On September 27, 2017, Tampa Electric filed with the FPSC an amended and restated settlement agreement that replaced the existing 2013 base rate settlement agreement and extended it another four years through December 31, 2021. The FPSC approved the agreement on November 6, 2017.

The amended agreement provides for SoBRAs for TEC’s investments in up to 600 MW of cost-effective solar generation. Tampa Electric has invested approximately $850 million during 2017 through 2021 related to 600 MW of solar projects recoverable under the SoBRAs, and AFUDC was accrued during construction.

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

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

On April 9, 2021, Tampa Electric requested a base rate increase, reflecting increased revenue requirements of $295 million, effective January 1, 2022. Tampa Electric’s proposed 2022 rates include recovery for the costs of the first phase of the Big Bend modernization project, 225 MW of utility-scale solar projects, the AMI investment, and accelerated recovery of the remaining net book value of retiring coal and other assets. Tampa Electric also requested approval for Generation Base Rate Adjustments for 2023 and 2024 that total approximately $130 million to recover the remaining investments in the Big Bend modernization project and additional utility-scale solar projects in subsequent years. A decision by the FPSC is expected by the end of 2021.

Tampa Electric expects to invest approximately $850 million during 2018 through 2023 to modernize the Big Bend Power Station, of which approximately $574 million has been invested through March 31, 2021. The Big Bend modernization project will repower Big Bend Unit 1 with natural gas combined-cycle technology and eliminate coal as this unit’s fuel. As part of the Big Bend modernization project, on June 1, 2020, Tampa Electric retired the Unit 1 components that will not be used in the modernized plant. At March 31, 2021 and December 31, 2020, Tampa Electric’s balance sheet included $200 million in electric utility plant and $89 million and $88 million, respectively, in accumulated depreciation related to Unit 1 components. In accordance with Tampa Electric’s 2017 settlement agreement approved by the FPSC, Tampa Electric will continue to account for its existing investment in Unit 1 in electric utility plant and depreciate the assets using the current depreciation rates until the FPSC approves Tampa Electric’s next depreciation and dismantlement study. In addition, Tampa Electric plans to retire Big Bend Unit 2 in 2021 as part of the Big Bend modernization project. In accordance with Tampa Electric’s 2017 settlement agreement, Tampa Electric was not required to request an asset recovery schedule for retired assets until the next depreciation study. On December 30, 2020, Tampa Electric filed a depreciation and dismantlement study and request for capital recovery schedule with the FPSC.

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

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

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

PGS’s 2020 base rates were established in 2009. In accordance with its 2017 settlement agreement, PGS had an allowed regulatory ROE range of 9.25% to 11.75%, reduced annual depreciation expense by $16 million, and accelerated the amortization of the regulatory asset associated with environmental remediation costs by $32 million over the period 2016 through 2020.

On June 8, 2020, PGS filed a petition for an increase in rates and service charges effective January 2021. On November 19, 2020, the FPSC approved a settlement agreement filed by PGS. The settlement agreement allows for an increase in base rates by $58 million annually effective January 2021, which is a $34 million increase in revenue and $24 million increase of revenues previously recovered through the cast iron and bare steel replacement rider. This settlement agreement includes an allowed regulatory ROE range of 8.90% to 11.00% with a 9.90% midpoint. It provides PGS the ability to reverse a total of $34 million of accumulated depreciation through 2023 and sets new depreciation rates 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.

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

Regulatory Assets and Liabilities
(millions)	March 31, 2021		December 31, 2020
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	96	$	90
Cost-recovery clauses ⁽²⁾		35		38
Environmental remediation⁽³⁾		23		22
Postretirement benefits ⁽⁴⁾		303		309
Asset retirement obligation ⁽⁵⁾		12		13
Other		11		13
Total regulatory assets		480		485
Less: Current portion		64		79
Long-term regulatory assets	$	416	$	406
Regulatory liabilities:
Regulatory tax liability⁽⁶⁾	$	691	$	691
Cost-recovery clauses ⁽²⁾		17		23
Accumulated reserve - cost of removal⁽⁷⁾		494		498
Storm reserve ⁽⁸⁾		48		48
Other		2		1
Total regulatory liabilities		1,252		1,261
Less: Current portion		62		67
Long-term regulatory liabilities	$	1,190	$	1,194

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

(2)

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

(3)

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

(4)

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

(5)

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

(6)

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

(7)

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

(8)

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. In 2019, Tampa Electric incurred storm restoration preparation costs for Hurricane Dorian of approximately $8 million, which was charged to the storm reserve regulatory liability.