. 04, 2018
4.3% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, maturity year			2048
4.3% Notes [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued			$ 350
Stated interest rate			4.30%
Debt instrument maturity date			Jun. 15, 2048
Redeemable principal amount percentage			100.00%
Basis spread on federal funds rate			0.20%
Redeemable principal amount percentage			100.00%
Debt instrument, start date of redemption			Dec. 15, 2047
Debt instrument, offering date			Jun. 07, 2018

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Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
PGS [Member]
Long Term Commitments [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 17	$ 21

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Commitments and Contingencies - Schedule of Long-term Commitments (Detail) $ in Millions	Dec. 31, 2020 USD ($)
Other Commitments [Line Items]
2021	$ 735
2022	368
2023	293
2024	226
2025	208
Thereafter	2,100
Total future minimum payments	3,930
Purchased Power [Member]
Other Commitments [Line Items]
2021	10
2022	0
2023	0
2024	0
2025	0
Thereafter	0
Total future minimum payments	10
Transportation [Member]
Other Commitments [Line Items]
2021	232
2022	232
2023	213
2024	207
2025	189
Thereafter	1,998
Total future minimum payments	3,071
Capital Projects [Member]
Other Commitments [Line Items]
2021	237
2022	76
2023	60
2024	0
2025	0
Thereafter	0
Total future minimum payments	373
Fuel and Gas Supply [Member]
Other Commitments [Line Items]
2021	238
2022	41
2023	1
2024	0
2025	0
Thereafter	0
Total future minimum payments	280
Long-term Service Agreements [Member]
Other Commitments [Line Items]
2021	11
2022	13
2023	16
2024	16
2025	17
Thereafter	54
Total future minimum payments	127
Operating Leases [Member]
Other Commitments [Line Items]
2021	3
2022	3
2023	3
2024	3
2025	2
Thereafter	48
Total future minimum payments	62
Demand Side Management [Member]
Other Commitments [Line Items]
2021	4
2022	3
2023	0
2024	0
2025	0
Thereafter	0
Total future minimum payments	$ 7

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Commitments and Contingencies - Schedule of Long-term Commitments (Parenthetical) (Detail) $ in Millions	Dec. 31, 2020 USD ($)
Other Commitments [Line Items]
Total future minimum payments	$ 3,930
Gas Transportation [Member] | PGS and SeaCoast [Member]
Other Commitments [Line Items]
Total future minimum payments	$ 117

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Revenue - Summary of Disaggregates TEC Revenue by Major Source (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation Of Revenue [Line Items]
Total electric revenue	$ 1,845	$ 1,961	$ 2,063
Total gas revenue	427	443	461
Total revenue	2,272	2,404	2,524
Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	1,018	1,046	1,067
Total gas revenue	158	154	157
Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	506	562	582
Total gas revenue	135	146	151
Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	133	156	161
Total gas revenue	23	21	21
Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(25)	(49)	(2)
Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	213	246	255
Total gas revenue	111	122	132
Tampa Electric [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	1,849	1,965	2,066
Total gas revenue	0	0	0
Total revenue	1,849	1,965	2,066
Tampa Electric [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	1,018	1,046	1,067
Total gas revenue	0	0	0
Tampa Electric [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	506	562	582
Total gas revenue	0	0	0
Tampa Electric [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	133	156	161
Total gas revenue	0	0	0
Tampa Electric [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(25)	(49)	(2)
Tampa Electric [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	217	250	258
Total gas revenue	0	0	0
PGS [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	433	461	488
Total revenue	433	461	488
PGS [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	158	154	157
PGS [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	135	146	151
PGS [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	23	21	21
PGS [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
PGS [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	117	140	159
Eliminations [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(4)	(4)	(3)
Total gas revenue	(6)	(18)	(27)
Total revenue	(10)	(22)	(30)
Eliminations [Member] | Residential [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	0	0	0
Eliminations [Member] | Commercial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	0	0	0
Eliminations [Member] | Industrial [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Total gas revenue	0	0	0
Eliminations [Member] | Regulatory Deferrals and Unbilled Revenue [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	0	0	0
Eliminations [Member] | Other [Member]
Disaggregation Of Revenue [Line Items]
Total electric revenue	(4)	(4)	(3)
Total gas revenue	$ (6)	$ (18)	$ (27)

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Revenue - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Regulated Operating Revenue [Abstract]
Remaining performance obligations, transaction price	$ 135	$ 140
Remaining performance obligations, expected year of revenue recognition	2033

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Related Party Transactions - Schedule of Related Parties (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Natural gas sales to/(from) affiliates	$ (139)	$ (111)	$ (38)
Services received from affiliates	6	65	65
Affiliate [Member]
Related Party Transaction [Line Items]
Accounts receivable excluding asset management agreements	7	10
Accounts payable	27	16
Taxes payable	19	4
Emera Energy Services Inc [Member]
Related Party Transaction [Line Items]
Accounts receivable related to asset management agreements to Emera Energy Services Inc.	4	4
TECO Energy [Member]
Related Party Transaction [Line Items]
Dividends to TECO Energy	408	373	362
Equity contributions from TECO Energy	$ 505	$ 395	$ 345

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2020 Segment Customer
Segment Reporting Information [Line Items]
Number of operating segments | Segment	2
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	792,500
PGS [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	426,000

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Segment Information - Schedule of Segment Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Total revenues	$ 2,272	$ 2,404	$ 2,524
Depreciation and amortization	384	377	372
Total interest charges	130	134	118
Provision for income taxes	82	77	81
Net income	424	370	341
Total assets	11,048	10,007	9,155
Capital expenditures	1,361	1,283	1,109
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	2,272	2,404	2,524
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(10)	(22)	(30)
Depreciation and amortization	0	0	0
Total interest charges	0	0	0
Provision for income taxes	0	0	0
Net income	0	0	0
Total assets	(653)	(593)	(487)
Capital expenditures	0	0	0
Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Eliminations [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	(10)	(22)	(30)
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Total revenues	1,849	1,965	2,066
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	1,849	1,965	2,066
Depreciation and amortization	339	336	312
Total interest charges	113	117	102
Provision for income taxes	66	59	65
Net income	372	316	294
Total assets	9,800	9,007	8,235
Capital expenditures	1,028	1,055	940
Tampa Electric [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	1,845	1,961	2,063
Tampa Electric [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	4	4	3
PGS [Member]
Segment Reporting Information [Line Items]
Total revenues	433	461	488
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	433	461	488
Depreciation and amortization	45	41	60
Total interest charges	17	17	16
Provision for income taxes	16	18	16
Net income	52	54	47
Total assets	1,901	1,593	1,407
Capital expenditures	333	228	169
PGS [Member] | Operating Segments [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	427	443	461
PGS [Member] | Operating Segments [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	$ 6	$ 18	$ 27

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Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 49	$ 64
Additional liabilities	8	0
Liabilities settled	(19)	(18)
Other	1	3
Ending balance	$ 39	$ 49

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Leases - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating Leased Assets [Line Items]
Operating lease, description	TEC has operating leases for buildings, land, telecommunication services and rail cars.
Operating lease, existence of option to extend	true
Operating lease options to extend	options to extend the leases for up to an additional 65 years.
Operating lease expense	$ 4	$ 4
Option to purchase assets related to CNG stations	Customers have the option to purchase the assets related to the CNG stations at any time after year five of the agreements, which is in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return.
Maximum [Member]
Operating Leased Assets [Line Items]
Operating lease renewal term	65 years
Minimum [Member]
Operating Leased Assets [Line Items]
Operating lease renewal term	1 year

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Leases - Summary of Lease Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Assets And Liabilities Lessee [Line Items]
Total lease liabilities	$ 27	$ 29
Other Deferred Debits [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Right-of-use asset	26	28
Other Current Liabilities [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Current	2	2
Deferred Credits and Other Liabilities [Member]
Schedule Of Assets And Liabilities Lessee [Line Items]
Long-term	$ 25	$ 27

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Leases - Future Minimum Lease Payments (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Minimum lease payments, 2021	$ 3
Minimum lease payments, 2022	3
Minimum lease payments, 2023	3
Minimum lease payments, 2024	3
Minimum lease payments, 2025	2
Minimum lease payments, Thereafter	48
Minimum lease payments, Total	62
Imputed interest, Total	(35)
Total lease liabilities	$ 27	$ 29

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Leases - Additional Information Related to Leases (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating cash flows for operating leases (millions)	$ 5	$ 3
Operating leases (millions)	$ 0	$ 11
Weighted average remaining lease term (years)	43 years	43 years
Weighted average discount rate - operating leases	4.30%	4.30%

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Leases - Net Investment in Direct Finance Leases (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Total minimum lease payments to be received	$ 31	$ 33
Less amounts representing estimated executory costs	(12)	(13)
Minimum lease payments receivable	19	20
Less unearned finance lease income	(10)	(11)
Net investment in direct finance and sales-type leases	9	9
Principal due within one year (included in "Receivables")	(2)	(2)
Net investment in direct finance and sales-type leases - long-term (included in "Other deferred debits")	$ 7	$ 7

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Leases - Future Minimum Direct Finance Lease Payments to be Received (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Minimum lease payments to be received, 2021	$ 2
Minimum lease payments to be received, 2022	2
Minimum lease payments to be received, 2023	2
Minimum lease payments to be received, 2024	2
Minimum lease payments to be received, 2025	2
Minimum lease payments to be received, Thereafter	21
Minimum lease payments to be received, Total	31	$ 33
Executory costs, Total	(12)
Minimum lease payments receivable	$ 19	$ 20

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Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Nov. 30, 2018
Natural Gas Storage and Transportation [Member]
Derivative [Line Items]
Derivative assets	$ 0	$ 0
Derivative liabilities	$ 0	$ 1,000,000

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Stock-Based Compensation - Additional Information (Detail) - Performance Share Unit Plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 8	$ 8	$ 4
Tax benefits related to compensation cost	2	2	1
Cash payment associated with PSU	9	0	$ 0
Unrecognized compensation cost	$ 5	$ 4
Weighted-average period expected to be recognized	2 years

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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, 2020 CAD ($) $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Outstanding as of December 31, 2019 | shares	504
Number of Units, Granted including DRIP | shares	78
Number of Units, Exercised | shares	(162)
Number of Units, Forfeited | shares	(27)
Number of Units, Transferred | shares	(3)
Number of Units, Outstanding as of December 31, 2020 | shares	390
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2019 | $ / shares	$ 45.45
Weighted Average Grant Date Fair Value, Granted including DRIP | $ / shares	52.68
Weighted Average Grant Date Fair Value, Exercised | $ / shares	45.41
Weighted Average Grant Date Fair Value, Forfeited | $ / shares	46.08
Weighted Average Grant Date Fair Value, Transferred | $ / shares	44.85
Weighted Average Grant Date Fair Value, Outstanding as of December 31, 2020 | $ / shares	$ 46.87
Aggregate Intrinsic Value, Outstanding as of December 31, 2019 | $	$ 28
Aggregate Intrinsic Value, Granted including DRIP | $	4
Aggregate Intrinsic Value, Exercised | $	9
Aggregate Intrinsic Value, Forfeited | $	0
Aggregate Intrinsic Value, Transferred | $	0
Aggregate Intrinsic Value, Outstanding as of December 31, 2020 | $	$ 21

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Long-Term PPAs - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($) MW
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 83	$ 49	$ 59
Power Purchase Agreements [Member] | Variable Interest Entity Not Primary Beneficiary [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Purchased power | $	$ 36	$ 25	$ 15
Minimum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range			121
Maximum [Member]
Long Term Contract For Purchase Of Electric Power [Line Items]
Multiple PPAs range			250
PPAs range		515

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Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) - Allowance for Credit Losses - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		$ 2	$ 2	$ 1
Charged to Income		9	5	7
Other Charges		0	0	0
Payments & Deductions	[1]	4	5	6
Balance at End of Period		$ 7	$ 2	$ 2

[1] Write-off of individual bad debt accounts