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’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 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.

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.

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.

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’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.

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.

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

Regulatory Assets and Liabilities


	December 31,		December 31,
(millions)	2022		2021
Regulatory assets:
Regulatory tax asset (1)	$	124	$	117
Cost-recovery clauses (2)		525		89
Capital cost recovery for early retired assets (3)		497		518
Environmental remediation (4)		20		22
Postretirement benefits (5)		272		230
Asset retirement obligation (6)		13		11
Storm reserve (7)		76		0
Other		25		15
Total regulatory assets		1,552		1,002
Less: Current portion		361		136
Long-term regulatory assets	$	1,191	$	866
Regulatory liabilities:
Regulatory tax liability (8)	$	601	$	638
Cost-recovery clauses - deferred balances (2)		30		16
Accumulated reserve—cost of removal (9)		498		468
Storm reserve (7)		0		46
Other		11		2
Total regulatory liabilities		1,140		1,170
Less: Current portion		85		78
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.