FLORIDA PUBLIC SERVICE COMMISSION
SPECIAL COMMISSION CONFERENCE AGENDA
CONFERENCE DATE AND
TIME: Tuesday, December
3, 2024, Following Agenda
LOCATION: Betty Easley Conference Center, Joseph P. Cresse Hearing Room 148
DATE ISSUED: November 22, 2024
NOTICE
Conference agendas, staff recommendations, and vote sheets are available from the PSC website, https://www.floridapsc.com/, by selecting Conferences & Meeting Agendas and Commission Conferences of the FPSC. Once filed, a verbatim transcript of the Commission Conference will be available from this page by selecting the conference date, or by selecting Clerk's Office and the Item's docket number (you can then advance to the Docket Details page and the Document Filings Index for that particular docket). If you have any questions, contact the Office of Commission Clerk at (850) 413-6770 or Clerk@psc.state.fl.us.
In accordance with the Americans with Disabilities Act, persons needing a special accommodation to participate at this proceeding should contact the Office of Commission Clerk no later than five days prior to the conference at 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850, 1-800-955-8770 (Voice) or 1-800-955-8771 (TDD), Florida Relay Service. Assistive Listening Devices are available at the Office of Commission Clerk, Gerald L. Gunter Building, Room 152.
The Commission Conference has a live video broadcast the day of the conference, which is available from the PSC website. Upon completion of the conference, the archived video will be available from the website by selecting Conferences & Meeting Agendas, then Audio and Video Event Coverage.
1 Docket
No. 20240026-EI – Petition for rate increase by Tampa Electric Company.
Docket No. 20230139-EI – Petition for approval of 2023 depreciation and
dismantlement study, by Tampa Electric Company.
Docket No. 20230090-EI – Petition to implement 2024 generation base rate
adjustment provisions in paragraph 4 of the 2021 stipulation and settlement
agreement, by Tampa Electric Company.
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Critical Date(s): |
12/02/24 (8-Month Statutory Deadline) |
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Commissioners Assigned: |
All Commissioners |
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Prehearing Officer: |
Clark (20240026-EI) Graham (20230139-EI) Administrative (20230090-EI) |
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Staff: |
ENG: P. Buys, Ballinger, Davis, Ellis, King, Ramirez-Abundez, Ramos, Smith II, O. Wooten AFD: D. Buys, Cicchetti, Ferrer, Folkman, Higgins, Hinson, G. Kelley, Mason, McGowan, Norris, Souchik, Vogel, Zaslow ECO: Barrett, Draper, Hampson, Hudson, Galloway, Guffey, Kunkler, McClelland, McNulty, Panek, Prewett, J. Wu GCL: Harper, Marquez, Sparks IDM: B. Crawford, Eichler |
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Post-Hearing Decision – Participation is
Limited to Commissioners and Staff
Is TECO’s projected test period for the 12 months ending December 31, 2025, appropriate?
Yes. TECO’s projected test period comprised of the 12 months ending December 31, 2025, is appropriate.
Are TECO’s forecasts of customers, kilowatt-hour (kWh), and kilowatt (kW) by revenue and rate class, appropriate?
TECO’s forecast of customers for the 2025 test period is
reasonable; however, TECO’s forecast of kWh (energy sales) and kW (demand)
should be adjusted to reflect recent weather trends. TECO’s retail energy sales
forecast for the 2025 test period should be increased by 204,301,725 kWh and
TECO’s monthly peak demand forecast should be adjusted to reflect 10-year
normal weather as shown in Table 2-4 of staff’s memorandum dated November 22,
2024. For purposes of the rate setting phase of this proceeding, TECO should be
directed to provide the associated adjusted revenue and rate class energy and
demand forecasts for all impacted classes.
What are the inflation, customer growth, and other trend factors that should be approved for use in forecasting the test year budget?
The trend factors that should be used in forecasting the test year budget are: 2.1 percent for inflation, 1.7 percent for customer growth, 3.75 percent for non-union labor, and 3.5 percent for union labor.
Is the quality of electric service provided by TECO adequate?
Yes. Staff recommends that TECO’s quality of service is adequate.
Should currently prescribed depreciation rates and provision for dismantlement of TECO be revised?
Yes. A review of TECO’s 2023 depreciation and dismantlement studies indicate the need for revising the currently prescribed depreciation rates and provision for dismantlement. The specific revisions are discussed in Issues 7 and 11.
What should be the implementation date for new depreciation rates and the provision for dismantlement?
Staff recommends January 1, 2025, as the date of implementation for the new depreciation rates and dismantlement provision.
What depreciation parameters and resulting depreciation rates for each depreciable plant account should be approved?
Staff recommends approval of the depreciation parameters and resulting depreciation rates for each depreciable plant account that are listed in Table 7-4 of staff’s memorandum dated November 22, 2024.
Based on the application of the depreciation parameters and resulting depreciation rates that the Commission approves, and a comparison of the theoretical reserves to the book reserves, what are the resulting imbalances?
If staff’s recommendation on Issue 7 is approved, based on the application of that recommendation and a comparison of the theoretical reserves to the book reserves, the resulting theoretical reserve imbalances for each category of TECO’s plant accounts are shown in Table 8-2 of staff’s memorandum dated November 22, 2024.
What, if any, corrective reserve measures should be taken with respect to the imbalances identified in Issue 8?
Staff recommends using the remaining life technique to correct the depreciation reserve imbalances identified in Issue 8.
Should the current amortization of investment tax credits (ITCs) and flow back of excess deferred income taxes (EDITs) be revised to reflect the approved depreciation rates?
Yes. The current amortization of ITCs and any flow back of EDITs should be revised to match the actual recovery periods for the related property, except for the ITCs related to TECO’s battery storage assets. The Company should file detailed calculations of the revised ITC amortization and flow back of EDITs at the same time it files its earnings surveillance report as specified in Rule 25-6.1352, F.A.C.
What annual accrual for dismantlement should be approved?
Staff recommends approval of a total annual accrual of $15,770,488 for TECO’s dismantlement of its generating facilities, as shown in Table 11-2 of staff’s memorandum dated November 22, 2024.
What, if any, corrective dismantlement reserve measures should be approved?
Staff recommends that all the dismantlement reserve imbalances should be resolved over the remaining service lives of the related assets, and no other corrective dismantlement reserve measures should be approved.
Has TECO made the appropriate adjustments to remove all non-utility activities from Plant in Service, Accumulated Depreciation, and Working Capital in the 2025 projected test year? What, if any, adjustments should be made?
Yes. TECO has made the appropriate adjustments to remove all non-utility activities from Plant in Service, Accumulated Depreciation, and Working Capital in the 2025 projected test year. Therefore no additional adjustments are necessary.
Should TECO’s proposed Future Environmental Compliance Project be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed Future Environmental Compliance Project, with a
capital cost of $18.2 million, should be included in the 2025 projected test
year with no adjustments as it allows TECO to evaluate the feasibility of
Carbon Capture and Storage. With federal dollars paying for the vast majority
of costs, and TECO being proactive in pursuing this evaluation, staff
recommends this project is in the customers’ interest.
Should TECO’s proposed Research and Development Projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. TECO’s proposed Long Duration Energy Storage project, with a capital cost of $4.2 million, should be included in the 2025 projected test year as it allows TECO to explore alternative battery technologies. The Florida Conservation and Technology Center Microgrid project, with a capital cost of $2.8 million, should be removed from the 2025 projected test year as it will not be in-service until 2026. Therefore, an adjustment should be made to remove $2,846,972.
Should TECO’s proposed Customer Experience Enhancement Projects be included in the 2025 projected test year? What, if any, adjustments should be made?
No. The proposed Customer Experience Enhancement projects should not be included in the 2025 projected test year because the projects are not needed for reliability and the customers indicated that they are unwilling to pay for the enhancements. Therefore, an adjustment should be made to remove $13.4 million.
Should TECO’s proposed Information Technology Capital Projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed Information Technology Capital Projects, with a capital $22.9 million, should be included in the 2025 projected test year without any adjustments. Staff recommends that these projects are needed to replace hardware and software that are at the end of their life and unsupportable, and will improve cybersecurity to protect TECO’s system and customer information.
Should TECO’s proposed Solar Projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed 2024 and 2025 Solar projects, with a combined capital costs of approximately $359.1 million, should be included in the 2025 projected test year with no adjustments. While providing a minimal reliability benefit, the projects do provide cost-effective renewable energy for TECO’s system that will provide savings for customers in the form of fuel savings.
Should TECO’s proposed Grid Reliability and Resilience Projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed Grid Reliability and Resilience Projects, with capital costs of $128.9 million, should be included in the 2025 projected test year without any adjustments. Staff recommends that these projects are in the customers’ interest as the projects will evolve the electric grid to meet customer demands while also providing reliability and safety benefits.
Should TECO’s proposed Energy Storage projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The four energy storage projects, with an estimated total capital cost of $156.1 million, should be included in the 2025 projected test year with no adjustments. The projects provide cost-effective energy storage for TECO’s system that will provide savings for customers.
Should TECO’s proposed Corporate Headquarters project be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed Corporate Headquarters, with a capital cost of $188.7 million, should be included in the 2025 projected test year without any adjustments. Relocating TECO employees to the new Corporate Headquarters will provide additional space for expansion, and the structure will be more storm resilient and built to current building codes.
Should TECO’s proposed South Tampa Resilience project be included in the 2025 projected test year? What, if any, adjustments should be made?
No. The South Tampa Resilience Project is not needed for reliability purposes in 2025 and its fuel savings are not projected to offset the early in-service date absent a reliability need. Therefore, an adjustment should be made to remove $167.245 million.
Should TECO’s proposed Bearss Operations Center project be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed Bearss Operations Center project, with a total cost of $335.0 million, should be included in the 2025 projected test year without any adjustments. The Bearss Operations Center was chosen by TECO for its storm resilience, office space, and strategic objectives.
Should TECO’s proposed Polk 1 Flexibility project be included in the 2025 projected test year? What, if any, adjustments should be made?
Yes. The proposed Polk 1 Flexibility project, with a total cost of $90.1 million, should be included in the 2025 projected test year. The conversion of Polk Unit 1 to a natural gas-fired simple cycle unit is projected to be more economic for customers than continuing as a combined cycle unit and incurring major capital expenses. However, as the remaining portions of Polk Unit 1 integrated gasification combined cycle system, including the gasification equipment, heat recovery steam generator, and steam turbine do not appear likely to return to service, they should be retired. Therefore, an adjustment should be made to remove $142,251,955. Staff recommends establishing a capital recovery schedule with an 11-year amortization period to address recovery of the remaining balance in rate base.
What amount of Plant in Service for the 2025 projected test year should be approved?
The amount of Plant in Service that should be approved for the 2025 projected test year is $12,868,236,740.
What amount of Accumulated Depreciation for the 2025 projected test year should be approved?
The amount of Accumulated Depreciation that should be approved for the 2025 projected test year is $3,679,106,305.
What amount of Construction Work in Progress for the 2025 projected test year should be approved?
The amount of Construction Work in Progress (CWIP) that should be approved for the 2025 projected test year is $230,175,000.
What amount of Property Held for Future Use for the 2025 projected test year should be approved?
The amount of Property Held for Future Use that should be approved for the 2025 projected test year is $68,034,000.
What amount of unfunded Other Post-Retirement Employee Benefit (OPEB) liability and any associated expense should be included in rate base?
The amount of unfunded Other Post-retirement Employee Benefit (OPEB) that should be included in rate base is $70,740,641.
What level of TECO’s fuel inventories should be approved?
Staff recommends that the Commission approve $36,509,000 as the jurisdictional fuel inventory value for the projected 2025 test year.
What amount of Working Capital for the 2025 projected test year should be approved?
The amount of Working Capital that should be approved for the 2025 projected test year is $223,971,393.
What amount of rate base for the 2025 projected test year should be approved?
The amount of rate base that should be approved for the 2025 projected test year is $9,711,309,827.
What amount of accumulated deferred taxes should be approved for inclusion in the capital structure for the 2025 projected test year?
The amount of accumulated deferred income taxes to include in the 2025 projected test year capital structure is $972.094 million.
What amount and cost rate of the unamortized investment tax credits should be approved for inclusion in the capital structure for the 2025 projected test year?
The Commission should approve an ITC amount of $208.205 million at a cost rate of 7.90 percent for inclusion in the capital structure for the 2025 projected test year.
What amount and cost rate for customer deposits should be approved for inclusion in the capital structure for the 2025 projected test year?
The amount and cost rate for customer deposits that should be approved for inclusion in the capital structure for the 2025 projected test year is $98.335 million at a cost rate of 2.41 percent.
What amount and cost rate for short-term debt should be approved for inclusion in the capital structure for the 2025 projected test year?
The amount and cost rate for short-term debt that should be approved for inclusion in the capital structure for the 2025 projected test year is $373.359 million and 3.90 percent, respectively.
What amount and cost rate for long-term debt should be approved for inclusion in the capital structure for the 2025 projected test year?
The amount and cost rate for long-term debt that should be approved for inclusion in the capital structure for the 2025 projected test year is $3,505.671 million at a cost rate of 4.53 percent.
What equity ratio should be approved for use in the capital structure for ratemaking purposes for the 2025 projected test year?
The Commission should approve an equity ratio of 54.00 percent based on investor-supplied capital for ratemaking purposes for the 2025 projected test year. The amount of common equity in the capital structure should be $4,553.645 million.
What authorized return on equity (ROE) should be approved for use in establishing TECO’s revenue requirement for the 2025 projected test year?
An authorized ROE of 10.30 percent, with a range of 9.30 percent to 11.30 percent, should be approved for use in establishing TECO’s revenue requirement for the 2025 projected test year.
What capital structure and weighted average cost of capital should be approved for use in establishing TECO’s revenue requirement for the 2025 projected test year?
A capital structure consisting of 54.00 percent common equity, 41.60 percent long-term debt, and 4.40 percent short-term debt as a percentage of investor sources should be approved for the 13-month average test year ending December 31, 2025. A weighted average cost of capital of 6.81 percent should be approved for establishing TECO’s projected test year revenue requirement and setting rates in this proceeding.
Has TECO correctly calculated the revenues at current rates for the 2025 projected test year?
If staff’s recommended adjustments to TECO’s 2025 energy and demand forecasts in Issue 2 are approved, TECO’s estimated revenues at current rates should be increased by $11.985 million, resulting in total revenues of $1.492 billion, to reflect such adjustments. If the Commission approves OPC’s proposed adjustment to TECO’s 2025 energy and demand forecasts in Issue 2, TECO’s estimated revenues at current rates should be increased by $12.260 million, resulting in total revenues of $1.493 billion. If the Commission approves TECO’s customer, energy sales, and demand forecasts as-filed, then TECO’s projected revenues at current rates is $1.481 billion, and no adjustment is necessary.
What amount of Total Operating Revenues should be approved for the 2025 projected test year?
If staff’s recommended adjustments to TECO’s test year energy sales/demand and revenue forecasts in Issue 2 and 41 are approved, the appropriate amount of Total Operating Revenues is $1.530 billion. If the Commission approves OPC’s recommended adjustments in Issues 2 and 41, the appropriate amount of Total Operating Revenues is $1.531 billion. If the Commission approves TECO’s customer, energy sales, demand, and revenue forecasts as-filed, the appropriate amount of Total Operating Revenues is $1.518 billion.
What amount of O&M expense associated with Polk Unit 1 has TECO included in the 2025 projected test year? Should this amount be approved and what, if any, adjustments should be made?
TECO included $9,685,047 of non-fuel O&M expense for Polk Unit 1. Consistent with Issue 24, staff recommends adjustments to reflect the retirement of the non-simple cycle components of Polk Unit 1, which reduce O&M expense by $1,500,332, for a resulting non-fuel O&M expense of $8,184,715.
What amount of O&M expense associated with Big Bend Unit 4 has TECO included in the 2025 projected test year? Should this amount be approved and what, if any, adjustments should be made?
TECO included $12,472,909 of non-fuel O&M expense for Big Bend 4. This amount should be approved with no adjustments.
What amount of generation O&M expense should be approved for the 2025 projected test year?
Consistent with Issues 22, 24, and 43, generation O&M expense should be reduced to reflect the denial of the South Tampa Resilience project and retirement of some of the Polk Unit 1 generating assets. In addition, staff recommends amortizing the atypical expenses in 2025 over a three-year period, for a total reduction of $8,286,667 million. Therefore, generation O&M should be $113,813,950 for the 2025 projected test year.
What amount of transmission O&M expense should be approved for the 2025 projected test year?
Transmission O&M should be $11,491,000 for the 2025 projected test year. This amount is below the Commission’s benchmark amount, is reasonable, and should be approved.
What amount of distribution O&M expense should be approved for the 2025 projected test year?
Distribution O&M should be $54,243,000 for the 2025 projected test year. This amount is below the Commission’s benchmark amount, is reasonable, and should be approved.
Has TECO made the appropriate test year adjustments to remove fuel revenues and fuel expenses recoverable through the Fuel Adjustment Clause?
Yes. Staff recommends that TECO has made the appropriate test year adjustments to remove fuel revenues and fuel expenses recoverable through the Fuel and Purchased Power Cost Recovery Clause.
Has TECO made the appropriate test year adjustments to remove conservation revenues and conservation expenses recoverable through the Conservation Cost Recovery Clause?
Yes. Staff recommends that TECO appropriately adjusted its Net Operating Income for the 2025 test year to remove conservation revenues and conservation expenses that are recoverable through the Energy Conservation Cost Recovery Clause.
Has TECO made the appropriate test year adjustments to remove capacity revenues and capacity expenses recoverable through the Capacity Cost Recovery Clause?
Yes. Staff recommends that TECO has made the appropriate test year adjustments to remove capacity revenues and capacity expenses recoverable through the Capacity Cost Recovery Clause.
Has TECO made the appropriate test year adjustments to remove environmental revenues and environmental expenses recoverable through the Environmental Cost Recovery Clause?
Yes. TECO removed $9.2 million of net operating income (NOI) from the test year calculations for the appropriate revenues and expenses associated with the Environmental Cost Recovery Clause.
Has TECO made the appropriate test year adjustments to remove all storm hardening revenues and expenses recoverable through the Storm Protection Plan Cost Recovery Clause?
Yes. Staff recommends that TECO has made the appropriate test year adjustments to remove all storm hardening revenues and expenses recoverable through the SPPCRC.
What amount of salaries and benefits, including incentive compensation, should be approved for the 2025 projected test year?
Staff recommends salaries and benefits of $376,802,000 for the 2025 projected test year.
Does TECO’s pension and Other Post-Retirement Employee Benefits (OPEB) expense properly reflect capitalization credits in the 2025 projected test year? If not, what adjustments, if any, should be made?
TECO has made the proper adjustments to reflect capitalization credits. Therefore, no adjustments to the OPEB expense is necessary.
What cost allocation methodologies and what amount of allocated costs and charges with TECO’s affiliated companies should be approved for the 2025 projected test year?
Staff recommends approving $28,650,000 in allocated costs and charges from Tampa Electric to its affiliate, and a total of $11,841,973 for allocated costs ($7,263,973) and direct charges ($4,578,000) incurred by TECO from affiliated companies for the 2025 projected test year. The amount for allocated costs reflects a reduction of $3,811,027 for the removal of half of allocated corporate responsibility costs. Staff recommends no changes to the cost allocation methodology.
What amount of Directors and Officers Liability Insurance expense for the 2025 projected test year should be approved?
Staff recommends that $151,500 in Directors and Officers Liability Insurance and $376,000 in Board of Director expense be approved, resulting in a total reduction of $527,500 for the 2025 test year.
What amount of Economic Development expense for the 2025 projected test year should be approved?
Staff recommends that $446,502 should be approved.
What amount and amortization period for TECO’s rate case expense for the 2025 projected test year should be approved?
Staff recommends the Commission approve a total rate case cost of $2,048,000 with a three-year amortization period. The corresponding annual amortization expense is $683,000.
What amount of O&M Expense for the 2025 projected test year should be approved?
The amount of O&M Expense that should be approved for the 2025 projected test year is $374,919,781.
What amount of depreciation and dismantlement expense for the 2025 projected test year should be approved?
The amount of depreciation and dismantlement expense should be $507,268,091 for the 2025 projected test year.
What amount of Taxes Other Than Income Taxes for the 2025 projected test year should be approved?
Staff recommends that Taxes Other Than Income Taxes for the 2025 projected test year should be $101,592,000.
What amount of Parent Debt Adjustment is required by Rule 25-14.004, F.A.C., for the 2025 projected test year?
The amount of Parent Debt Adjustment as contemplated by Rule 25-14.004, F.A.C., for the 2025 projected test year is $13,420,123 based on a jurisdictional common equity balance of $4,553,645 million.
What amount of Production Tax Credits should be approved and what is the proper accounting treatment for the 2025 projected test year?
The amount of Production Tax Credits that should be approved for the 2025 projected test year is $38.6 million as a reduction to income tax expense and the proper treatment is flow-through accounting.
What treatment, amounts, and amortization period for the Production Tax Credits that were deferred in 2022-2024 should be approved for the 2025 projected test year?
The PTC benefit that was deferred in 2022-2024 in the amount of $58.74 million should be accounted for as a regulatory liability, amortized over a three-year period for annual amortization in the amount of $19.58 million, with an additional $1.56 million carrying charge, resulting in an annual amount of $21.14 million. Therefore, staff recommends that TECO’s requested revenue requirement should be reduced by $15.64 million. A corresponding adjustment to decrease rate base by $219,567 should also be made.
What treatment and amount of the Investment Tax Credits pursuant to the Inflation Reduction Act should be approved for the 2025 projected test year?
The Commission should approve a five-year amortization period for Investment Tax Credits for Battery Storage assets as if the Company opted out of normalization. The amount of the Investment Tax Credits related to the battery storage assets is $37.031 million and the annual amortization should be $6.627 million for the 2025 projected test year.
What amount of Income Tax expense should be approved for the 2025 projected test year?
The amount of Income Tax expense that should be approved for the projected 2025 test year is ($1,011,625).
What amount of Net Operating Income should be approved for the 2025 projected test year?
The amount of Net Operating Income that should be approved for the 2025 projected test year is $547,059,693.
What revenue expansion factor and net operating income multiplier, including the appropriate elements and rates, should be approved for the 2025 projected test year?
Staff recommends that the appropriate revenue expansion factor should be 74.424 percent and net operating income multiplier should be 1.34364 for the 2025 projected test year. The appropriate elements and rates are discussed in the analysis portion of staff’s memorandum dated November 22, 2024.
What amount of annual operating revenue increase for the 2025 projected test year should be approved?
The amount of annual operating revenue increase that should be approved for the projected 2025 test year is $153,379,370.
Is TECO’s proposed separation of costs and revenues between the wholesale and retail jurisdictions appropriate?
Yes. TECO’s proposed separation of costs and revenues between the wholesale and retail jurisdictions is appropriate and should be approved as shown in MFR Schedule E, Volume I.
What is the appropriate methodology to allocate production costs to the rate classes?
The appropriate methodology is the 12 Coincident Peak (CP) and 1/13 Average Demand (i.e., energy) methodology. The gasifier of Polk Unit 1 and the scrubber of the Big Bend Unit 4 should continue to be allocated on an energy basis. TECO should file a revised cost of service study, including rates and tariffs, that reflect the Commission vote on all issues by December 9, 2024, close of business. The Commission-approved methodology should also be utilized in other cost recovery clauses for allocation of production demand classified costs to the rate classes.
What is the appropriate methodology to allocate transmission costs to the rate classes?
Transmission costs should be allocated on a 12 CP basis.
What is the appropriate methodology to allocate distribution costs to the rate classes?
Distribution plant in accounts 369 (service drops) and 370 (meters) should be classified as customer-related and distribution costs in accounts 364 through 368 (poles, overhead lines, underground lines, and transformers) as demand-related. The use of the Minimum Distribution System (MDS) should be rejected.
How should any change in the revenue requirement approved by the Commission be allocated among the customer classes?
The appropriate allocation of the change in revenue requirement, after recognizing any additional revenues realized in other operating revenues, should track, to the extent practical, the revenue deficiency of each class as determined from the approved cost of service study and move the classes toward parity to the extent practicable. The appropriate allocation compares present revenue for each class to the class cost of service requirement and then distributes the change in revenue requirements to the classes. No class should receive an increase greater than 1.5 times the system average percentage increase in total, and no class should receive a decrease.
Should the proposed modifications to the delivery voltage credit be approved?
TECO’s calculations of the delivery voltage credits are appropriate; however, TECO should be required to recalculate the credits if the Commission’s vote in other issues affects the calculations.
What are the appropriate service charges (initial connection, reconnect for nonpayment, connection of existing account, field visit, temporary overhead and underground, meter tampering)?
The appropriate service charges are $168.00 for initial connection, $18.00 for reconnection of service which has been disconnected due to nonpayment, $15.00 for reconnection of service which has not been disconnected due to nonpayment, $37.00 for field visit, $480.00 for temporary overhead and underground, and $75.00 for meter tampering.
Should the modifications to the emergency relay power supply charge be approved?
Yes, TECO proposed methodology to calculate emergency relay power supply charges is appropriate and should be approved. The final charges are subject to the Commission vote on the final revenue requirement; therefore, TECO should recalculate the charges.
What are the appropriate basic service charges?
The final basic service charges are a fall-out issue and will be decided at the December 19, 2024 Commission Conference. The calculation of the basic service charges is dependent on the Commission’s vote on the final revenue requirement, cost of service issues, including whether to use the MDS method or not. TECO should be required to recalculate the basis service charges based on the Commission vote on all prior issues.
What are the appropriate demand charges?
The methodology used by TECO to determine the demand charges is appropriate. The appropriate rate design for the demand charges is discussed in conjunction with the appropriate rate design for the energy charges decided in Issue 80. The final demand charges are a fall-out issue and will be decided at the December 19, 2024 Commission Conference.
What are the appropriate energy charges?
The appropriate rate design for the energy charges is discussed in conjunction with the appropriate rate design for the demand charges decided in Issue 79. The final energy charges are a fall-out issue and will be decided at the December 19, 2024 Commission Conference.
What are the appropriate Lighting Service rate schedule charges?
The appropriate Lighting Service rate schedule charges are a fall-out issue and will be decided at the December 19, 2024 Commission Conference.
What are the appropriate Standby Services (SS-1, SS-2, SS-3) rate schedule charges?
The appropriate Standby Services (SS-1, SS-2, SS-3) rate schedule charges are a fall-out issue and will be decided at the December 19, 2024 Commission Conference.
Should the proposed modifications to the time-of-day periods be approved?
No. The proposed modifications to the time-of-day periods should not be approved.
Should the proposed modifications to the Non-Standard Meter Rider tariff (Tariff Sheet No. 3.280) be approved?
No modification was proposed. The Non-Standard Meter Rider (NSMR) tariff is appropriate and no modifications should be made.
Should the proposed tariff modifications to the Budget Billing Program (Fifth Revised Tariff Sheet No. 3.020) be approved?
Staff recommends approval of the proposed tariff modifications to the Budget Billing Program, indicated on the Fifth Revised Tariff Sheet No. 3.020.
Should the proposed tariff modifications regarding general liability and customer responsibilities (Fifth Revised Tariff Sheet No. 5.070 and Original Tariff Sheet No. 5.081) be approved?
Yes. The Commission should approve the proposed tariff
modifications regarding general liability and customer responsibilities (Fifth
Revised Tariff Sheet No. 5.070 and Original Tariff Sheet No. 5.081). The
proposed revisions will provide greater clarity regarding customer
responsibilities and Company responsibilities.
Should the proposed tariff modifications to Contribution in Aid of Construction (Fifth Revised Tariff Sheet No. 5.105) be approved?
The proposed tariff modifications to Contribution in Aid of Construction (Fifth Revised Tariff Sheet No. 5.105) are reasonable and should be approved.
Should the proposed tariff modifications to the Economic Development Rider (Third Revised Tariff Sheet Nos. 6.720, 6.725, 6.730) be approved?
Yes. The proposed tariff modifications to the Economic
Development Rider (Third Revised Tariff Sheet Nos. 6.720, 6.725, 6.730) should
be approved. The proposed Economic Development Rider (EDR) modifications would
allow TECO to remain competitive in attracting new commercial and industrial
customers to its service area.
Should the proposed modifications to LS-1 (Eleventh Revised Tariff Sheet No. 6.809) regarding lighting wattage variance be approved?
Yes. Staff recommends approval of the proposed modifications to LS-1 regarding lighting wattage variance. The lighting wattage variance will increase to 25 percent, from the previously approved variance of 10 percent.
Should the proposed LS-2 Monthly Rental Factors (Original Tariff Sheet No. 6.845) be approved?
TECO’s calculations of the LS-2 monthly rental factors shown on Original Tariff Sheet No. 6.845 are appropriate; however, TECO should be required to recalculate the factors if the Commission’s vote in other issues affects the calculations. The new factors will permit customers to contract lighting service for a period between 1 and 25 years.
Should the proposed termination factors for long-term facilities (Fifth Revised Tariff Sheet No. 7.765) be approved?
TECO’s calculations of the monthly rental and termination factors for facilities rental agreement are appropriate; however, TECO should be required to recalculate the factors shown on Fifth Revised Tariff Sheet No. 7.765 if the Commission’s vote in other issues affects the calculations.
Should the non-rate related tariff modifications be approved?
The non-rate related tariff modifications are appropriate and should be approved.
Should the Commission give staff administrative authority to approve tariffs reflecting Commission approved rates and charges?
This is a fall-out issue and will be decided at the December 19, 2024 Commission Conference.
What are the considerations or factors that the Commission should evaluate in determining whether a SYA should be approved?
The Company has the burden to prove, by a preponderance of the evidence, that the annualization or project(s) that underlie the SYA are necessary to be accounted for in the current rate case as opposed to a future rate case. In analyzing whether to approve a SYA, the Commission should consider whether the project(s) associated with the requested SYA will substantially improve safety, reliability, or operational efficiency, and whether the project(s) will put pressure on the Company’s ability to earn within its range of return. In doing so, it should consider whether it appears sufficiently likely that approval of the project(s) will result in cost savings by avoiding or minimizing future rate proceedings. In a SYA, rates should only be increased for projects that are placed into service, as verified by the Company.
Should the Commission approve the inclusion of TECO’s proposed Solar Projects in the 2026 and 2027 SYA? What, if any, adjustments should be made?
In part. The annualization associated with the 2025 proposed Solar Projects should be included in the 2026 SYA, with an adjustment to include the annualization of the associated Accumulated Depreciation, but the proposed 2026 Solar Projects should be removed and there should be no 2027 SYA. While staff does not recommend the inclusion of the 2026 Solar Projects as part of the SYA, this does not preclude TECO from filing a request for the cost recovery in a future proceeding.
Should the Commission approve the inclusion of TECO’s proposed Grid Reliability and Resilience Projects in the 2026 and 2027 SYA? What, if any, adjustments should be made?
In part. The Grid Communications Network Project has an in-service date of August 2025 and the annualization amount should be included in the 2026 SYA, with an adjustment to include the annualization of the associated Accumulated Depreciation. The Customer Information Device Expansion Project ($24.3 million) and the Grid Communications Network Hardware, Back Office IT Systems, and Control Systems Projects ($108.3 million) will not be completed until 2026 and should be removed and there should be no 2027 SYA. While staff does not recommend the inclusion of the 2026 projects as part of the SYA, this does not preclude TECO from filing a request for the cost recovery in a future proceeding.
Should the Commission approve the inclusion of TECO’s proposed Polk 1 Flexibility Project in the 2026 SYA? What, if any, adjustments should be made?
Yes. The annualization of TECO’s proposed Polk 1 Flexibility project should be included in the 2026 SYA, with an adjustment to include the annualization of the associated Accumulated Depreciation.
Should the Commission approve the inclusion of TECO’s proposed Energy Storage Projects in the 2026 SYA? What, if any, adjustments should be made?
The annualization associated with TECO’s proposed Energy Storage Projects should be included in the 2026 SYA, with an adjustment to include the annualization of the associated Accumulated Depreciation. The Investment Tax Credits related to the battery storage projects in the 2026 SYA should be adjusted to reflect a 5-year amortization period. The annual ITC amortization should be $8,792,608, which results in a revenue requirement decrease of $1,713,381 for the 2026 SYA
Should the Commission approve the inclusion of TECO’s proposed Bearss Operations Center Project in the 2026 SYA? What, if any, adjustments should be made?
Yes. TECO’s proposed annualization of the Bearss Operations Center project should be included in the 2026 SYA, with an adjustment to include the annualization of the associated Accumulated Depreciation.
Should the Commission approve the inclusion of TECO’s proposed Corporate Headquarters Project in the 2026 SYA? What, if any, adjustments should be made?
Yes. TECO’s proposed annualization of the Corporate Headquarters project should be included in the 2026 SYA, with an adjustment to include the annualization of the associated Accumulated Depreciation.
Should the Commission approve the inclusion of TECO’s proposed South Tampa Resilience Project in the 2026 and 2027 SYA? What, if any, adjustments should be made?
No. Consistent with Issue 22, staff recommends removal of the South Tampa Resilience Project from the 2026 and 2027 SYAs.
Should the Commission approve the inclusion of TECO’s proposed Polk Fuel Diversity Project in the 2026 and 2027 SYA? What, if any, adjustments should be made?
No. TECO’s proposed Polk Fuel Diversity project should be removed from the 2026 and 2027 SYAs because its in-service date is beyond the projected test year and TECO has not demonstrated a definitive reliability need associated with the Polk Fuel Diversity project.
What overall rate of return should be used to calculate the 2026 and 2027 SYA?
As discussed in Issue 40, an overall rate of return of 6.81 percent should be used to calculate the 2026 and 2027 SYA.
Should the SYA for 2026 and 2027 reflect additional revenues due to customer growth? What, if any, adjustments should be made?
No. Any SYAs for 2026 and/or 2027 approved by the Commission should not reflect additional revenues resulting from customer growth. No adjustments should be made.
Should the Commission approve the inclusion of TECO’s proposed incremental O&M expense associated with the SYA projects in the 2026 and 2027 SYA?
The amount of incremental O&M expenses that should be approved are $2.3 million for the 2026 SYA and $0 for the 2027 SYA.
Should the depreciation expense and Investment Tax Credits amortization used to calculate the proposed 2026 and 2027 SYA be adjusted to reflect the Commission’s decisions on depreciation rates and ITC amortization for the 2025 projected test year?
Yes. If the Commission authorizes the utilization of the proposed 2026 and 2027 SYA, staff recommends that the depreciation expense and Investment Tax Credits amortization used to calculate the proposed 2026 and 2027 SYA be adjusted to reflect the Commission’s decisions on depreciation rates and Investment Tax Credit Amortization for the 2025 projected test year.
What annual amount of incremental revenues should be approved for recovery through the 2026 and 2027 SYA?
The annual amount of incremental revenues that should be approved for recovery through the 2026 SYA is $74,674,147, which is for recovery of the annualization associated with projects added in 2025 only, and $0 through the 2027 SYA.
What rate design approach should be used to develop customer rates for the 2026 and 2027 SYA?
TECO’s proposed rate design to develop customer rates for the 2026 and 2027 SYA is reasonable. If the Commission approves any SYAs, TECO should file a petition for proposed rates for January 2026 in September 2025 and for proposed rate for January 2027 in September 2026. The rate calculation should reflect the Commission-approved cost of service.
When should the 2026 and 2027 SYA become effective?
If the Commission approves any projects to be included for cost recovery via a SYA, the 2026 SYA should become effective with the first billing cycle in January 2026. The 2027 SYA, if approved, should become effective with the first billing cycle in January 2027.
Should TECO be required to file its proposed 2026 and 2027 SYA rates for Commission approval in September 2026 and 2027, respectively, reflecting then current billing determinants?
Yes. TECO should be
required to file its proposed 2026 and 2027 SYA rates for Commission approval
in September 2026 and 2027, respectively, verifying the in-service dates
of all projects and using then current
billing determinants.
Should TECO’s proposed Corporate Income Tax Change Provision be approved?
No. If there is a change in state or federal tax laws, TECO or other intervenors have the opportunity to file a petition for a limited proceeding pursuant to Section 366.076, F.S., requesting the Commission consider the issues affected by a potential corporate tax law change.
Should TECO’s proposed Storm Cost Recovery Provision be approved?
Yes. The proposed Storm Cost Recovery Provision should be approved.
Should TECO’s proposed Asset Optimization Mechanism be approved, and what, if any, modifications should be made?
Yes. The proposed AOM should be approved, effective January 1, 2025, with modifications. As the customer-sharing threshold has not been increased, the requested renewable energy credit (REC) sales and natural gas sales should not be added to the allowable optimization activities. In addition, staff recommends a docket should be opened to establish a generic proceeding to address incentives for all investor-owned utilities.
What are the appropriate updated Clean Energy Transition Mechanism factors and when should they become effective?
The Clean Energy Transition Mechanism (CETM) factors have been approved by the Commission in the 2021 Settlement Agreement; however, the final calculation of the CETM factors, are dependent on the Commission’s vote on ROE and cost of service. TECO should provide revised CETM factors and associated tariff for the December 19, 2024 Commission Conference.
Should the proposed Senior Care Program (Original Tariff Sheet No. 3.310) and associated cost recovery be approved?
No. The proposed
Senior Care Program (Original Tariff Sheet No. 3.310) and associated cost
recovery should not be approved as proposed. If TECO wishes to offer the
proposed
program which offers a fixed $10 monthly bill credit to TECO’s low-income
customers 65 and older, the program should be funded through voluntary rate
payer donations and/or by TECO employees and TECO shareholders.
Should TECO be required to perform any studies or analysis relating to the retirement of Polk Unit 1 and/or Big Bend Unit 4, including early retirement dates, environmental compliance costs, and/or procurement of alternative resources?
No. TECO is responsible for continuously evaluating its generating fleet for reliability, economics, and compliance with applicable regulations. Based on the record, TECO has performed reasonable analysis in regards to the early retirement of Polk Unit 1 and Big Bend Unit 4 and no further studies are needed at this time.
What is the appropriate effective date for TECO’s revised 2025 rates and charges?
This is a fall-out issue and will be decided at the December 19, 2024 Commission Conference.
Has the Commission considered TECO’s performance pursuant to Sections 366.80–366.83 and 403.519, F.S., when establishing rates?
Yes. The Commission has considered TECO’s performance pursuant to Sections 366.80-366.83 and 403.519, F.S., when establishing rates.
What considerations should the Commission give the affordability of customer bills and how does TECO’s rate increase impact ratepayers in this proceeding?
The Commission has broad discretion to carry out its legislative mandate of ensuring rates are fair, just, and reasonable. To the extent the Commission can consider the “affordability” of customer bills, it must do so within the context of its governing statutes in Chapter 366, F.S., which require the Commission to set rates that are fair, just, and reasonable. OPC and FL Rising/LULAC offered tests to gauge affordability, but staff is persuaded by the law, which is supported by the evidence presented by TECO regarding how it kept affordability in mind while making business decisions that would result in “affordable” rates. Moreover, if staff’s adjustments are approved by the Commission, the rate impact on customers will be lower and thus even more affordable for ratepayers.
Should TECO be required to file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records which will be required as a result of the Commission’s findings in this rate case?
Yes. TECO should be required to file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records which will be required as a result of the Commission’s findings in this rate case.
Should this docket be closed?
This docket should remain open for the Commission to determine the final rates at a subsequent Special Agenda.