EDGAR 10-K Filing

Company CIK: 96271
Filing Year: 2023
Filename: 96271_10-K_2023_0000950170-23-003912.json

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ITEM 1. BUSINESS
Item 1. BUSINESS
Tampa Electric Company, referred to as TEC, was incorporated in Florida in 1899 and was reincorporated in 1949. All of TEC’s common stock is owned by TECO Energy, a holding company. TECO Energy is an indirect, wholly owned subsidiary of Emera. Therefore, TEC is an indirect, wholly owned subsidiary of Emera.
TEC is a public utility operating within the State of Florida. At December 31, 2022 and for the year then ended, TEC had two operating segments. Its electric division, referred to as Tampa Electric, provides retail electric service to approximately 826,700 customers in West Central Florida with a net winter system generating capacity of 6,549 MW at December 31, 2022. 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 468,000 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 2022 was approximately 2.0 billion therms.
On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. See Note 1 to the 2022 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC.
TEC makes its SEC filings available free of charge on Tampa Electric’s website (www.tampaelectric.com/company/about/) as soon as reasonably practicable after they are filed with the SEC. TEC’s electronic SEC filings are also available on the SEC’s website (www.sec.gov).
TEC Revenues
TEC’s revenues consist of sales to residential, commercial, industrial and other customers. TEC’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities, power generation customers and other large volume operations. Other sales volumes consist primarily of off-system sales to other utilities and revenues from street lighting.
For TEC’s revenue and other financial information by operating segments, see Note 11 to the 2022 Annual TEC Consolidated Financial Statements.
TEC Human Capital
TEC had approximately 3,236 employees as of December 31, 2022, substantially all of whom are located in Florida. Tampa Electric had approximately 2,469 employees as of December 31, 2022, of which 698 were represented by the International Brotherhood of Electrical Workers and 165 were represented by the Office and Professional Employees International Union. PGS had approximately 767 employees as of December 31, 2022. Approximately 94 employees in four of PGS’s 14 service areas and call center are represented by various union organizations.
In alignment with our efforts to promote inclusion and diversity, TEC has in place a company-wide Inclusion and Diversity 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 of Polk, Pasco and Pinellas Counties. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. At December 31, 2022, Tampa
Electric had two generating stations in or near Tampa, one generating station in southwestern Polk County, and 21 photovoltaic power stations (twelve in Hillsborough County, eight in Polk County, and one in Pasco County).
The sources of Tampa Electric’s operating revenue and MWH sales were as follows:
Tampa Electric Operating Revenue
(millions)
By Customer Type
Residential
$
1,381
$
1,156
$
1,018
Commercial
Industrial
Other sales of electricity
Regulatory deferrals and unbilled revenue
(12
)
(8
)
(25
)
Total energy sales
2,426
2,116
1,797
Off system sales
Other
Total revenues
$
2,523
$
2,174
$
1,849
By Sales Type
Base
$
1,342
$
1,179
$
1,190
Clause
Capital cost recovery for early retired assets
Other
Total revenues
$
2,523
$
2,174
$
1,849
Megawatt-hour Sales
(thousands)
Residential
10,109
9,941
10,122
Commercial
6,300
6,144
6,058
Industrial
2,111
2,122
1,891
Other sales of electricity
1,947
1,886
1,883
Total retail
20,467
20,093
19,954
Off system sales
Total energy sold
20,872
20,207
20,029
No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or several would have a significant adverse effect on Tampa Electric. Tampa Electric experiences summer peak loads due to the use of air conditioning and other cooling equipment and winter peak loads due to electric space heating and fewer daylight hours.
Regulation
Base Rates
Tampa Electric’s retail operations are regulated by the FPSC. The FPSC’s objective is to set rates at a level that provides an opportunity for the utility to collect revenues (revenue requirements) equal to its prudently incurred costs of providing service to customers, plus a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility systems, excluding fuel, conservation costs, purchased power, storm protection plan projects and certain environmental costs, are recovered through base rates. These costs include O&M expenses, depreciation, taxes, and a return on investment in assets providing electric service (rate base). The rate of return on rate base, which is intended to approximate a company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes (at a zero cost rate) and an allowed ROE. Base rates are determined in FPSC rate setting hearings which occur at the initiative of Tampa Electric, the FPSC or other interested parties.
Tampa Electric’s 2022 base rates reflect a settlement agreement approved by the FPSC on November 10, 2021. Tampa Electric’s 2021 and 2020 results reflect a settlement agreement approved by the FPSC on November 6, 2017. See Note 3 to the 2022 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.
(1)Tampa Electric has a fuel recovery clause allowing recovery of actual fuel costs from customers through annual fuel rate adjustments. Differences between actual prudently incurred fuel costs and amounts recovered from customers in a year are recovered from or returned to customers in a subsequent period.
(2)Tampa Electric has a capacity recovery clause allowing recovery of firm demand payments associated with purchased power agreements.
(3)Tampa Electric has an environmental cost recovery clause which allows it to earn a return on investments in new facilities to comply with new environmental regulations and to recover the costs to operate and maintain these facilities.
(4)Through its conservation cost recovery clause, Tampa Electric offers its customers a comprehensive array of residential and commercial programs that have enabled it to meet its required demand side management goals, reduce weather-sensitive peak demand and conserve energy.
(5)Tampa Electric has a Storm Protection Plan cost recovery clause allowing recovery of prudent transmission and distribution storm hardening costs for incremental activities not already included in base rates as outlined in the programs in its approved Storm Protection Plan.
During the fourth quarter of 2022, the FPSC approved cost-recovery rates for the above clauses effective January 1, 2023. See Note 3 to the 2022 Annual TEC Consolidated Financial Statements for further information. In addition, Tampa Electric’s 2021 rate case settlement agreement established a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years. The recovery started in January 2022 and will survive the term of the settlement agreement.
FERC and Other Regulations
Tampa Electric is subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.
Tampa Electric is subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section of the MD&A).
Competition
Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. The principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.
Generation Sources
In 2022 and 2021, approximately 86% and 86%, respectively, of Tampa Electric’s gross generation of electricity was natural gas-fired, with solar representing 7% and 6%, respectively, and coal representing 7% and 8%, respectively. In 2022 and 2021, Tampa Electric used its generating units to meet approximately 90% and 89%, respectively, of the total system load requirements, with the remaining 10% and 11%, 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 information regarding Tampa Electric’s generation costs.
Average cost per MMBTU
Natural Gas (1)
$
8.32
$
4.83
$
3.31
Coal (2)
3.52
3.49
3.69
Average generation cost per MWh (3)
37.85
33.73
20.27
(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)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, 2022, approximately 80% of Tampa Electric’s 2.0 million BCF of gas storage capacity was full. Tampa Electric has contracted for 62% of its expected gas needs for the January through December 2023 period. Tampa Electric expects to issue RFPs to meet its remaining 2023 gas needs and begin contracting for its 2024 requirements. Additional volume requirements are purchased in the short-term spot market.
Coal. Tampa Electric burned less than 0.6 million tons of coal during 2022. Coal consumption is expected to decrease in 2023 compared to 2022. Consistent with 2022, Tampa Electric will be purchasing its coal in 2023 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.
Franchises and Other Rights
Florida utilities must obtain franchises to operate in certain municipalities. Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights-of-way that it carries for its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years.
Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. At December 31, 2022, these agreements have various expiration dates ranging through 2052 and are expected to be renewed under similar terms and conditions.
Franchise fees expense totaled $56 million and $49 million in 2022 and 2021, respectively. Franchise fees are calculated using a formula based primarily on electric revenues and are recovered on a dollar-for-dollar basis from customers.
Utility operations in Hillsborough, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits granted by the Florida Department of Transportation or the County Commissioners of such counties. There is no law limiting the time for which such permits may be granted. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements.
Environmental Matters
Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters. TEC, through its Tampa Electric 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
On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. See Note 1 to the 2022 Annual TEC Consolidated Financial Statements for information regarding the separation of PGS from TEC. The following is a summary of the PGS division as operated under TEC through December 31, 2022. From and after January 1, 2023, the PGS business is no longer operated by TEC.
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 operates a natural gas distribution system that serves approximately 468,000 customers. The system includes approximately 15,100 miles of gas mains and 8,400 miles of service lines (see PGS’s Franchises and Other Rights section below).
In 2022, the total throughput for PGS was approximately 2 billion therms. Of this total throughput, 7% was gas purchased and resold to customers by PGS, 88% was third-party supplied gas that was delivered to transportation-only customers and 5% 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 compressed natural gas vehicles and renewable natural gas operations. There are 56 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)
Residential
$
$
$
Commercial
Industrial
Off-system sales
Power generation
Other revenues
-
-
-
Total
$
$
$
1,987
1,937
2,108
PGS experiences winter peak throughputs due to higher therm usage for heating during colder temperatures. 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.
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.
See Note 3 to the 2022 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 2023, was approved by the FPSC in November 2022.
In addition to its base rates and PGA clause charges, PGS 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. The majority of the cast iron and bare steel pipe has been removed from the system, with the replacement of obsolete plastic pipe continuing under the rider through 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, 2022, PGS had approximately 26,900 transportation-only customers out of approximately 42,700 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 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.
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 122 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. PGS’s franchise agreements have various expiration dates through 2052. PGS expects to negotiate up to 16 franchise renewals in 2023 under similar terms, in addition to those franchise agreements that have auto renewals effective during 2023. Franchise fees expense totaled $15 million and $13 million in 2022 and 2021, respectively. 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. See Note 8 to the 2022 Annual TEC Consolidated Financial Statements and the Environmental Compliance section of the MD&A for additional information.

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ITEM 1A. RISK FACTORS
Item 1A. RISK FACTORS
Risks Relating to TEC’s Business and Strategy
Regulatory, Legislative, and Legal Risks
TEC’s electric utility is regulated; changes in regulation or the regulatory environment could reduce revenues, increase costs or competition.
TEC’s electric utility operates in a regulated industry. Retail operations, including the rates charged and costs eligible for recovery under clauses, are regulated by the FPSC, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or regulatory actions could have an adverse effect on TEC’s financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure. Additionally, if regulators deny or delay cost recovery approvals, Tampa Electric’s earnings could be negatively impacted.
If Tampa Electric earns returns on equity above its allowed range, indicating a trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged returns above its allowed range could result in credits or refunds to customers, which could reduce future earnings and cash flow.
Changes in the environmental and land use laws and regulations affecting its business could increase TEC’s costs or curtail its activities.
TEC’s business is subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TEC, requiring cost-recovery proceedings and/or requiring it to modify its business model.
Federal or state regulation of GHG emissions, depending on how they are enacted, could increase Tampa Electric’s costs or the rates charged to its customers, which could curtail sales.
On June 19, 2019, the EPA released a final rule named the Affordable Clean Energy (ACE) rule. The ACE rule, which replaces the Clean Power Plan adopted in 2015, contained emission guidelines for states to address GHG emissions from existing coal-fired electric generating units. On January 19, 2021, the D.C. Circuit vacated the ACE rule and remanded it to the EPA. A replacement rule is under development.
The outcome of the pending rulemaking process and expected further litigation, and its impact on Tampa Electric’s business, is uncertain at ‎this time; however, it could result in increased operating costs and/or decreased operations at Tampa Electric’s coal-fired plants. Tampa Electric currently expects prudently incurred costs for compliance to be recovered through rates. However, timing of recovery could impact earnings and cash flows, and increases in rates charged to customers could result in reduced sales.
The computation of TEC’s provision for income taxes is impacted by changes in tax legislation.
Any changes in tax legislation could affect TEC’s future cash flows and financial position. The value of TEC’s existing deferred tax assets and liabilities are determined by existing tax laws and could be impacted by changes in laws. See Note 4 of the 2022 Annual TEC Consolidated Financial Statements for further information regarding TEC’s income taxes.
Tampa Electric may not be able to secure adequate rights-of-way to construct transmission lines, 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 relies 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:
•
May need to remove or abandon its facilities on the property covered by rights-of-way or franchises and seek alternative
locations for its transmission or distribution facilities;
•
May need to rely on more costly alternatives to provide energy to its customers;
•
May not be able to maintain reliability in its service area;
•
May need to exercise the power of eminent domain, which can be costly and take time; and/or
•
May experience a negative impact on its ability to provide electric service to new
customers.
The franchise rights held by Tampa Electric could be lost in the event of a breach by such utilities or could expire and not be renewed.
Tampa Electric holds franchise agreements with counterparties throughout its service area. In some cases, these rights could be lost in the event of a breach of these agreements. These agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. Some agreements contain provisions allowing municipalities to purchase the portion of the utility’s system located within a given municipality’s boundaries under certain conditions.
Operational and Construction Risks
TEC’s business is sensitive to variations in weather and the effects of extreme weather and have seasonal variations.
TEC’s utility business is affected by variations in general weather conditions including severe weather. Energy sales by its electric utility are particularly sensitive to seasonal variations in weather conditions, including unusually mild summer or winter weather that cause lower energy usage for cooling or heating purposes. Tampa Electric has both summer and winter peak periods that are dependent on weather conditions. Tampa Electric forecasts energy sales based on normal weather, which represents a long-term historical average. If there is unusually mild weather, or if climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.
TEC is subject to several risks that arise or may arise from climate change.
TEC is subject to risks that may arise from the impacts of climate change. There is increasing public concern about climate change and growing support for reducing carbon dioxide emissions. Municipal, state, and federal governments have been setting policies and enacting laws and regulations to deal with climate change impacts in a variety of ways, including de-carbonization initiatives and promotion of cleaner energy and renewable energy generation of electricity. Refer to “changes in the environmental and land use laws and regulations” above. Insurance companies have begun to limit their exposure to coal-fired electricity generation and are evaluating the medium and long-term impacts of climate change which may result in fewer insurers, more restrictive coverage and increased premiums.
Climate change may lead to increased frequency and intensity of weather events and related impacts such as storms, hurricanes, cyclones, heavy rainfall, extreme winds, wildfires, flooding and storm surge. The potential impacts of climate change, such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce even greater damage to coastal generation and other facilities. Climate change is also characterized by rising global temperatures. Increased air temperatures may bring increased frequency and severity of wildfires, including within TEC’s service territory. Refer to “variations in weather” above.
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 dioxide emissions or climate change public disclosure issues.
For thermal plants requiring cooling water, reduced availability of water resulting from climate change could adversely impact operations or the costs of operations.
The facilities and operations of TEC could be affected by natural disasters or other catastrophic events.
TEC’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g., hurricanes, floods, high winds, fires and earthquakes), equipment failures, terrorist or physical attacks, vandalism, a major accident or incident at one of the sites, and other events beyond the control of TEC. The operation of generation, transmission and distribution systems involves certain risks, including 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.
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 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 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 decline, retail customer growth rates may stagnate or decline, and customers’ energy usage may decline, adversely affecting TEC’s results of operations, net income and cash flows. A factor in customer growth in Florida is net in-migration of new residents, both domestic and non-U.S. A slowdown in the U.S. economy could reduce the number of new residents and slow customer growth.
Potential competitive changes may adversely affect TEC.
There is competition in wholesale power sales across the United States. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers or voters, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.
Florida electric utilities, including Tampa Electric, currently benefit from operating in a regulated environment with limited competition in their market for retail customers. However, the commercial and regulatory frameworks under which Tampa Electric operates can be impacted by changes in government and shifts in government policy. These include initiatives regarding deregulation or restructuring of the energy industry, which may result in increased competition and unrecovered costs that could adversely affect operations, net income and cash flows.
Disruption of fuel supply could have an adverse impact on the financial condition of TEC.
Tampa Electric depends on third parties to supply fuel, including natural gas, 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 business.
TEC’s business is 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.
Developments in technology could reduce demand for electricity.
Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy-efficient appliances and equipment. Advances in these or other technologies could reduce the cost of producing electricity, or otherwise make Tampa Electric’s existing generating facilities uneconomic. Advances in such technologies could reduce demand for electricity, which could negatively impact the results of operations, net income and cash flows of TEC.
Results at TEC may be affected by changes in customer energy-usage patterns.
For the past several years, at Tampa Electric and electric utilities across the United States, weather-normalized electricity consumption per residential customer has declined due to the combined effects of voluntary conservation efforts and improvements in equipment efficiency.
Forecasts by TEC are based on normal weather patterns and trends in customer energy-usage patterns. TEC could be negatively impacted if customers further reduce their energy usage in response to increased energy efficiency, economic conditions or other factors.
Increased customer use of distributed generation could adversely affect Tampa Electric.
In many areas of the United States, including in the markets where TEC operates, there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, known as distributed generation. Distributed generation is encouraged and supported by various constituent groups, tax incentives, renewable portfolio standards and special rates designed to support such generation.
Increased usage of distributed generation can reduce utility electricity sales but does not reduce the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce future earnings and cash flows.
Failure to attract and retain an appropriately qualified workforce, or workforce disruptions, could adversely affect TEC’s financial results.
Events such as increased retirements due to an aging workforce or the departure of employees for other reasons without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development. Failure to attract and hire employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or workforce disruptions due to work stoppages or strikes, or the future availability and cost of contract labor may cause costs to operate TEC’s systems to rise. If TEC is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
Liquidity and Capital Requirements Risks
TEC’s indebtedness could adversely affect its business, financial condition and results of operations, as well as its ability to meet its payment obligations on its debt.
TEC has indebtedness that it is obligated to pay. It must meet certain financial covenants as defined in the applicable agreements to borrow under its credit facilities. Also, TEC has certain restrictive covenants in specific agreements and debt instruments. The level of TEC’s indebtedness and potential inability to meet the requirements of the restrictive covenants contained in its debt obligations could have significant consequences to its business, could create risk for the holders of its debt, and could limit its ability to obtain additional financing (see Management’s Discussion & Analysis - Significant Financial Covenants section). Such risks include:
•making it more difficult for TEC to satisfy its debt obligations and other ongoing business obligations, which may result in defaults;
•events of default if it fails to comply with the financial and other covenants contained in the agreements governing such debt, which could result in all of its debt becoming immediately due and payable or require it to negotiate an amendment to financial or other covenants that could cause it to incur additional fees and expenses;
•reducing the availability of cash flow to finance its business and limiting its ability to obtain additional financing for these purposes;
•increasing its vulnerability to the impact of adverse economic and industry conditions;
•limiting its flexibility in planning for, or reacting to, and increasing its vulnerability to, changes in its business and the overall economy;
•and increasing its cost of borrowing.
TEC has obligations that do not appear on its balance sheet, such as letters of credit. To the extent material, these obligations are disclosed in the notes to the financial statements.
Financial market conditions could limit TEC’s access to capital and increase TEC’s costs of borrowing or refinancing, or have other adverse effects on its results.
TEC has debt maturing in subsequent years, which TEC anticipates will need to be refinanced. Future financial market conditions could limit TEC’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings and cash flows.
Declines in the financial markets or in interest rates 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, 2022 measurement date, TECO Energy’s pension plan was fully funded. Any future declines in the financial markets or interest rates could increase the amount of contributions required to fund its pension plan in the future and could cause pension expense to increase.
TEC’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast or costs are not recoverable through rates.
TEC’s capital plan includes significant investments in generation, infrastructure modernization and customer-focused technologies. Any projects planned or currently in construction, particularly significant capital projects, may be subject to risks including, but not limited to, impact on costs from schedule delays, risk of cost overruns, ensuring compliance with operating and environmental requirements and other events within or beyond TEC’s control. Total costs may be higher than estimated, and there can be no assurance that TEC will be able to obtain the necessary project approvals, regulatory outcomes or applicable permits at the federal, state and or local level to recover such expenditures through regulated rates. If TEC’s capital expenditures exceed the forecasted levels or are not recoverable, it may need to draw on credit facilities or access the capital markets on unfavorable terms.
TEC’s financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade.
The senior unsecured debt of TEC is rated by S&P at ‘BBB+’, by Moody’s at ‘A3’ and by Fitch at ‘A’. A downgrade to below investment grade by the rating agencies, which would require a four-notch downgrade by Moody’s and Fitch and a three-notch downgrade by S&P, may affect TEC’s ability to borrow, may change requirements for future collateral or margin postings, and may increase financing costs, which may decrease earnings. Downgrades could adversely affect TEC’s relationships with customers and counterparties. Some of the factors that can affect TEC’s credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, political, legislative, and regulatory actions, and changes in Emera’s credit ratings.
In the event TEC’s ratings were downgraded to below investment grade, certain agreements could require immediate payment or full collateralization of net liability positions. Counterparties to its derivative instruments could request immediate payment or full collateralization of net liability positions. Credit provisions in long-term gas transportation agreements would give the transportation providers the right to demand collateral, which is estimated to be approximately $129 million at December 31, 2022.
TEC may be subject to risks relating to its separation from PGS.
On January 1, 2023, TEC completed the separation from its former PGS division to PGSI. TEC’s business is less diversified as a result of the separation since its remaining Tampa Electric business serves only electric utility customers and operates in a more narrow geographic area than its former PGS division.
In connection with the separation, TEC and PGSI entered into an intercompany loan agreement. Borrowings under the loan agreement mature on December 29, 2023. TEC expects that PGSI will access the third-party lending market during 2023 to obtain independent financing, and repay the loans on or prior to their maturity date. During 2023, TEC is subject to certain risks in connection with the loan agreement, which risks include that PGSI may default on its obligations under the loan agreement. In addition, under the terms of the loan agreement TEC may be required to use a portion of its existing available liquidity to provide additional revolving loans to PGSI (for which PGSI has agreed to reimburse TEC for all costs and expenses).
The separation is intended to be a tax-free transaction for U.S. federal income tax purposes. The IRS has issued a private letter ruling (IRS Ruling) to the effect that, subject to the limitations specified therein and the accuracy and compliance with certain representations, warranties and covenants, the distribution of the PGSI stock, together with certain related transactions, will qualify as a tax-free “reorganization” for U.S. federal income tax purposes. If any of these items are inaccurate, the separation may not qualify for tax-free treatment, which could result in material tax liabilities for TEC.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

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ITEM 2. PROPERTIES
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 2022 net winter generating capability of 6,549 MWs. Tampa Electric assets include the Big Bend Power Station (2,023 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 as of December 31, 2022 are twenty-one solar arrays (1,023 MWs).
Tampa Electric owns 208 substations having an aggregate transformer capacity of 25,453 mega volts amps. The transmission system consists of approximately 1,349 total circuit miles of high voltage transmission lines, including underground and double-circuit lines. The distribution system consists of approximately 6,202 circuit miles of overhead lines and approximately 6,173 circuit miles of underground lines. As of December 31, 2022, there were 839,977 meters in service. All of this property is located in Florida.
Tampa Electric’s property, plant and equipment are owned, except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances common to properties of the size and character of those of Tampa Electric.
Tampa Electric has easements or other property rights for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. Transmission and distribution lines located in public ways are maintained under franchises or permits.
Tampa Electric has a long-term lease for the office building in downtown Tampa, which serves as headquarters for TECO Energy, Tampa Electric and PGS.
PEOPLES GAS SYSTEM
PGS’s distribution system extends throughout the areas it serves in Florida and consisted of approximately 23,500 miles of pipe, including approximately 15,100 miles of mains and 8,400 miles of service lines, at December 31, 2022. 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 by PGS. The PGS properties were contributed to PGSI, and from and after January 1, 2023, are no longer properties of TEC.

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ITEM 3. LEGAL PROCEEDINGS
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 2022 Annual TEC Consolidated Financial Statements.
PART II

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ITEM 4. MINE SAFETY DISCLOSURE

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS
OVERVIEW
Prior to January 1, 2023, TEC had regulated electric and gas utility operations in Florida. From and after January 1, 2023, the gas utility operations are operated by PGSI, which is no longer a subsidiary of TEC. At December 31, 2022, Tampa Electric served approximately 826,700 customers in a 2,000-square-mile service area in West Central Florida and had electric generating plants with a winter peak generating capacity of 6,549 MW. PGS, Florida’s largest gas distribution utility, served approximately 468,000 residential, commercial, industrial and electric power generating customers at December 31, 2022 in all major metropolitan areas of the state, with a total natural gas throughput of approximately 2.0 billion therms in 2022.
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 2022 Annual TEC Consolidated Financial Statements for information regarding related party transactions.
2022 PERFORMANCE
All amounts included in this MD&A are pre-tax, except net income and income taxes.
In 2022, TEC’s net income was $540 million, compared with $446 million in 2021. 2022 results were impacted by higher base revenues, partially offset by higher depreciation expense, higher O&M expense, higher interest expense and lower AFUDC. See Operating Results below for further detail regarding 2022 results as compared to 2021. For information regarding 2021 results as compared to 2020, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of TEC’s Annual Report on Form 10-K for the year ended December 31, 2021.
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.
On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. As a result, from and after January 1, 2023, the PGS division is no longer operated by TEC. See Note 1 to the 2022 Annual TEC Consolidated Financial Statements for further information regarding the separation of PGS from TEC.
Tampa Electric anticipates earning within its ROE range in 2023. New base rates effective January 1, 2023 as a result of the 2021 settlement agreement will result in Tampa Electric 2023 earnings to be higher than in 2022. Normalizing 2022 for weather, Tampa Electric sales volumes in 2023 are projected to be higher than in 2022 due to customer growth. Tampa Electric expects customer growth rates in 2023 to be similar with 2022, reflective of current expected economic growth in Florida.
On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the final 2022 fuel under-recovery of $518 million over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.
In September 2022, Tampa Electric was impacted by Hurricane Ian. The majority of Hurricane Ian restoration costs were charged against Tampa Electric’s FPSC-approved storm reserve, resulting in minimal impact on earnings and capital expenditures. Total restoration costs were $126 million, with $119 million charged to the storm reserve. Restoration costs charged to the storm reserve exceed the reserve balance and this amount will be deferred and collected from customers in subsequent periods. In November 2022, Tampa Electric incurred costs of approximately $2 million related to Hurricane Nicole. In January 2023, Tampa Electric petitioned the FPSC for recovery of storm costs. Recovery will include costs associated with Hurricanes Ian and Nicole that exceeded the reserve, $10 million of storm restoration costs charged to the reserve since 2018, and the replenishment of the balance in the reserve to the $56 million level that existed as of October 31, 2013 for a total of approximately $131 million. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023 through March 2024.
Tampa Electric has a capital investment program that supports achieving its goal to reduce CO2 emissions to 60% of 2000 levels by 2025. Since 2000, Tampa Electric has reduced its CO2 emissions by more than 50%.
	In 2023, Tampa Electric expects to invest approximately $1.3 billion, excluding AFUDC, in capital projects. Capital projects support normal system reliability and growth. AFUDC will be earned on eligible capital projects during the construction periods. Tampa Electric investments include solar investments, grid modernization and storm hardening investments. 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).
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 2022 Annual TEC Consolidated Financial Statements).
(millions)
Revenues
Tampa Electric
$
2,523
$
2,174
$
1,849
PGS
Eliminations
(10
)
(7
)
(10
)
TEC
$
3,169
$
2,695
$
2,272
Net income
Tampa Electric
$
$
$
PGS
TEC
$
$
$
TAMPA ELECTRIC
Electric Operations Results
Tampa Electric’s net income in 2022 was $458 million, compared with $369 million in 2021. Results primarily reflected higher revenues resulting from the 2021 rate case settlement agreement, favorable weather and customer growth, partially offset by higher depreciation expense and higher 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)
% Change
% Change
Revenues
$
2,523
$
2,174
$
1,849
O&M expense
Depreciation and amortization expense
Taxes, other than income
Non-fuel operating expenses
1,049
Fuel expense
Purchased power expense
Total fuel & purchased power expense
Total operating expenses
1,881
1,684
1,329
Operating income
$
$
(6
)
$
AFUDC-equity
$
(22
)
$
$
Provision for income taxes
$
$
(14
)
$
Net income
$
$
(1
)
$
Megawatt-Hour Sales (thousands)
Residential
10,109
9,941
(2
)
10,122
Commercial
6,300
6,144
6,058
Industrial
2,111
(1
)
2,122
1,891
Other
1,947
1,886
1,883
Total retail
20,467
20,093
19,954
Off system sales
Total energy sold
20,872
20,207
20,029
Retail customers-(thousands)
At December 31
Retail net energy for load
21,572
21,033
(0
)
21,055
Total degree days
4,820
4,565
(5
)
4,807
Operating Revenues
Revenues were $349 million higher than in 2021 primarily driven by higher base revenues of $163 million, higher fuel recovery clause revenue of $84 million as a result of increased fuel costs and revenues related to capital cost recovery for early retired assets of $69 million. Base revenue increased due to new base rates as a result of the 2021 rate case settlement agreement, favorable weather and customer growth. Total degree days (a measure of heating and cooling demand) in Tampa Electric's service area in 2022 were 11% above normal (a 20-year statistical degree day average) and 6% above 2021, reflecting favorable weather in 2022 compared to 2021. Total net energy for load, which is a calendar measurement of energy output, in 2022 was 3% higher compared to 2021.
Customer and Energy Sales Growth Outlook
The Tampa labor market (as measured by employment levels) continues to outperform the state and U.S. labor markets. The Tampa area unemployment rate decreased to 2.6% in 2022 from 4.3% in 2021. Similarly, Florida’s unemployment rate decreased to 2.8% in 2022 from 4.6% in 2021 and the U.S. rate dropped to 3.7% from 5.4% in 2021. Population growth in the area is forecasted to continue to be a major driver of customer growth. In 2023, retail energy sales volumes are expected to be similar to 2022 levels. In 2022, energy sales benefited from weather that was warmer than normal. Normalizing 2022 for weather, 2023 energy sales volumes are expected to be above 2022 levels due to customer growth. Tampa Electric expects 2023 customer growth to be approximately 2% and to be 1.5% to 2.0% annually over the next few years.
Operating Expenses
In 2022, operations and maintenance expense was $43 million higher than in 2021 due to $29 million in amortization of the regulatory asset for early retired assets, increased operating expenses of $12 million and increased costs related to FPSC-approved cost-recovery clauses of $2 million. The increase in operating expenses was primarily due to higher transmission and distribution, employee benefit costs, and insurance. Depreciation and amortization expense increased $15 million in 2022 compared to 2021 as a result of additions to facilities and the in-service of generation projects of $32 million and increased depreciation costs related to
FPSC-approved cost-recovery clauses of $8 million, partially offset by $25 million decrease in depreciation costs resulting from the reclassification of early retired assets from plant in service to regulatory assets.
O&M expense in 2023 is expected to increase due to normal inflation. In 2023, depreciation expense is expected to increase due to solar projects and other plant additions.
Fuel Prices and Fuel Cost Recovery
In 2022, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental, conservation and storm protection plan costs for 2023. The rates include the expected cost for natural gas and coal in 2023. These rates are typically set annually, based on information provided in September of the year prior to the year the rates take effect. Recovery of the net prior period under-recovery true-up of fuel and purchased power clause expense was addressed in a filing in January 2023, and recovery is expected to begin in April 2023.
In January 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million beginning April 1, 2022 through December 2022 due to an increase in fuel commodity and capacity costs. On March 1, 2022, the FPSC voted to approve the mid-course adjustment, and the order reflecting such approval was issued on March 18, 2022.
In January 2023, Tampa Electric requested an adjustment to its fuel charges to recover the final 2022 fuel under-recovery of $518 million over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.
Total fuel expense increased in 2022 from 2021 primarily due to higher natural gas prices. Delivered natural gas prices increased approximately 70% in 2022 due to market forces affected by global events. Total 2023 fuel and purchased power costs are expected to be less than in 2022 due to decreased prices for natural gas.
PGS
Operating Results
In 2022, PGS reported net income of $82 million, compared with $77 million in 2021. Results reflect a 5.1% increase in the number of customers in 2022 compared to 2021. Revenues were $128 million higher than in the prior year primarily due to higher off-system sales and higher PGA clause-related revenues. The base revenue increase of $9 million was primarily due to customer growth, partially offset by unfavorable winter weather compared to 2021. Margin on off-system sales was $3 million higher than in 2021. Operations and maintenance expense was $11 million higher than in 2021 primarily due to $7 million of higher labor and contractor costs to operate, maintain and expand the distribution system and $4 million related to FPSC-approved cost-recovery clauses. Depreciation and amortization decreased $8 million in 2022 due to the $14 million reversal of accumulated depreciation, partially offset by increases due to asset growth. The PGS rate case settlement, which was approved in November 2020, provides the ability to reverse a total of $34 million of accumulated depreciation through 2023 (see Note 3 to the TEC Consolidated Financial Statements for further information). Property taxes were $3 million higher in 2022 due to asset growth. Earnings on the cast iron and bare steel replacement rider was $3 million higher in the 2022 period.
In 2022 and 2021, total throughput for PGS was approximately 2.0 billion therms and 1.9 billion therms, respectively. 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 in 2022 and 2021 were 41 million therms and 39 million therms, respectively. Currently, there are 56 CNG fueling stations connected to the PGS system. PGS owns one CNG filling station, and the cost of the station 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.
Summary of Operating Results
(millions, except customers)
% Change
% Change
Revenues
$
$
$
Cost of gas sold
Operating expenses
Operating income
$
$
$
Net income
$
$
$
Therms sold - by customer segment
Residential
(2
)
Commercial
Industrial
(6
)
(1
)
Off-system sales
(62
)
Power generation
(15
)
Total
1,987
1,937
(8
)
2,108
Therms sold - by sales type
System supply
(25
)
Transportation
1,745
(1
)
1,756
(6
)
1,867
Total
1,987
1,937
(8
)
2,108
Customer (thousands) - at December 31
See Business-Peoples Gas System-Competition for information regarding PGS’s transportation-only customers.
OTHER ITEMS IMPACTING NET INCOME
Other Income, Net
Other income, net was $55 million and $50 million in 2022 and 2021, respectively, and included AFUDC-equity. AFUDC-equity was $35 million and $45 million in 2022 and 2021, respectively. The decrease 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. Other Income was $20 million and $5 million in 2022 and 2021, respectively. The increase in Other Income is primarily due to interest income on the deferred fuel balance and interest income related to the capital cost recovery for early retired assets.
AFUDC is expected to decrease in 2023 due to the timing of construction of the Big Bend modernization, solar generation and grid modernization. Other Income is expected to increase in 2023, primarily due to expected interest income from an affiliate resulting from the intercompany receivable from PGSI (formerly PGS) established upon the separation of PGS from TEC, effective January 1, 2023.
Interest Expense
In 2022, interest expense, excluding AFUDC-debt, was $178 million compared to $151 million in 2021. The increase is due to an increase in interest rates and higher borrowings to support ongoing operations, including fuel under recoveries, and TEC’s ongoing capital investments program.
Interest expense is expected to increase in 2023, reflecting higher balances and interest rates.
Income Taxes
The provision for income taxes increased in 2022 primarily due to higher pre-tax income and higher state tax expense. Income tax expense as a percentage of income before taxes was 18.3% in 2022 and 15.2% in 2021. TEC expects the 2023 annual effective tax rate to be approximately 20% .
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 $2 million and $62 million in 2022 and 2021, respectively.
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 2022 Annual TEC Consolidated Financial Statements.
LIQUIDITY, CAPITAL RESOURCES
Balances as of December 31, 2022
(millions)
Credit facilities/ commercial paper / intercompany advances
$
1,395
Drawn amounts/LCs
1,215
Available credit facilities
Cash and short-term investments
Total liquidity
$
Cash from Operating Activities
Cash flows from operating activities in 2022 were $511 million, a decrease of $286 million compared to 2021. The decrease is primarily due to the under-recovery of fuel costs related to higher natural gas prices, higher accounts receivables balances due to increasing fuel prices reflected in customer bills and higher inventory balances due to plant growth and inflation, partially offset by the timing of invoice payments and new PGS customer rates going into effect in January 2021.
Cash from Investing Activities
Cash flows from investing activities in 2022 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 2022 resulted in net cash inflows of $902 million. TEC received $605 million of equity contributions from Parent, $595 million of proceeds from long-term debt, $400 million proceeds from the 1-year term credit agreement, $374 million increase in short-term debt with maturities of less than 90 days and $195 million in advances from Parent. These increases in cash flows were partially offset by dividend payments to Parent of $517 million, repayment of a 1-year term credit agreement of $500 million, and repayment of long-term debt of $250 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 and commercial paper 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 2023 as it invests in solar projects, grid modernization 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, intercompany activity, and debt issuances so that Tampa Electric maintains its capital structure allowed by the regulator. 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.
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, 2022 was primarily caused by short-term borrowings and periodic fluctuations in assets and liabilities related to FPSC clauses and riders. At December 31, 2022, TEC’s unused capacity under its credit facilities was $180 million.
TEC has credit facilities and commercial paper that provide $1,200 million of credit, including $400 million maturing in 2023 and $800 million maturing in 2026. See Note 6 to the 2022 Annual TEC Consolidated Financial Statements for additional information regarding the credit facilities and commercial paper. TEC expects that its liquidity will be adequate for both the near and long term, given its expected operating cash flows, capital expenditures and related financing plans.
TEC expects cash from operations in 2023 to be higher than in 2022 primarily due to an increase in base rates effective in January 2023, higher cash inflows from fuel, and customer growth (see Note 3 to the 2022 Annual TEC Consolidated Financial
Statements). TEC plans to use cash in 2023 to fund capital spending and to pay dividends to its shareholder. Dividends are paid at the discretion of TEC’s Board of Directors.
TEC’s credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). TEC estimates that it could fully utilize the total available capacity under its facilities in 2023 and remain within the covenant restrictions.
Short-Term Borrowings
TEC had the following credit facilities and related borrowings as of December 31, 2022 and 2021.
December 31, 2022
December 31, 2021
Borrowings
Borrowings
Letters of
Borrowings
Borrowings
Letters of
Credit
Outstanding -
Outstanding -
Credit
Credit
Outstanding -
Outstanding -
Credit
(millions)
Facilities
Credit Facilities (1)
Commercial Paper (1)
Outstanding
Facilities
Credit Facilities (1)
Commercial Paper (1)
Outstanding
5-year facility (2)
$
$
$
$
$
$
$
$
1-year term facility (3)
Total
$
1,200
$
$
$
$
1,300
$
$
$
(1)Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets.
(2)This 5-year facility matures December 17, 2026.
(3)This 1-year term facility was set to mature on December 16, 2022. On December 13, 2022, TEC extended the maturity date to December 13, 2023.
At December 31, 2022, the credit facility required a commitment fee of 12.5 basis points. The weighted average interest rate on outstanding amounts payable under the credit facilities and commercial paper program at December 31, 2022 and 2021 was 5.00% and 0.58%, respectively. For a complete description of the credit facilities see Note 6 to the 2022 Annual TEC Consolidated Financial Statements.
Maximum
Minimum
Average
Average
drawn
drawn
drawn
interest
(millions)
amount
amount
amount
rate
2022 credit facility utilization
$
1,135
$
$
2.37
%
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, 2022, 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, 2022. Reference is made to the specific agreements and instruments for more details.
Calculation
Instrument
Financial Covenant (1)
Requirement/Restriction
at December 31, 2022
Credit facility- $800 million (2)
Debt/capital
Cannot exceed 65%
46.7%
Term facility - $400 million (2)
Debt/capital
Cannot exceed 65%
46.7%
(1)As defined in each applicable instrument.
(2)See Note 6 to the 2022 Annual TEC Consolidated Financial Statements for a description of the credit facilities.
Credit Ratings
Standard &
Poor’s (S&P)
Moody’s
Fitch
Credit ratings of senior unsecured debt
BBB+
A3
A
Credit ratings outlook
Negative
(1)
Negative
(1)
Negative
(1)
(1)In the fourth quarter of 2022, S&P, Moody's and Fitch changed the outlook to negative from stable due to changes in the credit outlook of Emera.
S&P, Moody’s and Fitch describe credit ratings in the A3 or A category as having a strong capacity to meet its financial commitments. Ratings in the BBB or Baa category are described as representing adequate capacity for payment of financial obligations. The lowest investment grade credit rating for S&P is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus, the three credit rating agencies assign TEC’s senior unsecured debt investment-grade credit ratings.
A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. TEC’s access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of its securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings.
Summary of Contractual Obligations
The following table lists the contractual obligations of TEC, including cash payments to repay long-term debt, interest payments, lease payments and unconditional commitments related to capital expenditures.
Contractual Cash Obligations at December 31, 2022
Payments Due by Period
(millions)
Total
After 2027
Long-term debt (1)
$
3,775
$
$
$
$
$
$
3,474
Interest payment obligations(2)
3,273
2,508
Transportation(3)
3,160
1,914
Pension plan(4)
Capital projects(5)
Fuel and gas supply
Purchased power
Long-term service agreements(6)
Operating leases
Demand side management
Total contractual obligations
$
11,111
$
1,009
$
$
$
$
$
7,975
(1)Includes debt at Tampa Electric and PGS (see the Consolidated Statements of Capitalization and Note 7 to the 2022 Annual TEC Consolidated Financial Statements for a list of long-term debt and the respective due dates). On January 1, 2023, the liabilities that were recorded in the books of PGS were moved from TEC to the newly formed PGSI, including PGS’s allocation of outstanding unsecured notes issued by TEC and outstanding short-term borrowings. These combined borrowings of $670 million were converted into an Intercompany Debt Agreement with TEC.
(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, 2022. $2,819 million of the interest payment obligations were held by Tampa Electric at December 31, 2022.	
(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). As of December 31, 2022, $1,518 million were related to transportation contracts held by Tampa Electric.
(4)Under calculation requirements of the Pension Protection Act, as of the January 1, 2022 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 2022 Annual TEC Consolidated Financial Statements).
(5)Represents outstanding commitments for major capital projects, including solar projects, storm hardening for the transmission and distribution systems, new technology for distribution system grid modernization and the maintenance and refurbishment of existing generating facilities.
(6)Represents outstanding commitments for service, including long-term capitalized maintenance agreements for Tampa Electric’s CTs.
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, 2022.
Capital Investments
(millions)
Actual 2022
Forecasted 2023
Tampa Electric (1)
Renewable generation
$
$
Transmission
Distribution
Generation
Facilities, equipment, vehicles and other
Tampa Electric total
1,083
1,290
PGS
Net cash effect of accruals, retentions and AFUDC
Total
$
1,427
$
1,625
(1)Individual line items exclude AFUDC-debt and equity.
Tampa Electric invested approximately $850 million in solar projects during 2017 to 2021 (solar wave I). On February 18, 2020, Tampa Electric announced its intention to invest approximately $800 million in an additional 600 MW of new utility-scale solar photovoltaic projects by the end of 2023 (solar wave II). In addition, Tampa Electric intends to invest approximately $600 million in an additional 375 MW of new utility-scale solar photovoltaic projects in 2022 through 2025 (solar wave III). As of December 31, 2022, Tampa Electric still expects to spend approximately $740 million in solar wave II and solar wave III. In addition, in 2023 through 2025 Tampa Electric expects to spend approximately $600 million in capital for the storm protection plan, $535 million in grid modernization, and $165 million for 125 MW of battery storage. AFUDC is being earned on these projects during construction.
Tampa Electric invested approximately $876 million, including $91 million of AFUDC, during through 2022 to modernize the Big Bend Power Station. This modernization project included conversion of Unit 1 from coal-fired to natural gas combined-cycle technology and the early retirement of Units 2 and 3. AFUDC was earned on this project during construction. As part of the Big Bend modernization, the two combustion turbines on Unit 1 modernization were placed into service on December 1, 2021 and Units 5 and 6 were placed into service in 2022.
Tampa Electric’s 2022 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 2023, Tampa Electric expects capital expenditures to include solar generation projects, storm hardening for the transmission and distribution systems, new technology for distribution system grid modernization, battery storage and the maintenance and refurbishment of existing generating facilities.
The forecasted capital expenditures shown above are based on current estimates and assumptions. Actual capital expenditures could vary materially from these estimates due to changes in and timing of projects and changes in costs for materials or labor (see the Risk Factors section).
Capital Structure
At December 31, 2022, TEC’s year-end capital structure was 47% debt and 53% common equity. At December 31, 2021, TEC’s year-end capital structure was 46% debt and 54% common equity.
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 2022 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 2022 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 2022 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, 2022, TEC does not have a valuation allowance. At December 31, 2022, TEC had a net deferred income tax liability of $1,045 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 2022 Annual TEC Consolidated Financial Statements.
Employee Postretirement Benefits
TEC is a participant in the retirement plans of TECO Energy. TECO Energy sponsors a defined benefit pension plan (pension plan), a fully-funded non-qualified, non-contributory supplemental executive retirement benefit plan available to certain members of senior management and an unfunded non-qualified, non-contributory Restoration Plan that allows certain members of senior management to receive an additional benefit to restore what is limited by the IRS under the pension plan. TEC recognizes in its statement of financial position the over-funded or under-funded status of its allocated portion of TECO Energy’s postretirement benefit plans. The accounting related to employee postretirement benefits is a critical accounting estimate for TEC for the following
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 6.50%, 6.70% and 7.00% as of January 1, 2022, 2021 and 2020, respectively. Given recent capital market returns and market expectations for long-term interest rates, TECO Energy expects the expected return on assets to be 7.05% for 2023 (based on actuarial 20-year expected market returns). Actual losses in 2022 were 23.5%.
The discount rate assumption used to measure benefit expense was an above-mean yield curve. The above-mean yield curve technique matches the yields from high-quality (AA-rated, non-callable) corporate bonds to the company’s projected cash flows for the plans to develop a present value that is converted to a discount rate assumption, which is subject to change each year.
Holding all other assumptions constant, a 1% decrease in the assumed rate of return on pension plan assets or the discount rate assumption would have had in 2022 and is anticipated to have in 2023 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
$5 million increase
$1 million increase
$7 million increase
$1 million increase
Unrecognized actuarial gains and losses for the pension plan are being recognized over a period of approximately 11 years, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with applicable accounting guidance for pensions.
The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under the applicable accounting guidance, include the assumed discount rate and the assumed rate of increases in future health care costs. TECO Energy determines the discount rate for the OPEB’s projected benefit cash flows. In estimating the health care cost trend rate, TECO Energy considers its actual health care cost experience, future benefit structures, industry trends, and advice from our outside actuaries.
See the discussion of employee postretirement benefits in Note 5 to the 2022 Annual TEC Consolidated Financial Statements.
RECENTLY ISSUED ACCOUNTING STANDARDS
Change in Accounting Policy
TEC considers the applicability and impact of all ASUs issued by the FASB. TEC was not required to and did not adopt any new ASUs in 2022.
ENVIRONMENTAL COMPLIANCE
Environmental Matters
TEC has significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act. Its operations are also impacted by provisions in the Clean Water Act and federal and state legislative initiatives on environmental matters.
Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT) Mercury Air Toxics Standards (MATS)
On June 29, 2015, the U.S. Supreme Court remanded the EPA’s Mercury Air Toxics Standards (MATS) to the D.C. Circuit Court of Appeals for failing to properly consider the cost of compliance. The litigation is currently in abeyance while the EPA reconsiders its action. MATS remain in effect until the D.C. Circuit Court of Appeals acts.
All of Tampa Electric’s conventional coal-fired units are already equipped with electrostatic precipitators, scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Therefore, Tampa Electric has minimized the impact of this rule and has demonstrated compliance on all applicable units with the most stringent “Low Emitting Electric Generating Unit” classification for MATS with nominal additional capital investment.
Carbon Reductions and GHG
Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 2000, Tampa Electric has reduced its system-wide emissions of CO2 by more than 50%, bringing emissions to below 1990 levels. Tampa Electric CO2 emissions continue to remain below 1990 levels. In addition to the emission decreases in 2005 as the result of the repowering of two Gannon Station coal units to natural gas and the shut-down of the remaining Gannon Station coal-fired units, Tampa Electric has optimized its existing coal units to operate on natural gas. During this same time frame, the number of retail customers and retail energy sales have risen. Tampa Electric 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. By the end of 2023, the Big Bend Unit 1 modernization project, capable of producing 1,090 megawatts of power, will lead to lower system-wide emissions. See Capital Investments above for information regarding Tampa Electric’s solar projects. Tampa Electric has announced a long-term goal to reduce CO2 emissions to 80% of 2000 levels by 2040 and aspires to reach a net zero future by 2050.
On June 19, 2019, the EPA released a final rule, named the Affordable Clean Energy (ACE) rule, to establish emission guidelines for states to address GHG emissions from existing coal-fired electric generating units (EGUs). On January 19, 2021, the D.C. Circuit Court of Appeals vacated the ACE rule and remanded it to the EPA. The Supreme Court decision in West Virginia vs. EPA reversed the ruling; however, the EPA has stated that it does not plan to implement the ACE rule and is working on a replacement rule expected to be proposed in 2023. Compliance with the terms of the new rule that replaces the ACE rule, once adopted, and finalized, 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.
Ozone
On December 31, 2020, the EPA published a final rule to retain the national ambient air quality standards (NAAQS) for photochemical oxidants including ozone, originally adopted in 2012. Under the Clean Air Act, the EPA is required to review the NAAQS every five years and, if appropriate, revise it. The EPA has announced that the NAAQS is currently under review, which could result in revisions to the standard affecting compliance in Tampa Electric’s service territory. The impact of this potential new standard on the operations of Tampa Electric will depend on the standard that is ultimately adopted and on the outcome of any related litigation or other developments.
Water Supply and Quality
The EPA’s final rule under 316(b) of the Clean Water Act (effective October 2014) addresses perceived impacts to aquatic life by cooling water intakes and is applicable to Tampa Electric's Bayside and Big Bend Power Stations. Polk Power Station is not covered by this rule since it does not operate an intake on waters of the 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 were used by FDEP to determine the necessity of cooling water system retrofits. FDEP agreed with Tampa Electric’s proposed plan for Bayside and Tampa Electric began a multi-year construction project to install new fish-friendly modified traveling screens and a fish return in 2022. Tampa Electric is negotiating an alternative schedule for Big Bend (as allowed by the rule) but completed a portion of the compliance requirements with the Big Bend modernization project with the installation of fish-friendly modified traveling screens and a fish return on modernized Unit 1. The remainder of the compliance requirements are to be determined and completed at a later date. The full impact of the new regulations on Tampa Electric will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by FDEP.
The final EPA rule for existing steam electric effluent limit guidelines (ELGs) became effective January 4, 2016 and establishes limits for wastewater discharges from flue gas desulfurization (FGD) processes, fly ash and bottom ash transport water, leachate from ponds and landfills containing coal combustion residuals, gasification processes, and flue gas mercury controls. The new guidelines are expected to be incorporated into National Pollutant Discharge Elimination System permit renewals for Big Bend Station (FGD wastewater and bottom ash transport water) and Polk Power Station (gasification wastewater) to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023. The EPA decided to extend the near-term deadlines for FGD wastewater and bottom ash transport water to as soon as possible after November 1, 2020. On November 22, 2019, the EPA published in the Federal Register its proposed updates to the ELGs, in which the EPA revised limits for both bottom ash transport water and FGD wastewater and extended the final compliance deadline by two years for FGD wastewater. The final rule with revised limits was published on October 13, 2020 and became effective December 14, 2020. Although a legal challenge to this rule is pending in the D.C. Circuit Court of Appeals, no stays are in effect. However, the EPA has announced that this rule is currently under review, and a revised rule is expected to be proposed in 2023.
The preliminary draft of the NPDES Permit for Big Bend stated that effluent limitations for total recoverable arsenic, mercury, and selenium and total nitrate/nitrite for FGD wastewater are applicable no later than December 31, 2023. Big Bend will complete construction of a deep injection well system in December 2023 for disposal of FGD wastewater, bottom ash transport water and other process wastewaters. Since Polk Power Station disposes of any gasification wastewater created down the deep injection well rather than discharging it to surface water, the effluent limitations do not apply to that power station.
EPA Waters of the US
In January 2020, the EPA and the Corps finalized a rule, called the Navigable Waters Protection Rule (NWPR), to define “waters of the United States” and thereby establish federal regulatory authority under the Clean Water Act. This final rule became effective in June 2020 and replaced the rule published in October 2019. While there have been numerous legal challenges filed in federal court, there are no legal stays in effect. However, the EPA and the U.S. Army Corps of Engineers (the Corps) are in receipt of an order of the U.S. District Court for the District of Arizona dated August 30, 2021, which vacates and remands the NWPR. As a result of this order, the agencies have halted implementation of the NWPR and are currently interpreting “waters of the United States” consistent with its meaning prior to the adoption of the 2015 rule that was repealed in October 2019. The EPA is also engaging in additional rulemaking to revise NWPR. In November 2021, the EPA and the Corps announced a proposed rule which would re-establish the pre-2015 definition of “waters of the United States” updated “to reflect consideration of Supreme Court decisions".
On February 24, 2022, EPA and the Corps announced the selection of ten roundtables that highlight geographic differences and a range of perspectives. The agencies will work with each selected roundtable to facilitate discussion on implementation of “waters of the United States” (WOTUS), while highlighting regional differences. These roundtables concluded on June 24, 2022.
Superfund and Former Manufactured Gas Plant Sites
As of December 31, 2022, TEC, through its Tampa Electric division and former PGS division, was a PRP for certain superfund sites and, through its former PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 2022 and 2021, TEC estimated its ultimate financial liability to be $13 million and $14 million, respectively, 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 that was attributable to TEC. The estimates to perform the work were 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.
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 was completed in October 2021. Closure of Tampa Electric’s West Slag Dewatering Pond and improvements were completed in 2020. The final phase of the drainage improvements to Tampa Electric’s North Gypsum Stackout Area is scheduled for completion in 2023. In August 2019, the EPA proposed Phase II revisions to the rule that 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’s customers for these products. Review of this rule is ongoing. FDEP has proposed a Florida CCR permitting program to be incorporated into the existing state solid waste regulation, which will operate in lieu of the Federal permitting program. However, since TEC has already closed all currently regulated CCR Units by October 2021, neither Federal nor State programs regulating CCRs would be expected to have a significant impact on TEC. See Note 12 to the 2022 Annual TEC Consolidated Financial Statements for information regarding the estimated impact on Tampa Electric’s AROs.
Conservation
In 2022, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial Demand Side Management (DSM) programs that enabled the company to meet all of its required annual DSM goals. Tampa Electric completed the first full year of testing the integrated renewable energy system that utilizes a large solar array integrated with battery storage and electric vehicle and large commercial vehicle battery charging systems. In 2022, Tampa Electric initiated a new residential load management program, which leverages its Advanced Metering Infrastructure System with a smart thermostat to facilitate this program to control customers pool pumps, water heaters, and HVAC systems. Also in 2022, Tampa Electric started the process of facilitating the development of the Technical Potential Study which will serve as the starting point for the DSM goals development for the next upcoming period (2025-2034).
In 2022, Tampa Electric achieved all of the residential and commercial annual energy and demand goals. To achieve these DSM goals, Tampa Electric offered 36 cost-effective DSM Programs. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause rate on the customer’s electric bill. Since their inception to January 1, 2022, Tampa Electric’s conservation programs have contributed to reducing the summer peak demand by 791 MWs and the winter peak demand by 1,308 MWs.
PGS offered a walkthrough energy audit for commercial customers in 2022. This program was approved by the FPSC as part of its DSM goals in 2019. PGS received approval for its DSM plan in June 2021, which will support the achievement of DSM goals on an annual basis. Starting in 2019, PGS initiated the reporting of annual energy reduction achievements as part of meeting the requirements of the Florida Energy Efficiency and Conservation Act. 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 2022 Annual TEC Consolidated Financial Statements for a description of the utilities’ base rates, cost-recovery clauses and competition.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.
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.
TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. The primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on customers.
On November 6, 2017, the FPSC approved an amended and restated settlement agreement filed by Tampa Electric, which includes a provision for a moratorium on hedging of natural gas purchases ending on December 31, 2022. On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric related to its 2021 rate case that extended the moratorium to December 31, 2024 (see Note 3 to the 2022 Annual TEC Consolidated Financial Statements for further information on the settlement agreements). As of December 31, 2022 and 2021, 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, contain provisions that require our debt to maintain an investment-grade credit rating from any or all of the major credit rating agencies. If TEC’s debt ratings were to fall below investment grade or not be rated, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.
Interest Rate Risk
TEC is exposed to changes in interest rates primarily from borrowing under the company's credit facilities and commercial paper program. A hypothetical 10% increase in TEC's weighted-average interest rate on its borrowings under the credit facilities and commercial paper outstanding at December 31, 2022 and 2021 would have resulted in a $5 million and zero impact on pre-tax earnings, respectively. This is driven by rising interest rates and higher outstanding balances. A hypothetical 10% increase in interest rates would have decreased the fair market value of TEC's long-term debt by 6.0% at December 31, 2022 and 4.0% at December 31, 2021. See the Financing Activity section and Notes 6 and 7 to the 2022 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 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. Tampa Electric’s use of natural gas, with its more volatile pricing, for generation of electricity was 86% in 2022 and 86% in 2021 (see the Business section). PGS has exposure related to the price of purchased gas and pipeline capacity.
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, 2022 and 2021, a change in commodity prices would not have had a material impact on earnings for Tampa Electric or PGS, but could have and has had an impact on the timing of the cash recovery of the cost of fuel.
TAMPA ELECTRIC COMPANY

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2022 and 2021, the related consolidated statements of income and comprehensive income, capitalization and cash flows for each of the three years in the period ended December 31, 2022 and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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 Board of Directors and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the effects of regulatory matters
Description of the Matter
As disclosed in Note 3 of the consolidated financial statements, the Company has $1,552 million in regulatory assets and $1,140 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, but not limited to, property, plant and equipment, revenues, and expenses.
Auditing the impact of rate regulation on the Company’s financial statements is complex and highly judgmental due to the significant judgments made by the Company to support its accounting and disclosure for regulatory matters when final regulatory decisions or orders have not yet been obtained or when regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of future regulatory decisions on
the financial statements. Although the Company expects to recover costs from customers through rates, there is a risk that the regulator may not approve full recovery of costs incurred. The Company’s judgments include making an assessment of the probable recovery of and return on costs incurred, of the potential disallowance of part of the cost incurred, or of the probable refund to customers through future rates.
How We Addressed the Matter in Our Audit
We performed audit procedures that included, among others, assessing the Company’s evaluation of the probability of future recovery for regulatory assets and refund of regulatory liabilities by obtaining and reviewing relevant regulatory orders, filings, testimony, hearings and correspondence, and other publicly available information. For regulatory matters for which regulatory decisions or orders have not yet been obtained, we inspected the regulatory filings for any evidence that might contradict the Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities within the same jurisdiction to assess the likelihood of recovery in future rates based on the regulator’s treatment of similar costs under similar circumstances. We obtained and evaluated an analysis from the Company and corroborated that analysis with letters from legal counsel, when appropriate, regarding cost recoveries or future changes in rates. We also assessed the methodology, accuracy and completeness of the Company’s calculations of regulatory asset and liability balances based on provisions and formulas outlined in rate orders and other correspondence with the regulators. We also evaluated the Company's disclosures related to the impacts of rate regulation.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2018.
Tampa, Florida
February 23, 2023
TAMPA ELECTRIC COMPANY
Consolidated Balance Sheets
Assets
December 31,
December 31,
(millions)
Property, plant and equipment
Utility plant
Electric
$
12,536
$
11,563
Gas
2,938
2,626
Utility plant, at original costs
15,474
14,189
Accumulated depreciation
(3,845
)
(3,601
)
Utility plant, net
11,629
10,588
Other property
Total property, plant and equipment, net
11,644
10,602
Current assets
Cash and cash equivalents
Receivables, less allowance for credit losses of $4 and $7 at December 31, 2022 and 2021, respectively
Due from affiliates
Inventories, at average cost
Fuel
Materials and supplies
Regulatory assets
Prepayments and other current assets
Total current assets
Other assets
Regulatory assets
1,191
Deferred charges and other assets
Total other assets
1,250
1,015
Total assets
$
13,803
$
12,196
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Balance Sheets-continued
Liabilities and Capital
December 31,
December 31,
(millions)
Capitalization
Common stock
$
5,075
$
4,470
Accumulated other comprehensive loss
(1
)
(1
)
Retained earnings
Total capital
5,420
4,792
Long-term debt
3,734
3,136
Total capital
9,154
7,928
Current liabilities
Long-term debt due within one year
Notes payable
1,019
Accounts payable
Due to affiliates
Customer deposits
Regulatory liabilities
Accrued interest
Accrued taxes
Other
Total current liabilities
2,037
1,727
Other liabilities
Deferred income taxes
1,045
Regulatory liabilities
1,055
1,092
Investment tax credits
Deferred credits and other liabilities
Total other liabilities
2,612
2,541
Commitments and Contingencies (see Note 8)
Total liabilities and capital
$
13,803
$
12,196
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Con solidated Statements of Income and Comprehensive Income
(millions)
For the years ended December 31,
Revenues
Electric
$
2,519
$
2,170
$
1,845
Gas
Total revenues
3,169
2,695
2,272
Expenses
Fuel
Purchased power
Cost of natural gas sold
Operations & maintenance
Depreciation and amortization
Taxes, other than income
Total expenses
2,396
2,089
1,672
Income from operations
Other income
Allowance for other funds used during construction
Other income, net
Total other income
Interest charges
Interest expense
Allowance for borrowed funds used during construction
(11
)
(21
)
(14
)
Total interest charges
Income before provision for income taxes
Provision for income taxes
Net income
$
$
$
Comprehensive income
$
$
$
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Co nsolidated Statements of Cash Flows
(millions)
For the years ended December 31,
Cash flows from or used in operating activities
Net income
$
$
$
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization
Deferred income taxes and investment tax credits
Allowance for equity funds used during construction
(35
)
(45
)
(30
)
Deferred recovery clauses
(422
)
(58
)
(40
)
Receivables, less allowance for credit losses
(45
)
(32
)
(10
)
Inventories
(41
)
(8
)
Taxes accrued
(23
)
(13
)
Accounts payable
Regulatory assets and liabilities
(100
)
(10
)
(18
)
Other
(11
)
Cash flows from operating activities
Cash flows from or used in investing activities
Capital expenditures
(1,427
)
(1,397
)
(1,361
)
Net proceeds from sale of assets
Cash flows used in investing activities
(1,417
)
(1,397
)
(1,355
)
Cash flows from or used in financing activities
Equity contributions from Parent
Proceeds from long-term debt issuance
Repayment of long-term debt
(250
)
(279
)
Net change in short-term debt (maturities of 90 days or less)
(230
)
Proceeds from other short-term debt (maturities over 90 days)
Repayment of other short-term debt (maturities over 90 days)
(500
)
(300
)
Dividends to Parent
(517
)
(450
)
(408
)
Advances from Parent
Other financing activities
(3
)
(2
)
Cash flows from financing activities
Net increase (decrease) in cash and cash equivalents
(4
)
(4
)
Cash and cash equivalents at beginning of the year
Cash and cash equivalents at end of the year
$
$
$
Supplemental disclosure of cash paid (received):
Interest
$
$
$
Income taxes
$
$
$
Supplemental disclosure of non-cash activities:
Change in accrued capital expenditures
$
(6
)
$
$
The accompanying notes are an integral part of the consolidated financial statements.
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, 2019
3,385
$
$
(1
)
$
3,695
Net income
Equity contributions from Parent
Dividends to Parent (2)
(408
)
(408
)
Balance, December 31, 2020
$
3,890
$
$
(1
)
$
4,216
Net income
Equity contributions from Parent
Dividends to Parent (2)
(450
)
(450
)
Balance, December 31, 2021
$
4,470
$
$
(1
)
$
4,792
Net income
Equity contributions from Parent
Dividends to Parent (2)
(517
)
(517
)
Balance, December 31, 2022
$
5,075
$
$
(1
)
$
5,420
Preferred stock - $100 par value
1.5 million shares authorized, none outstanding.
Preferred stock - no par
2.5 million shares authorized, none outstanding.
Preference stock - no par, subordinate to the preferred stock
2.5 million shares authorized, none outstanding.
(1)Common stock without par value, 25 million shares authorized
(2)Dividends are declared and paid at the discretion of TEC’s Board of Directors.
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Statements of Capitalization - continued
At December 31, 2022 and 2021, TEC had the following long-term debt outstanding:
Long-Term Debt
(millions)
Due
Tampa Electric
Notes (1)(2)(3) : 2.60%
$
$
3.88%
2.40%
6.55%
6.15%
4.10%
4.35%
4.20%
4.30%
4.45%
3.63%
3.45%
5.00%
Total long-term debt of Tampa Electric
3,205
2,905
PGS
Notes (1)(2)(3) : 2.60%
3.88%
2.40%
6.15%
4.10%
4.35%
4.20%
4.30%
4.45%
3.63%
3.45%
5.00%
Total long-term debt of PGS
Total long-term debt
3,775
3,425
Unamortized debt discount, net
(11
)
(12
)
Debt issuance costs
(30
)
(27
)
Total carrying amount of long-term debt
3,734
3,386
Less amount due within one year
Total long-term debt
$
3,734
$
3,136
(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.
TAMPA ELECTRIC COMPANY
Consolidated Statements of Capitalization-continued
At December 31, 2022, long-term debt had a carrying amount of $3,734 million and an estimated fair market value of $3,234 million. At December 31, 2021, total long-term debt had a carrying amount of $3,386 million and an estimated fair market value of $4,036 million. The fair value of the debt securities is determined using Level 2 measurements (see Note 14 for information regarding the fair value hierarchy).
A substantial part of Tampa Electric’s tangible assets is pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Gross maturities and annual sinking fund requirements of long-term debt are as follows:
Long-Term Debt Maturities
Total
As of December 31, 2022
Long-Term
(millions)
Thereafter
Debt
Tampa Electric
$
$
$
$
$
$
2,942
$
3,205
PGS
Total long-term debt maturities
$
$
$
$
$
$
3,474
$
3,775
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
Description of the Business
TEC had two operating segments as of December 31, 2022 and for the year then ended. Its Tampa Electric division 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. See "Separation of PGS from TEC" below for information regarding the separation that occurred on January 1, 2023. TEC’s significant accounting policies are as follows:
Principles of Consolidation and Basis of Presentation
TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates.
TEC is a wholly owned subsidiary of TECO Energy, Inc. 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.
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, 2022
December 31, 2021
Electric generation
21-60 years
$
6,300
$
5,395
Electric transmission
10-77 years
1,109
1,068
Electric distribution
10-59 years
3,296
3,064
Gas transmission and distribution
15-75 years
2,567
2,360
General plant and other
3-71 years
1,020
Total cost
14,292
12,833
Less Tampa Electric accumulated depreciation
(3,158
)
(2,937
)
Less PGS accumulated depreciation
(687
)
(664
)
Tampa Electric construction work in progress
1,219
PGS construction work in progress
Total property, plant and equipment, net
$
11,644
$
10,602
Depreciation
The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.2%, 3.5% and 3.2% for 2022, 2021 and 2020, respectively. Construction work in progress is not depreciated until the asset is placed in service. TEC's total depreciation expense for the years ended December 31, 2022, 2021 and 2020 was $402 million, $408 million and $381 million, respectively. For the year ended December 31, 2022, 2021 and 2020, Tampa Electric's depreciation expense was $359 million, $357 million and $339 million, respectively.
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. The rates used to calculate AFUDC are revised periodically to reflect significant changes in cost of capital. In 2022, 2021 and 2020, Tampa Electric’s rate was 6.00%, 6.46% and 6.46%, respectively. PGS’s rate used to calculate its AFUDC in 2022, 2021 and 2020 was 6.00%, 6.00% and 5.97%, respectively. Total AFUDC for the years ended December 31, 2022, 2021 and 2020 was $46 million, $66 million and $44 million, respectively.
Inventory
TEC values materials, supplies and fossil fuel inventory (natural gas and coal) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or net realizable value.
Regulatory Assets and Liabilities
Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3).
Deferred Income Taxes
TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at enacted tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates. See Note 4 for additional details.
Investment 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, environmental and storm protection plan 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 $295 million and $252 million as of December 31, 2022 and 2021, 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. 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, 2022 and 2021, unbilled revenues of $82 million and $74 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 $145 million, $129 million and $109 million for the years ended December 31, 2022, 2021 and 2020, respectively.
Deferred Charges and Other Assets
Deferred charges and other assets consist primarily of pension assets net of accrued pension liabilities (see Note 5), right-of-use assets related to operating leases (see Note 13) and a contribution made by TEC in order to fully fund its SERP obligation (see Note 5).
Deferred Credits and Other Liabilities
Other deferred credits primarily include accrued 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, 2022 and 2021 ranged from 4.00% to 5.78% and 1.63% to 4.00%, respectively.
Derivatives and Hedging Activities
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. On October 21, 2021, the FPSC approved a settlement agreement filed by Tampa Electric related to its 2021 rate case that extended the moratorium to December 31, 2024 (see Note 3 for further information on the settlement agreements). TEC was hedging its exposure to the variability in future cash flows until November 30, 2018 for financial natural gas contracts. TEC had $5 million and zero derivative assets as of December 31, 2022 and 2021, respectively, and $1 million and zero derivative liabilities as of December 31, 2022 and December 31, 2021, respectively.
TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of December 31, 2022 and 2021, all of TEC’s physical contracts qualified for the NPNS exception, which was elected.
TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.
Separation of PGS from TEC
PGS became an operating division of TEC in 1997 when TECO Energy purchased PGS and merged that corporation into TEC. Since then, PGS has operated as a stand-alone regulated utility, including having its own tariff and its own books and records.
On January 1, 2023, TEC transferred the assets and liabilities of its PGS division into a separate corporation called Peoples Gas System, Inc. (PGSI) pursuant to a Contribution Agreement. This new corporation is a wholly owned subsidiary of a newly formed gas operations holding company, TECO Gas Operations, Inc., a wholly owned subsidiary of TECO Energy. On January 1, 2023, the assets, liabilities, and equity that had been recorded in the books of PGS were transferred from TEC to the newly formed PGSI at book value in a tax-free transaction. PGSI issued 100 shares of common stock to TEC related to the transfer of PGS, which were subsequently distributed to TECO Energy, Inc. and then contributed to TECO Gas Operations, Inc. This is a transaction between entities under common control; therefore, TEC did not recognize a gain or loss on the transaction.
Included in the liabilities transferred was PGS’s allocation of outstanding unsecured notes issued by TEC and outstanding short-term borrowings. The obligations related to these combined borrowings are reflected in an intercompany loan agreement between TEC and PGSI. The initial obligation of PGSI under the loan agreement at January 1, 2023 was a term loan in the principal amount of $670 million and a revolving loan in the principal amount of $66 million. The maturity date for both is December 29, 2023. PGSI intends to access the third-party lending market during 2023 but cannot predict when during the year that it will do so. To assist its affiliate and to facilitate an orderly transfer of its gas assets, Tampa Electric will continue to be responsible for providing capital as needed to PGSI under an intercompany loan agreement guaranteed by TECO Energy and TECO Gas Operations, Inc.
See Note 11 for certain financial information related to PGS. In addition, the following table presents the assets and liabilities of PGS in TEC’s Consolidated Balance Sheet as of December 31, 2022:
December 31,
(millions)
Property, plant and equipment
Utility plant
$
2,938
Accumulated depreciation
(687
)
Total property, plant and equipment, net
2,251
Current assets
Cash and cash equivalents
Receivables, less allowance for credit losses of $1 at December 31, 2022
Due from affiliates
Inventories, at average cost
Materials and supplies
Regulatory assets
Prepayments and other current assets
Total current assets
Other assets
Regulatory assets
Deferred charges and other assets
Total other assets
Total assets
$
2,471
Capitalization
Common stock
$
Retained earnings
Total capital
Long-term debt
Total capital
1,556
Current liabilities
Notes payable
Accounts payable
Due to affiliates
Customer deposits
Regulatory liabilities
Accrued interest
Accrued taxes
Other
Total current liabilities
Other liabilities
Deferred income taxes
Regulatory liabilities
Deferred credits and other liabilities
Total other liabilities
Total liabilities and capital
$
2,471
2. New Accounting Pronouncements
TEC considers the applicability and impact of all ASUs issued by the FASB. TEC was not required to and did not adopt any new ASUs in 2022.
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 2021 and 2020 reflected an amended and restated settlement agreement, approved by the FPSC on November 6, 2017, that replaced the previous 2013 base rate settlement agreement and extended it another four years through 2021. The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. Under the agreement, the allowed equity in the capital structure was 54% from investor sources of capital. The amended agreement provided for SoBRAs for Tampa Electric’s substantial investments in solar generation. Tampa Electric invested approximately $850 million in these solar projects during 2017 to 2021 and accrued AFUDC during construction. The agreement included a sharing provision that allowed customers to benefit from 75% of any cost savings for projects below $1,500/kWac.
Between 2017 and 2021, TEC filed annual SoBRA petitions along with supporting tariffs demonstrating the cost-effectiveness of four tranches representing 600 MW and $104 million in estimated revenue requirements. The FPSC approved the tariffs on each of the SoBRA filings and Tampa Electric began receiving the applicable revenues after each of the tranches was commercially completed (tranche 1 for $24 million in revenue starting September 2018, tranche 2 for $46 million in revenue starting January 2019, tranche 3 for $26 million in revenue starting January 2020 and tranche 4 for $8 million in revenue starting January 2021).
The true-up filing for SoBRA tranche 1 and 2 revenue requirement estimates that were included in base rates as of September 2018 and January 2019, respectively, was submitted on April 30, 2020, and the FPSC approved the amount on August 18, 2020. The $5 million true-up was returned to customers in 2020. The true-up filing for SoBRA tranche 3, included in base rates as of January 2020, was approved by the FPSC on October 12, 2021. A $4 million true-up was returned to customers during 2021. No true-up for SoBRA tranche 4 was required.
The 2017 settlement agreement further contained a provision related to tax reform. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are achieved is also included. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2022 and that it will make no investments in gas reserves.
On August 6, 2021, Tampa Electric filed with the FPSC a joint motion for approval of a settlement agreement dated as of August 6, 2021 (the Settlement Agreement) by and among Tampa Electric and the intervenors in Tampa Electric’s rate case filed with the FPSC in April 2021. The Settlement Agreement agreed to an increase in base rates annually effective with January 2022 bills, to generate a $191 million increase in revenue consisting of $123 million of traditional base rate charges and $68 million in a new charge to recover the costs of retiring assets. The Settlement Agreement further included two subsequent year adjustments of $90 million and $21 million, effective January 2023 and January 2024, respectively. Under the agreement, the allowed equity in the capital structure continued to be 54% from investor sources of capital. The Settlement Agreement included an allowed regulatory ROE range of 9.0% to 11.0% with a 9.95% midpoint. The Settlement Agreement allows a 25 basis point increase in the allowed ROE range and mid-point, and $10 million of additional revenue, if the average 30-year United States Treasury Bond yield rate for any period of six consecutive months is at least 50 basis points greater than the yield rate on the date the FPSC votes to approve the agreement. Under the agreement, base rates will not change from January 1, 2022 through December 31, 2024, unless Tampa Electric’s earned ROE were to fall below the bottom of the range during that time. The Settlement Agreement contained a provision whereby Tampa Electric agrees to quantify the future impact of a decrease or increase in corporate income tax rates on net operating income through a reduction or increase in base revenues within 180 days of when such tax change becomes law or its effective date. The Settlement Agreement further created a mechanism to recover the costs of retiring coal generation units and meter assets over a period of 15 years which survives the term of that agreement. The Settlement Agreement set new depreciation and dismantlement rates effective January
1, 2022 and contained the provisions that Tampa Electric will not have to file another depreciation study during the term of the agreement but will file a new depreciation study no more than one year, nor less than 90 days, before the filing of its next general base rate proceeding. Additionally, Tampa Electric agreed to a financial hedging moratorium for natural gas ending on December 31, 2024. On October 21, 2021, the FPSC approved the Settlement Agreement and the final order, reflecting such approval, was issued on November 10, 2021.
Tampa Electric's 2021 settlement agreement provision allowed Tampa Electric to request a revenue and ROE increase due to increases in the 30-year U.S. Treasury bond yield rate. On July 1, 2022, Tampa Electric requested to adjust its base rates to collect an additional $10 million annually (prorated in the first year) effective September 1, 2022 and increase its mid-point ROE and upper and lower allowed ranges. On August 16, 2022, the FPSC approved the change. The new mid-point ROE is 10.20%, and the range is 9.25% to 11.25% effective July 1, 2022.
Tampa Electric Big Bend Modernization Project
Tampa Electric invested $876 million, including $91 million of AFUDC, during 2018 through 2022 to modernize the Big Bend Power Station. The Big Bend modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the Big Bend modernization project, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant in 2020 and Big Bend Unit 2 in 2021. Tampa Electric 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.
At December 31, 2020, Tampa Electric’s balance sheet included $636 million in electric utility plant and $267 million in accumulated depreciation related to Unit 1 components and Unit 2 and Unit 3 assets. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric continued to account for its investment in Units 1, 2 and 3 in electric utility plant and depreciated the assets using the current depreciation rates until December 31, 2021, at which point they were reclassified to a regulatory asset on the balance sheet.
Tampa Electric’s Settlement Agreement provided recovery for the Big Bend modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs will be recovered as part of the 2023 subsequent year adjustment. The Settlement Agreement also included a new charge to recover the remaining costs of the retiring Big Bend coal generation assets, Units 1 through 3, which will be spread over 15 years and will survive the term of the Settlement Agreement. The special capital recovery schedule for all three units was applied beginning January 1, 2022.
Tampa Electric Mid-Course Adjustment to Fuel Recovery
In July 2021, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges, effective with September 2021 customer bills, due to an increase in fuel commodity and capacity costs in 2021. On August 3, 2021, the FPSC approved the request to recover $83 million of additional costs during the months of September through December 2021.
In January 2022, Tampa Electric requested a mid-course adjustment to its fuel and capacity charges to recover an additional $169 million beginning April 1, 2022 through December 2022 due to an increase in fuel commodity and capacity costs. On March 1, 2022, the FPSC voted to approve the mid-course adjustment, and the order reflecting such approval was issued on March 18, 2022.
On January 23, 2023, Tampa Electric requested an adjustment to its fuel charges to recover the $518 million final 2022 fuel under-recovery over a period of 21 months. The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $170 million for the balance of 2023. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023.
Tampa Electric Storm Protection Cost Recovery Clause and Settlement Agreement
On October 3, 2019, the FPSC issued a rule to implement a Storm Protection Plan (SPP) Cost Recovery Clause. This clause provides a process for Florida investor-owned utilities, including Tampa Electric, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. A settlement agreement was approved on August 10, 2020 and Tampa Electric’s cost recovery began in January 2021. The current approved plan addresses the years 2020, 2021 and 2022, and in April 2022 Tampa Electric submitted a new plan to determine cost recovery in 2023, 2024, and 2025. On October 4, 2022, the FPSC approved Tampa Electric’s SPP.
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. This provision was also included in Tampa Electric’s subsequent 2017 amended and restated settlement agreement and in Tampa Electric’s 2021 rate case settlement agreement. In 2021, 2020 and 2019, Tampa Electric incurred total storm restoration preparation costs for multiple hurricanes of approximately $10 million, which was charged to the storm reserve regulatory liability.
In September 2022, Tampa Electric was impacted by Hurricane Ian. The majority of Hurricane Ian restoration costs were charged against Tampa Electric’s FPSC approved storm reserve, resulting in minimal impact on earnings and capital expenditures. Total restoration costs were $126 million, with $119 million charged to the storm reserve. Restoration costs charged to the storm reserve exceed the reserve balance and this amount will be deferred and collected from customers in subsequent periods. In November 2022, Tampa Electric incurred costs of approximately $2 million related to Hurricane Nicole. In January 2023, Tampa Electric petitioned the FPSC for recovery of storm costs. Recovery will include costs associated with Hurricanes Ian and Nicole that exceeded the reserve, $10 million of storm restoration costs charged to the reserve since 2018, and the replenishment of the balance in the reserve to the $56 million level that existed as of October 31, 2013 for a total of approximately $131 million. The proposed changes will be decided by the FPSC in March 2023, and recovery is expected to begin in April 2023 through March 2024.
PGS Base Rates
PGS’s base rates for 2022 and 2021 were established in 2020, and its base rates for 2020 were originally established in May 2009.
On February 7, 2017, the FPSC approved a settlement agreement filed by PGS and the OPC in which PGS agreed to adopt 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 would 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% would continue to be used for the calculation of return on investment for clauses and riders. The allowed equity in its capital structure was 54.7% from all investor sources of capital.
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 and OPC. The settlement agreement provides for an increase in base rates by $58 million annually effective January 2021, which is a $34 million increase in revenue and $24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint, including the ability to reverse a total of $34 million of accumulated depreciation through 2023. During 2022, PGS reversed $14 million of the $34 million accumulated depreciation. No amounts were reversed prior to 2022. In addition, the agreement sets new depreciation rates effective January 1, 2021 that are consistent with PGS’s current overall average depreciation rate. Under the agreement, base rates are frozen from January 1, 2021 to December 31, 2023, unless its earned ROE were to fall below 8.90% before that time with an allowed equity in the capital structure of 54.7% from investor sources of capital. The settlement agreement further addresses tax rate changes. The agreement contains a provision whereby PGS agrees to quantify the future impact of a decrease in tax rates on net operating income through a reduction in base revenues within 120 days of when such tax change becomes law. If on the contrary, tax legislation results in a tax rate increase, PGS can establish a regulatory asset to neutralize the impact of the increase in income tax rate to be addressed in a future proceeding and with recovery beginning no sooner than January 2024.
PGS Storm Restoration Cost Recovery
On September 28, 2022, Hurricane Ian made landfall in Southwest Florida, impacting PGS’s Fort Myers and Sarasota areas. The restoration costs were approximately $2 million and were charged against PGS’s FPSC-approved storm reserve, resulting in minimal impact on earnings. PGS recorded the $1 million above the storm reserve balance of $1 million as a regulatory asset for future recovery as of December 31, 2022.
Regulatory Assets and Liabilities
Details of the regulatory assets and liabilities are presented in the following table:
Regulatory Assets and Liabilities
December 31,
December 31,
(millions)
Regulatory assets:
Regulatory tax asset (1)
$
$
Cost-recovery clauses (2)
Capital cost recovery for early retired assets (3)
Environmental remediation (4)
Postretirement benefits (5)
Asset retirement obligation (6)
Storm reserve (7)
Other
Total regulatory assets
1,552
1,002
Less: Current portion
Long-term regulatory assets
$
1,191
$
Regulatory liabilities:
Regulatory tax liability (8)
$
$
Cost-recovery clauses - deferred balances (2)
Accumulated reserve-cost of removal (9)
Storm reserve (7)
Other
Total regulatory liabilities
1,140
1,170
Less: Current portion
Long-term regulatory liabilities
$
1,055
$
1,092
(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 corporate income tax rate reduction.
(2)These assets and liabilities are related to FPSC clauses and riders, primarily related to the fuel clause and the increase in natural gas prices as well as the storm protection plan cost recovery clause. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in a subsequent period.
(3)This regulatory asset is related to the remaining net book value of Big Bend Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and will be recovered as a separate line item on customer bills for a period of 15 years. See “Tampa Electric Big Bend Modernization Project” above for further information.
(4)This asset 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.
(5)This asset is related to the deferred costs of postretirement benefits and it is amortized over the remaining service life of plan participants. Deferred costs of postretirement benefits that are included in expense are recognized as cost of service for rate-making purposes as permitted by the FPSC.
(6)This asset is related to costs associated with an asset retirement obligation, which is a legal obligation for the future retirement of certain tangible, long-lived assets. This regulatory asset does not earn a return because it is offset with related assets and liabilities within rate base. It is recovered and removed as the obligation is settled and removed as the activities for the retirement of the related assets have been completed.
(7)See "Tampa Electric Storm Restoration Cost Recovery" and "PGS Storm Restoration Cost Recovery" above for information regarding this reserve. The regulatory asset is included in rate base and earns a rate of return as permitted by the FPSC. The timing of recovery is expected to be determined by a petition approved by the FPSC.
(8)The regulatory tax liability is primarily related to the revaluation of TEC’s deferred income tax balances recorded on December 31, 2017 at the lower corporate income tax rate due to U.S. tax reform. The liability related to the revaluation of the deferred income tax balances is amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and the settlement agreement for tax reform benefits approved by the FPSC.
(9)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.
4. Income Taxes
Change in Florida Corporate Income Tax Rate
On September 14, 2021, the state of Florida issued a corporate tax rate reduction from 4.46% to 3.53% effective January 1, 2021 through December 31, 2021. In 2021, TEC recorded a $4 million regulatory liability in recognition of its obligation to pass the tax rate reduction expense benefit to customers per the 2017 settlement agreement. Effective January 1, 2022, the Florida corporate income tax rate is 5.5%.
Inflation Reduction Act
On August 16, 2022, the Inflation Reduction Act was signed into legislation and includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024, and introduces new technology-neutral clean energy related credits beginning in 2025. TEC has determined that electing production tax credits for its solar plants placed in service in 2022 will be more beneficial for customers compared to ITCs and has recorded a $7 million regulatory liability in recognition of its obligation to pass the tax benefits to customers.
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 2022, 2021 and 2020, TEC recorded net tax provisions of $121 million, $80 million and $82 million, respectively.
Income tax expense consists of the following components:
Income Tax Expense (Benefit)
(millions)
For the year ended December 31,
Current income taxes
Federal
$
(13
)
$
$
State
(3
)
(7
)
Deferred income taxes
Federal
State
Investment tax credits amortization
(6
)
(9
)
(7
)
Total income tax expense
$
$
$
During 2022, TEC increased its net operating loss carryforward. Total current income tax expense for the year ended December 31, 2022, was reduced by $59 million to reflect the benefits of operating loss carryforwards.
For the three years presented, the overall effective tax rate differs from the U.S. federal statutory rate as presented below:
Effective Income Tax Rate
(millions)
For the year ended December 31,
Income before provision for income taxes
$
$
$
Federal statutory income tax rates
%
%
%
Income taxes, at statutory income tax rate
Increase (decrease) due to
State income tax, net of federal income tax
Excess deferred tax amortization
(25
)
(26
)
(26
)
ITC amortization
(6
)
(9
)
(7
)
AFUDC-equity
(7
)
(9
)
(6
)
Tax credits
(9
)
(3
)
(8
)
Other
Total income tax expense on consolidated statements of income
$
$
$
Income tax expense as a percent of income before income taxes
18.3
%
15.2
%
16.2
%
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,
Deferred tax liabilities (1)
Property related
$
1,318
$
1,210
Deferred fuel
Pension and postretirement benefits
Insurance reserves
Total deferred tax liabilities
1,577
1,329
Deferred tax assets (1)
Loss and credit carryforwards (2)
Medical benefits
Insurance reserves
Pension and postretirement benefits
Capitalized energy conservation assistance costs
Other
Total deferred tax assets
Total deferred tax liability, net
$
1,045
$
(1)Certain property related assets and liabilities have been netted. At December 31, 2022, PGS total deferred tax liabilities and deferred tax assets were $213 million and $37 million, respectively, with the majority of the balances related to property and capitalized energy conservation assistance costs.
(2)Deferred tax assets for net operating loss and tax credit carryforwards have been reduced by unrecognized tax benefits of $9 million and $6 million at December 31, 2022 and 2021, respectively.
The expiration of TEC's tax credits and NOL carryforwards are as follows:
(millions)
December 31, 2022
Expiration Year
General business credits
$
2027-2042
Federal NOL carryforwards
2032-2037
Federal NOL carryforwards (1)
indefinite
State NOL carryforwards
2032-2037
State NOL carryforwards (1)
indefinite
Total tax credits and NOL carryforwards
$
1,223
(1)Indefinite carryforward for Federal NOLs and NOLs for states that have adopted the U.S. Tax Cuts and Jobs Act of 2017 provisions, generated in tax years beginning after December 31, 2017.
TEC has unused general business credits of $304 million expiring between 2027 and 2042, of which $264 million relate to ITCs expiring between 2034 and 2041. As a result of TECO Energy's merger with Emera in 2016, TECs NOLs and credits will be utilized by EUSHI, in accordance with the benefits-for-loss allocation which provide that tax attributes are utilized by the consolidated tax return group of EUSHI.
Unrecognized Tax Benefits
TEC accounts for uncertain tax positions as required by U.S. GAAP. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize in its financial statements the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates that it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination, including resolution of any related appeals and litigation processes.
The following table provides details of the change in unrecognized tax benefits as follows:
(millions)
Balance at January 1,
$
$
$
Decreases due to tax positions related to prior year
(2
)
Increases due to tax positions related to prior year
Increases due to tax positions related to current year
Decreases due to settlements with tax authorities
(5
)
Balance at December 31,
$
$
$
As of December 31, 2022 and 2021, TEC’s uncertain tax positions for federal R&D tax credits were $9 million and $6 million, respectively, all of which was recorded as a reduction of deferred income tax assets for tax credit carryforwards. TEC’s unrecognized federal tax benefits decreased in 2021 and 2020 by approximately $5 million and $2 million, respectively, due to the resolution of its 2016 federal tax credits issue with IRS Appeals. The recognition of the 2020 tax benefits decreased the effective tax rate resulting in an income tax benefit of approximately $2 million in 2020. The settlement of the federal R&D credits audit did not impact the effective tax rate during 2021. TEC had $9 million and $6 million of unrecognized tax benefits at December 31, 2022 and 2021, respectively, 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 2022, 2021 and 2020, 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, 2022, 2021 and 2020.
The IRS concluded the Compliance Assurance Program (CAP) audit for the short tax year ending June 30, 2016 and the EUSHI 2016 federal consolidated tax return, which includes TEC's short tax year ending December 31, 2016. The U.S. federal statute of limitations remains open for the year 2017 and forward. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized.
5. Employee Postretirement Benefits
Pension Benefits
TEC is a participant in the 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.
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.
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)
Change in benefit obligation
Benefit obligation at beginning of year
$
$
$
$
Service cost
Interest cost
Plan participants’ contributions
Benefits paid
(79
)
(77
)
(19
)
(17
)
Actuarial gain
(142
)
(32
)
(50
)
(6
)
Plan settlements (3)
(4
)
Benefit obligation at end of year
$
$
$
$
Change in plan assets
Fair value of plan assets at beginning of year
$
$
$
$
Actual (loss) return on plan assets
(214
)
Employer contributions
Employer direct benefit payments
Plan participants’ contributions
Benefits paid
(78
)
(76
)
Direct benefit payments
(1
)
(1
)
(19
)
(17
)
Plan settlements (3)
(4
)
Fair value of plan assets at end of year (1)
$
$
$
$
(1)The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.
(2)Represent amounts for TECO Energy’s Florida-based other postretirement benefit plan.
(3)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.
Decreases in the benefit obligation for the period ended December 31, 2022 are the result of increases in the discount rate used to calculate the benefit obligation, annual benefits paid to participants, incorporation of new census data as of January 1, 2022 and the updating of the retirement rate as the result of an experience study performed during the year.
At December 31, the aggregate financial position for TECO Energy pension plans and Florida-based other postretirement plans with projected benefit obligations and accumulated projected benefit obligations in excess of plan assets was as follows:
TECO Energy
Pension Benefits
Other Benefits (1)
Funded Status
(millions)
Benefit obligation (PBO/APBO)
$
$
$
$
Less: Fair value of plan assets
Funded status at end of year
$
(16
)
$
$
(142
)
$
(200
)
(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 $634 million at December 31, 2022 and $819 million at December 31, 2021.
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)
Noncurrent assets
$
$
$
$
Accrued benefit costs and other current liabilities
(7
)
(3
)
(12
)
(12
)
Deferred credits and other liabilities
(9
)
(12
)
(121
)
(175
)
$
(16
)
$
$
(133
)
$
(187
)
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)
Net actuarial loss
$
$
$
$
Amount recognized
$
$
$
$
Assumptions used to determine benefit obligations at December 31:
Pension Benefits
Other Benefits
Discount rate
5.55
%
2.77
%
5.53
%
2.84
%
Rate of compensation increase
3.79
%
3.05
%
3.79
%
3.04
%
Healthcare cost trend rate
Immediate rate
n/a
n/a
6.39
%
5.61
%
Ultimate rate
n/a
n/a
4.00
%
4.00
%
Year rate reaches ultimate trend rate
n/a
n/a
The discount rate assumption used to determine the December 31, 2022 and 2021 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)
(millions)
Service cost
$
$
$
$
$
$
Interest cost
Expected return on plan assets
(51
)
(52
)
(50
)
Amortization of:
Actuarial loss
Prior service (benefit) cost
(2
)
(2
)
(3
)
Settlement loss
(2)
Net periodic benefit cost
$
$
$
$
$
$
Net loss (gain) arising during the year (includes curtailment gain)
$
$
(56
)
$
(8
)
$
(50
)
$
(5
)
$
Amounts recognized as component of net periodic benefit cost:
Amortization or curtailment recognition of prior service credit
Amortization or settlement of actuarial loss
(19
)
(23
)
(20
)
(3
)
(4
)
(1
)
Total recognized in OCI and regulatory assets
$
$
(79
)
$
(28
)
$
(51
)
$
(7
)
$
Total recognized in net periodic benefit cost, OCI and regulatory assets
$
$
(67
)
$
(12
)
$
(43
)
$
$
(1)Represents amounts for TECO Energy’s Florida-based other postretirement benefit plan
(2)Represents TECO Energy’s SERP and Restoration settlement charges as a result of the retirement of certain executives. These charges did impact TEC’s financial statements.
TEC’s portion of the net periodic benefit costs for pension benefits was $8 million, $10 million and $12 million for 2022, 2021 and 2020, respectively. Tampa Electric’s portion of the net periodic benefit costs for pension benefits was $4 million, $7 million and $10 million for 2022, 2021 and 2020, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $9 million, $11 million and $7 million for 2022, 2021 and 2020, respectively. Tampa Electric’s portion of the net periodic benefit costs for other benefits was $8 million, $9 million and $6 million for 2022, 2021 and 2020, respectively. TEC’s and Tampa Electric’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”.
Assumptions used to determine net periodic benefit cost for years ended December 31:
Pension Benefits
Other Benefits
Discount rate
2.77
%
2.37
%
3.21
%
2.84
%
2.47
%
3.32
%
Expected long-term return on plan assets
6.50
%
6.70
%
7.00
%
n/a
n/a
n/a
Rate of compensation increase
3.05
%
3.08
%
3.79
%
3.04
%
3.07
%
3.79
%
Healthcare cost trend rate
Initial rate
n/a
n/a
n/a
5.61
%
5.74
%
6.03
%
Ultimate rate
n/a
n/a
n/a
4.00
%
4.50
%
4.50
%
Year rate reaches ultimate trend rate
n/a
n/a
n/a
The discount rate assumption used to determine the benefit cost for 2022, 2021 and 2020 was based on the same technique that was used to determine the December 31, 2022 and 2021 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, 2022, TECO Energy’s pension plan’s actual loss was approximately 23.5%.
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
Target Allocation
Target Allocation
Actual Allocation, End of Year
Asset Category
Equity securities
50%-70%
50%-70%
%
%
Fixed income securities
30%-50%
30%-50%
%
%
Total
%
%
%
%
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, 2022
(millions)
Level 1
Level 2
Level 3
Using NAV (1)
Total
Cash
$
$
$
$
$
Accounts receivable
Accounts payable
(62
)
(62
)
Short-term investment funds (STIFs)
Real estate investment trusts (REITs)
Mutual funds
Municipal bonds
Government bonds
Corporate bonds
Mortgage backed securities (MBS)
Collateralized mortgage obligations (CMOs)
Short Sales
(3
)
(3
)
Written Options
Swaps
(1
)
(1
)
Investments not utilizing the practical expedient
Common and collective trusts (1)
Mutual fund (1)
Total investments
$
$
$
$
$
(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, 2021
(millions)
Level 1
Level 2
Level 3
Using NAV (1)
Total
Cash
$
$
$
$
$
Accounts receivable
Accounts payable
(70
)
(70
)
Short-term investment funds (STIFs)
Common stocks
Real estate investment trusts (REITs)
Mutual funds
Municipal bonds
Government bonds
Corporate bonds
Mortgage backed securities (MBS)
Collateralized mortgage obligations (CMOs)
Short Sales
(2
)
(2
)
Long Futures
Swaps
Investments not utilizing the practical expedient
Common and collective trusts (1)
Mutual fund (1)
Total investments
$
$
$
$
$
(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.
•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, 2022.
•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, 2022.
•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 $8 million and $10 million of assets as of December 31, 2022 and 2021, 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, 2022 and 2021.
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 129.22% of the Pension Protection Act funded target as of January 1, 2022 and is estimated at 118.00% of the Pension Protection Act funded target as of January 1, 2023.
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 2022, 2021 and 2020, which met the minimum funding requirements for 2022, 2021 and 2020. TEC’s portion of the contribution in 2022 was $15 million, in 2021 was $17 million and in 2020 was $16 million. Tampa Electric’s portion of the contribution was $12 million in 2022, $14
million in 2021 and $13 million 2020. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TEC estimates its portion of the 2023 contribution to be $13 million. Tampa Electric estimates its portion of the 2023 contribution to be $11 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 2022, 2021 and 2020 was zero. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2023. TEC made SERP payments of approximately $2 million, $1 million and $1 million from the trust in 2022, 2021 and 2020, respectively, and expects to make a SERP payment of approximately $5 million from the trust in 2023.
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 2023, TEC expects to make a contribution of approximately $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)
$
$
2028-2032
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, 2022, 2021 and 2020, TEC’s portion of expense totaled $22 million, $22 million and $21 million, respectively, related to the matching contributions made to this plan. Tampa Electric’s portion of expense totaled $19 million, $18 million and $20 million, respectively, related to the matching contributions made to this plan. The expense related to the matching contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.
Effective October 21, 2019, TECO Energy amended the defined contribution plan such that certain participants covered by the IBEW collective bargaining agreement shall not be eligible to participate in the plan for purposes of receiving the fixed matching contribution. This has been replaced with a non-elective employer contribution on a bi-weekly basis equal to a percentage of the member’s compensation for that period based on years of tenure of employment. For the years ended December 31, 2022, 2021 and 2020, Tampa Electric recognized expense totaling $10 million, $10 million and $9 million, respectively, related to the contributions made to this plan. The expense related to this contribution is included on the Consolidated Statements of Income in “Operations & maintenance”.
6. Short-Term Debt
Credit Facilities
December 31, 2022
December 31, 2021
Borrowings
Borrowings
Letters
Borrowings
Borrowings
Letters
Credit
Outstanding -
Outstanding -
of Credit
Credit
Outstanding -
Outstanding -
of Credit
(millions)
Facilities
Credit Facilities (1)
Commercial Paper (1)
Outstanding
Facilities
Credit Facilities (1)
Commercial Paper (1)
Outstanding
5-year facility (2)
$
$
$
$
$
$
$
$
1-year term facility (3)
Total
$
1,200
$
$
$
$
1,300
$
$
$
(1)Borrowings outstanding are reported as notes payable in the Consolidated Balance Sheets.
(2)This 5-year facility matures on December 17, 2026. TEC also has an active commercial paper program for up to $800 million, of which the full amount outstanding is backed by TEC’s credit facility. The amount of commercial paper issued results in an equal amount of its credit facility being considered drawn and unavailable.
(3)This 1-year term facility was set to mature on December 16, 2022. On December 13, 2022, TEC extended the maturity date to December 13, 2023.
At December 31, 2022, this credit facility required a commitment fee of 12.5 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities and commercial paper at December 31, 2022 and 2021 was 5.00% and 0.58%, respectively.
Commercial Paper Program
On May 25, 2021, TEC established a commercial paper program (the Program) under which TEC may issue on a private placement basis unsecured commercial paper notes (the Notes). Amounts available under the Program may be borrowed, repaid and reborrowed with the aggregate amount of the Notes outstanding under the Program at any time not to exceed $800 million. The maturities of the Notes will vary, but may not exceed 270 days from the date of issue. The rates of interest will depend on whether the Note will be a fixed or floating rate. TEC must have credit facilities in place, at least equal to the amount of its commercial paper program. TEC cannot issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
TEC Term Loan
On December 13, 2022, TEC extended the maturity date of its $500 million credit agreement that was set to mature on December 16, 2022 and reduced the amount of the loan to $400 million. The credit agreement has a maturity date of December 13, 2023; contains customary representations and warranties, events of default, and financial and other covenants; and provides for interest to accrue at variable rates based on either the term secured overnight financing rate (SOFR), Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin.
5-Year Credit Facility
On December 17, 2021, TEC amended and restated its $800 million bank credit facility, entering into a Seventh Amended and Restated Credit Agreement. The amendment extended the maturity date of the credit facility from March 22, 2023 to December 17, 2026 (subject to further extension with the consent of each lender); and provided for an interest rate based on either the London interbank deposit rate, Wells Fargo Bank’s prime rate, or the federal funds rate, plus a margin; allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $100 million in the aggregate; and made other technical changes.
7. Long-Term Debt
A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time.
TEC 3.875% Notes due 2024 and 5.00% Notes due 2052
On July 12, 2022, TEC completed a sale of (i) $300 million aggregate principal amount of 3.875% Notes due July 12, 2024 (the 2024 Notes) and (ii) $300 million aggregate principal amount of 5.00% Notes due July 15, 2052 (the 2052 Notes, and collectively, the Notes). Until July 12, 2024, in the case of the 2024 Notes, or January 15, 2052, in the case of the 2052 Notes, TEC may redeem all or any part of such series of Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of such series of Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the Notes to be redeemed that would be due if the Notes matured on (a) July 12, 2024, in the case of the 2024 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate (as defined in the Indenture), plus 15 basis points, or (b) July 15, 2052, in the case of the 2052 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, plus 30 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after January 15, 2052, in the case of the 2052 Notes, TEC may, at its option, redeem the 2052 Notes, in whole or in part, at 100% of the principal amount of such series of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.
TEC 2.40% Notes due 2031 and 3.45% Notes due 2051
On March 18, 2021, TEC completed a sale of (i) $400 million aggregate principal amount of 2.40% Notes due March 15, 2031 (the 2031 Notes) and (ii) $400 million aggregate principal amount of 3.45% Notes due March 15, 2051 (the 2051 Notes, and collectively, the Notes). Until December 15, 2030, in the case of the 2031 Notes, or September 15, 2050, in the case of the 2051 Notes, TEC may redeem all or any part of such series of Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of such series of Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the Notes to be redeemed that would be due if the Notes matured on (a) December 15, 2030, in the case of the 2031 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate (as defined in the Indenture), plus 15 basis points, or (b) September 15, 2050, in the case of the 2051 Notes, discounted to the redemption date on a semiannual basis at the applicable treasury rate, plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after December 15, 2030, in the case of the 2031 Notes or September 15, 2050, in the case of the 2051 Notes, TEC may, at its option, redeem such series of the Notes, in whole or in part, at 100% of the principal amount of such series of the Notes being redeemed plus accrued and unpaid interest thereon to, but excluding, the date of redemption.
8. Commitments and Contingencies
Legal Contingencies
From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss.
Superfund and Former Manufactured Gas Plant Sites
As of December 31, 2022, TEC, through its Tampa Electric division and former PGS division, was a PRP for certain superfund sites and, through its former PGS division, for certain former MGP sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of December 31, 2022 and 2021, TEC estimated its ultimate financial liability to be $13 million and $14 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 that was attributable to TEC. The estimates to perform the work were 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 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, 2022:
Purchased
Capital
Fuel and Gas
Long-term Service
Operating
Demand Side
(millions)
Power
Transportation(1)(3)
Projects
Supply(2)
Agreements
Leases
Management
Total
Year ended December 31:
$
$
$
$
$
$
$
$
Thereafter
1,914
1,993
Total future minimum payments
$
$
3,160
$
$
$
$
$
$
4,063
(1)As of December 31, 2022, $106 million is related to a gas transportation contract through 2040 between PGS and SeaCoast, a related party.
(2)As of December 31, 2022, $45 million is related to fuel and gas supply contractual obligations between Tampa Electric and Emera Energy Services, a related party.
(3)As of December 31, 2022, $1,518 million is related to transportation contracts held by Tampa Electric.
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, 2022 and 2021, TEC was in compliance with all required financial covenants.
9. Revenue
The following disaggregates TEC’s revenue by major source:
(millions)
Tampa
Tampa Electric
For the year ended December 31, 2022
Electric
PGS
Eliminations
Company
Electric revenue
Residential
$
1,381
$
$
$
1,381
Commercial
Industrial
Regulatory deferrals and unbilled revenue
(12
)
(12
)
Other (1)
(4
)
Total electric revenue
2,523
(4
)
2,519
Gas revenue
Residential
Commercial
Industrial (2)
Other (3)
(6
)
Total gas revenue
(6
)
Total revenue
$
2,523
$
$
(10
)
$
3,169
For the year ended December 31, 2021
Electric revenue
Residential
$
1,156
$
$
$
1,156
Commercial
Industrial
Regulatory deferrals and unbilled revenue
(8
)
(8
)
Other (1)
(4
)
Total electric revenue
2,174
(4
)
2,170
Gas revenue
Residential
Commercial
Industrial (2)
Other (3)
(3
)
Total gas revenue
(3
)
Total revenue
$
2,174
$
$
(7
)
$
2,695
For the year ended December 31, 2020
Electric revenue
Residential
$
1,018
$
$
$
1,018
Commercial
Industrial
Regulatory deferrals and unbilled revenue
(25
)
(25
)
Other (1)
(4
)
Total electric revenue
1,849
(4
)
1,845
Gas revenue
Residential
Commercial
Industrial (2)
Other (3)
(6
)
Total gas revenue
(6
)
Total revenue
$
1,849
$
$
(10
)
$
2,272
(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, 2022 and 2021, the aggregate amount of the transaction price allocated to remaining performance obligations was approximately $140 million and $135 million, respectively. The 2022 amount includes $11 million of future performance obligations related to an asset management agreement with Emera Energy, a related party, through 2025. 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 2042.
10. Related Party Transactions
A summary of activities between TEC and its affiliates follows:
Net transactions with affiliates:
(millions)
Natural gas sales to/(from) affiliates
$
(232
)
$
(236
)
$
(139
)
Services received from affiliates
Dividends to TECO Energy
Equity contributions from TECO Energy
Amounts due from or to affiliates at December 31,
(millions)
Accounts receivable related to asset management agreements to Emera Energy Services Inc. (1)
$
$
Accounts receivable excluding asset management agreements (1)
Taxes receivable (2)
Accounts payable (1)
Note payable to TECO Energy (3)
Taxes payable (2)
(1)Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
(2)Taxes receivable were due from EUSHI and taxes payable were due to EUSHI. See Note 4 for additional information.
(3)The note payable with TECO Energy bears interest at a rate approximating the market rate of TEC's commercial paper.
On January 1, 2023, TEC entered into an intercompany loan agreement with PGSI. See "Separation of PGS from TEC" in Note 1 for further 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 826,700 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 468,000 residential, commercial, industrial and electric power generation customers in the State of Florida.
Tampa
(millions)
Electric
PGS
Eliminations
TEC
Revenues - external
$
2,519
$
$
$
3,169
Sales to affiliates
(10
)
Total revenues
2,523
(10
)
3,169
Depreciation and amortization
Total interest charges
Provision for income taxes
Net income
Total assets
12,064
2,471
(732
)
(1)
13,803
Capital expenditures
1,099
1,427
Revenues - external
$
2,170
$
$
$
2,695
Sales to affiliates
(7
)
Total revenues
2,174
(7
)
2,695
Depreciation and amortization
Total interest charges
Provision for income taxes
Net income
Total assets
10,650
2,209
(663
)
(1)
12,196
Capital expenditures
1,081
1,397
Revenues - external
$
1,845
$
$
$
2,272
Sales to affiliates
(10
)
Total revenues
1,849
(10
)
2,272
Depreciation and amortization
Total interest charges
Provision for income taxes
Net income
Total assets
9,800
1,901
(653
)
(1)
11,048
Capital expenditures
1,028
1,361
(1)Amounts relate to consolidated deferred tax reclassifications. Deferred tax assets are reclassified and netted with deferred tax liabilities upon consolidation.
12. Asset Retirement Obligations
Tampa Electric accounts for AROs at fair value at inception of the obligation if there is a legal obligation under applicable law, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. When the liability is initially recorded in “Deferred credits and other liabilities” in the Consolidated Balance Sheets, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The ARO estimates are reviewed quarterly. Any updates are revalued based on current market prices.
Reconciliation of beginning and ending carrying amount of asset retirement obligations:
December 31,
(millions)
Beginning balance
$
$
Additional liabilities
Liabilities settled (1)
(9
)
Other
Ending balance
$
$
(1)Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The decrease in the ARO in 2021 is due to the closure of CCR management facilities.
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. All contracts for which TEC is the lessee are held by Tampa Electric, and all contracts for which TEC is the lessor are held by PGS.
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
Tampa Electric has operating leases for buildings, land, telecommunication services and rail cars. Tampa Electric’s leases have remaining lease terms of 1 year to 64 years, some of which include options to extend the leases for up to an additional 65 years. These options are included as part of the lease term when it is considered reasonably certain that they will be exercised.
(millions)
Classification
December 31, 2022
December 31, 2021
Right-of-use asset
Deferred charges and other assets
$
$
Lease liabilities
Current
Other current liabilities
$
$
Long-term
Deferred credits and other liabilities
Total lease liabilities
$
$
Tampa Electric has recorded operating lease expense for the year ended December 31, 2022, 2021 and 2020 of $4 million, $5 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, 2022:
(millions)
Year ended December 31:
Thereafter
Total
Minimum lease payments
$
$
$
$
$
$
$
Less imputed interest
(32
)
Total future minimum payments
$
Additional information related to Tampa Electric’s leases is as follows:
Year ended December 31,
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases (millions)
$
$
Weighted average remaining lease term (years)
Weighted average discount rate - operating leases
4.4
%
4.4
%
Lessor
The net investment in direct finance leases consists of the following:
(millions)
December 31, 2022
December 31, 2021
Total minimum lease payments to be received
$
$
Less amounts representing estimated executory costs
(11
)
Minimum lease payments receivable
$
$
Less unearned finance lease income
(9
)
Net investment in direct finance and sales-type leases
$
$
Principal due within one year (included in "Receivables")
(2
)
Net investment in direct finance and sales-type leases - long-term (included in "Deferred charges and other assets")
$
$
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. The PGS customers had the option to purchase the assets related to the CNG stations at any time after year five of the agreements, which was in 2021, by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return. This option was exercised on both CNG stations in 2022.
14. Fair Value Measurements
Items Measured at Fair Value on a Recurring Basis
Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As a basis for considering assumptions that market participants would use in pricing an asset or liability, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
Level 1:
Observable inputs, such as quoted prices in active markets;
Level 2:
Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and
Level 3:
Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.
There were no Level 3 assets or liabilities for the periods presented.
As of December 31, 2022 and 2021, the fair value of TEC’s short-term debt was not materially different from the carrying value due to the short-term nature of the instruments and because the stated rates approximate market rates. The fair value of TEC’s short-term debt is determined using Level 2 measurements.
See Note 5 and Consolidated Statements of Capitalization for information regarding the fair value of the pension plan investments and long-term debt, respectively.
15. Stock-Based Compensation
Emera has a performance share unit (PSU) plan and a restricted share unit (RSU) plan. The PSU and RSU liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Emera common shares are traded on the Toronto Stock Exchange under the symbol EMA.
Performance Share Unit Plan
Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and are paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance.
PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the Emera Management Resources and Compensation Committee (MRCC) early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios.
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, 2021
47.74
Granted including DRIP
59.26
Exercised
(123
)
42.86
Forfeited
(51
)
44.41
Transferred
47.98
Outstanding as of December 31, 2022
56.21
Compensation cost recognized for the PSU plan for the years ended December 31, 2022, 2021 and 2020 was $4 million, $3 million and $8 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2022, 2021 and 2020 were $1 million, $1 million and $2 million, respectively. Cash payments made during the year ended December 31, 2022, 2021 and 2020 associated with the PSU plan were $7 million, $10 million and $9 million, respectively. As of December 31, 2022 and 2021, there was $3 million and $3 million, respectively, of unrecognized compensation cost related to non-vested PSUs that is expected to be recognized over a weighted-average period of two years.
Restricted Share Unit Plan
Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the RSU plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price.
RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios.
A summary of the activity related to TEC employee RSUs is presented in the following table:
Weighted
Aggregate
Number of
Average Grant
Intrinsic
Units
Date Fair Value
Value
(Thousands)
(Per Unit)
(Millions)
Outstanding as of December 31, 2021
54.64
Granted including DRIP
59.31
Forfeited
(6
)
56.47
Outstanding as of December 31, 2022
56.23
Compensation cost recognized for the RSU plan for the years ended December 31, 2022, 2021 and 2020 was $3 million, $2 million and $1 million, respectively. Tax benefits related to this compensation cost for share units realized for the years ended December 31, 2022, 2021 and 2020 were $1 million, zero and zero, respectively. As of December 31, 2022 and 2021, there was $3 million and $3 million, respectively, of unrecognized compensation cost related to non-vested RSUs that is expected to be recognized over a weighted-average period of two years.
16. Long-Term PPAs
In 2019, Tampa Electric entered into a long-term PPA with a wholesale energy provider in Florida with up to 515 MW of available capacity, which expires in 2023. 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 $70 million, $46 million and $36 million under this long-term PPA for the three years ended December 31, 2022, 2021 and 2020, 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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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
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, 2022 (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, 2022 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, 2022.
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.

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ITEM 9B. OTHER INFORMATION
Item 9B. OTHER INFORMATION
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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
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
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Fees Paid by TEC to the Independent Auditors
The following table presents fees for professional audit services and other services rendered by Ernst & Young LLP for the audit of TEC’s annual financial statements and other services for the years ended December 31, 2022 and 2021, respectively.
Audit fees
$
694,800
$
503,300
Audit-related fees
17,600
Tax fees
Tax planning fees
128,696
18,393
Total
$
841,096
$
521,693
Audit fees consist of fees for professional services performed for (i) the audit of TEC’s annual financial statements (ii) the related reviews of the financial statements included in TEC’s 10-Q filings (iii) services related to securities offerings (iv) services that are normally provided in connection with statutory and regulatory filings or engagements.
Audit-related fees consist of fees for professional services that are reasonably related to the performance of the audit or review of our financial statements, such as required activities related to agreed upon procedures.
Tax fees consist of certain property tax planning fees.
Audit Committee Pre-Approval Policy
All services performed by the independent auditor are approved by the Audit Committee of the Emera Board of Directors in accordance with Emera’s pre-approval policy for services provided by the independent auditor.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)Certain Documents Filed as Part of this Form 10-K
1.Financial Statements
Tampa Electric Company Financial Statements
Reports of Independent Registered Public Accounting Firms (PCAOB ID: 42)
Consolidated Balance Sheets at December 31, 2022 and 2021
Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Capitalization for the Years Ended December 31, 2022, 2021 and 2020
Notes to Consolidated Financial Statements
2.Financial Statement Schedules
Tampa Electric Company Schedule II - Valuation and Qualifying Accounts and Reserves
3.Exhibits
(b)The exhibits filed as part of this Form 10-K are listed on the List of Exhibits below.
(c)The financial statement schedules filed as part of this Form 10-K are listed in paragraph (a)(2) above, and follow immediately.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
TAMPA ELECTRIC COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2022, 2021 and 2020
(millions)
Balance at
Additions
Balance at
Beginning
Charged to
Other
Payments &
End of
of Period
Income
Charges
Deductions (1)
Period
Allowance for Credit Losses:
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1)Write-off of individual bad debt accounts
LIST OF EXHIBITS
Exhibit
No.
Description
3.1
Restated Articles of Incorporation of Tampa Electric Company, as amended on November 30, 1982 (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company). (P)
*
3.2
Bylaws of Tampa Electric Company, as amended effective February 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of Tampa Electric Company).
*
4.1
Loan and Trust Agreement dated as of Jul. 2, 2007 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (including the form of Bond) (Exhibit 4.1, Form 8-K dated Jul. 25, 2007 of Tampa Electric Company).
*
4.2
First Supplemental Loan and Trust Agreement dated as of March 26, 2008 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1, Form 8-K dated March 26, 2008 of Tampa Electric Company).
*
4.3
Loan and Trust Agreement dated as of November 15, 2010 among Tampa Electric Company, Polk County Industrial Development Authority and The Bank of New York Mellon Trust Company, N.A., as trustee (including the form of bond) (Exhibit 4.1, Form 8-K dated November 23, 2010 of Tampa Electric Company).
*
4.4
Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee, dated as of January 5, 2006 (including the form of bond) (Exhibit 4.1, Form 8-K dated January 19, 2006 of Tampa Electric Company).
*
4.5
Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jul. 1, 1998 (Exhibit 4.1, Registration Statement No. 333-55873 of Tampa Electric Company).
*
4.6
Third Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jun. 15, 2001 (Exhibit 4.2, Form 8-K dated Jun. 25, 2001 of Tampa Electric Company).
*
4.7
Fifth Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of May 1, 2006 (Exhibit 4.16, Form 8-K dated May 12, 2006 of Tampa Electric Company).
*
4.8
Sixth Supplemental Indenture dated as of May 1, 2007 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.18, Form 8-K dated May 25, 2007 of Tampa Electric Company).
*
4.9
Seventh Supplemental Indenture dated as of May 1, 2008 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.20, Form 8-K dated May 16, 2008 of Tampa Electric Company).
*
4.10
Eighth Supplemental Indenture dated as of November 15, 2010 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee (including the form of 5.40% Notes due 2021) (Exhibit 4.1, Form 8-K dated December 9, 2010 of Tampa Electric Company).
*
4.11
Ninth Supplemental Indenture dated as of May 31, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.10% Notes due 2042) (Exhibit 4.23, Form 8-K dated June 5, 2012 for Tampa Electric Company).
*
4.12
Tenth Supplemental Indenture dated as of September 19, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing and amending the Indenture dated as of July 1, 1998, as amended (including the form of 2.60% Notes due 2022) (Exhibit 4.25, Form 8-K dated September 28, 2012 for Tampa Electric Company).
*
4.13
Eleventh Supplemental Indenture dated as of May 12, 2014 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.35% Notes due 2044) (Exhibit 4.27, Form 8-K dated May 15, 2014).
*
4.14
Twentieth Supplemental Indenture dated as of December 1, 2013 between Tampa Electric Company and US Bank, N.A., as successor trustee, amending and restating the Indenture of Mortgage among Tampa Electric Company, State
*
Street Trust Company and First Savings & Trust Company of Tampa, dated as of August 1, 1946 (Exhibit 4.30, Form 10-K for 2013 of Tampa Electric Company).
4.15
Twelfth Supplemental Indenture dated as of May 20, 2015, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.20% Notes due 2045) (Exhibit 4.24, Form 8-K dated May 20, 2015 of Tampa Electric Company).
*
4.16
Thirteenth Supplemental Indenture dated as of June 7, 2018, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.9, Form 8-K dated June 7, 2018 of Tampa Electric Company).
*
4.17
Fourteenth Supplemental Indenture dated as of October 4, 2018 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.11, Form 8-K dated October 4, 2018 of Tampa Electric Company).
*
4.18
Fifteenth Supplemental Indenture dated as of July 24, 2019, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.13, Form 8-K dated July 24, 2019 of Tampa Electric Company).
*
4.19
Sixteenth Supplemental Indenture dated as of March 18, 2021, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.9, Form 8-K dated March 18, 2021 of Tampa Electric Company).
*
4.20
Seventeenth Supplemental Indenture dated as of July 12, 2022, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (Exhibit 4.12, Form 8-K dated July 12, 2022 of Tampa Electric Company).
*
10.1
TECO Energy Group Supplemental Executive Retirement Plan, as amended and restated as of November 1, 2007 (Exhibit 10.1, Form 10-K for 2007 of Tampa Electric Company).
*
10.2
TECO Energy Group Supplemental Disability Income Plan, dated as of March 20, 1989 (Exhibit 10.22, Form 10-K for 1988 of TECO Energy, Inc.). (P)
*
10.3
TECO Energy Group Supplemental Benefits Trust Agreement effective as of January 1, 2020 (Exhibit 10.4, Form 10-K for 2019 of Tampa Electric Company).
*
10.4
TECO Energy Group Benefit Restoration Plan dated as of November 13, 2015 (Exhibit 10.4, Form 10-K for 2015 of Tampa Electric Company).
*
10.5
Insurance Agreement dated as of January 5, 2006 between Tampa Electric Company and Ambac Assurance Corporation (Exhibit 10.1, Form 8-K dated January 19, 2006 of Tampa Electric Company).
*
10.6
Amended and Restated Purchase and Contribution Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Originator, and TEC Receivables Corp., as the Purchaser (Exhibit 10.1, Form 8-K dated March 24, 2015 of TECO Energy, Inc.).
*
10.7
Loan and Servicing Agreement dated as of March 24, 2015, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent (Exhibit 10.2, Form 8-K dated March 24, 2015 of TECO Energy, Inc.).
*
10.8
Amendment No. 1 to Loan and Servicing Agreement dated as of August 10, 2016, among TEC Receivables Corp., as Borrower, Tampa Electric Company, as Servicer, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2016 of Tampa Electric Company).
*
10.9
Amendment No. 2 dated as of March 23, 2018 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders
*
named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 8-K dated March 23, 2018 of Tampa Electric Company).
10.10
Fifth Amended and Restated Credit Agreement dated as of March 22, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.1, Form 8-K dated March 22, 2017 of Tampa Electric Company).
*
10.11
Master Lenders’ Amendment and Consent dated as of December 19, 2019 to the Fifth Amended and Restated Credit Agreement dated as of March 22, 2017, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.12, Form 10-K for 2019 of Tampa Electric Company).
*
10.12
Credit Agreement dated as of February 6, 2020, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated February 6, 2020 of Tampa Electric Company).
*
10.13
Amendment No. 4 dated as of July 14, 2020 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2020 of Tampa Electric Company).
*
10.14
Amendment No. 5 dated as of October 30, 2020 to Loan and Servicing Agreement dated as of March 24, 2015, between Tampa Electric Company, as the Servicer, and TEC Receivables Corp., as the Borrower, certain lenders named therein, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Program Agent (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2020 of Tampa Electric Company).
*
10.15
Amendment No. 1 dated January 29, 2021 to Credit Agreement dated as of February 6, 2020, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.15, Form 10-K for 2020 of Tampa Electric Company).
*
10.16
Sixth Amended and Restated Credit Agreement dated as of December 18, 2020, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated December 18, 2020 of Tampa Electric Company).
*
10.17
Seventh Amended and Restated Credit Agreement dated as of December 17, 2021, among Tampa Electric Company, as Borrower, with Wells Fargo Bank, National Association, as Administrative Agent, and the Credit Facility Lenders party thereto (Exhibit 10.2, Form 8-K dated December 17, 2021 of Tampa Electric Company).
*
10.18
Credit Agreement dated as of December 17, 2021, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated December 17, 2021 of Tampa Electric Company).
*
10.19
Amended and Restated Credit Agreement dated as of December 14, 2022, among Tampa Electric Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated as of December 14, 2022 of Tampa Electric Company).
*
10.20
Contribution Agreement dated January 1, 2023 between Tampa Electric Company and Peoples Gas Systems, Inc. (Exhibit 10.1, Form 8-K dated January 1, 2023 of Tampa Electric Company).
*
10.21
Loan Agreement dated January 1, 2023 between Tampa Electric Company and Peoples Gas Systems, Inc. (Exhibit 10.2, Form 8-K dated January 1, 2023 of Tampa Electric Company).
*
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.
Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
99.1
Stipulation and Settlement Agreement, dated as of August 6, 2021, by and among Tampa Electric Company, the Office of Public Counsel, the Florida Industrial Power Users Group, Federal Executive Agencies, the Florida Retail Federation, Walmart, Inc., and the West Central Florida Hospital Utility Alliance (Exhibit 99.1, Form 10-Q for the quarter ended June 30, 2021 of Tampa Electric Company).
*
101.INS**
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the inline XBRL document.
101.SCH**
Inline XBRL Taxonomy Extension Schema Document.
101.CAL**
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF**
Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB**
Inline XBRL Taxonomy Label Linkbase Document.
101.PRE**
Inline XBRL Taxonomy Presentation Linkbase Document.
The cover page from TEC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 has been formatted in Inline XBRL.
(1)This certification accompanies the Annual Report on Form 10-K and is not filed as part of it.
* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.
Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.4, above are management contracts or compensatory plans or arrangements in which executive officers or directors of Tampa Electric Company participate.