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 cost of providing service, plus a reasonable return on invested capital.

Tampa Electric’s results for 2017 and 2016 reflect the stipulation and settlement agreement entered into on September 6, 2013, which resolved all matters in Tampa Electric’s 2013 base rate proceeding.

This agreement provided for an additional $110 million in base revenue effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%. The agreement provided that Tampa Electric could not file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% before that time. If its earned ROE were to rise above 11.25%, any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software.

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 described above and extended it another four years through 2021. The FPSC approved the agreement on November 6, 2017.

The amended agreement provides for SoBRAs for TEC’s substantial investments in solar generation. It includes the following potential revenue adjustments for the SoBRAs: $31 million for 150 MWs effective September 1, 2018, $51 million for 250 MWs effective January 1, 2019, $31 million for 150 MWs effective January 1, 2020, and an additional $10 million for 50 MWs effective on January 1, 2021. In order for each tranche of SoBRAs to take effect, Tampa Electric must show they are cost-effective and each individual project has a cost cap of $1,500/kWac. Additionally, in order to receive a SoBRA for the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1,475/kWac. The agreement includes a sharing provision that allows customers to benefit from 75% of any cost savings for projects below $1,500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects during the period from 2017 to 2021 and will accrue AFUDC 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.

The agreement further maintains Tampa Electric’s allowed regulatory ROE and allowed equity in the capital structure and extends the rate freeze date from January 1, 2018 to December 31, 2021, subject to the same ROE thresholds. The agreement further contains a provision whereby Tampa Electric agrees to quantify the impact of tax reform on net operating income and neutralize the impact of tax reform through a reduction in base revenues within 120 days of when tax reform becomes law. Additionally, any effects of tax reform between the effective date and the date the base rates are adjusted would be refunded through a one-time clause refund in 2019. See “Tampa Electric Tax Reform and Storm Settlement” below for information regarding the impact of tax reform. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are achieved is also included, and 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.

As a result of Tampa Electric’s 2013 rate case settlement, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56 million, the level of the reserve as of October 31, 2013. In the third quarter of 2017, Tampa Electric was impacted by Hurricane Irma and incurred storm restoration costs of approximately $102 million, of which $90 million was charged to the storm reserve, $3 million was charged to O&M expense and $9 million was charged to capital expenditures. At December 31, 2017, the amount of costs charged to the storm reserve regulatory liability exceeded the balance in the storm reserve by $47 million, which was recorded as a regulatory asset on the balance sheet as allowed by an FPSC order. This regulatory asset amount was eliminated in 2018 to reflect the effective recovery as discussed in Tampa Electric Tax Reform and Storm Settlement below. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated Hurricane Irma storm costs plus approximately $10 million in restoration costs from prior named storms and to replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. See the Regulatory Assets and Liabilities table below.

On March 1, 2018, the FPSC approved a settlement agreement filed by Tampa Electric that addressed both the recovery of storm costs and the return of tax reform benefits to customers (see Note 4) while keeping customer rates stable in 2018. Beginning on April 1, 2018, the agreement authorized Tampa Electric to net the estimated amount of storm cost recovery against Tampa Electric’s estimated 2018 tax reform benefits. As a result, during 2018, Tampa Electric recorded O&M expense and a reduction of the storm reserve regulatory asset of $47 million and O&M expense and an increase in the storm reserve regulatory liability of $56 million to reflect effective recovery of the storm costs due to the allowed netting of storm cost recovery with tax reform benefits. Tampa Electric’s final storm costs subject to netting will be determined in a separate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 20, 2018, the FPSC approved lowering base rates by $103 million annually beginning on January 1, 2019 as a result of lower tax expense.

PGS’s base rates were established in May 2009 and reflect an allowed ROE range of 9.75% to 11.75% with base rates set at the middle of the range of 10.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital.

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. On December 15, 2016, PGS and OPC filed a settlement with the FPSC (which was approved by the FPSC on February 7, 2017) agreeing to new depreciation rates that reduce annual depreciation expense by $16 million, 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 decrease the bottom of the ROE range from 9.75% to 9.25%. The settlement agreement provided that the bottom of the range will remain until the earlier of new base rates established in PGS’s next general base rate proceeding or December 31, 2020, the top of the range will continue to be 11.75%, and the ROE of 10.75% will continue to be used for the calculation of return on investment for clauses and riders. No change in customer rates resulted from this agreement.

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

The 2017 PGS settlement agreement did not contain a provision for tax reform. In 2018, the FPSC approved a settlement agreement filed authorizing the utility to accelerate the remaining amortization of PGS’s regulatory asset associated with the MGP environmental liability in 2018 up to the $32 million to net it against the estimated 2018 tax reform benefits. Therefore, PGS recorded amortization expense and a regulatory asset reduction of $11 million in 2018.

In accordance with the settlement agreement, PGS will reduce its base rates by $12 million for the impact of tax reform and reduce depreciation rates by $10 million beginning in January 2019. PGS is permitted to initiate a general base rate proceeding in 2020 if it forecasts that ROE will fall below its allowed range.

Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. 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 or the advance recovery of expenditures for approved costs.

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

	December 31,		December 31,
(millions)	2018		2017
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	56	$	45
Cost-recovery clauses ⁽²⁾		55		13
Environmental remediation ⁽³⁾		23		33
Postretirement benefits ⁽⁴⁾		295		272
Storm reserve ⁽⁵⁾		3		47
Other		26		23
Total regulatory assets		458		433
Less: Current portion		88		77
Long-term regulatory assets	$	370	$	356
Regulatory liabilities:
Regulatory tax liability ⁽⁶⁾	$	715	$	730
Cost-recovery clauses ⁽²⁾		17		32
Storm reserve ⁽⁷⁾		56		0
Accumulated reserve—cost of removal ⁽⁸⁾		513		518
Other		9		5
Total regulatory liabilities		1,310		1,285
Less: Current portion		44		58
Long-term regulatory liabilities	$	1,266	$	1,227

(1)

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

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

(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)

See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding the storm reserve regulatory asset. The Tampa Electric regulatory asset reflected at December 31, 2017 was effectively recovered in 2018. Additionally, in October 2018, Hurricane Michael impacted PGS’s Panama City division and the cost of restoration exceeded PGS’s storm reserve balance. The balance at December 31, 2018 reflects PGS’s storm reserve costs expected to be recovered in 2019. The regulatory assets were included in rate base and earned a rate of return as permitted by the FPSC.

(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. The liability related to the revaluation of the deferred income tax balances will be amortized and returned to customers through rate reductions or other revenue offsets based on IRS regulations and a settlement agreement for tax reform benefits approved by the FPSC. See Note 4 to the TEC Consolidated Financial Statements for further information.

(7)	See Tampa Electric Storm Restoration Cost Recovery discussion above for information regarding this reserve. The regulatory liability is being replenished to the FPSC-allowed storm reserve balance of $56 million.

(8)

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