3. Regulatory

Tampa Electric Base Rates-2013 Agreement

Tampa Electric’s results reflect the stipulation and settlement agreement entered into on September 6, 2013, between Tampa Electric and the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $58 million effective November 1, 2013, an additional $8 million effective November 1, 2014, an additional $5 million effective November 1, 2015, and an additional $110 million effective the date that the expansion of Tampa Electric’s Polk Power Station went into service, which was January 16, 2017. The agreement also provided for Tampa Electric’s allowed regulatory ROE to be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provided that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2018, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) 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 beginning on January 1, 2013.

Tampa Electric Base Rates-2017 Agreement

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

The amended agreement provides for solar base rate adjustments (SoBRAs) for TEC’s substantial investments in solar generation. It includes the following 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 SoBRA 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 build the last tranche of 50 MWs, the first two tranches of 400 MW must be constructed at or below $1475/kWac. The agreement includes a sharing provision that allows Tampa Electric to retain 25% of any cost savings for projects below $1500/kWac. Tampa Electric plans to invest approximately $850 million in these solar projects over four years and will accrue AFUDC during construction.

The agreement maintains Tampa Electric’s allowed regulatory ROE at a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional base rate increases to be effective sooner than January 1, 2022, unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE were increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE were increased as described above) 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 remains at 54%. The agreement contains certain customer protections related to potential changes in federal tax policy. An asset optimization provision that allows Tampa Electric to share in the savings for optimization of its system once certain thresholds are crossed is also included and Tampa Electric agrees to a five-year financial hedging moratorium for natural gas and no investments in gas reserves.

Tampa Electric Storm Restoration Cost Recovery

Prior to the September 6, 2013 stipulation and settlement agreement, Tampa Electric was accruing $8 million annually to an FPSC-approved self-insured storm reserve. Effective November 1, 2013, Tampa Electric ceased accruing for this storm reserve as a result of the 2013 rate case settlement. However, 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. As of December 31, 2016, the balance of the self-insured storm reserve was $56 million.

As a result of several named storms, including Tropical Storm Colin, Hurricane Hermine and Hurricane Matthew, Tampa Electric incurred $10 million of storm costs in 2016. In the first quarter of 2017, Tampa Electric applied the $10 million of storm costs to the storm reserve. This resulted in a storm reserve balance of $46 million as of March 31, 2017. Tampa Electric was impacted by Hurricane Irma in the third quarter of 2017 and has currently estimated the total incurred incremental cost of restoration to be approximately $70 million, of which $60 million was charged to the storm reserve, $4 million was charged to O&M expense, and $6 million was charged to capital expenditures. At September 30, 2017, the amount of $60 million charged to the storm reserve exceeded the $46 million balance by $14 million, which is currently recorded as a regulatory asset on the balance sheet. Based on an FPSC order, if the charges to the storm reserve exceed the account balance, the excess is to be carried as a regulatory asset. Tampa Electric expects to petition the FPSC in early 2018 for recovery of the storm costs in excess of the reserve as well as replenish the balance in the reserve to the $56 million level that existed as of October 31, 2013 for a total of $70 million. See the Regulatory Assets and Liabilities table below.

PGS Base Rates

On June 28, 2016, PGS filed its depreciation study with the FPSC seeking approval for new depreciation rates. After communications with the FPSC staff, on December 15, 2016, PGS and OPC filed a settlement with the FPSC 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 ROE 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 ROE 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. On February 7, 2017, the FPSC approved the settlement agreement. 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 will be amortized over a two-year recovery period beginning in 2016. In 2016, PGS recorded $16 million of this amortization expense. This additional amortization expense in 2016 was offset by the decrease in depreciation expense as discussed above with no impact to 2016 earnings. For the three and nine months ended September 30, 2017, PGS recorded amortization expense of $1 million and $4 million, respectively.

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the FASB’s accounting standards for regulated operations. Areas of applicability include: revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm restoration or the future removal of property.

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

Regulatory Assets and Liabilities
(millions)	September 30, 2017		December 31, 2016
Regulatory assets:
Regulatory tax asset ⁽¹⁾	$	83	$	86
Cost-recovery clauses - deferred balances ⁽²⁾		7		8
Environmental remediation⁽³⁾		33		37
Postretirement benefits ⁽⁴⁾		276		272
Storm reserve ⁽⁵⁾		14		0
Other		22		18
Total regulatory assets		435		421
Less: Current portion		38		28
Long-term regulatory assets	$	397	$	393
Regulatory liabilities:
Regulatory tax liability	$	12	$	6
Cost-recovery clauses - deferred balances ⁽²⁾		38		112
Cost-recovery clauses - offsets to derivative assets⁽²⁾		0		17
Storm reserve ⁽⁵⁾		0		56
Accumulated reserve - cost of removal⁽⁶⁾		524		547
Other		7		7
Total regulatory liabilities		581		745
Less: Current portion		65		154
Long-term regulatory liabilities	$	516	$	591

(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.

(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. In the case of the regulatory liability related to derivative assets, refund occurs in the year following the settlement of the derivative position.

(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 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 asset will be recovered over a 12-month period.

(6)

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.