State of Florida |
Public Service Commission Capital Circle Office Center ● 2540 Shumard
Oak Boulevard -M-E-M-O-R-A-N-D-U-M- |
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DATE: |
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TO: |
Office of Commission Clerk (Teitzman) |
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FROM: |
Division of Accounting and Finance (D. Buys, Cicchetti, Ferrer, Folkman, Higgins, G. Kelley, McGowan, Quigley, Richards, Souchik, Vogel, Zaslow) Division of Engineering (Ellis, King, Ramirez-Abundez, Ramos, Smith II, Thompson) Office of the General Counsel (Brownless) Office of Industry Development and Market Analysis (Eichler, Hitchins, Rogers, Wooten) |
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RE: |
Docket No. 20240099-EI – Petition for rate increase by Florida Public Utilities Company. |
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AGENDA: |
03/04/25 – Regular Agenda – Proposed Agency Action for All Issues, Except for Issues 63 and 64 - Interested Persons May Participate |
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COMMISSIONERS ASSIGNED: |
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PREHEARING OFFICER: |
Passidomo Smith |
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02/20/25 (5-Month Effective Date-PAA Rate Case) |
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SPECIAL INSTRUCTIONS: |
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Issue Description Page
1 Projected Test Period (Kunkler)
2 Forecasted Billing Determinants
(Kunkler)
3 Estimated Electric Revenues
(Kunkler)
4 Non-Payroll Trend Factors (Barrett)
5 Quality of Service
(Ramirez-Abundez)
6 Substations & Transmission
Assets (Thompson, Higgins, Richards)
7 Reliability Projects (Thompson,
Richards)
8 Safety Projects (Thompson,
Richards)
9 Security Camera Projects
(Ramirez-Abundez, Richards)
10 Communication System
(Ramirez-Abundez, Richards)
11 New Customer Information System
(Ramirez-Abundez, Richards)
12 Non-Utility Activities (Richards)
13 Plant in Service (Richards)
14 Accumulated Depreciation (Higgins)
16 Construction Work in Progress
(Richards)
17 Property Held for Future Use (G.
Kelley)
19 Accumulated Deferred Taxes (Ferrer)
24 Return on Common Equity (D. Buys)
25 Capital Structure & WACC
(Quigley)
26 Miscellaneous Service Revenue
(Barrett, Prewett)
27 Total Operating Revenue (Kunkler)
28 S&P Global Platts Cost (Folkman)
30 Conservation Adjustments (Prewett,
Barrett)
31 Line Operation Supervisors (Thompson,
Zaslow)
32 Storm Hardening Adjustments
(Hitchens, Roberts, Wooten)
33 Storm Reserve (Ramirez-Abundez,
Folkman)
34 Advertising Expense (Folkman)
35 Economic Development Expense
(Folkman)
36 Rate Case Expense (G. Kelley)
37 Cost Allocation Methodologies
(Folkman, Higgins)
38 Salaries & Benefits (Zaslow)
39 Bad Debt Expense (G. Kelley)
40 Distribution O&M Expense
(Thompson, Zaslow)
41 Transmission O&M Expense
(Thompson, Zaslow)
43 Depreciation Expense (Higgins)
44 Taxes Other Than Income (Zaslow)
45 Income Tax Expense (G. Kelley)
46 Net Operating Income (G. Kelley)
47 Revenue Expansion Factor (G. Kelley)
48 Annual Operating Revenue Increase (G.
Kelley)
49 Cost of Service Methodology (Hampson)
50 Revenue Allocation (Hampson)
51 Customer Facilities Charges (Hampson)
54 Removal of Standby Service (Guffey)
55 Temporary Service Charges (Guffey)
56 Deposits to Prepare Cost Estimates
(Guffey)
57 Miscellaneous Service Charges (P.
Kelley)
58 Closure of Non-Firm Energy Tariff (P.
Kelley)
59 Technology Cost Recovery Rider
(Guffey)
60 Hurricane Michael Surcharge (P.
Kelley)
61 Rates & Charges Effective Date
(P. Kelley)
62 Administrative Authority to Approve
Tariffs (P. Kelley)
64 Description of Adjustments (Higgins)
Florida Public Utilities Company (FPUC or Company) filed a test year notification letter with the Florida Public Service Commission (Commission) on June 18, 2024, in which the Company indicated its intent to seek a permanent increase in its rates and charges based on a test year ending December 31, 2025, and a request for an interim rate increase. On August 22, 2024, FPUC filed its petition for an increase in base rates, as well as minimum filing requirements schedules (MFRs) and direct testimony of 10 witnesses. The Company is engaged in business as a public utility providing electric service as defined in Section 366.02, Florida Statutes (F.S.), and is subject to the jurisdiction of the Commission. FPUC serves approximately 15,000 retail customers in Calhoun, Liberty, and Jackson counties in the Company’s Northwest Division and approximately 18,100 retail customers in Nassau County in its Northeast Division.
FPUC requested an increase in base rates to generate an additional $12,593,450 in annual revenues, using the Commission’s proposed agency action (PAA) process under Section 366.06(4), F.S. The requested increase, according to FPUC, will provide the Company with an opportunity to earn a rate of return of 6.89 percent on the Company's plant and property used to serve its customers based on a return on equity of 11.30 percent. The Company based its request on a 13-month average rate base of $150,053,096 for the projected test year ending December 2025.
FPUC, in its petition stated that the key drivers for the proposed rate increase are: (1) investments tied to improvements in reliability: purchases and renovation of substations, increased costs associated with safety regulations, and increased depreciation expenses, (2) supply chain shortage and increased prices for labor, fuel, materials, insurance, high inflation, additional costs for cyber-security improvements, and (3) implementation of a new Customer Information System (CIS).
FPUC stated in its petition that the requested test year period ending December 31, 2025, is the most relevant period upon which the Company’s operations should be analyzed for purposes of establishing rates for the period in which the new rates will be in effect. The Company further stated that this period will be indicative of its actual revenues, expenses, and investment during the first 12 months that the new rates will be in effect. The Commission last granted FPUC an approximately $3.75 million rate increase by Order No. PSC-14-0517-S-EI.[1]
On September 4, 2024, the Office of Public Counsel (OPC) filed its notice of intervention in this docket and the Order acknowledging the intervention was issued on September 5, 2024.[2] On September 4, 2024, FPUC filed revisions to MFR Schedules B-2 and G-3 to correct a reference to the prior rate case order. No numeric values were changed.
In its petition, FPUC also requested an interim rate increase in its base rates and charges to generate $1,812,869 in additional gross revenues until the permanent rates become effective. The Company has based its interim request on a historical test year which ended December 31, 2023. In its petition, FPUC stated that it will hold any revenues collected, subject to refund, with interest at a rate determined pursuant to Rule 25-6.0435(3), Florida Administrative Code (F.A.C.) and that it be allowed to collect the interim increase subject to a corporate undertaking. In Order No. PSC-2024-0441-PCO-EI, the Commission suspended the proposed permanent rates and approved the requested interim rate increase.[3]
During the review process staff conducted an audit of FPUC based on the historical test year ended December 31, 2023. The auditors report and findings were issued on December 20, 2024.[4] Additionally, during the review process, noticed in-person customer service hearings were held on December 4, 2024, in Fernandina Beach and on January 8, 2025, in Marianna. Twelve customers provided testimony at the December 4, 2024 service hearing and 20 customers provided testimony at the January 8, 2025 service hearing. Additionally, ten customers and the Jackson County Board of County Commissioners opposing the proposed rate increase have filed written comments in the correspondence side of the docket as of February 10, 2025.
This recommendation addresses FPUC’s requested permanent rate increase. The final rates based on the Commission vote on the requested permanent rate increase will be addressed at the subsequent special agenda, scheduled for March 20, 2025. The Commission has jurisdiction over this matter pursuant to Chapter 366, F.S., including Sections 366.06 and 366.071, F.S.
Is FPUC's projected test period for the twelve months ending December 31, 2025, appropriate?
Recommendation:
Yes, FPUC’s projected test period for the twelve months ending December 31, 2025, is appropriate. (Kunkler)
Staff Analysis: In general, a projected test year methodology uses forecasted data for
a 12-month period to match average revenues and expenses with average rate base
investment. FPUC proposed the year ending December 31, 2025 as its test year
for this docket, stating that it will “reflect actual conditions, be indicative
of the actual revenues, expenses, and investment during the first 12-months
that new rates will be in effect.”[5]
Staff agrees with FPUC that the 12 months ending December 31, 2025, provides a reasonable basis for assessing FPUC’s financial and operational performance, allowing for a thorough evaluation of revenues, expenses, and rate base investment. Further, staff believes this test period ensures that the projections reflect current trends and future conditions, making it a sound period for regulatory and financial planning. Therefore, staff believes that the projected test period of the twelve months ending December 31, 2025, is appropriate.
CONCLUSION
Staff recommends that FPUC’s projected test period for the twelve months ending December 31, 2025, is appropriate.
Are FPUC’s forecasts of customers, energy, and demand by revenue and rate class for the projected test year appropriate?
Recommendation:
Yes, FPUC’s forecasts of customers, energy, and demand by revenue and rate class are appropriate. (Kunkler)
Staff Analysis:
This issue addresses whether FPUC’s forecasts of customers, energy (kWh), and demand (kW) by revenue and rate class for the projected test year are appropriate. Staff analyzed the methodologies, assumptions, and data inputs utilized by the Company to project customer counts, energy consumption, and peak demand across its various rate classes.
FPUC currently provides electric service to customers across two separate service areas. FPUC provided the forecasts for these two service areas separately due to geographical differences between the two areas. The Northeast division, headquartered in Fernandina Beach, Florida, serves customers on Amelia Island while the Northwest division, based in Marianna, Florida, serves customers in the surrounding counties of Jackson, Calhoun, and Liberty.
Customers
FPUC explained that the customer count forecasts for each
rate class were developed using a time trend based on 2020 to 2023 data, and
then adjusted for known growth factors and growth estimates for service
territories and rate classes.[6]
Each service territory is composed of six rate classes – Residential (RS),
General Service (GS or Commercial Small), General Service Demand (GSD or
Commercial), General Service Large Demand (GSLD or Large Commercial), General
Service Large Demand 1 (GSLD 1 or Industrial), and Lighting (Outdoor Lighting
and Street Lighting).
The Company served an average monthly total of 33,091 customers across the two divisions in 2023, and projected its total customer count to increase to 33,190 in 2024 (0.2 percent growth), and then increase again to its test year projection of 33,290 customers in 2025 (0.3 percent growth). The Company’s historical and forecasted customer data, by rate class and division, is broken down further in the tables below.
Table 2-1
FPUC Average Monthly Customers – Northeast Division
Year |
Residential |
Commercial
Small |
Commercial |
Large
Commercial |
Industrial |
Lighting |
Total |
Percent
Growth (Y/O/Y) |
2021 |
15,343 |
1,700 |
253 |
11 |
2 |
486 |
17,795 |
- |
2022 |
15,440 |
1,710 |
250 |
11 |
2 |
475 |
17,888 |
0.52% |
2023 |
15,599 |
1,723 |
253 |
11 |
2 |
472 |
18,060 |
0.96% |
2024* |
15,645 |
1,727 |
255 |
11 |
2 |
469 |
18,109 |
0.27% |
2025** |
15,690 |
1,728 |
255 |
10 |
2 |
470 |
18,155 |
0.25% |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Supplemental Response No. 12 in Staff’s Fourth Data Request and Response No. 2 in Staff’s Twenty-Eighth Data Request.
Table 2-2
FPUC Average Monthly Customers – Northwest Division
Year |
Residential |
Commercial Small |
Commercial |
Large Commercial |
Industrial |
Lighting |
Total |
Percent
Growth (Y/O/Y) |
2021 |
10,004 |
2,020 |
395 |
13 |
0 |
2,448 |
14,880 |
- |
2022 |
10,076 |
2,056 |
400 |
13 |
0 |
2,421 |
14,966 |
0.58% |
2023 |
10,120 |
2,058 |
408 |
14 |
0 |
2,431 |
15,031 |
0.43% |
2024* |
10,162 |
2,063 |
410 |
14 |
0 |
2,432 |
15,081 |
0.33% |
2025** |
10,205 |
2,070 |
413 |
15 |
0 |
2,432 |
15,135 |
0.36% |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Supplemental Response No. 12 in Staff’s Fourth Data Request and Response No. 2 in Staff’s Twenty-Eighth Data Request.
Table 2-3
FPUC Average Monthly Customers – Total Combined
Year |
Residential |
Commercial Small |
Commercial |
Large Commercial |
Industrial |
Lighting |
Total |
Percent Growth (Y/O/Y) |
2021 |
25,347 |
3,720 |
648 |
24 |
2 |
2,934 |
32,675 |
- |
2022 |
25,516 |
3,766 |
650 |
24 |
2 |
2,896 |
32,854 |
0.55% |
2023 |
25,719 |
3,781 |
661 |
25 |
2 |
2,903 |
33,091 |
0.72% |
2024* |
25,807 |
3,790 |
665 |
25 |
2 |
2,901 |
33,190 |
0.30% |
2025** |
25,895 |
3,798 |
668 |
25 |
2 |
2,902 |
33,290 |
0.30% |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Supplemental Response No. 12 in Staff’s Fourth Data Request and Response No. 2 in Staff’s Twenty-Eighth Data Request.
Staff analyzed the Company’s historical customer data for both divisions. The historical data for the Company’s Northeast division shows moderate growth (approximately 1.3 percent per year since 2015), however the Company forecasted 0.3 percent growth for both 2024 and 2025. The Company explained that the lower projected growth compared to the historical average is due to the service area on Amelia Island being nearly fully-developed, with less opportunities each year for new developments, which the Company supported with a list of residential building permits issued by year, showing a substantial reduction since 2019.[7] The historical customer data for Company’s Northwest division data shows minimal growth in recent years and virtually zero growth since 2015.[8] FPUC explained that the Northwest division is more rural and still recovering from the effects of Hurricane Michael. Both of these factors support FPUC’s forecasts of minimal growth in the test year.
Based on staff’s review of the Company’s customer forecast methodology, past historical trends, and the Company’s response to staff data requests, staff believes FPUC’s customer count forecast of 33,290 for the 2025 test year is reasonable.
Energy Sales
FPUC’s projects total
energy sales of 613,810,520 kWh for the 2025 test year, as detailed in its
MFRs.[9]
FPUC witness Taylor provided forecast models for the Company’s RS class, the GS
class, and the GSD class, by service area, and referred to these classes as
Residential, Commercial Small, and Commercial, respectively. These models
detail each service area’s historical and forecasted use-per-customer (UPC) by
rate class which, when multiplied by the service area’s projected customer
counts, result in the service area’s projected energy sales (in kWh) for the
test year for those rate classes. [10]
Company total projected sales are simply the sum of FPUC’s two service area’s
projected sales.
The Company’s models
used to project UPC for these rate classes utilized a 10-year average of
Cooling Degree Days (CDDs) and Heating Degree Days (HDDs) and a time trend.[11]
Staff analyzed FPUC’s inputs and assumptions used in its forecast models for
these rate classes. Staff notes that it is unusual for a company’s usage models
to only consist of weather variables and a time trend variable, neglecting to
include other variables that are often found to impact sales, such as energy
price, average income, efficiency standards, etc. Even so, staff agrees with
witness Taylor that the UPC models are statistically significant and the
regression models’ independent variables explain a relatively high percentage
of the variation in UPC for these rate classes.[12] The Company’s historical and forecasted UPC
data for the Residential, Commercial Small, and Commercial rate classes are
detailed in the tables below.
Table 2-4
FPUC Average Annual UPC (kWh) – Residential
Year |
Northeast Division |
Percent Growth (Y/O/Y) |
Northwest Division |
Percent Growth (Y/O/Y) |
2019 |
12,284 |
- |
12,753 |
- |
2020 |
12,090 |
-1.58% |
12,317 |
-3.43% |
2021 |
11,920 |
-1.40% |
12,129 |
-1.52% |
2022 |
11,886 |
-0.29% |
12,115 |
-0.11% |
2023 |
11,528 |
-3.01% |
11,887 |
-1.89% |
2024* |
11,579 |
0.44% |
12,052 |
1.39% |
2025** |
11,439 |
-1.21% |
11,901 |
-1.25% |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Supplemental Response No. 12 in Staff’s Fourth Data Request and Response No. 2 in Staff’s Twenty-Eighth Data Request.
Table 2-5
FPUC Average Annual UPC (kWh) – Commercial Small
Year |
Northeast Division |
Percent Growth (Y/O/Y) |
Northwest Division |
Percent Growth (Y/O/Y) |
2019 |
17,302 |
- |
14,239 |
- |
2020 |
16,127 |
-6.80% |
13,440 |
-5.61% |
2021 |
16,746 |
3.84% |
13,594 |
1.15% |
2022 |
16,506 |
-1.43% |
14,532 |
6.89% |
2023 |
16,608 |
0.61% |
14,504 |
-0.19% |
2024* |
16,608 |
0.00% |
14,729 |
1.55% |
2025** |
16,631 |
0.14% |
15,026 |
2.02% |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Supplemental Response No. 12 in Staff’s Fourth Data Request and Response No. 2 in Staff’s Twenty-Eighth Data Request.
Table 2-6
FPUC Average Annual UPC (kWh) – Commercial
Year |
Northeast Division |
Percent Growth (Y/O/Y) |
Northwest Division |
Percent Growth (Y/O/Y) |
2019 |
306,699 |
- |
205,482 |
- |
2020 |
294,331 |
-4.03% |
198,170 |
-3.56% |
2021 |
303,547 |
3.13% |
201,343 |
1.60% |
2022 |
324,685 |
6.96% |
205,583 |
2.11% |
2023 |
315,008 |
-2.98% |
200,648 |
-2.40% |
2024* |
301,352 |
-4.34% |
199,780 |
-0.43% |
2025** |
307,390 |
2.00% |
203,084 |
1.65% |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Supplemental Response No. 12 in Staff’s Fourth Data Request and Response No. 2 in Staff’s Twenty-Eighth Data Request.
For the Company’s
large commercial and industrial rate classes, General Service Large Demand
(GSLD) and General Service Large Demand1 (GSLD1), due to the small number of
customers (27 total customers across both divisions in 2023) and the minimal
customer growth expected, the usage projections were forecasted separately
utilizing a combination of past usage along with identified known changes in
each individual customer’s operations.[13]
For the Company’s
lighting customers, consisting of Outdoor Lighting (OL) and Street Lighting
(SL), the customer growth rate from their respective service territories was
used as a proxy for the expected growth of lighting energy sales.[14]
FPUC explained this decision was due to the Company’s expectation that the
recent growth in lighting revenues will not continue, partly due to the SL
class now being closed to new enrollment. Staff analyzed the Company’s
historical usage as well as the Company’s explanation for any deviations from
the historical norm and believes the test year usage projections for these rate
classes are reasonable.
Based on staff’s review of the Company’s MFR’s, models, assumptions, results, as well its responses to staff data requests, staff agrees with FPUC that its total energy sales projection of 613,810,520 kWh for the 2025 test year, is reasonable.
Demand
FPUC currently has three rate classes that employ
a demand component – the GSD class, the GSLD class, and the GSLD1 class. FPUC
stated that the forecasts of billing demand for the GSD and GSLD rate classes
by service area were based on the historical relationship with CDDs, HDDs, and
a time trend variable, combined with the forecast of the number of customers by
rate class. In some cases, the demand forecasts were adjusted based on known
and measurable changes to customer’s operations. For example, for one of the
Northeast Division’s Large Commercial Customers, a building owned by the
customer was demolished, therefore FPUC made an adjustment to the forecasted
demand for that customer class.[15]
The Company explained that since the GSLD1 rate
class consists of only two customers (both in the Northeast Division), the test
year demand was forecasted “directly” for these two customers.[16]
The Company is proposing the GSLD1 customer and lone GSLD1 Standby Customer be
consolidated, eliminating the Standby tariff (Issue 54). The Company’s
historical and forecasted demand, by rate class and division, are detailed in
the tables below.
Table 2-7
FPUC Demand Forecasts (kW) – Northeast Division
Year |
Commercial (GSD) |
Large Commercial (GSLD) |
Industrial (GSLD1) |
Industrial (GSLD –Standby) |
2020 |
218,333 |
75,271 |
212,600 |
312,000 |
2021 |
222,241 |
78,427 |
121,900 |
312,000 |
2022 |
239,374 |
76,160 |
171,600 |
312,000 |
2023 |
228,906 |
77,603 |
232,100 |
312,000 |
2024* |
230,100 |
79,933 |
199,500 |
312,000 |
2025** |
232,090 |
72,099 |
192,567 |
312,000 |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Response No. 3 in Staff’s Twenty-eighth Data Request.
Table 2-8
FPUC Demand Forecasts (kW) – Northwest Division
Year |
Commercial (GSD) |
Large Commercial (GSLD) |
2020 |
304,271 |
89,104 |
2021 |
328,378 |
89,334 |
2022 |
333,022 |
93,374 |
2023 |
331,590 |
94,323 |
2024 |
323,984 |
94,702 |
2025 |
333,565 |
93,055 |
*4 months of actual data, 8 months of forecasted data.
**Forecasted Test Year.
Source: Response No. 3 in Staff’s Twenty-eighth Data Request.
Staff has reviewed the Company’s historical
demand data, its forecast of demand for the 2025 test year, as well as the
Company’s explanation for any measurable deviations and believes the Company’s
demand projections for the test year are reasonable.
CONCLUSION
FPUC’s forecasts of customers, energy, and demand by revenue and rate class, are appropriate.
Are FPUC's estimated revenues from sales of electricity by rate class at present rates for the projected test year appropriate? If not, what adjustments should be made?
Recommendation:
Yes, FPUC's estimated revenues from sales of electricity by rate class at present rates for the projected test year are appropriate. No adjustments are necessary. (Kunkler)
Staff Analysis:
This issue addresses whether FPUC’s estimated revenues from sales of electricity by rate class at present rates for the projected test year are appropriate. In general, to calculate total revenues from sales of electricity, first, the Company’s forecasted customer counts for each class are multiplied by the present customer charge for that class to arrive at its base customer charge revenue. Similarly, the forecasted usage (in kWh) for each customer class are multiplied by their respective present energy charge to arrive at its energy charge revenue. Lastly, for the rate classes with a demand component, forecasted demand (in kW) for each applicable class is multiplied by the present demand charge to calculate demand revenue. These three components are then summed to yield total revenues from sales of electricity.
As explained in Issue 2, FPUC provided forecasted customer counts, energy sales, and demand (where applicable) for all of the Company’s rate classes for the 2025 test year and, in that issue, staff recommends no adjustments to such forecasts. Staff confirmed that FPUC used the correct current rates and forecasted units for all customer classes in its calculations of test year revenue, arriving at a total revenue from sales of electricity by rate class at present rates of $24,375,589, as summarized in Table 3-1 below.
Table 3-1
Estimated Revenues from Sales of Electricity by Rate Class at Present Rates - 2025 Test Year
Customer Class |
Customer Charge
Revenue |
Energy Charge
Revenue |
Demand Charge
Revenue |
Total Revenue |
Residential Service (RS) |
$5,267,161 |
$8,396,460 |
$0 |
$13,663,622 |
General Service (GS) |
$1,269,069 |
$1,736,912 |
$0 |
$3,005,981 |
General Service Demand (GSD) |
$660,118 |
$887,789 |
$2,542,617 |
$4,090,524 |
General Service Large Demand (GSLD) |
$46,596 |
$198,578 |
$1,060,285 |
$1,305,459 |
General Service Large Demand 1 (GSLD 1) |
$23,395 |
$0 |
$597,419 |
$620,814 |
Lighting Service (OL and SL) |
$1,689,189 |
$0 |
$0 |
$1,689,189 |
Totals |
$8,955,529 |
$11,219,739 |
$4,200,321 |
$24,375,589 |
Source:
MFR Schedule E-13c.
CONCLUSION
FPUC's estimated revenues from sales of electricity by rate class at present rates for the projected test year are appropriate. No adjustments are necessary.
What are the appropriate inflation, customer growth, and other non-payroll trend factors for use in forecasting the 2024 and 2025 test year budgets?
Recommendation:
The non-payroll trend factors appropriate for forecasting the 2024 and 2025 test year budgets are: 2.84 percent for inflation, 0.30 percent for customer growth, and 0.34 percent for the revenue trend factor (for 2024), and 2.31 percent for inflation, 0.31 percent for customer growth, and (0.09) percent for revenue (for 2025). The combination of customer and inflation trend factors for 2024 and 2025 are also appropriately used for this purpose. (Barrett)
Staff Analysis:
Trend factors are numeric escalators (or multipliers) that are applied to historic expenses as an operations and maintenance (O&M) benchmarking tool and for preparing the forward-looking test year O&M expense budget amounts. O&M expenses that have trend factors applied are generally grouped as “payroll” and “non-payroll” expenses. Witness Napier stated that the most commonly used trend factors for non-payroll expenses are inflation and inflation times customer growth.[17] This issue addresses FPUC's application of inflation, customer growth, and other trend factors for the 2025 forecasted test year budget for non-payroll related expenses.
Witness Napier stated that FPUC used inflation, customer growth, payroll growth, a revenue trend factor, and two factors in combination for projecting test year O&M expenses.[18] Witness Napier asserts the O&M expenses from the 2023 historic year were used as the starting point for developing the 2024 and 2025 test year estimates. From that starting point, the Company made all necessary adjustments through the application of trend factors, as reflected in the MFR Schedules associated with this rate proceeding. The witness states that all appropriate trend factors were used in this manner, and when trend factors were not used, direct expense projections were used, which relied upon the expertise of internal managers or known items impacting certain expenses as a basis for the projection.[19] Witness Napier further stated that the Company’s application of trend factors in the instant case is consistent with how trend factors were used in prior rate proceedings.[20]
Inflation Trend Factor
FPUC used a weighted average of Consumer Price Index for All Urban Consumers (CPI-U) as its measure of inflation.[21] The Company used an inflation trend factor to project certain non-payroll O&M expenses for the 2025 projected test year.[22] The Company states that its forecasted data was provided by the Bloomberg Weighted Average CPI Forecast, which estimated average inflation values of 2.84 percent for 2024, and 2.31 percent for 2025.[23] FPUC stated that the Bloomberg forecasts are derived from monthly and quarterly surveys it conducted and from forecasts submitted by various banks. FPUC also stated the weighted average incorporates more than 40 different economists’ expectations to calculate its weighted average CPI. FPUC believes the derived averages from Bloomberg are appropriate for use in this proceeding, since the weighted average incorporates multiple perspectives.[24] FPUC stated it did not consider any alternative sources of CPI other than Bloomberg’s.
The Company believes average CPI is the most appropriate inflation trend factor, as it was approved in the last FPUC electric rate case, as well as the Company’s 2022 Florida natural gas rate case.[25] FPUC believes its use in this proceeding demonstrates and promotes consistent use and application across all the Company’s Florida regulated operations.[26]
Staff notes that FPUC’s 2023 inflation forecast for 2024 (2.84 percent) used to prepare its budget in this case is conservative relative to the similar forecast prepared at a later point in time (an inflation forecast of 2024 prepared in September of 2024, showing 2.90 percent). A similar analysis reflects that FPUC’s 2023 inflation forecast for 2025 (2.31 percent) remained the same for 2025, as shown in Table 4-1 below. Staff believes FPUC’s trend factors for inflation used to prepare its test year budgets are reasonable.
Table 4-1
Projections of CPI in
Bloomberg Forecasts
Bloomberg's Weighted Average CPI |
Date of Forecast |
|
December 2023 |
September 2024 |
|
Forecast of CPI for 2024 |
2.84 percent |
2.90 percent |
Forecast of CPI for 2025 |
2.31 percent |
2.31 percent |
Source: Document No. 09904-2024, FPUC’s response to
staff’s 11th data request, No. 2 and Document No. 09977-2024, FPUC’s
response to staff’s 13th data request, No. 4.a.
Customer Growth Trend
Factor
A customer growth trend factor is a composite of elements that influence the rate at which a customer base expands over time. FPUC estimates customer growth at 0.30 percent for 2024, and 0.31 percent for 2025.[27] FPUC utilized the Bureau of Labor Statistics data as a resource for its customer growth data.[28] Staff notes that FPUC’s customer growth trend factor is a fallout calculation of the customer count forecasts by rate class addressed in Issue 2.
According to witness Napier, FPUC based the customer growth trend factor on a detailed analysis, in which FPUC tested the reasonableness of its results from “revenue related projections used within this rate proceeding.”[29] The witness also stated that the application of customer growth and other trend factors used in this proceeding is consistent with how expense projections were developed in prior rate proceedings. Consistent with staff’s analysis and recommendation in Issue 2, staff believes FPUC’s 2024 and 2025 projections of customer growth (0.30 percent for 2024 and 0.31 percent for 2025) it used for forecasting its test year budgets are reasonable.
Other Trend Factors
In addition to the inflation and customer growth trend factors, MFR Schedule C-7 reflects that FPUC used a revenue trend factor for the limited purpose of projecting uncollectible expenses for the forecasted test year budget. In addition, MFR Schedule C-7 reflects that FPUC used two combination trend factors, or factors that were the product of multiplying stand-alone trend factors. The combination trend factors are inflation and customer growth.
CONCLUSION
The non-payroll trend factors appropriate for forecasting FPUC’s 2024 and 2025 test year budgets include: for 2024, 2.84 percent for inflation, 0.30 percent for customer growth, and 0.34 percent for revenue; For 2025, 2.31 percent for inflation, 0.31 percent for customer growth, and (0.09) percent for revenue. The combination of customer and inflation trend factors for 2024 and 2025 are also appropriately used for this purpose.
Is the quality of electric service provided by FPUC adequate?
Recommendation:
Yes. Staff recommends that FPUC’s overall quality of service is adequate. (Ramirez-Abundez)
Staff Analysis:
Pursuant to Section 366.041(1), F.S., in fixing rates the Commission is authorized to give consideration, among other things, to the efficiency, sufficiency, and adequacy of the facilities provided and the services rendered. In making this assessment, Commission staff reviewed:
1. Complaints filed with the Commission via its Consumer Activity Tracking System (CATS) from January 1, 2020, through October 24, 2024[30]
2. Complaints filed with FPUC from January 1, 2020, through October 24, 2024
3. Testimony made by customers at the in-person service hearings held on December 4, 2024 (Northeast division) and January 8, 2025 (Northwest division)
4. Correspondence filed in the docket file
There were 94 complaints logged in the CATS system and 127 complaints were received by FPUC over the five-year period.[31] FPUC serves approximately 33,100 customers. Table 5-1 shows these complaints by source and type. As shown below, majority of these complaints are related to billing issues which include concerns regarding high bills, overall rates and charges, and bill discrepancies.
Table 5-1
Customer Complaints
|
FPUC Complaints |
CATS Complaints |
||
Year |
Quality of Service |
Billing Issues |
Quality of Service |
Billing Issues |
2020 |
7 |
4 |
1 |
4 |
2021 |
7 |
21 |
2 |
19 |
2022 |
8 |
20 |
0 |
19 |
2023 |
8 |
22 |
2 |
23 |
2024(January – October) |
6 |
24 |
1 |
23 |
Total |
36 |
91 |
6 |
88 |
Source: Response No. 1 in Staff’s Tenth Data Request, Document No. 09893-2024.
Of the 94 CATS complaints, there were 23 complaints (22 billing complaints and one quality of service) that appeared to demonstrate Commission rule violations associated with improper disconnects, improper bills and/or not providing timely responses. Based on the above, the total complaints from CATs and FPUC (94+127) averages to approximately 44 complaints per year. When compared to the Company’s total customer base of 33,100 customers, the resulting calculation is approximately 0.1 percent.
A total of 33 customers spoke at both service hearings. The principle comment made by customers was opposition to the proposed rate increase. Customers also discussed: (1) difficulties reaching FPUC by phone; (2) a lack of physical locations to pay bills; and (3) inaccurate bills. There were also 6 customers that spoke in favor of FPUC’s service quality. Through data requests, FPUC indicated that it was aware, prior to the service hearings, of the issues expressed by customers regarding difficulty contacting them. Since mid-2023, FPUC has made efforts to improve its call handling practices by increased staffing and enhanced training. FPUC’s call center currently consists of approximately 30 customer service agents and the average wait-time is 4 minutes and 36 seconds. In addition to calling the Company, customers may also contact them by mail, email, or its website.[32] As stated above, customers also expressed concern regarding a lack of physical locations available to pay their bills. FPUC indicated that customers may find retail centers, where bills can be paid in-person with no additional fees, on the back of their bill or on the Company’s EZ-Pay webpage using their account number.[33] Customers may also pay their bills by mail or EZ-Billing, when automatic payments are set up to a checking or savings account, with no fees. There is a payment fee of $2.25 per $750 for bills paid by phone or EZ-Pay one-time payments. In an effort to resolve the issues brought forth at the service hearings, the Company reached out to all of the customers that provided testimony.[34] In addition, by letter dated February 10, 2025, the Company notified the Commission of the following additional customer outreach actions: (1) added a website page to further explain bill components and the Company’s rate increase request; (2) initiated informative social media posts regarding conservation programs and payment assistance; and (3) invited customers to its in-person event in the Northwest division to address further questions and to provide payment information and assistance.[35]
Additionally, 11 comments have been filed in the docket file that address the rate increase and customer service difficulties. Of these 11 comments, one was a letter from the Jackson County Board of County Commissioners opposing the overall rate increase. In order to improve its quality of service, FPUC has recently implemented the following:
1. Five9 – provides updates to call flow options for inbound contacts to deliver their call to the appropriately skilled agent via a single dashboard.
2. Voice of the Customer – gathers direct customer feedback via post-call and email surveys, identifies trends and develops plans to deliver improvements in the areas customers find most beneficial.
3. Service Excellence Strategy – provides the blueprint for actualizing commitment to improved customer service by focusing on the quality of service across every touchpoint.
4. New Customer Information System (CIS) – provides customer communication improvements such as notification and preference management system that will allow customers to set channel and contact preferences for outbound communications for billing and payments, and marketing, which will allow the customer to control how and when the Corporation contacts them. This is further discussed in Issue 11.
CONCLUSION
FPUC’s overall quality of service appears to be adequate given the relatively low average number of complaints with respect to its total customer base. Furthermore, the recent improvements by FPUC (e.g., Five9, Voice of the Customer, and CIS demonstrate the Company’s efforts to enhance its customer service and overall quality of service. Therefore, staff recommends that FPUC’s overall quality of service is adequate.
Should FPUC’s proposed acquisition and replacement of substations and transmission assets be included in the 2025 projected test year?
Recommendation:
Yes. FPUC’s proposed acquisition and replacement of substations and transmission assets should be included in the 2025 projected test year. These projects will allow FPUC to maintain and improve the reliability and integrity of its electric system and provide savings to customers. Further, staff recommends the Commission authorize FPUC to increase its base rates by the incremental revenue requirement associated with the substation and transmission projects once these assets are in service. FPUC should be required to file its step increase calculations and tariffs for staff review. The Commission should give staff administrative authority to approve FPUC’s revised tariffs. (Thompson, Higgins, Richards)
Staff Analysis:
In its 2025 projected test year, FPUC has included the costs associated with the acquisition and replacement of four substations and a transmission line in its Northwest Florida territory, and replacement/rebuild of two FPUC-owned substations in its Northeast Florida territory.
The Northwest Florida acquisitions will be purchased from Florida Power & Light Company (FPL), and the purchase is expected to be completed by February 2025. In response to staff’s data requests, FPUC indicated that within the purchased assets, certain equipment, primarily substation transformers, will need to be replaced due to age, and additional modifications, such as the addition of redundant transformers, will be necessary to improve the reliability and resiliency of these assets.[36] In response to a follow-up data request, FPUC indicated that thus far, only a visual inspection has been conducted to determine which equipment will potentially need to be replaced.[37] Based on this inspection, FPUC determined that several transformers are approximately 58 years old and therefore nearing the end of their useful life based on the average service life of distribution substation equipment in Florida, which ranges from 45 to 60 years. FPUC stated that the age of the other substation equipment could not be determined visually; however, a visual assessment of the equipment and substation design was completed to identify equipment that would likely require replacements/updates. Once the substation and transmission assets have been acquired, FPUC intends to review previous testing results and conduct additional testing for these assets to confirm what equipment will require replacement or updates. The replacement/update of these assets is expected to be completed by December 2025. The purchase of these assets is expected to cost approximately $4.2 million, and the replacement/update of these assets is expected to cost approximately $6.5 million. FPUC expects the acquisition of these assets to result in annual savings to customers of approximately $1.4 million by eliminating the distribution charge paid to FPL for the provision of purchased power to FPUC from these assets. These projected savings will be passed on to FPUC’s customers through reduced purchased power costs and a reduced fuel factor.[38]
For FPUC’s two Northeast Florida substations, AIP and JL Terry, FPUC indicated that aging equipment needs to be replaced, and the substations need to be rebuilt for safety and regulatory compliance. In response to staff’s data requests, FPUC indicated that the AIP substation metal clad switchgear, which was placed in-service in the 1970s, has reached its end of useful life based on testing and the resulting repairs over the last 15 years.[39] The load currently served by this substation cannot be served from another substation; therefore, FPUC intends to rebuild this substation using the existing transformers to reduce costs. Regarding the JL Terry substation, FPUC indicated that due to load growth and to match impedance of the other transformer at this substation, FPUC intends to replace the 30 megavolt-amperes (MVA) transformer with a new 40 MVA transformer. Upon replacement, the current 30 MVA transformer would be relocated to the step down substation to replace a 20 MVA transformer that has been in service for over 70 years and has reached its end of useful life. The rebuild of the AIP substation is expected to be completed by April 2025, and the replacement at the JL Terry substation is expected to be completed by November 2025. These projects are expected to cost approximately $6.3 million and $2.4 million, respectively.
To complete the above projects, FPUC has selected a contractor who has been previously vetted against other contractors by, and has an existing contract with, the Company. The project cost estimates for the replacement/rebuild projects were provided by the contractor, in consultation with FPUC personnel, and the cost estimate for the acquisitions was developed by FPL based on the current depreciated book value of the assets, and the costs associated with separation of the assets.
Staff has reviewed these projects and believes that they are necessary to maintain and improve the reliability and integrity of FPUC’s electric system. Additionally, the acquisition of the Northwest Florida substation and transmission assets is expected to save customers approximately $1.4 million annually in avoided distribution charges. As such, staff recommends that FPUC’s proposed acquisition and replacement of substations and transmission assets be approved for inclusion in the 2025 projected test year.
Accounting Treatment
FPUC has requested certain accounting treatment for the costs associated with the substations discussed in this issue. Specifically, the substation assets are entering into service throughout the projected test year concluding in December 2025.[40] Due to the staggered in-service of the various substation investments throughout 2025, the associated revenue requirements under the normal ratemaking process are less than they would otherwise be had the assets been in service for the full 13 months of the rate-setting test period. This is because in ratemaking, the average rate base value is determined on a 13-month basis, while any associated operating expenses generally begin at the point of in-service. Thus, assets must be in-service for the entire duration of the test period for the total associated revenue requirement to be included in service rates. However, FPUC has essentially requested that full-year revenue requirements associated with the substation investments be included in the new rates set in this proceeding. This would be achieved by using year-end account balances of the associated investments rather than 13-month average balances for determining the revenue requirement.
The additional revenue requirement associated with the Company’s proposal is $503,280, or $678,271 after grossing up for income taxes, regulatory assessment fees (RAFs) and bad debt.[41] This revenue requirement amount was calculated using the Company’s requested weighted average cost of capital of 6.89 percent. Using staff’s proposed weighted average cost of capital of 6.34 percent (Issue 25), the additional revenue requirement is $475,697, or $641,097 after grossing up for income taxes, RAFs, and bad debt (Issue 39).
Staff recommends that the substation project be approved; however, the full revenue requirement associated with these assets should not be included in rates at this time as requested by FPUC. To calculate base rates at this time, the 13-month average rate base value should be used. The additional annual revenue requirement, i.e., the difference in the associated revenue requirement based on 13-month versus year-end account balances, should be included in customer rates as a step increase following the entire project’s in-service date. Therefore, staff recommends that the Commission grant FPUC authorization to increase its rates when all proposed substation assets have been placed into service for the benefit of FPUC’s customers. Additionally, FPUC should be required to file a rate calculation and associated tariff information for staff review and administrative approval following the in-service date of the substation project. The Company should limit the total recovery amount to the incremental cost identified in this proceeding, updated to reflect the Commission’s vote on cost of capital (Issues 19-25) and Net Income Multiplier issues.[42] Further, for rate derivation purposes, FPUC should develop a factor equal to the ratio of the incremental revenue requirement associated with the project and the forecasted base revenue from electricity sales used in developing the 2025 projected test year. The factor should then be applied uniformly to FPUC’s base rates by customer class.
CONCLUSION
FPUC’s proposed acquisition and replacement of substations and transmission assets should be included in the 2025 projected test year. These projects will allow FPUC to maintain and improve the reliability and integrity of its electric system and provide savings to customers. Further, staff recommends the Commission authorize FPUC to increase its base rates by the incremental revenue requirement associated with the substation and transmission projects once these assets are in service. FPUC should be required to file its step increase calculations and tariffs for staff review. The Commission should give staff administrative authority to approve FPUC’s revised tariffs.
Should FPUC’s proposed reliability projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. FPUC’s proposed reliability projects, with a total estimated capital cost of approximately $4.2 million, should be included in the 2025 projected test year with no adjustments. These projects will allow FPUC to maintain and improve the reliability of its electric system. (Thompson, Richards)
Staff Analysis:
FPUC has included the costs associated with three projects in its 2025 projected test year to improve the reliability of its system: (1) the installation of a new transformer, (2) the installation of IntelliRupters, and (3) the installation of a substation loop and switches.
For the installation of a new transformer, FPUC indicated that the load growth in its Amelia Island service area has made it necessary to have three 75 MVA transformers at the step down substation to ensure reliable power for this area. The step down substation currently has two 75 MVA transformers, and one 50 MVA transformer. In response to staff’s data requests, FPUC stated that if one of the current 75 MVA transformers were to fail, there would be instances where the remaining 50 MVA and 75 MVA transformers would not ensure reliable power to Amelia Island.[43] Therefore, FPUC intends to replace the remaining 50 MVA transformer with another 75 MVA transformer, and sell the 50 MVA transformer once replaced. FPUC expects this project to be completed by November 2025, with a total estimated cost of approximately $2.7 million. FPUC intends to select the suppliers and contractors selected for the previous transformer replacements at the same location based on the success and efficiency of those replacements. The cost estimate for this project was developed using the transformer cost from the manufacturer, and installation costs based on the previous replacements.
For the installation of IntelliRupters, or fault detecting devices, FPUC indicated that it intends to install such devices to detect which sections of the system have outages, and minimize outage times to customers. In response to staff’s data requests, FPUC indicated that currently, an entire distribution feeder remains out of service until Company personnel can travel to the location, determine the issue, and perform switching operations to restore service to most customers.[44] This has contributed to FPUC’s reliability indicators comparing unfavorably to other large investor-owned utilities, especially when large sections, such as an entire distribution feeder, are tripped offline due to issues such as a tree falling on a power line or a car hitting a pole. This project would improve the reliability to customers by detecting the approximate location of the issue, and automatically isolating the impacted section.[45] FPUC expects this project to be completed by December 2025, with a total estimated cost of approximately $750,000. The Company intends to complete this project internally which will minimize the rate impact on customers. Cost estimates for this project were developed internally with input from the equipment vendors who provided estimates on equipment and installation costs.
For the installation of a substation loop and switches, FPUC stated that this project is part of a long term project to provide more reliable backup transmission service to the substations in its Amelia Island service area. This project consists of the installation of a 69 kilovolt underground cable and seven switches at FPUC’s stepdown substation. In response to staff’s data requests, FPUC indicated that it does not have the ability to work on transmission lines while still energized and as such, at least two transmission lines feeding a substation are necessary to keep the substation energized during maintenance activities and prevent interruptions to customers served from that substation.[46] The additional transmission line and switches being installed for this project will allow FPUC to isolate and de-energize each respective transmission line during maintenance activities, which will allow the Company to keep the substation energized and ensure a continuous supply of electricity to customers served by this substation. Additionally, this project would provide backup transmission service in the event that the primary transmission line has an outage. This project would improve reliability by providing backup transmission service at the stepdown substation, and allowing maintenance to be performed without impact to customers. FPUC expects this project to be completed by May 2025, with a total estimated cost of approximately $750,000. FPUC opted to select a contractor who has an existing contract with the Company to complete this project based on the complexities of this type of project. Cost estimates for this project were provided by the contractor.
Staff has reviewed these projects and believes that they will allow FPUC to maintain and improve the reliability of its electric system by ensuring reliable power to its Amelia Island service area and reducing service interruptions across its entire service area. As such, staff recommends that FPUC’s proposed reliability projects be approved for inclusion in the 2025 projected test year with no adjustments.
CONCLUSION
FPUC’s proposed reliability projects, with a total estimated capital cost of approximately $4.2 million, should be included in the 2025 projected test year with no adjustments. These projects will allow FPUC to maintain and improve the reliability of its electric system.
Should FPUC’s proposed safety projects be included in the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. FPUC’s proposed safety projects, with a total estimated capital cost of approximately $1.6 million, should be included in the 2025 projected test year with no adjustments. Staff recommends that these projects are necessary to improve the safety and reliability of FPUC’s system, and to reduce risk to life and property. (Thompson, Richards)
Staff Analysis:
FPUC has included the costs associated with three projects in its 2025 projected test year to improve the safety of its system: (1) the replacement of fibercrete vaults, (2) the replacement of live front equipment, and (3) the replacement of unjacketed underground cable. FPUC intends to complete all of these projects internally, which will minimize the rate impact on customers. Cost estimates for these projects were developed internally based on previous similar work completed by Company personnel.
For the fibercrete vaults replacement project, FPUC indicated in response to staff data requests that the fibercrete vaults under four manholes are eroding and need to be replaced.[47] These vaults are underground concrete enclosures that are used to provide a protected, accessible underground space to house and maintain Company electrical equipment. FPUC expects this project to be completed by December 2025, with a total estimated cost of approximately $400,000.
For the live front equipment replacement project, FPUC indicated in response to staff data requests that this equipment has been in service for many years, is outdated, and is unreliable as it has been responsible for numerous outages.[48] Live front equipment is electrical equipment containing uninsulated, energized electrical connections, which requires workers to use extra safety precautions to avoid direct contact with electricity. FPUC stated that due to this equipment being uninsulated, it poses a safety threat to workers, and is vulnerable to wildlife contact and contamination. Therefore, FPUC intends to replace 10 live fronts with traditional pad-mounted dead front equipment. Pad-mounted dead front equipment is electrical equipment installed on a concrete pad containing insulated, energized electrical connections, which ensures that there are no exposed connections. This equipment provides safety protection and eliminates the risk of exposure to wildlife or foreign objects due to being insulated. FPUC expects this project to be completed by December 2025, with a total estimated cost of approximately $720,000.
For the unjacketed underground cable project, FPUC indicated in response to staff data requests that this equipment is unreliable and at the end of its useful life.[49] Unjacketed underground cable is a cable with insulated high voltage wires, but no outer protective layer to shield the conductors. According to FPUC, the unjacketed underground cable uses a concentric neutral consisting of several bare copper conductors that are wrapped around the cable. The concentric neutral is uninsulated and therefore exposed to the elements. As such, the concentric neutral deteriorates over time, which impacts the reliability and safe operation of the equipment it is connected to. Therefore, FPUC intends to replace unjacketed underground cable with new jacketed underground cable, which provides insulation for the concentric neutral and thus protects it from exposure to the elements, resulting in improved reliability and safety of the equipment it is connected to. FPUC expects to replace approximately 7,000 feet of unjacketed underground cable by December 2025, with a total estimated cost of approximately $500,000.
Staff has reviewed these projects and believes that they are necessary to improve the safety and reliability of FPUC’s system and reduce risk to life and property, and that the associated costs appear to be reasonable. As such, staff recommends that FPUC’s proposed safety projects be approved for inclusion in the 2025 projected test year with no adjustments.
CONCLUSION
FPUC’s proposed safety projects, with a total estimated capital cost of approximately $1.6 million, should be included in the 2025 projected test year with no adjustments. Staff recommends that these projects are necessary to improve the safety and reliability of FPUC’s system, and to reduce risk to life and property.
Should FPUC’s proposed security camera project be included in the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. The proposed security camera project, with a capital cost of $326,430 and annual O&M expense of $63,024, should be included in the 2025 projected test year without any adjustments. Staff recommends that this project is needed to improve security and monitoring to align with North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection (CIP) standards and to also ensure the security of FPUC’s assets. (Ramirez-Abundez, Richards)
Staff Analysis:
FPUC’s requested security camera project includes the installation of 27 multi-sensor and dual cameras used to monitor and record activities in specific areas.[50] Of the 27 cameras, five will be installed at the Fernandina Beach Operation Center and three at the Marianna Operation Center. The remaining 19 cameras will be installed amongst FPUC’s seven substations.[51] The control house at each location will also be equipped with card readers, electric strike door locks, door contacts, request to exit motion, and communications equipment. FPUC requested a total capital cost of $326,430 and annual O&M expense of $63,024 for this project. The O&M expense would include Cloud storage, on premises video retention for each site, and the video management system. FPUC began installing cameras in November 2024 in Fernandina Beach and will then move to Marianna. Installations are expected to be completed in the first quarter of 2025.[52] The vendor for this project is Advantech. Advantech won a bid for the role of security integrator for Chesapeake in 2017 and the Company has continued to use them for similar projects since that time.
FPUC witness Haffecke testified that cameras are being added at substations and offices to provide additional security for FPUC’s equipment, better protect the public, and help deter theft that could lead to potential reliability issues. Additionally, FPUC indicated that this project is also needed to align with the NERC CIP standards.
CONCLUSION
Staff agrees that this project is necessary to align with NERC CIP standards and to also ensure the security of FPUC’s assets. Therefore, staff recommends the proposed security camera project, with a capital cost of $326,430 and annual O&M expense of $63,024 for the 2025 projected test year are appropriate and should be approve without any adjustments.
Should FPUC’s proposed two-way communication system be included in the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. The proposed two-way communication system, with a capital cost of $326,430 should be included in the 2025 projected test year. This results in a reduction to rate base of $940,711 and a reduction to depreciation expense of $187,357. Staff recommends that this project is needed to improve employee safety and increase restoration efficiency. (Ramirez-Abundez, Richards)
Staff Analysis:
FPUC’s requested two-way communication system is a system that allows employees to communicate by radio rather than cellular service. Witness Haffecke testified that previously the Company did not have a two-way communication system and relied on cellular telephones to communicate between its operation centers and field crews. Difficulties appear when cell towers are damaged and cellular communication is lost, especially during severe weather.[53] The Company originally requested to recover capital costs of $1.3 million for this project with no associated O&M expenses. However, based upon updated information and bids, the estimated capital costs for this project is $326,430 with no associated O&M expenses, which results in a rate base reduction of $940,711 from the Company’s original request.[54]
FPUC asserts that the two-way communication system would improve safety for the Company’s employees and the public. This system will also help expedite outage restoration times by allowing dispatchers and management to guide crews directly to outages and assist with switching activities. Furthermore, employees will have the ability to contact each other when additional materials are needed. A reliable communication system for field crews helps ensure that FPUC’s employees working on an affected circuit are in a safe position before energizing the circuit. Currently, restoration activities are performed by visual confirmation when cellular service is not available, which requires employees to physically go see impacted circuits.[55] The Company received two bids for the radio and end-user equipment, one of which is from Radio One. A final vendor has not yet been selected. The $326,430 of capital costs for this project is based off of the Radio One bid, which contemplates Motorola equipment, the anticipated amount for additional antennas and poles, installation, and Federal Aviation Administration regulatory compliance. FPUC stated it commissioned and just recently received the completed radio propagation study to ensure reliable radio coverage would be available over the entire electrical service territory.[56] The two-way communication system is planned to go in service June 2025.
CONCLUSION
Based on the above, the addition of the proposed two-way communication system will improve safety with field workers due to having the ability to communicate with other personnel even without cellular service. The communication system would also increase efficiency due to no longer needing visual confirmation of damaged circuits if cellular service is not available. Therefore, staff recommends FPUC’s proposed two-way communication system, with a capital cost of $326,430 should be included in the 2025 projected test year. This results in a reduction to rate base of $940,711 and a reduction to depreciation expense of $187,357.
Should FPUC’s proposed New Customer Information System (CIS) be included in the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. The proposed CIS, with a capital cost of $6.9 million and O&M expense of $356,083, should be included in the 2025 projected test year without any adjustments. Staff recommends that the project is needed to replace software that is at the end of its life, and will improve the customer billing system and cybersecurity, which will protect FPUC’s system and customer information. (Ramirez-Abundez, Richards)
Staff Analysis:
FPUC’s requested CIS went live on August 26, 2024, and was capitalized on October 1, 2024. The total capital cost for the system is $6,912,623. FPUC witness Estrada testified that the CIS project will replace two existing billing and payment platforms that are at end-of-life expectancy, with one streamlined system with an automated billing and invoicing process. The new system will allow customers to experience improvements with timing and accuracy of billing. The number of customers who receive paperless bills and make electronic payments has the potential to increase. Once entered into the system, meter readings are automatically reviewed, allowing identification of outliers such as unexpected high or low readings, and if necessary, create an exception.[57] This would allow for a process where the system will detect missing or unusual data that can be reviewed and adjusted, if necessary, prior to going out to customers. This project helps with reducing the manual processing time, which allows bills to be prepared efficiently. By the end of 2025, as part of this project, the customer self-service portal will allow residential and commercial customers to view and download their bills, view usage and payment history, make payments at any time, and have the ability to start and stop service. This foundational system provides a platform for future enhancements.
FPUC witness Gadgil testified that the CIS is based on the Systems, Applications, and Products (SAP) platform, a technology platform for enterprise and business applications. The new SAP platform allows better scheduling and real-time updates, resulting in reasonable and reliable service for FPUC customers. With cybersecurity threats increasing, it is imperative to secure customer data. The new SAP solution will incorporate security measures to protect sensitive information and ensure compliance with industry standards and regulations. The new system will provide data management capabilities to ensure the integrity and confidentiality of customer information to build greater trust and confidence among customers.[58] Monitoring that enables the Company to identify and address any potential compliance deviations, ensures that the standards of data protection and cybersecurity are consistent. For this project, FPUC selected TMG for the system assessment and procurement process and selected Ernst & Young for the analysis of system replacement alternatives because both were priced reasonably and had relevant experience with Utility billing system projects and related software implementation. Throughout the implementation, other vendors were also utilized to complete specialized tasks associated with this project. For example, KPMG performed quality assurance checks and Storm Runner conducted performance testing. During the alternative assessment phase of this project evaluation, each potential option was evaluated against a set of risk factors, such as execution, reliability and security, and ongoing operations. After consideration of the system replacement alternatives and associated risk factors, FPUC ultimately chose the CIS system proposed in this issue. The cybersecurity and continuous monitoring components of the system result in an annual O&M expense of $356,083.[59]
CONCLUSION
Staff agrees that the CIS would replace end of life software and provide billing benefits to customers on one streamlined system. Furthermore, staff believes the cyber security components through the SAP platform of the CIS are necessary and reasonable considering the Company’s increasing amount of customer data through its various platforms along with the sophistication of cyber security threats. Therefore, staff recommends the proposed project with capital cost of $6.9 million and O&M expense of $356,083, for the 2025 projected test year should be approved without any adjustments to replace software that is at the end of its life, and will improve the customer billing and cybersecurity, which will protect FPUC’s system and customer information.
Has FPUC 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?
Recommendation:
Yes. Staff believes the Company has made the appropriate adjustments to remove all non-utility activities from Plant in Service and Accumulated Depreciation in the 2025 projected test year. No adjustments to Working Capital are necessary. (Richards)
Staff Analysis:
In accordance with Order No. PSC-2008-0327-FOF-EI, and as shown on MFR Schedule B-2, the Company removed a portion of electric assets shared with other divisions from Plant in Service in the amount of $7,684. FPUC also made an associated adjustment to reduce accumulated depreciation by $1,954.[60] In its response to staff’s data request, the Company stated “the only non-utility plant was related to five vehicles used by employees that work on other business units. Any payroll or costs related to those employees were charged directly to those non-regulated business units.”[61] FPUC witness Napier stated in her direct testimony “[t]he Company has removed plant and its reserve for a portion of the assets used and/or shared with other non-utility operations, consistent with the treatment approved by Order No. PSC-2008-0327-FOF-EI.”[62] As the Company has made the above adjustments as ordered by the Commission, staff does not believe any further adjustments are necessary.
CONCLUSION
Staff believes the Company 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.
What level of Plant in Service should be approved for the 2025 projected test year?
Recommendation:
The appropriate level of Plant in Service for the 2025 projected test year is $203,856,204. (Richards)
Staff Analysis:
In its filing on MFR Schedule B-3 (2025), the Company recorded a 13-month average Plant in Service balance of $227,496,601. Additionally, the Company recorded an allocated 13-month average Plant in Service balance of $1,761,909. This allocated portion consists of $269,511 from the Company’s Florida common plant, and $1,492,397 from its corporate common plant as shown on MFR Schedule B-8 (2025).
As shown on MFR Schedule B-3 (2025), the Company reduced Plant in Service by $307,918 to remove the 13-month average balance of customer advances for construction.
As discussed in Issue 12, the Company made an adjustment to decrease Plant in Service by $7,684 by removing non-utility plant per Order No. PSC-2008-0327-FOF-EI. Additionally, adjustments were made removing capitalized investments in the Storm Protection Plan (SPP) Cost Recovery Clause from Plant in Service. These adjustments are shown below in Table 13-1.
Table 13-1
Adjustments to Remove Capitalized Investments in SPP Cost Recovery Clause
Description |
Amount |
Acct. 355S Poles & Fixtures |
$2,121,968 |
Acct. 364S Poles, Towers & Fixtures |
9,710,781 |
Acct. 365S Overhead Conductors & Devices |
11,324,543 |
Acct. 366S Underground Conduits |
989,797 |
Total SPP Adjustments |
$24,147,089 |
Source: MFR Schedule B-8
(2025).
Additionally, the Company increased Plant in Service by $11,472,643 to record substation additions in 2025 as if they were in service for a full year, as described in FPUC witness Haffecke’s direct testimony. FPUC witness Haffecke stated “[a]llowing the Company to use a full-year approach would reduce the need for additional rate relief shortly after implementation of rates resulting from this rate case.”[63] As discussed in Issue 6, staff removed the Company’s increase of $11,472,643.
As discussed in Issue 10, an adjustment was made to the two-way communication system reducing Plant in Service by $939,615.
Based on the adjustments described above and the calculations provided in the Company’s MFRs, staff recommends the appropriate level of Plant in Service for the 2025 projected test year is $203,856,204 as shown in Table 13-2 on the following page.
Table 13-2
Summary of Plant Adjustments
Description |
Amount |
Plant in Service |
$227,496,601 |
Allocated Florida Electric Division Common Plant in Service |
269,511 |
Allocated Corporate Common Plant in Service |
1,492,397 |
Removal of Customer Advances-Construction |
(307,918) |
Adjustment to remove non-utility plant |
(7,684) |
Adjustment to remove SPP |
(24,147,089) |
Adjustment by Company to include full-year of substation investment |
11,472,643 |
Staff adjustment to remove full-year of substation investment |
(11,472,643) |
Adjustment for two-way communication system |
(939,615) |
Total Adjusted Plant in Service |
$203,856,204 |
Sources: MFR Schedules B-3
(2025), B-8 (2025), and staff calculations.
CONCLUSION
The appropriate level of Plant in Service for the 2025 projected test year is $203,856,204.
What level of Accumulated Depreciation should be approved for the 2025 projected test year?
Recommendation:
Staff recommends the Commission approve an accumulated depreciation level of $80,674,837 for the 2025 projected test year. (Higgins)
Staff Analysis:
Accumulated depreciation essentially tracks asset value reduction over time, thus assisting to provide a real-time understanding of the value associated with the Company’s balance sheet. Accounting for accumulated depreciation helps to ensure that the Company’s financial statements reflect the value of its assets and to provide an accurate view of its financial health.
The Company’s as-filed level of accumulated depreciation
for the 2025 test year is $77,701,596 per books. After accounting for FPUC’s
proposed adjustments, the projected 2025 test year level of accumulated
depreciation is $80,961,538.[64] Incorporating
the changes made to depreciation expense discussed in Issue 43, as well as
amendments made to the reserve balances of Account 391.1 - Computer and
Peripheral and Account 391.2 - Computer Hardware, the amended jurisdictional
adjusted level of accumulated depreciation for the 2025 test year is
$81,100,045.[65] Staff
further adjusted $337,844 from the Company’s request related to the recommended
recovery of the substation assets discussed in Issue 6. Additionally, staff
adjusted accumulated depreciation by $87,365 associated with the Company’s
proposed two-way communication system discussed in Issue 10.[66]
Thus, the jurisdictional adjusted level of accumulated depreciation for the
2025 test year is $80,674,837.
CONCLUSION
Staff recommends the Commission approve an accumulated depreciation level of $80,674,837 for the 2025 projected test year.
What level of Working Capital should be approved for the 2025 projected test year?
Recommendation:
The appropriate level of Working Capital for the 2025 projected test year is $12,767,460. (Richards)
Staff Analysis:
In its filing, the
Company recorded a 13-month average net Working Capital balance of $12,995,015
for its consolidated electric division, and a 13-month average net Working Capital
balance of $5,272,225 for its common allocation. Combined, the Company recorded
a 13-month average Working Capital balance of $18,267,240.
In its review, staff discovered a debit
balance of $6,482,906 in the Company’s allocated accrued pension and post
medical account. In response to a staff data request, the Company explained the
reasoning for a debit balance.[67] The Company
explained:
The amount in the
electric business unit represents the net benefit plan liability of over funded
status. The liability continues to decline over time based on the actuarial
data. The Company expects benefit payments for both the pension plan and the
OPRB plan will continue to decline over time. Although both plans are frozen
for new participants, the assets continue to perform at a level that enables
them to meet future obligations and reduce the Company’s requirement to have to
make contributions to cover any shortfalls.
The Company’s net Working Capital is detailed below in Table 15-1.
Table 15-1
13-Month Average Working Capital Balance
Description |
Amount |
Consolidated Electric Division Assets |
$29,581,730 |
Less: Consolidated Electric Division Liabilities |
(16,586,715) |
Net Working Capital (Consolidated Electric Division) |
$12,995,015 |
|
|
Florida Common Division Allocation Assets |
$25,665 |
Less: Florida Common Division Allocation Liabilities |
(1,236,346) |
Allocated accrued pension and post medical account |
6,482,906 |
Net Working Capital (Florida Common Division Allocation) |
$5,272,225 |
|
|
Total Net Working Capital |
$18,267,240 |
Sources: MFR Schedules B-3 (2025) and B-3A (2025).
As shown on MFR Schedule B-2 (2025), the
Company reduced Working Capital balance by $1,331,206 to remove the deferred
rate case expense. While FPUC witness Napier argued in testimony that the
Company believes it should be allowed to include one-half of the deferred rate
case expense, the full amount was removed in this filing.
FPUC also reduced Working Capital by $3,769,633 to remove storm
recovery costs which are interest-earning. Additionally, the Company further
reduced Working Capital by $398,941 to remove an under-recovery which is
interest-earning in its Storm Protection Plan.
Table 15-2
Working Capital Calculation
Description |
Amount |
Total Net Working Capital |
$18,267,240 |
Removal of deferred rate case expense |
(1,331,206) |
Removal of interest-earning storm recovery costs |
(3,769,633) |
Removal of interest-earning under-recovery in SPP |
(398,941) |
Total Working Capital |
$12,767,460 |
Sources: MFR Schedules B-2 (2025), B-3 (2025) and B-3A (2025).
Based on the calculations above and detailed in Table 15-2, staff recommends a Working Capital balance for the 2025 projected test year of $12,767,460.
CONCLUSION
The appropriate level of Working Capital for the 2025 projected test year is $12,767,460.
What level of Construction Work in Progress should be approved for the 2025 test year?
Recommendation:
The appropriate level of Construction Work in Progress for the 2025 projected test year is $8,221,809. (Richards)
Staff Analysis:
Construction work in
progress (CWIP) is an accounting classification that includes the costs of
ongoing construction projects in rate base. In its filing, MFR Schedule B-3 (2025) the
Company recorded a 13-month average CWIP of $12,869,084.
The Company removed CWIP related to the SPP
Clause, which resulted in a reduction (of CWIP) of $3,827,550. Additionally,
the Company reduced CWIP by $731,263 by removing the amounts which are eligible
for available funds used during construction (AFUDC) under Rule 25-6.0141,
F.A.C. Finally, FPUC removed CWIP associated with the substation additions in
2025 as if they were transferred to plant for a full year as discussed in Issue
6. This adjustment resulted in a reduction to CWIP of $6,331,558.
As discussed in Issues 6 and 13, staff does
not believe it is appropriate to include the full-year calculation for the
substations in Plant in Service, and therefore returned $6,331,558 to CWIP
associated with the substations. Additionally, as discussed in Issue 10, staff
made an adjustment reducing Plant in Service for the two-way communication
system. As such, staff made a corresponding adjustment reducing CWIP by
$88,462.
In total, the Company reduced CWIP by $10,890,371. Staff made a net adjustment increasing CWIP by $6,243,096 and therefore, staff recommends the appropriate level of CWIP for the 2025 projected test year is $8,221,809.
CONCLUSION
The appropriate level of Construction Work in Progress for the 2025 projected test year is $8,221,809.
Issue 17: What level of Property Held for Future Use should be
approved for the 2025 projected test year?
Recommendation:
Staff recommends that the appropriate level of Property Held for Future Use is $0. (G. Kelley)
Staff Analysis:
Property Held for Future Use refers to land, structures, or equipment owned by a utility that is currently not in use but is being held in anticipation of future needs. On MFR Schedule B-15, FPUC stated that it has no Property Held for Future Use for the 2025 projected test year.[68] Therefore, staff recommends that the appropriate level of Property Held for Future Use should be $0.
CONCLUSION
Staff recommends that the appropriate level of Property Held for Future Use is $0.
What is the level of rate base that should be approved for the 2025 projected test year?
Recommendation:
Staff recommends that the appropriate level of rate base for the 2025 projected test year is $144,170,635. (Richards)
Staff Analysis:
This is a fall-out amount based on decisions made in Issues 13, 14,
15, and 16. As summarized in Table 18-1 below, the appropriate level of rate base
for the 2025 projected test year is $144,170,635.
Table 18-1
Staff Recommended Rate Base
Issue |
Description |
Amount |
13 |
Plant in Service |
$203,856,204 |
14 |
Accumulated Depreciation |
(80,674,837) |
15 |
Working Capital |
12,767,460 |
16 |
Construction Work in Progress |
8,221,809 |
Total |
$144,170,635 |
Source:
Staff calculations.
CONCLUSION
Staff recommends that the appropriate level of Rate Base for the 2025 projected test year is $144,170,635.
What amount of accumulated deferred taxes should be approved for inclusion in the capital structure for the 2025 projected test year?
Recommendation:
The amount of accumulated deferred income taxes to be included in the 2025 projected test year capital structure is $13,497,717. (Ferrer)
Staff Analysis:
FPUC requested a total accumulated deferred income tax (ADITs)
balance of $13,206,708, be included in the 2025 projected test year capital
structure, which is presented on MFR Schedule D-1a (Supplement).[69]
FPUC witness Crowley explains that FPUC’s regulatory capital structure reflects
similar levels of stability within the debt and equity components. Across other
capital items, for example, accumulated deferred income taxes and regulatory
tax liability attributable to electric operations, FPUC has experienced some
variability over years 2023 to 2025. In the case of deferred income tax, this
balance declines from approximately $22 million in 2023 to approximately $13
million in 2025.
In Audit Finding 4, staff determined that the appropriate credit
ADIT balance associated with the requested rate case expense was not properly
included in the 2025 projected test year capital structure.[70] On
MFR Schedule C-10, FPUC projected a total rate case expense of $1,530,907. This
cost was spread over a four-year amortization period which yields a test year
amortization expense of $382,727.[71]
The unamortized rate case expense for the remaining three years is $1,148,180
which creates an ADIT credit of $291,009. FPUC’s effective tax rate of 25.345
percent is multiplied by the unamortized balance of rate case expense to
calculate the ADIT credit. Staff made a specific adjustment to increase the
ADIT balance by $291,009 to reflect the adjustment. After staff’s adjustment,
the ADIT balance for the 2025 test year capital structure is $13,497,717.
CONCLUSION
Staff recommends the Commission approve an
ADIT balance of $13,497,717 to be included in the 2025 projected test year
capital structure.
What amount and cost rate for customer deposits should be approved for inclusion in the capital structure for the 2025 projected test year?
Recommendation:
The amount and cost rate for customer deposits that should be included in the 2025 projected test year capital structure is $4,001,097 at a cost rate of 2.20 percent. (Ferrer)
Staff Analysis:
In
MFR Schedule D-1a (Supplement), FPUC presented its 2025 projected test year
capital structure.[72]
The capital structure is based on a 13-month average reflecting a customer
deposit balance in the amount of $4,001,097. Staff confirmed that the
regulatory capital structure contained the appropriate amount and confirmed
that customer deposits should be at a cost rate of 2.20 percent.
Staff
reviewed MFR Schedule D-6, and confirmed the calculation of interest associated
with customer deposits complies with the requirements set forth in Rule
25-6.097(5)(a), F.A.C.[73]
Accordingly, staff recommends the amount and cost rate for customer deposits
that should be approved for the 2025 projected test year capital structure is
$4,001,097 at a cost rate of 2.20 percent.
CONCLUSION
The amount and cost rate for customer deposits that should be included in the 2025 projected test year capital structure is $4,001,097 at a cost rate of 2.20 percent.
What is the appropriate amount and cost rate for short-term debt to include in the capital structure for the 2025 projected test year?
Recommendation:
The appropriate amount for short-term debt to include in the capital structure for the 2025 projected test year is $6,906,199 at a cost rate of 5.81 percent. (Souchik)
Staff Analysis:
As presented in MFR Schedule D-1a, and MFR Schedule D-3, FPUC requested a short-term debt cost rate of 5.81 percent with a jurisdictional amount of $7,255,028. FPUC obtains its short-term debt from its parent company Chesapeake Utilities Corporation (CUC). CUC has a syndicated credit facility revolver for short-term borrowings with six participating banks. CUC’s Revolver is currently comprised of a multi-tranche short-term borrowing facility with a total capacity of $450 million. According to FPUC witness Russell, CUC’s Revolver provides cost-effective competitive financing and benefits to FPUC by providing short-term capital availability for Company projects during construction, before obtaining permanent long-term financing once the projects are in service. As of June 30, 2024, the pricing for CUC’s short-term borrowing includes an unused commitment fee of 0.20 percent and an interest rate of 0.90 percent over the Secured Overnight Financing Rate (SOFR), plus a 0.10 percent credit adjustment. The current SOFR rate as of December 11, 2024, was approximately 4.67 percent. Witness Russell explained CUC’s pricing is very competitive in the market and is comparable to pricing available to many publicly traded electric utilities that also have investment grade debt.
The amount of short-term debt in the projected test year capital structure is based on CUC’s investor supplied capital structure, which includes a ratio of short-term debt of 5.65 percent. After reconciling the capital structure to the rate base amount recommended in Issue 18, the amount of short-term debt in the jurisdictional capital structure is $6,906,199. Based on the aforementioned, staff believes the amount and cost rate are reasonable.
CONCLUSION
The appropriate amount for short-term debt to include in the capital structure for the 2025 projected test year is $6,906,199 at a cost rate of 5.81 percent.
What amount and cost rate for long-term debt should be approved for inclusion in the capital structure for the 2025 projected test year?
Recommendation:
The amount of long-term debt to include in the capital structure for the 2025 projected test year is $54,153,162 at a cost rate of 4.51 percent. (Souchik)
Staff Analysis:
In its initial filing, FPUC presented its 2025 projected test year capital structure based on a 13-month average consisting of long-term debt in the jurisdictional adjusted amount of $56,888,413 at a cost rate of 4.51 percent. These values are shown on MFR Schedule D-1a (Supplement). FPUC does not issue its own debt and receives all its capital funding from its parent company CUC. FPUC uses CUC’s capital structure and cost rates as CUC provides all investor sources of capital to FPUC, which benefits FPUC through a lower cost of capital.
FPUC presented two calculations for its cost of long-term debt. The calculation using the traditional method to calculate the embedded cost of debt is presented in MFR Schedule D-4a. The traditional calculation was based on CUC’s entire amount of long-term debt outstanding, reflecting a cost rate of 5.21 percent. The long-term debt cost rate requested by the Company is presented in MFR Schedule D-4a (Supplement). FPUC’s cost rate of 4.51 percent includes adjustments to remove a portion of the debt associated with CUC’s acquisition of Florida City Gas (FCG). As explained by witness Russell, only 21 percent of the six issuances of long-term debt issued in November 2023 is assigned to FPUC for rate making purposes. The coupon rates on the six Senior Notes listed in MFR Schedule D-4a range from 6.39 percent to 6.73 percent which are significantly higher than coupon rates on previous long-term debt issuances. The six Senior Notes total $550 million and were issued by CUC in November 2023, and were predominately used to finance the acquisition of FCG. Three of the seven notes total $300 million and have maturities of less than seven years. FPUC anticipates that both short-term and long-term interest rates will decline from current levels, and in the future, it will be in a better position to replace the higher cost debt with lower cost longer term debt. FPUC requested that the Commission use MFR Schedule D-4a (Supplement) as it includes only 21 percent of the six Senior Notes relating to the overall funding operations for FPUC, resulting in a lower cost of long-term debt for its customers. This calculation effectively removes approximately $500,000 from FPUC’s revenue requirement and lowers the Weighted Average Cost of Capital (WACC) by 26 basis points. FPUC requested that if the methodology used to calculate the long-term debt cost rate of 4.51 percent as presented in MFR Schedule D-4a (Supplement) is not approved, that the Commission approve the capital structure provided in in MFR D-1a which includes a cost rate of 5.21 percent.
The long-term debt of CUC has an investment credit rating of NAIC-2B issued from the National Association of Insurance Commissioners (NAIC). This assigned rating indicates high quality obligations with a low credit risk and would be equivalent to Standard & Poor’s, and Moody’s credit ratings of BBB and Baa2. According to FPUC witness Russell, U.S. Treasury rates for 3-, 5-, 7-, and 10-year durations are currently at elevated levels, but are just slightly below the rate presented on MFR Schedule D-4a (Supplement). If CUC were to issue any new long-term debt, the rate would include a spread that supports the CUC’s NAIC-2B rating. In response to staff’s data request, FPUC explained the issuances of Senior Notes 28 and 29 in the 2025 test year will be used to fund capital construction growth with the intent of maintaining its capital structure balance.[74] FPUC estimated the coupon rate of 5.75 percent for Senior Notes 28 and 29 by estimating the spread between the last-twelve month average for the 10-year and 20-year U.S. Treasury rates and the BBB Corporate Bond Index. Mathematically, the Company calculated the spread between the average of the 10-year and 20-year U.S. Treasury Bond yields and the average of the 10-year and 20-year BBB Corporate Bond yields. The methodology of using the U.S. Treasury Bond yields and adding the Corporate Bond yield spread is reasonable and consistent with past Commission practice.[75]
After reviewing the Company’s assumptions and calculations for the requested cost rate for long-term debt, staff believes the cost rate of 4.51 percent, is very reasonable. In comparison, the 2025 forecasted yields on 10-year and 30-year U.S. Treasury Bonds are 4.40 percent and 4.70 percent, respectively.[76] Based on the above, staff believes the requested cost rate of 4.51 percent is reasonable and benefits the customers of FPUC in comparison to the unadjusted cost rate of 5.21 percent. After reconciling the capital structure to the rate base amount recommended in Issue 18, the amount of long-term debt is $54,153,162.
CONCLUSION
The amount of long-term debt to include in the capital structure for the 2025 projected test year is $54,153,162 at a cost rate of 4.51 percent.
What equity ratio should be approved for use in the capital structure for ratemaking purposes for the 2025 projected test year?
Recommendation:
An equity ratio of 50.04 percent, based on investor sources, should be approved for use in the capital structure for ratemaking purposes for the 2025 projected test year. (McGowan)
Staff Analysis:
In its filing, FPUC requested a projected test year capital structure consisting of an equity ratio of 50.04 percent based on investor-supplied capital for ratemaking purposes. FPUC witness Russell explained the Company does not issue debt or equity directly and as a result, any funding needs for FPUC are provided by its parent company, CUC. With the original source of funding being derived from the equity issuances or debt financing at the parent level, FPUC employs CUC’s capital structure to determine its rate of return.
Witness Russell explained the Company’s capital structure at the end of the 2025 projected test year consists of common equity of 50.04 percent, long-term debt of 44.31 percent, and short-term debt of 5.65 percent, based on investor sources. Witness Russell affirmed an equity ratio of 55 percent is the midpoint of the target equity ratio range of 50 to 60 percent approved by CUC’s board of directors and the Corporation strives to achieve that target range. Furthermore, Exhibit No. NTR-1, Schedule 1 shows CUC’s historical equity ratios for calendar years 2014 through 2023. As explained by witness Russell and as the schedule reflects, CUC has consistently achieved its targeted equity range with limited deviations. Upon review, the average equity ratio from 2014 through 2023 is 50.22 percent, which is consistent with the forecasted equity ratio of 50.04 percent requested by FPUC for the 2025 projected test year.
The Commission-authorized equity ratios for Florida’s investor-owned electric (55.53 percent) and natural gas (53.57 percent) utilities average 54.30 percent. FPUC’s requested equity ratio for the projected test year is within the range of equity ratios of the aforementioned utilities, which are summarized below in Table 23-1.
Table 23-1
Florida Investor-Owned Electric and Natural Gas Equity Ratios
Company |
Order Number |
Issued |
Equity Ratio |
Duke Energy Florida, LLC |
PSC-2024-0472-AS-EI |
11/12/2024 |
53.00% |
Florida City Gas |
PSC-2023-0177-FOF-GU |
06/09/2023 |
59.60% |
Florida Power & Light Company |
PSC-2021-0446-S-EI |
12/02/2021 |
59.60% |
FPUC (Natural Gas Division) |
PSC-2023-0103-FOF-GU |
03/15/2023 |
55.10% |
Peoples Gas System, Inc. |
PSC-2023-0388-FOF-GU |
12/27/2023 |
54.70% |
Sebring Gas System, Inc. |
PSC-2020-0047-PAA-GU |
02/03/2020 |
38.43% |
St. Joe Natural Gas Company, Inc. |
PSC-2025-0035-PAA-GU |
01/30/2025 |
60.00% |
Tampa Electric Company |
PSC-2025-0038-FOF-EI |
02/03/2025 |
54.00% |
Average |
|
|
54.30% |
Source: Staff Analysis.
Witness Russell confirmed that just prior to the acquisition of Florida City Gas (FCG), the equity ratio for CUC was approximately 53 percent as of September 30, 2023. As discussed in Issue 22, CUC issued debt to partially fund its acquisition of FCG, which lowered its equity ratio below 50 percent. Witness Russell affirmed since the acquisition, CUC has moved this ratio from approximately 47 percent to above 48 percent and is on path to restore its equity ratio within the target range (in the test year) and proceed towards the midpoint.
Staff notes FPUC used CUC’s capital structure in its 2014 electric rate case which included an equity ratio of approximately 58 percent.[77] Additionally, FPUC employed CUC’s capital structure for its 2022 natural gas rate case in which the Commission approved an equity ratio of 55.10 percent.[78] Accordingly, the use of CUC’s capital structure to establish FPUC’s regulatory capital structure is consistent with prior Commission decisions for both the Company’s electric and gas utilities.
Based on its analysis of this issue, staff believes FPUC’s requested equity ratio of 50.04 percent, based on investor sources, for the 2025 projected test year is reasonable. After reconciling the capital structure to the rate base amount recommended in Issue 18, the amount of common equity that should be included in the 2025 projected test year capital structure is $61,164,185.
CONCLUSION
An equity ratio of 50.04 percent, based on investor sources, should be approved for use in the capital structure for ratemaking purposes for the 2025 projected test year.
What return on common equity should be approved for use in establishing FPUC’s revenue requirement for the 2025 projected test year?
Recommendation:
A return on common equity of 10.15 percent, with a range of 9.15 percent to 11.15 percent, should be approved for use in establishing FPUC’s revenue requirement for the 2025 projected test year. (D. Buys)
Staff Analysis:
The return on common equity (ROE) is the cost of common equity included in a company’s regulatory capital structure used to establish a revenue requirement. A reasonable ROE for a regulated company requires determining the market-based cost of capital. The market-based cost of capital for a regulated firm represents the return investors could expect from other investments, while assuming no more and no less risk. In other words, the authorized ROE should be equivalent to investors’ required return to invest in FPUC. FPUC’s current authorized ROE is 10.25 percent and was last set in 2014 through a settlement with the Office of Public Counsel.[79] In the instant case, FPUC requested an ROE of 11.30 percent based on the testimony of witness Crowley. Witness Crowley’s ROE models are largely based on historical financial and market data from 2021 through 2023, and in staff’s opinion, do not reflect expected market conditions or investor required equity returns. To test the reasonableness of witness Crowley’s ROE model analysis, staff performed its own ROE analysis using more recent market data and forecasted interest rates and derived an ROE of 10.15 percent.
Legal Standard
The U.S. Supreme Court Hope and Bluefield decisions established standards for setting a fair rate of return for equity investment in utilities providing service to the public. Under the Hope and Bluefield decisions, the U.S. Supreme Court established that a fair rate of return should be comparable to returns on investments in other enterprises having similar risks, sufficient to assure confidence in the financial integrity of the company, support reasonable credit quality, and allow a company to raise capital at reasonable costs and terms.[80] The Bluefield decision stated in pertinent part that:
A public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are realized or anticipated in highly profitable enterprises or speculative ventures. The return should be reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties. A rate of return may be reasonable at one time and become too high or too low by changes affecting opportunities for investment, the money market and business conditions generally.
Based on the Bluefield decision, staff believes a reasonable ROE is also based on the expectation that the company’s costs reflect efficient and economical management, and the ROE will support its credit standing and access to capital, but will not be in excess of this level. Also, the Bluefield decision recognizes that a reasonable ROE will change based on economic market conditions and investment opportunities.
Proxy Groups
Because FPUC is not publicly traded and does not issue publicly traded equity securities, a group of publicly traded companies that have comparable risk characteristics to FPUC must be used as a proxy group to which cost of equity models are applied to determine the required ROE. Witness Crowley used three separate proxy groups in his analysis: 15 mid-size electric companies, 6 natural gas companies, and 13 small non-utility companies. The 15 electric companies have market capitalization values from $1.0 billion to over $20 billion.[81] In comparison, FPUC’s parent company, Chesapeake Utilities Corporation’s (CUC) market capitalization is $2.9 billion. CUC is primarily a gas distribution company with a net plant of $2.456 billion. Only $143.513 million or 6.0 percent of CUC’s $2.456 billion net plant is for electric distribution. FPUC contributed $99.5 million to CUC total revenues of $670.604 million as of December 31, 2023. The proportion of revenue from FPUC to the total for CUC is 14.83 percent ($99.5M ÷ $670.6M = 14.83%). Based on FPUC’s percentage of revenue contribution to CUC, FPUC’s estimated market capitalization would be $430 million at CUC’s stock price of $126.44 per share (14.83% × $2.9 billion = $430 million). FPUC’s market capitalization would be less than half of the smallest electric company in witness Crowley’s proxy group, which is Unitil Corporation with a market capitalization of $970 million.
Mid-Size Electric Company Proxy Group[82]
Witness Crowley opined that it is virtually impossible to select a sizeable set of electric companies that are exclusively retail electric companies, and therefore, some of the 15 electric companies are also engaged in non-electric retail business lines including natural gas, albeit not a significant portion. Staff determined that all of the companies in the electric and gas proxy groups obtain over 65 percent of their revenues from regulated operations with the exception of Otter Tail Corporation (34 percent) and Southwest Gas Holdings, Inc. (47 percent). These latter two companies are therefore not comparable to FPUC all of whose revenues are regulated. For the electric proxy group, one of witness Crowley’s selection criteria was consistent quarterly dividends and positive long-term earnings growth forecasts from at least two sources. Hawaiian Electric is no longer paying dividends due to its financial position resulting from the fires in Lahaina, Hawaii. Unitil Corporation has limited forecasted earnings and dividends making forward-looking market data unavailable. Based on the discrepancies between witness Crowley’s proxy group selection criteria and the characteristics or lack of market data for Hawaiian Electric, Otter Tail Corporation, and Unitil Corporation, staff believes these companies should not have been included in witness Crowley’s electric proxy group. In addition, Alliant Energy, CenterPoint Energy, Inc. and Evergy, Inc. are considered large-capitalization companies and are significantly larger than CUC, and especially FPUC. These three utilities represent 47 percent of the weighted average of witness Crowley’s ROE model results. While staff does not disagree with weighting the results of the cost of capital models witness Crowley included three large cap companies that biased the results of his analysis toward the three companies that are significantly larger than FPUC.
Natural Gas Distribution Company Proxy Group[83]
Witness Crowley also used a proxy group of six natural gas companies that have market capitalizations ranging from $1.66 billion to $15 billion. Witness Crowley did not perform a quantitative analysis of FPUC’s risk characteristics to that of his gas proxy group but explained that qualitatively, FPUC is similar to a natural gas distribution company. In response to staff’s data requests, FPUC explained because natural gas companies deliver services through a distribution pipeline to individual customer delivery points through a meter, the risk of the gas proxy group closely compares to that of FPUC’s electric operations.[84] FPUC also stated that both FPUC and the companies in the gas proxy group provide essential services required for a functioning economy; own and operate substantial, long-lived capital infrastructure; and operate in a regulated utility environment.[85] Thus, witness Crowley believes gas utilities face many of the same financial, regulatory, and cybersecurity risks as electric utility operations, like those of FPUC.[86] FPUC further explained that all else equal, the gas proxy companies would be less risky because they do not have the same exposure to weather risk and could bias the cost of equity estimate downward.[87] Staff agrees that regulated natural gas distribution companies can be used as a proxy for FPUC. However, Southwest Gas Holdings, Inc. obtains less than 50 percent of its total revenue from regulated operations and is not comparable to FPUC.
Non-Regulated Company Proxy Group[88]
Witness Crowley selected 13 non-regulated companies with market capitalizations less that $2 billion as his Non-Regulated Proxy Group. Witness Crowley explained that some of the non-regulated companies are financed exclusively with equity. Such a company would not have a financial risk comparable to that of FPUC which is requesting an equity ratio of 50.04 percent and would not be an appropriate proxy company. Staff does not believe that an additional proxy group beyond the electric and natural gas proxy groups is necessary to estimate the cost of equity for FPUC. Further, based on witness Crowley’s quantitative evaluation of his ROE results in Table 2 on page 7 of his testimony, he excluded the results from the Non-Utility Company Proxy Group from the average results used to develop his recommended range of ROEs. In the interest of brevity, staff will not critique witness Crowley’s cost of equity analysis for his non-utility proxy group and recommends the Commission exclude it from consideration in this case.
Cost of Equity Models
Witness Crowley used three cost of equity models applied to his three proxy groups. Those are the constant growth Discounted Cash Flow (DCF) model, the Capital Asset Pricing Model (CAPM) and a Risk Premium (RP) analysis. In addition, witness Crowley included an analysis of the Realized Market Returns for the companies in his electric and gas proxy groups by calculating the historical earned returns based on stock price appreciation and dividends paid for the historical period 2014 through 2023. The assumptions and methodologies used by witness Crowley in his cost of equity models are unorthodox and diverge from traditional methodologies used by other ROE witnesses that have testified before the Commission in prior dockets. Staff believes witness Crowley’s application of the cost of equity models are not supported by reasonable assumptions for estimating the forward-looking ROE for a regulated utility and the market data used in his models is either stale or not verifiable. Consequently, the Commission should not use witness Crowley’s testimony to approve an ROE for FPUC. A summary of witness Crowley’s ROE model results as presented in his testimony is provided in Table 24-1.
Table 24-1
Summary of FPUC ROE Model Results
|
Low Results |
High Results |
Average |
Staff Corrected |
Discounted Cash Flow (DCF) |
|
|
|
|
Mid-Sized Electric Utilities |
9.37% |
9.77% |
9.57% |
|
Gas Distribution Utilities |
9.55% |
12.08% |
10.81% |
|
Capital Asset Pricing Model
(CAPM) |
|
|
|
|
Mid-Sized Electric Utilities |
10.39% |
11.61% |
11.18% |
|
Gas Distribution Utilities |
10.14% |
11.31% |
10.72% |
|
Low Risk Non-Utility Companies |
10.10% |
11.63% |
11.29% |
|
Risk Premium Model (RP) |
|
|
|
|
Mid-Sized Electric Utilities |
|
|
10.52% |
|
Gas Distribution Utilities |
|
|
9.89% |
|
Low Risk Non-Utility Companies |
|
|
11.39% |
|
Realized Market Returns,
Rolling 10 Yrs. |
|
|
|
|
For 2013-2023 |
|
|
|
|
Mid-Sized Electric Utilities |
|
|
11.52% |
9.65% |
Gas Distribution Utilities |
|
|
13.21% |
8.95% |
Low Risk Non-Utility Companies |
|
|
9.89% |
|
FPUC Recommended Return on
Equity[89] |
10.43% |
12.21% |
11.30% |
|
Staff Corrected Range of Results |
9.68% |
10.90% |
|
10.30% |
Sources: Witness Crowley’s
Direct Testimony, Table 2, page 7, and staff analysis.
While not described in his testimony, witness Crowley calculated the range of his ROE model results of 10.43 percent to 12.21 percent by deriving the statistical central tendency (not the average) of the low and high DCF model and CAPM results, and Realized Market Returns using a somewhat complex calculation involving the standard deviation of the values in the “Average” column in Table 24-1 (excluding the Non-Utility Companies).[90] Witness Crowley apparently did not include the results from his RP analysis in his average final results. His estimated ROEs include an upward adjustment of 14 basis points to recognize flotation costs.
In general terms, witness Crowley “averaged” his low results from the DCF model, the CAPM, and the Realized Market Returns for both the electric and gas proxy groups to derive the low end of his range of results of 10.43 percent as shown in Table 24-1. He repeated his process using the high results of his models to derive the high end of his range of results of 12.21 percent. When calculating his low and high estimates witness Crowley included the historical Realized Market Returns of 11.52 percent and 13.21 percent for both his electric and gas proxy groups, respectively. The addition of the Realized Market Returns in his low- and high-end averages simply increased witness Crowley’s overall results. Excluding the Realized Market Returns from his calculations yields a range of 10.21 percent to 11.20 percent with a central tendency of 10.72 percent.
Witness Crowley apparently based his recommended ROE of 11.30 percent on the mid-point of his range of results of 10.43 percent to 12.21 percent. The values in the “Average” column (excluding the Non-Utility Companies) were used to calculate the standard deviation of the low and high results from his ROE models to develop the central tendency of his results. That methodology increased the range of his overall results. The values in the “Average” column do not equal 11.30 percent. The average equals 10.93 percent.
Most importantly, witness Crowley apparently made an error in deriving his range of “Average” results as denoted in Table 24-1 and Table 2, page 7 of his testimony. In Table 2, for his estimate of the 2023 10-year Realized Market Returns, he incorrectly listed 11.52 percent for the electric proxy group and 13.21 percent for the gas proxy group which are from 2022, not 2023. As shown in Exhibits NAC-29 and NAC-31, and in his work papers, the 2023 10-year returns for the electric and gas proxy groups as presented are 9.65 percent and 8.95 percent, respectively. After making those changes to correct witness Crowley’s Table 2 to match the results described therein, and adjusting the same in the calculations in his worksheets, his range of ROE results becomes 9.68 percent to 10.90 percent, averaging 10.30 percent, including flotation costs.
FPUC DCF Model
Witness Crowley used the single-stage constant growth DCF methodology to estimate the investor required return of his electric and gas proxy groups. Expressed mathematically as: ROE = (dividend ÷ stock price) + growth rate. Witness Crowley adjusted the dividend yield by increasing the dividend by a factor of ½ the growth rate. The basic equation he used was ROE = [(dividend × 1 + 0.5 growth rate) ÷ stock price] + growth rate. For the stock price, witness Crowley used the closing price on the first trading day of May for each of the companies in his electric and gas proxy groups. The stock prices from May of 2023 are now over 20 months in the past and don’t represent the most recent stock market price data. Witness Crowley’s testimony was filed on August 22, 2024, and staff believes he could have included market data through at least May of 2024. Witness Crowley’s growth rates for the electric and gas companies in 2023 were the average of estimated growth rates obtained from Zack’s and Yahoo Finance. The low results from witness Crowley’s DCF model application reflect data from 2023 which is more recent than his high results which reflect data from 2021 and 2022. His low results were 9.37 percent for the electric proxy group and 9.55 percent for the gas proxy group.
Witness Crowley explained that expected growth rates for 2021 and 2022 were not available from Zacks and Yahoo Finance at the time of his analysis and 10-year average historical growth rates for each company were used to calculate earnings per share for 2021 and 2022. The 2021 and 2022 growth rates reflected a weighting of 90 percent of earnings per share plus a 10 percent weighting of the dividends per share. The 10-year average of the earnings per share and dividends per share were calculated using the average of the geometric mean and the arithmetic mean.
In response to a staff data request, witness Crowley explained that “[e]lectric and gas utilities generally exhibit stable earnings and dividend growth, and while not perfect predictors of future earnings because of unforeseen economic events, historical growth rates in earnings and dividends serve as a benchmark and are a reasonable estimate of near-term earnings growth.”[91] Witness Crowley cited Professor Damodaran’s text and paraphrased that one method to estimate the growth of any firm is to look at growth in a firm’s past earnings which can be useful input when valuing stable firms such as the companies in the electric and gas proxy groups. However, Professor Damodaran also stated in his text that “[t]he historical growth rate can often not be estimated, and even if it can, it cannot be relied upon as an estimate of expected future growth.” He also stated that “[e]stimating growth rates can also be complicated by the presence of negative earnings in the past or in the current period.” In fact, some of the companies in the electric and gas proxy groups had negative earnings for some of the historical years as presented in witness Crowley’s work papers. Professor Damodaran also wrote that using approaches – such as the method used by witness Crowley – to estimate historical growth rates do not provide any information on whether the growth rates are useful in predicting future growth. Professor Damodaran wrote that “[i]t is not incorrect and, in fact it may be appropriate, to conclude that the historical growth rate is ‘not meaningful’ when earnings are negative and to ignore it in predicting future growth.”[92] Therefore, staff concluded that it is unreasonable to use historical growth rates to predict expected growth rates in the DCF model for estimating the required ROE for regulated utilities. Witness Crowley also admitted that for some companies, the historical growth rate of earnings or dividends was clearly not reflective of forward-looking growth, as the historical data was anomalous. In those instances, he used the average growth rates from the remaining companies. In addition, the historical returns from 2021 and 2022 using the DCF model results do not reflect current market data and should not be considered.
In his 2023 DCF model analysis, witness Crowley used the same growth rate of 6.04 percent for two of his electric proxy companies.[93] As explained by witness Crowley, the growth rate estimates for Northwestern Energy Group were not believable, and earnings growth estimates for Unitil Corporation were not available. Again, witness Crowley used the average growth rates from the remaining companies in his proxy group and not the actual growth rates of the individual companies. If the information was not available or believable, the companies should have been excluded from the proxy group. Witness Crowley was unable to provide copies of his source information as support for the stock prices, dividends, and growth rates used in his DCF analysis, and consequently, staff was unable to verify the information. Based on these flaws in his calculations and the unsupported data, staff believes witness Crowley’s DCF analysis is unreliable and doesn’t reflect current investor expectations or the prospective required rate of return for the proxy groups or FPUC.
Staff DCF Model Results
Staff applied a DCF model to the same electric and gas proxy groups as witness Crowley excluding Otter Tail Corporation, Hawaiian Electric, and Unitil Corporation from the electric proxy group, and Southwest Gas Holdings, Inc. from the gas proxy group. Hawaiian Electric and Unitil Corporation companies were excluded because they do not have forecasted dividends and earnings from Value Line. Otter Tail Corporation and Southwest Gas Holdings, Inc. were excluded because the companies obtain less than 50 percent of revenues from regulated operations. Staff used the same single-stage constant growth DCF model as did witness Crowley: ROE = [(dividend × 1 + 0.5 growth rate) ÷ stock price] + growth rate. First staff calculated the dividend yield (dividend ÷ stock price) for each company in the proxy group. Staff relied on the company reports as published by Value Line for the dividend and Yahoo Finance for the average stock price in December 2024. Staff adjusted the dividend by multiplying the dividend paid in 2024 by one-half the forecasted growth rate. The average adjusted dividend yields for the electric and gas proxy groups were 3.75 percent and 3.31 percent, respectively. Staff relied on the forecasted annual rates of change of earnings per share as estimated by Value Line for the growth rate. The average growth rates for the electric and gas proxy groups were 5.75 percent and 5.70 percent, respectively. Staff weighted the results by the market capitalization as reported by Value Lines of each company in the proxy groups. The weighted average of staff’s single-stage constant growth DCF results were 9.62 percent and 9.00 percent, for the electric and gas proxy groups, respectively.
CAPM
The CAPM is a market-based model that estimates the cost of equity for a stock as a function of a risk-free return plus a market risk premium (MRP). The market risk premium is defined as the incremental return of the stock market as a whole less the risk-free rate multiplied by the beta for the individual security. The beta is expressed as the volatility of an individual security compared against the stock market as a whole. A beta value of 1.0 indicates the individual security has the same volatility as the stock market. A beta value of less than 1.0 is considered less risky than the stock market as a whole and a beta value greater than 1.0 is considered more risky. The basic CAPM equation requires only three inputs to estimate the cost of equity: (1) the risk-free rate; (2) the beta coefficient; and (3) the MRP expressed in this equation: ROE = risk-free rate + Beta (market return - risk-free rate). Witness Crowley used the same expected stock market returns and risk-free rates in his CAPM for both the electric and gas proxy groups. The only difference between the results from the electric proxy group and the gas proxy group was based on the beta value applied to the MRP.
Risk-Free Rate
Witness Crowley testified that he used the risk-free rate equal to the average monthly yield on 30-year U.S. Treasury securities for two timeframes including 2013-2023 and 2021-2023, observed in monthly frequency. However, his work papers show that he calculated a historical risk-free rate of 3.39 percent from the period January 1, 2018 through June 1, 2024, excluding the period during Covid-19 (March 1, 2020 through June 1, 2021). The other risk-free rate of 4.31 percent was calculated using the time period April 1, 2023 through June 1, 2024. The CAPM is a forward-looking model for which the inputs should reflect forecasted and expected data. Blue Chip Financial Forecasts provides forecasted 30-year U.S. Treasury rates for the future five quarters from the issue date. The most recent Blue Chip forecast for the 30-year U.S. Treasury Yield in 2025 is 4.66 percent.[94] Hence, the more appropriate risk-free rate for witness Crowley’s CAPM analysis is his estimate of 4.31 percent because it is closer to the forecasted rate of 4.66 percent.
Expected Market Return
Witness Crowley’s expected stock market return was based on historical realized returns for U.S. markets, measured in real terms. Once estimated, the observed real rate of return for equity markets was adjusted upwards for expected inflation of 2.46 percent. The inflation estimate of 2.46 percent was calculated using the average estimated Treasury Inflation Protected Securities (TIPS) that compares 5-year to 10-year inflation expectations, and the average of three surveys.[95] Real rates of return were calculated as the arithmetic average of annual U.S. stock market returns over two timeframes, 1970 through 2023, and 1990 through 2023. These results are then adjusted to account for current expected inflation.
Witness Crowley’s low end expected market return of 10.63 percent is derived using historical returns from the total U.S. Markets during the period 1970 through 2023. His high end expected market return of 11.62 percent is derived from total U.S. Markets during the period 1990 through 2023. He averaged the two estimates to arrive at an expected market return of 11.13 percent. Staff has concerns regarding the use of these ex-post methods. A realized return is the holding-period return earned in the past. Whereas the expected return is the holding-period return for a stock in the future based on expected dividend yield and the expected price appreciation return. Realized returns can be substantially different from expected returns due to changes in economic conditions and business cycle interruptions and don’t necessarily reflect expected returns. For estimating the required ROE for rate setting purposes, staff believes realized or historical returns are not a reliable indicator of expected returns. As such, witness Crowley’s ex post method to estimate the expected market return is questionable and should not be relied upon.
Beta Value
Witness Crowley obtained his 2023 betas for the electric and gas proxy groups from Morningstar and Yahoo Finance. Again, staff was unable to confirm the beta values because the source information was not provided. Witness Crowley adjusted the raw betas to account for central tendency by applying the Blume method to the beta values. This adjustment resulted in moving the raw betas for both the gas companies and electric companies closer to 1.0. The effect of this adjustment was to produce CAPM results close to or at the expected market return which indicates that his proxy groups are not much more or less risky than the market as a whole. The weighted average adjusted beta values witness Crowley used to calculate his CAPM results for the electric and gas proxy groups were 1.01 and 0.944, respectively. In comparison, the weighted average of the betas published in Value Line for the electric and gas proxy groups are slightly lower at 0.983 and 0.907, respectively. The lower beta values would produce a lower ROE result indicating that applying the Blume adjustment increases the results of the CAPM.
FPUC CAPM Results
For the electric proxy group, witness Crowley’s low CAPM estimate was 10.39 percent, and his high CAPM estimate was 11.61 percent. The weighted average result was 11.18 percent. The simple average of the low and high CAPM results was 11.00 percent. For the gas proxy group, the low end CAPM estimate was 10.14 percent and the high end CAPM estimate was 11.31 percent. The weighted average results were 10.72 percent. The simple average was also 10.72 percent. Witness Crowley’s CAPM estimates should not be relied upon because they include MRP estimates based on ex post methodologies, do not reflect forecasted risk-free interest rates, and use adjusted betas that skew his results upwards.
Staff CAPM Results
As a comparison, staff applied a CAPM to the same electric and gas proxy group as witness Crowley excluding Otter Tail Corporation, Hawaiian Electric, and Unitil Corporation from the electric proxy group, and Southwest Gas Holdings, Inc. from the gas proxy group. Staff used the same CAPM methodology approved by the Commission in its annual leverage formula.[96] Staff relied on an estimated market return for companies followed by Value Line, the average projected yield on the U.S. Treasury’s 30-year bonds for the five quarters from the second quarter of 2025 through the second quarter of 2026, as of January 31, 2025, published by Blue Chip Financial Forecasts (4.66 percent), and the weighted average beta for the electric and gas proxy groups of 0.988 and 0.8973, respectively. An expected return on the overall stock market of 10.81 percent was calculated using a quarterly DCF model applied to a large number of dividend-paying publicly traded companies with stock prices as of January 14, 2025. The average beta of the proxy groups was weighted using the market capitalization of each company as reported by Value Line. Staff’s estimated expected MRP is 6.15 percent (10.81% - 4.66% = 6.15%). Staff’s CAPM results were 10.74 percent and 10.18 percent for the electric and gas proxy groups, respectively.
FPUC Risk Premium Analysis
A risk premium method estimates the required return on equity in excess of the return one could receive for an investment in risk-free assets. In this case, witness Crowley derived an equity MRP based on the historical return on the total U.S. stock market from 2014 to 2023, less the return on long-term U.S. Treasury Bonds over the same time period. He then multiplied the average betas of the electric and gas proxy groups to calculate a beta adjusted MRP. He then added a risk-free rate to the beta adjusted MRP to calculate his RP estimated ROE. By applying the beta values of the proxy groups to the MRP and adding the risk-free rate to the product, the end result is another CAPM application. To drive his RP result, witness Crowley first estimated the expected inflation at 3.98 percent. The 3.98 percent inflation estimate added 1.53 percent to witness Crowley’s inflation estimate of 2.46 percent from his CAPM expected market return calculation. The additional 1.53 percent is the Laoubach-Williams R-star estimate that reflects short-term inflation.[97] He then added the differential of real returns on intermediate and long-term U.S. Treasury Bonds to estimate a risk-free rate of 5.43 percent. For his risk premium, he calculated the difference between the 10-year average from 2014 to 2023 of equity returns and real returns on long-term U.S. Treasury Bonds and obtained a result of 5.83 percent. He then multiplied the risk premium by the unadjusted beta values of the electric (0.873) and gas (0.764) proxy groups to calculate the market risk premium for proxy groups. He added the risk-free rate of 5.43 percent to each proxy group risk premium to derive is final RP estimate. His results for the electric and gas proxy groups were 10.52 percent and 9.89 percent, respectively. It is important to note that all of the data inputs used by witness Crowley were historical and reflected data more than a year in the past, and consequently, do not indicate a forward-looking required return. Further, as mentioned previously, witness Crowley did not use the results from his RP analysis in his final derivation of his range of results although he did appear to use it to calculate the standard deviation applied to his other results to determine the central tendency. Therefore, staff believes the Commission should not consider witness Crowley’s results from his RP analysis in their decision.
FPUC Realized Returns Analysis
Witness Crowley used the 10-year average realized market returns from the proxy companies over the past three years (2021, 2022, and 2023) to estimate investors required return in the future. Staff believes that the realized returns from 2021 and 2022 are dated and should not be considered. While the 2023 results reflect more recent market information, they do not indicate a ROE of 11.30 percent. The method witness Crowley used is also referred to as a comparable earnings approach, which typically uses realized book returns from companies with similar risk characteristics as a comparison to the regulated subject company. The basic premise of the comparable earnings approach is that regulation should emulate the competitive result. However, there are several issues with this method. First, using companies that have substantial regulated revenues can be circular. That is, returns earned on past investments reflect past regulatory awarded ROEs and don’t reflect the opportunity cost of investing in non-regulated companies with similar risk. Second, the comparable earnings approach uses historic earned returns to indicate the cost of equity, whereas in a regulatory proceeding prospective required returns need to be considered. Third, the actual cost of equity for a regulated utility is most appropriately determined by the application of the CAPM and DCF Model. In this case witness Crowley calculated the annual change in stock price, plus dividends paid for each company in the electric and gas proxy groups, and a non-regulated, non-utility group of companies. This method simply calculates what investors have received in the past and does not take into account any forward-looking estimates of ROE or earnings that are available from Value Line and other sources. The results witness Crowley obtained for the 10-year average ending in 2023 for the electric and gas proxy groups were 9.65 percent and 8.95 percent, respectively. The results obtained from the 5-year average 2019 through 2023 for the non-utility proxy group was 9.89 percent. In conclusion, staff does not believe witness Crowley’s realized market return analysis is reasonable nor do his most recent results from 2023 support a ROE of 11.30 percent.
Financial Risk
Financial risk is created by the introduction of debt into the capital structure. The higher proportion of debt in the capital structure the greater the financial risk. Consistent with the basic principle of risk and return, common equity investors require higher returns as compensation for bearing higher financial risk. Conversely, a company with a comparatively higher equity ratio will have less financial risk, all else equal, and the required return will be lower than a comparable company with a lower equity ratio. Witness Crowley did not address financial risk in his testimony. Staff obtained the 2025 forecasted equity ratios for each of the companies in the electric and gas proxy groups as provided in Value Line Reports. The weighted average projected 2025 equity ratios for the electric and gas proxy groups, excluding Otter Tail Corporation, Hawaiian Electric, and Unitil Corporation from the electric proxy group, and Southwest Gas Holdings, Inc. from the gas proxy group, were 45.15 percent and 55.21 percent, respectively. The weighted average equity ratio of the combined electric and gas proxy groups is 48.00 percent. FPUC’s equity ratio for the 2025 projected test year is 50.04 percent. Additionally, the average Standard & Poor’s (S&P) credit rating for the combined electric and gas proxy groups is BBB+ which is one notch higher than that of CUC at an S&P equivalent credit rating of BBB, indicating FPUC’s credit metrics are comparable to the proxy groups.[98] Therefore, staff believes the proxy groups, on average, have similar financial risk to that of CUC and FPUC.
Flotation Costs
Flotation costs are those costs associated with the sale of new issuances of common stock. They include the mandatory unavoidable costs of issuance (e.g., underwriting fees and out-of-pocket costs for printing, legal, registration, etc.). For every dollar raised through debt or equity offerings, the company receives less than one full dollar in financing. Therefore, in order for the ROE to reflect the full cost of equity realized by a company, flotation costs should be accounted for in the estimated cost of equity. The Commission has a long-standing policy to recognize flotation costs in the cost of equity models used to estimate the ROE. Witness Crowley made an upward flotation cost adjustment to his ROE model results of approximately 14 basis points based on the stock issuance costs of CUC. A similar methodology to derive the flotation costs was approved by the Commission in prior litigated rate cases.[99] Staff believes the flotation cost adjustment of 14 basis points is reasonable. Staff’s DCF model includes a flotation cost in the result by making a reduction to the stock price of 3 percent. The result of this adjustment increased the result of the DCF model by 14 basis points. Therefore, staff believes a 14-basis point adjustment for flotation costs is reasonable.
Business Risk
Witness Crowley did not provide an analysis of the business and operational risks of FPUC as compared to the companies in his electric proxy group. Staff believes that FPUC’s business and operational risks are lower than the electric companies in the proxy group. FPUC provides only transmission and distribution electric service and does not own or operate any electric generation assets. Witness Crowley’s electric proxy group includes vertically integrated electric companies, that is, the companies own and operate electric generation assets in addition to providing transmission and distribution service. Vertically integrated electric companies are riskier than distribution-only electric companies and typically receive higher authorized returns on equity for bearing the higher business and operational risk. A report by Regulatory Research Associates (RRA) published on February 5, 2025, found “[t]he annual average authorized ROEs in vertically integrated cases involving generation have historically been about 30-65 basis points higher than in distribution-only cases.” RRA also stated the difference likely reflects the increased risk associated with the ownership and operation of generation assets.[100] In 2024, the industry average authorized ROE for vertically integrated electric utilities was 9.84 percent as compared to 9.53 percent for electric distribution-only cases, a difference of 31 basis points.[101] However, when comparing FPUC’s business risks to the companies in the gas proxy group, FPUC’s exposure to extreme weather risk is greater than the gas companies. On balance, staff believes FPUC’s business and operational risks are comparable to the combined electric and gas proxy groups.
Comparable Authorized ROEs
Staff’s recommended ROE of 10.15 percent is within the range of ROEs the Commission has recently approved for other Florida electric and natural gas companies (9.50% - 11.00%) as summarized in Table 24-2. The Florida electric companies’ authorized ROEs range from 10.30 percent to 10.80 percent. However, all three of the other Florida electric companies are vertically integrated electric companies which makes them riskier as compared to FPUC, which provides only transmission and distribution electric service. Also, there were seven ROE decisions made by other state regulatory agencies in December 2024 for electric and gas utilities. The ROEs awarded ranged from 9.34 percent to 10.50 percent, and averaged 9.81 percent, including the Commission’s decision of 10.50 percent in the TECO rate case.[102] Of note was an awarded ROE of 9.34 percent for Portland General Electric Company and 10.10 percent for Otter Tail Power Company, two of the companies included in witness Crowley’s proxy group.
Table 24-2
Florida Investor-Owned Electric and Natural Gas approved ROEs
Company |
Order Number |
Issued |
ROE |
Duke Energy Florida, LLC |
PSC-2024-0472-AS-EI |
11/12/2024 |
10.30% |
Florida City Gas |
PSC-2023-0177-FOF-GU |
06/09/2023 |
9.50% |
Florida Power & Light Company |
PSC-2022-0358-FOF-EI |
10/21/2022 |
10.80% |
FPUC (Natural Gas Division) |
PSC-2023-0103-FOF-GU |
03/15/2023 |
10.25% |
Peoples Gas System, Inc. |
PSC-2023-0388-FOF-GU |
12/27/2023 |
10.15% |
Sebring Gas System, Inc. |
PSC-2020-0047-PAA-GU |
02/03/2020 |
11.00% |
St. Joe Natural Gas Company, Inc. |
PSC-2025-0035-PAA-GU |
01/30/2025 |
10.50% |
Tampa Electric Company |
PSC-2025-0038-FOF-EI |
02/03/2025 |
10.50% |
Average |
|
|
10.375% |
Source: Staff Analysis.
Summary
Based on a review of witness Crowley’s testimony and ROE analysis, staff has concluded that FPUC has not supported its requested ROE of 11.30 percent. Witness Crowley’s ROE models do not reflect the required equity returns of investors on a forward-looking basis because his results are largely based on historical data prior to and including 2023, and do not reflect current market conditions and data. Also, witness Crowley apparently made an error in his calculation of the range of his average results, and after correction, his range of results decreased to 9.68 percent to 10.90 percent, with an average of 10.30 percent. Further, some of the companies included in witness Crowley’s proxy groups do not meet the selection criteria he defined and do not have the same business risk characteristics of FPUC, that is, they have a lower percentage of regulated revenues from operations. Witness Crowley did not provide testimony regarding a comparison of business or financial risks of his proxy groups to that of FPUC and no adjustments were made to account for any specific business or financial risks of FPUC as compared to the proxy groups. Based on the analysis presented above, staff believes witness Crowley’s cost of equity models should not be relied upon.
To test the reasonableness of witness Crowley’s DCF model and CAPM results, staff applied the same form of DCF model and CAPM to the most recent available market data for the companies in witness Crowley’s electric and gas proxy groups, excluding Otter Tail Corporation, Hawaiian Electric, and Unitil Corporation from the electric proxy group, and Southwest Gas Holdings, Inc. from the gas proxy group. Staff’s cost of equity model results ranged from 9.59 percent to 10.74 percent. Staff averaged the results of its DCF model and the CAPM for each proxy group, and then used the weighted average of the electric and gas proxy groups based on market capitalization to derive a final weighted average ROE of 10.01 percent. Staff added a flotation cost adjustment of 14 basis points (the same as witness Crowley) to the final weighted average to arrive at an ROE of 10.15 percent. Staff’s results are presented in Table 24-3. The purpose of staff’s cost of equity analysis is to demonstrate that using the most recent ex ante financial market data and projected interest rates as opposed to historical financial returns and older market data results in a significantly lower ROE than the 11.30 percent presented by witness Crowley. Therefore, staff recommends that FPUC’s midpoint ROE be set at 10.15 percent. Staff believes an ROE of 10.15 percent is appropriate because, on average, it reflects the forward-looking required returns on equity of the electric and gas proxy groups, which on the whole, have comparable risks to FPUC, and therefore, meet the Hope and Bluefield standards.
Table 24-3
Staff ROE Analysis
|
DCF |
CAPM |
Average |
Weight |
Weighted Avg |
Electric proxy group |
9.62% |
10.74% |
10.18% |
71.61% |
7.2895% |
Gas Proxy group |
9.00% |
10.18% |
9.59% |
28.39% |
2.723% |
Average |
|
|
|
|
10.01% |
Flotation Cost |
|
|
|
|
0.14% |
Weighted Average ROE |
|
|
|
|
10.15% |
Source: Staff Analysis
CONCLUSION
A return on common equity of 10.15 percent, with a range
of 9.15 percent to 11.15 percent, should be approved for use in establishing
FPUC’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 FPUC’s revenue requirement for the 2025 projected test year?
Recommendation:
A capital structure consisting of 50.04 percent common equity, 44.31 percent long-term debt, and 5.65 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 6.34 percent should be approved for establishing FPUC’s 2025 projected test year revenue requirement. (Quigley)
Staff Analysis:
The capital structure and weighted average cost of capital (WACC) is a fall-out issue that incorporates the amounts and cost rates of the capital sources into a final WACC, also referred to as the overall rate of return. On MFR Schedule D-1a (Supplement), FPUC presented its requested 2025 projected test year capital structure based on a 13-month average as of December 31, 2025, consisting of common equity in the amount of $64,253,557, long-term debt in the amount of $56,888,413, and short-term debt in the amount of $7,255,028. The Regulatory Tax Liability is the unamortized balance of the flow-back of excess deferred income taxes that were created from the Tax Cuts and Jobs Act of 2017.[103] FPUC’s requested jurisdictional capital structure is summarized in Table 25-1.
Table 25-1
FPUC Requested 13-Month Average Capital Structure
Capital Component |
Amount |
Ratio |
Cost Rate |
Weighted Cost |
Common Equity |
$64,253,557 |
42.82% |
11.30% |
4.84% |
Long-Term Debt |
56,888,413 |
37.91% |
4.51% |
1.71% |
Short-Term Debt |
7,255,028 |
4.83% |
5.81% |
0.28% |
Customer Deposits |
4,001,097 |
2.67% |
2.20% |
0.06% |
Accumulated Deferred Income Taxes |
13,206,708 |
8.80% |
0.00% |
0.00% |
Regulatory Tax Liability |
4,448,275 |
2.96% |
0.00% |
0.00% |
Total |
$150,053,078 |
100.00% |
|
6.89% |
Source: MFR Schedule D-1a (Supplement).
The cost rates and amounts of the capital components are recommended in Issues 19 through 24. The 13-month average amounts are taken directly from FPUC’s MFR Schedule D-1a (Supplement). As discussed in Issue 19, staff made an adjustment to increase the amount of accumulated deferred income taxes (ADITs) by $291,009. As discussed in Issue 20, staff recommends a cost rate for customer deposits of 2.20 percent. As discussed in Issue 21, staff recommends a cost rate for short-term debt of 5.81 percent. As discussed in Issue 22, staff recommends a cost rate for long-term debt of 4.51 percent. As discussed in Issue 24, staff recommends a return on common equity of 10.15 percent. With these adjustments and after reconciling the capital structure to the amount of rate base recommended in Issue 18, the WACC that should be approved is 6.34 percent. Staff’s recommended capital structure is summarized in Table 25-2.
Table 25-2
Staff Recommended 13-Month Average Capital Structure
Capital Component |
Amount |
Ratio |
Cost Rate |
Weighted Cost |
Common Equity |
$61,164,185 |
42.42% |
10.15% |
4.31% |
Long-Term Debt |
54,153,162 |
37.56% |
4.51% |
1.69% |
Short-Term Debt |
6,906,199 |
4.79% |
5.81% |
0.28% |
Customer Deposits |
4,001,097 |
2.76% |
2.20% |
0.06% |
Accumulated Deferred Income Taxes |
13,497,717 |
9.30% |
0.00% |
0.00% |
Regulatory Tax Liability |
4,448,275 |
3.07% |
0.00% |
0.00% |
Total |
$144,170,635 |
100.00% |
|
6.34% |
Sources: Staff Analysis and
MFR Schedule D-1a (Supplement).
The net effect of staff’s adjustments is a decrease in the WACC from 6.89 percent as requested by the Company to 6.34 percent. Based upon the proper components, amounts, and cost rates associated with the capital structure for the test year ending December 31, 2025, the projected test year jurisdictional capital structure that should be approved for establishing FPUC’s projected test year revenue requirement is 42.42 percent common equity, 37.56 percent long-term debt, 4.79 percent short-term debt, 2.76 percent customer deposits, 9.30 percent ADITs, and 3.07 percent regulatory tax liability.
CONCLUSION
A capital structure consisting of 50.04 percent common equity, 44.31 percent long-term debt, and 5.65 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 6.34 percent should be approved for establishing FPUC’s 2025 projected test year revenue requirement.
What amount of Miscellaneous Service Revenue should be approved for the 2025 projected test year?
Recommendation:
The amount of $163,225 in Miscellaneous Service Revenue should be approved for the 2025 projected test year. (Barrett, Prewett)
Staff Analysis:
This issue addresses what amount of Miscellaneous Service Revenue should be approved for the 2025 projected test year, based on the estimated number of transactions for various service types multiplied by the current charges for each type of service transaction. MFR Schedule C-5, sponsored by FPUC witness Galtman, is the primary schedule for recording all operating revenue types and sources, and Miscellaneous Service Charges are listed on this schedule as a line entry for “Other Operating Revenues.”
For the 2025 test year, MFR Schedule C-5 reflects that FPUC is projecting a balance of $163,225 in Miscellaneous Service Revenues. MFR Schedule E-13b identifies the Miscellaneous Service Charges and the number of transactions (sales) that produce the 2025 revenue addressed in this issue. The detail is shown in Table 26-1 below:
Table 26-1
Miscellaneous Service
Charge - 2025 Test Year Revenue
Description |
Estimated
Number of Transactions |
Current
Charge per Transaction ($) |
Test
Year Revenue Total ($) |
Initial Establishment of Service |
289 |
61.00 |
17,629 |
Re-establish. Service or Change Account |
3,619 |
26.00 |
94,094 |
Customer Disconnect then Reconnect |
304 |
65.00 |
19,760 |
Reconn. Svc./ Rule Violation (normal hours) |
245 |
52.00 |
12,740 |
Reconn. Svc./ Rule Violation (other hours) |
6 |
178.00 |
1,068 |
Collection Charge |
1,973 |
16.00 |
31,568 |
Temporary Service |
0 |
85.00 |
0 |
Return Check Charge |
1,179 |
43.64 |
51,454 |
Miscellaneous Allowances & Adjustments |
(1,437) |
16.00 |
(65,088) |
2025 Miscellaneous Service Charges (Total) |
$163,225 |
Source: MFR Schedule E-13b (Revenues by Rate Schedule
– Service Charges [Account 451]).
Staff reviewed historic amounts of Miscellaneous Service Revenue amounts that have been recorded since 2020, as reflected in Table 26-2 below.
Table 26-2
Revenue from Miscellaneous
Service Charge – (2020 – 2025)
Year |
Amount
($) |
2020 |
197,569 |
2021 |
198,626 |
2022 |
189,246 |
2023 |
203,299 |
2024 (projected) |
176,299 |
2025 (projected) |
163,225 |
Source: FPUC’s Response to staff’s 13th
Data Request, Item 5 (Document No. 09977-2024).
The decline in Miscellaneous Service Revenue amounts for the 2024 and 2025 projected test years appear to be driven primarily by fewer 2024 and 2025 transactions projected for the service charges identified as: (1) Initial Establishment of Service and (2) Re-establishing Service or Change Account.
CONCLUSION
Staff recommends that the amount of $163,225 in Miscellaneous Service Revenue should be approved for the 2025 projected test year.
What amount of Total Operating Revenue should be approved for the 2025 projected test year?
Recommendation:
The appropriate amount of Total Operating Revenue for the 2025 projected test year is $25,353,946. (Kunkler)
Staff Analysis:
Staff’s recommendations on Issues 2, 3, and 26
provide direct inputs into its recommendation on this issue. Per staff’s recommendation on Issues 2 and 3, there are
no recommended adjustments to FPUC's forecasts of customers, energy sales,
demand, or revenue from the sales of electricity at present rates for the 2025
projected test year. Per staff’s recommendation in Issue 3, the test year
revenue from these electricity sales sources is $24,353,946.
In addition to “Total Revenue From the Sales of Electricity at Present Rates”, FPUC also receives “Other Operating Revenue,” which includes revenue from multiple sources, such as forfeited discounts, miscellaneous service revenues (see Issue 26), rent from electric property, etc., together totaling $978,357. Staff does not recommended adjustments to any of these revenue amounts proposed by FPUC.
Summing “Other Operating Revenue” with “Total Revenue From the Sales of Electricity at Present Rates” yields Total Operating Revenue” for the 2025 test year of $25,353,946, as detailed in Table 27-1 below.
Table 27-1
FPUC Operating Revenue Projections – 2025 Test Year
Account Nos. |
Account Title |
Revenues |
440-447 |
Total Revenue From
Sales of Electricity at Present Rates (From Issue 3) |
$24,375,589 |
450 |
Forfeited Discounts |
$507,014 |
451 |
Miscellaneous Service
Revenues |
$163,225 |
454 |
Rent From Electric Property |
$269,439 |
456.2 |
Other Revenues |
$38,679 |
|
Total Other Operating Revenue |
$978,357 |
|
Total Operating
Revenues |
$25,353,946. |
Source: MFR Schedule C-5,
Page 3 of 3.
CONCLUSION
The appropriate amount of Total Operating Revenue for the 2025 projected test year is $25,353,946.
Should FPUC’s proposed costs for the S&P Global Platts package be approved for the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. FPUC’s proposed costs associated with the S&P Global Platts package should be approved for the 2025 projected test year. (Folkman)
Staff Analysis:
The S&P Global Platts Commodity Service Model is a premium subscription platform used for forecasting commodity prices. For FPUC, natural gas prices must be forecasted in order to complete its fuel cost projection petition filed in the annual Fuel and Purchased Power Cost Recovery Clause and to assess potential costs associated with its purchased power agreements in general.[104] The total cost for the 2025 S&P Global Platts subscription is $71,136, with $26,887 being allocated to FPUC’s electric division.
CONCLUSION
Staff recommends that FPUC’s proposed costs associated with the S&P Global Platts Package should be approved for the 2025 projected test year.
Has FPUC made the appropriate test year adjustments to remove fuel revenues and fuel expenses recoverable through the Fuel and Purchased Power Cost Recovery Clause?
Recommendation:
Yes. FPUC has made the appropriate test year adjustments to remove fuel revenues and fuel expenses recoverable through the Fuel and Purchased Power Cost Recovery Clause. (Folkman)
Staff Analysis:
Fuel revenues and fuel expenses are processed through the Fuel and Purchased Power Cost Recovery Clause and the corresponding fuel cost recovery charge. As such, fuel revenues and expenses should not be included in the derivation of base rates. Thus, the purpose of this issue is to ensure any fuel revenues and expenses that are recovered in the Fuel and Purchased Power Cost Recovery Clause have been removed from the calculation of base rates.
As detailed in MFR Schedule C-2 (2025), FPUC removed $65,063,104 of revenue associated with projected cost requirements and recoveries in the Fuel and Purchased Power Cost Recovery Clause. For fuel-related purchased power costs, FPUC removed a total expense of $52,194,761 including taxes. The balance of the revenue adjustment, or $12,875,012, is revenue associated with demand costs that are also recovered in the Fuel and Purchased Power Cost Recovery Clause.
CONCLUSION
Staff recommends that FPUC 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 FPUC made the appropriate test year adjustments to remove conservation revenues and conservation expenses recoverable through the Conservation Cost Recovery Clause?
Recommendation:
Yes. FPUC has made the appropriate test year adjustments to remove conservation revenues and conservation expenses recoverable through the Conservation Cost Recovery Clause. (Prewett, Barrett)
Staff Analysis:
For the projected 2025 test year, FPUC removed $883,887 in conservation revenues and an equal amount in conservation expenses recoverable through the Conservation Cost Recovery Clause. These amounts are removed adjustments to Net Operating Income in MFR Schedule C-2, and are removed as negative income and expense adjustment entries to signify that these are amounts that reduce the total revenues and total expenses of the Company. Similar amounts and adjustments were made for the projected 2024 test year ($883,573), and for the 2023 historic test year as well ($700,392). The process is explained in the direct testimony of FPUC witness Napier.[105] She states:
Consistent with prior rate proceedings, the fuel and conservation revenues and expenses, as well as their respective net under recoveries, have been eliminated from both the historic and projected test years. The items are handled in separate dockets outside of the base rate proceeding and are appropriate for review and approval within those separate proceedings.
Staff notes that the referenced amounts are shown on MFR Schedule C-2 as negative adjustment entries, which indicates the amounts are adjustments that reduce the total revenues and total expenses of the Company. Staff believes such adjustments are appropriate because the referenced revenue and expense amounts are subject to recovery through the Energy Conservation Cost Recovery clause mechanism, rather than through base rate recovery.
CONCLUSION
Staff recommends that FPUC has made the appropriate test year adjustments to remove conservation revenues and conservation expenses recoverable through the Conservation Cost Recovery Clause.
Should FPUC’s proposed addition of Electric Line Operation Supervisor in both the Northeast and Northwest Territory be included in O&M Expense for the 2025 projected test year? What, if any, adjustments should be made?
Recommendation:
Yes. FPUC’s proposed addition of an Electric Line Operation Supervisor in both its Northeast and Northwest territories, with a salary of $105,000 for each position, should be included in the 2025 projected test year with no adjustments. (Thompson, Zaslow)
Staff Analysis:
In its 2025 projected test year, FPUC has included the costs associated with the addition of a new Electric Line Operation Supervisor in both its Northeast and Northwest territories for a total of two new positions. FPUC indicated that these positions were added in order to remain in compliance with its O&M policies. To facilitate this, these positions would be responsible for overseeing distribution line crews, monitoring material used/spent, facilitating training, reviewing qualifications, ensuring safety equipment compliance, monitoring fleet compliance and performance, ensuring compliance with construction standards, performing field safety observations, overseeing time coding, and performance reviews. These positions were filled in October 2024, with a salary of $105,000 for each position.
FPUC previously leveraged the Manager of Electric Operations, Engineering and Safety, as well as contractors, to address the Electric Line Operation Supervisors’ responsibilities. However, due to increased workload and complexity of the work, FPUC stated in response to staff data requests that it was necessary to add the supervisor positions to provide direct oversight of distribution line workers, and ensure the safest and most efficient work environment.[106] These positions will provide an additional level of supervision necessary to assist construction personnel while also consolidating the responsibilities outlined above into a single source. Additionally, FPUC indicated that these positions would allow management personnel to focus more on strategic activities while the supervisors support field crews.
Staff has reviewed these positions and believes that they will provide FPUC with the supervision necessary to remain in compliance with its O&M policies by overseeing the performance and safety of field employees and contractors, amongst other responsibilities. As such, staff recommends that FPUC’s proposed addition of an Electric Line Operation Supervisor in both its Northeast and Northwest territories be approved for inclusion in the 2025 projected test year with no adjustments.
CONCLUSION
FPUC’s proposed addition of an Electric Line Operation Supervisor in both its Northeast and Northwest territories, with a salary of $105,000 for each position, should be included in the 2025 projected test year with no adjustments.
Has FPUC made the appropriate test year adjustments to remove all storm hardening revenues and expenses recoverable through the Storm Protection Plan Cost Recovery Clause?
Recommendation:
Yes. Staff recommends that FPUC has made the appropriate test year adjustments to remove all storm hardening revenues and expenses recoverable through the SPPCRC. (Hitchens, Roberts, Wooten)
Staff Analysis:
In 2023, 2024, and 2025, FPUC made adjustments to move Storm Protection Plan (SPP) revenue and under-recovery from base rates to the Storm Protection Plan Cost Recovery Clause (SPPCRC). In 2023, 2024, and 2025, FPUC also made adjustments to remove SPP-related income and other taxes, as well as depreciation expenses. Furthermore, FPUC reallocated tree trimming and inspection costs, and associated income tax from base rates to the 2025 SPPCRC.
In MFR Schedule C-7, FPUC made adjustments using inflation and customer growth rates, further adjusting for tree trimming and inspection costs. These total amounts were then removed from MFR Schedule C-2 for 2024 and 2025, respectively. In the Fifteenth Data Request, staff asked whether FPUC had made the appropriate adjustments to remove all storm hardening revenues and expenses recoverable through the SPPCRC for the 2025 projected test year. FPUC’s discovery response stated that it had inadvertently removed the 2024 inspection cost from its 2025 MFRs causing $57,238 in net over recovery of expenses.
FPUC’s C-2 and C-3 MFRs show a decrease in Net Operating Income (NOI) of $1,169,117 in 2025 for the SPPCRC, which includes $5,494,310 in total operating revenues minus $4,325,193 in total operating expenses. FPUC removed an NOI of $721,522 in 2024, which includes $3,133,444 in total operating revenues minus $2,411,922 in total operating expenses. FPUC removed an NOI of $524,274 in 2023, which includes $1,325,715 in total operating revenues minus $801,441 in total operating expenses.
According to the staff audit, FPUC made an adjustment of ($413,690) to working capital to remove under-recovery which was interest earning, for its SPP. In addition, the amount of ($413,690) was included in the Fuel Under-Recovery adjustment. Audit staff determined that the amount of ($413,690) was removed twice. However, the adjustment has no effect on the projected 2025 test year.
Pursuant to 366.96, F.S. and Rule 25-6.031, F.A.C., utilities may recover costs for SPP activities through base rates or the SPPCRC. Staff recommends that FPUC’s adjustments are reasonable; therefore, staff recommends that FPUC has made the appropriate SPPCRC adjustments, as shown on MFR schedules C-2, C-3, C-7, and in the above-mentioned discovery.
CONCLUSION
Staff recommends FPUC has made the appropriate test year
adjustments to remove all storm hardening revenues and expenses recoverable
through the Storm Protection Plan Cost Recovery Clause.
Is FPUC’s proposed reserve target level and annual storm damage accrual for the 2025 projected test year appropriate? If not, what adjustment should be made?
Recommendation:
Yes. FPUC’s proposed increase to its annual accrual is reasonable and therefore, staff recommends that FPUC’s proposed reserve target level of $1.5 million and annual storm damage accrual of $446,979 for the 2025 projected test year are appropriate and should be approved without any adjustments. (Ramirez-Abundez, Folkman)
Staff Analysis:
FPUC witness Napier explained that the Company is requesting an increase in its annual storm reserve accrual due to exposure to the risk of storm damage, the conditions relating to storm activity changing in Florida, and a current projection for the storm reserve to be underfunded by the end of the 2025 test year. Storm costs in 2024 are estimated to be $778,816, and FPUC projects storm costs for 2025 to be $619,454, which would create a deficit of $734,893 in FPUC’s storm reserve by the end of the 2025 test year. The 2025 projected storm costs are an average of FPUC’s actual storm costs for 2020 through 2023 plus the estimates of the 2024 costs. Additionally, FPUC requested to spread the collection of its reserve replenishment over five years in order to mitigate the rate impact to its customers. The resulting calculation amounts to $446,979 annually.
Rule 25-6.0143, F.A.C., addresses the establishment of a storm reserve account and outlines the types of storm related costs that an investor-owned electric utility can charge to its storm reserve. FPUC’s existing storm reserve target level is $1.5 million and its existing annual storm damage accrual is $121,620.[107] If FPUC’s annual storm damage accrual remains unchanged, it would take 18 years to replenish the storm reserve target level to $1.5 million. FPUC is requesting to increase its annual accrual amount by approximately $325,359 to $446,979, in order to collect $2,234,894 over five years. This will replenish the level of the storm reserve to $1.5 million. The Company did not request any changes to its existing reserve target level of $1.5 million.
CONCLUSION
Based on the information above, staff agrees with FPUC’s calculations which demonstrate that its storm reserve would be deficient by the end of 2025 if its annual accrual remains unchanged. Additionally, staff recognizes the need for FPUC to maintain its storm reserve given the Company’s risk of storm damage. FPUC’s proposed increase to its annual accrual is reasonable and therefore, staff recommends that FPUC’s proposed reserve target level of $1.5 million and annual storm damage accrual of $446,979 for the 2025 projected test year are appropriate and should be approved without any adjustments.
What amount of advertising expense should be approved for the 2025 projected test year?
Recommendation:
An advertising expense of $103,998 should be approved for the 2025 projected test year. (Folkman)
Staff Analysis:
Advertising serves to convey information regarding utility services, safety, conservation, and other customer-related matters. FPUC has estimated an advertising expense of $103,998 for the 2025 projected test year, reflecting an increase of $2,662 from the previous year’s expense of $101,336. In FPUC’s Response to Staff’s First Data Request, the Company indicated it anticipates its 2025 advertisement expense will remain consistent with those of recent years.[108] Thus, FPUC’s 2024 advertising budget was only increased by the customer growth and inflation factor of 1.0263 to arrive at the 2025 budgeted amount.
CONCLUSION
Staff recommends that an advertising expense of $103,998 be approved for the 2025 projected test year.
What amount of economic development expense should be approved for the 2025 projected test year?
Recommendation:
An amount of $19,055 should be approved for the 2025 projected test year. (Folkman)
Staff Analysis:
As defined by Rule 25-6.0426, F.A.C., economic development refers to activities aimed at enhancing the quality of life for all Floridians by supporting businesses or creating jobs. FPUC is permitted to recover most expenses associated with these activities. In compliance with Rule 25-6.0426(3)(b), F.A.C., the Company reduced economic development expenses by five percent of the total cost. This adjustment remains below the allowable maximum total of 0.225 percent of gross revenues for the 2025 projected test year.
In MFR C-3, FPUC removed a pretax total of $953 for its portion of the 2025 test year economic development expense.[109] This adjustment was calculated by multiplying the total expense of $18,000 by 5 percent and then applying an inflation/customer growth factor of 1.0586 (from 2023 to 2025). FPUC has confirmed that all economic development expenditures will conform to the guidelines set forth in Rule 25-6.0426(3)(b), F.A.C.[110] Staff has reviewed the Company’s request and believes it complies with the applicable rule.
CONCLUSION
Staff recommends that an economic development expense of $19,055 be approved for the 2025 projected test year.
What annual rate case expense should be approved for the 2025 projected test year?
Recommendation:
Staff recommends the Commission approve a total rate case cost of $1,530,907 with a four-year amortization period. The corresponding annual amortization expense is $382,727. (G. Kelley)
Staff Analysis:
Generally, rate case costs encompass preparing and effectuating a rate case. On MFR Schedule C-10, FPUC projected a total rate case cost of $1,530,907. This cost is proposed to be recovered over a four-year amortization period, which yields a test year amortization expense of $382,727.[111] FPUC witness Napier stated that the Company is not staffed at a level to process a rate case proceeding, and instead, hires extra assistance when needed. This includes legal services, contracting with expert witnesses and consultants, and hiring a full-time temporary internal staff to assist with processing the rate case work. The components of FPUC’s requested rate case cost is summarized in Table 36-1.
Table 36-1
Rate Case Cost
Description |
Cost |
Legal Services |
$133,500 |
Outside Consultants |
596,105 |
Additional/Temporary Resources above Baseline |
772,497 |
Travel |
28,805 |
Total |
$1,530,907 |
Source: MRF Schedule C-10.
CONCLUSION
Staff recommends that the Commission approve a total rate case cost of $1,530,907 with a four-year amortization period. The corresponding annual amortization expense is $382,727.
What are the appropriate cost allocation methodologies and what, if any, adjustments should be made to the allocated costs and charges with affiliated companies for FPUC for the 2025 projected test year?
Recommendation:
Staff recommends that FPUC’s cost allocation methodologies are reasonable and that no adjustments are necessary. (Folkman, Higgins)
Staff Analysis:
Affiliate Administrative and General Expenses (A&G) are either directly recorded to FPUC or allocated from groups performing shared services across business units. These A&G expenses encompass employee salaries and benefits, office supplies, and third-party administrative services, e.g., legal services, human resource consulting, financial statement audits, insurance, advertising, and the facilities costs associated with office locations. Additionally, A&G expense includes pension and benefit costs specific to the Company.
The Company states that allocations of A&G expenses are reviewed annually, or as significant changes occur, to ensure they are distributed appropriately among business units.[112] CUC’s Cost Accounting Manual (CAM) outlines the allocation practices and methodologies used to account for all allocated Operations and Maintenance expenses, including A&G costs. The CAM’s purpose is to document these allocation practices and methodologies as they are applied through the Company’s accounting processes and financial reporting systems. Further, the CAM is meant to ensure that CUC’s financial practices and methodologies prevent the subsidization of non-regulated business activities by its regulated electric operations.
FPUC’s instant request contains several methodologies of cost allocation. The allocation methodologies are designed to reflect the size and benefit of each business unit. These allocations may be based on metrics such as payroll, profitability, adjusted gross plant, adjusted capital expenditures, or the specific level of effort or focus. A&G expenses are further divided among departments to facilitate precise tracking and recording.
FPUC and/or CUC employ three primary allocation methodologies:
1. Modified Distrigas Formula: This methodology - based on a Federal Energy Regulatory Commission-approved formula - uses three equally weighted factors: gross plant, earnings before income taxes, and labor cost (payroll) to determine allocation amounts. Departments utilizing this method include Accounting and Finance, Information and Technology (IT) Network, Data and Desktop Maintenance and Support, Human Resources, Internal Audit, Security, Safety, Facilities, and Communications.
2. Task-Based Allocation: This methodology considers the department’s functions and assigns functions at different levels based on effort or focus to each business unit receiving its services. CUC utilizes this method to allocate costs associated with the Audit Committee, projects within IT departments, management, leadership, treasury, accounts payable, Regulatory Affairs, and specific IT systems.
3. Capital Expenditure-Based Allocation: This methodology allocates costs based on capital expenditures in each business unit. This includes costs associated with corporate governance, the CUC Board of Directors, and investor relations. These associations are related to growth which are driven by capital expenditures.
In response to Staff’s First Data Request, FPUC provided the CAM applicable to CUC companies/affiliates.[113] The CAM provides detailed documentation of the cost allocation methodologies present in this proceeding. Following its review, staff believes CUC’s CAM aligns with the Commission’s “Cost Allocation and Affiliate Transactions” rule, or Rule 25-6.1351, F.A.C. In general, this rule establishes guidelines for allocating costs among affiliates to prevent cross-subsidization and ensure transparency. Staff believes the CAM, and the cost allocation methodologies contained therein, adequately support FPUC’s request and are reasonable.
CONCLUSION
Staff recommends that FPUC’s cost allocation methodologies are reasonable and that no adjustments are necessary.
What amount of salaries and benefits, including incentive compensation, should be approved for the 2025 projected test year?
Recommendation:
Staff recommends the amount of salaries and benefits is $11,388,043 for the 2025 projected test year. (Zaslow)
Staff Analysis:
FPUC witness Devon stated that the Company’s salary and benefit expenses are reasonable and necessary. Witness Devon explained that FPUC’s proposed compensation package, which includes base pay, long-term, and short-term incentive plans is necessary in order to attract and retain skilled team members in the competitive job environment.[114]
CUC commissioned a compensation study which FPUC utilized in preparing its rate case.[115] In evaluating the compensation study, staff observed that FPUC’s base salary is comparable to the market median and competitive with the market overall. Staff also reviewed FPUC’s recent historical and forecasted benefit accounts and asked the Company to explain any items that displayed significant variation (increasing or decreasing significantly year over year).[116] Notable benefit accounts with large variations included Retiree Benefits, Other Health Benefits, and Other Benefits. Staff found the Company’s explanations for these shifts, such as reduced retirement benefits, reductions related to adjusting for prior year’s workers compensation exposure, and a new Other Benefits program to be reasonable. Based on its analysis, staff believes that the Company’s proposed salary and benefits expense is reasonable.
Therefore, staff recommends the appropriate level of FPUC’s salaries and benefits package for the 2025 projected test year is $11,388,043.
CONCLUSION
Staff recommends the amount of salaries and benefits is $11,388,043 for the 2025 projected test year.
What amount of Bad Debt expense should be approved for the 2025 projected test year?
Recommendation:
Staff recommends that the appropriate amount of Bad Debt expense for the 2025 projected test year is $602,010 and an average bad debt rate of 0.5227 percent be incorporated into the Revenue Expansion Factor. (G. Kelley)
Staff Analysis:
The purpose of Bad Debt expense is to compensate the Company for uncollectible service charges. On MFR Schedule C-11, FPUC stated its Bad Debt expense for the 2025 projected test year should be $602,010, and an average bad debt rate of 0.5227 percent was incorporated into the Revenue Expansion Factor (Issue 47), as shown on Schedule C-44.[117] The proposed bad debt rate reflects a three-year average of the 2023 historical test year, the 2024 prior year, and the 2025 projected test year. In addition, the proposed bad debt is lower than the three-year historical average of calendar years 2021, 2022, and 2023, which results in an average bad debt rate of 0.6628 percent. Therefore, staff recommends that the appropriate amount of Bad Debt expense is $602,010 and the average bad debt rate is 0.5227 percent.
CONCLUSION
Staff recommends that the appropriate Bad Debt expense is $602,010 for the 2025 projected test year and an average bad debt rate of 0.5227 percent be incorporated into the Revenue Expansion Factor.
What amount of distribution O&M expense should be approved for the 2025 projected test year?
Recommendation:
FPUC’s distribution O&M expense should be $3,935,481 for the 2025 projected test year. Staff recommends that the overall distribution O&M expense is reasonable, including the costs associated with the engineering and supervision of plant improvement projects due to the increased workload associated with the acquisition and replacement/rebuild of the substation assets discussed in Issue 6, and increased position responsibilities. This amount is based on directly projecting known distribution O&M expenses, and increasing historic test year distribution O&M expenses for inflation and customer growth, consistent with FPUC’s prior base rate proceedings. (Thompson, Zaslow)
Staff Analysis:
FPUC has included $4,987,655 per books in distribution
O&M expense in its 2025 projected test year. After applying
($975,504) in adjustments for tree trimming and inspections related to the
Storm Protection Plan, FPUC’s included distribution O&M expense is
$4,012,151. The distribution O&M expense is
based on directly projecting known distribution O&M expenses,
including costs associated with the engineering and supervision of FPUC’s
proposed plant improvement projects discussed in Issue 6, and increasing
historic test year distribution O&M expenses for inflation and
customer growth, consistent with FPUC’s prior base rate
proceedings. These costs reflect the addition of an Instrumentation and
Measurement Control (IMC) Technician in both FPUC’s Northeast and Northwest
territories, and the restructure of the Supervisor of Engineering’s
departmental duties, which resulted in a salary allocation to electric expense.
FPUC indicated that the IMC technicians are the personnel that are primarily responsible for the operation and maintenance of substations. The responsibilities of these positions include conducting inspections, performing necessary switching activities, collecting substation load readings, documenting relay operations, equipment maintenance activities, substation battery maintenance, substation security, ensuring the substations are maintained in a clean and orderly manner, and ensuring specialized work by contractors is completed efficiently and assisting when needed. The more routine activities, which are the majority of the tasks in the substations, will be completed by the IMC Technicians, while more specialized activities will be conducted by contractors, with the oversight of the IMC Technicians.
Both FPUC’s Northeast and Northwest territories already had one IMC Technician; however, FPUC indicated in response to staff data requests that this position was responsible for both substation and metering related duties, which resulted in the workload exceeding FPUC staff’s capacity.[118] With the addition of a new IMC Technician position in both territories, the duties will be split between the positions. As such, one IMC Technician will be responsible for substation related duties, while the other IMC Technician will be responsible for metering related duties. The Northeast IMC Technician position was filled in the third quarter of 2023, and the Northwest IMC Technician position was filled in the third quarter of 2024, with a base hourly salary of $47.43 per hour each, which is the same salary as the original IMC Technicians. Additionally, costs related to Company-provided substation maintenance, annual training, and equipment and supplies, totaling approximately $73,000, have been included for the new Northwest IMC Technician due to the acquisition of the substation assets discussed in Issue 6.
The Supervisor of Engineering’s
departmental duties were restructured in 2024, which resulted in a 39.2 percent
salary allocation to electric expense rather than the previous salary allocation
of 100 percent to capital expense. FPUC indicated that this allocation is due
to the additional internal engineering costs related to additional substation
maintenance planning, with more focus on vegetation management,
transmission/distribution relay modifications, and monitoring feeder loading.
The total included in the 2025 projected test year for the salary allocation to
electric expense is $61,041.
Staff has reviewed the distribution O&M expense and believes that the overall distribution O&M expense is reasonable, including the costs associated with the engineering and supervision of plant improvement projects due to the increased workload associated with the acquisition and replacement/rebuild of the substation assets discussed in Issue 6, and increased position responsibilities. Given its recommendation in Issue 32, specifically for removal of additional Storm Protection Plan expenses, staff recommends the 2025 projected test year O&M expense be reduced by ($76,670).[119] As such, staff recommends that FPUC’s distribution O&M expense should be $3,935,481 for the 2025 projected test year.
CONCLUSION
FPUC’s distribution O&M expense should be $3,935,481 for the 2025 projected test year. Staff recommends that the overall distribution O&M expense is reasonable, including the costs associated with the engineering and supervision of plant improvement projects due to the increased workload associated with the acquisition and replacement/rebuild of the substation assets discussed in Issue 6, and increased position responsibilities. This amount is based on directly projecting known distribution O&M expenses, and increasing historic test year distribution O&M expenses for inflation and customer growth, consistent with FPUC’s prior base rate proceedings.
What amount of transmission O&M expense should be approved for the 2025 projected test year?
Recommendation:
FPUC’s transmission O&M expense should be $144,837 for the 2025 projected test year. This amount is based on directly projecting known transmission O&M expenses, and increasing historic test year transmission O&M expenses for inflation and customer growth, consistent with FPUC’s prior base rate proceedings. Therefore, staff recommends that FPUC’s transmission O&M expense is reasonable and should be approved. (Thompson, Zaslow)
Staff Analysis:
FPUC has included $144,837 in transmission O&M expense in its 2025 projected test year. Consistent with FPUC’s prior base rate proceedings, this amount it based on directly projecting known transmission O&M expenses, and increasing historic test year transmission O&M expense for inflation and customer growth. As such, staff recommends that FPUC’s transmission O&M expense is reasonable and should be included in its 2025 projected test year.
CONCLUSION
FPUC’s transmission O&M expense should be $144,837 for the 2025 projected test year. This amount is based on directly projecting known transmission O&M expenses, and increasing historic test year transmission O&M expense for inflation and customer growth, consistent with FPUC’s prior base rate proceedings. Therefore, staff recommends that FPUC’s transmission O&M expense is reasonable and should be approved.
What total amount of O&M expense should be approved for the 2025 projected test year?
Recommendation:
Staff recommends O&M expense for the 2025 projected test year of $16,169,022. (Zaslow)
Staff Analysis:
The Company’s proposed O&M expense per books is $20,084,163. Combined with the net operating income adjustments of ($3,838,470), this results in an adjusted jurisdictional O&M expense of $16,245,692.[120] Given its recommendation in Issue 32, specifically for removal of additional Storm Protection Plan expenses, staff recommends the 2025 projected test year O&M expense be reduced by ($76,670).[121] This results in an adjusted test year O&M expense of $16,169,022.
CONCLUSION
Staff recommends O&M expense for the 2025 projected test year of $16,169,022.
What amount of depreciation expense should be approved for the 2025 projected test year?
Recommendation:
Staff recommends the Commission approve a depreciation expense of $5,119,891 for the 2025 projected test year. (Higgins)
Staff Analysis:
The purpose of depreciation expense is to allocate and ultimately recover the costs of long-lived (i.e., generally greater than one year) assets over their respective useful lives. Alternatively stated, depreciation ensures that the cost of an asset is spread over its useful life, which matches the expense to the time period in which the asset is “used and useful” in providing utility service. Further, accounting for depreciation helps to provide an accurate picture of the Company’s financial performance by recognizing that assets lose value over time due to factors such as “wear and tear,” obsolescence, or age.
FPUC’s proposed annual depreciation expense for the 2025 test year is $5,584,900 per books.[122] After accounting for its proposed adjustments, FPUC’s level of depreciation expense is $5,280,274 for the 2025 projected test year. The Company calculated its depreciation expense using the appropriate rates as prescribed by Commission Order No. PSC-2023-0384-PAA-EI.[123]
Staff reviewed the Company’s depreciation expense proposals as contained in the MFRs and observed eight accounts with anomalous expense results. The specific accounts are as follows: Account 303.2 - Intangible Plant CIS, Account 350.2 - Rights of way, Account 352 - Structures & Improvements, Account 353 - Station Equipment, Account 354 - Towers & Fixtures, Account 355 - Poles & Fixtures - Concrete, Account 355 - Poles & Fixtures-SPP, and Account 365 - Overhead Conductors & Devices. Staff questioned FPUC on these specific accounts through the data request process.[124] In responding to staff’s data request, the Company indicated that certain adjustments to the MFRs were necessary. These adjustments were provided in FPUC’s Responses to Staff’s Seventh Set of Data Requests.[125] Staff reviewed the adjustments and believe they are appropriate. Further, additional retirement-related adjustments reducing depreciation expense were performed for Account 391.1 - Computer and Periphery and Account 391.2 - Computer Hardware.[126] After accounting for the aforementioned changes, the amended adjusted annual depreciation expense for the 2025 test year is $5,518,536.
Staff further adjusted $211,288 from the Company’s request related to the recommended recovery of the substation assets discussed in Issue 6. Additionally, staff adjusted depreciation expense by $187,357 associated with the Company’s proposed two-way communication system discussed in Issue 10. Thus, the jurisdictional adjusted level of depreciation expense for the 2025 test year is $5,119,891.
CONCLUSION
Staff recommends the Commission approve a depreciation expense of $5,119,891 for the 2025 projected test year.
What amount of Taxes Other Than Income should be approved for the 2025 projected test year?
Recommendation:
Staff recommends Taxes Other Than Income taxes for the 2025 projected test year of $2,357,780. (Zaslow)
Staff Analysis:
Taxes Other Than Income (TOTI) taxes generally consist of ad valorem, gross revenue or gross receipts taxes, state unemployment insurance, franchise taxes, federal excise taxes, social security taxes, and all other taxes assessed by federal, state, county, municipal, or other local governmental authorities with the exception of income taxes.
The total 2025 projected test year Company proposed TOTI per books is $9,376,855. Combined with net operating income adjustments of ($7,019,075), results in an adjusted jurisdictional TOTI amount of $2,357,780.[127] In response to staff’s data request, the Company provided the projected 2025 property tax expense calculations.[128] Staff observed that the forecasted 2025 property tax increased relative to prior 2024 year as a result of forecasted increases to 2025 average plant in service. Staff believes the increased forecast for average plant to be reasonable; thus, the forecasted 2025 property tax calculations are also reasonable.
CONCLUSION
Staff recommends Taxes Other Than Income taxes for the 2025 projected test year of $2,357,780.
What amount of Income Tax expense should be approved for the 2025 projected test year?
Recommendation:
Staff recommends that the amount of Income Tax expense for the 2025 projected test year is ($2,415,324). (G. Kelley)
Staff Analysis:
This is a fall-out issue. On MFR Schedule C-22, FPUC calculated an adjusted jurisdictional Income Tax expense of ($1,970,618) for the 2025 projected test year.[129] Staff reviewed the Company’s proposed interest expense and observed anomalous results which led to discovery on the topic. In FPUC’s Responses to Staff’s Ninth Data Request, the Company determined that adjustments to the proposed MFRs were necessary. This resulted in the as-filed revenue requirement being overstated by $732,820 and an Income Tax expense decrease of $541,193.[130]
Based on adjustments to Issues 32 and 43, along with corresponding adjustments to all NOI issues, staff recommends a total decrease in 2025 Income Tax expense of $444,706, resulting in a total Income Tax expense, including interest synchronization, of ($2,415,324).
CONCLUSION
Staff recommends that the appropriate Income Tax expense is ($2,415,324) for the 2025 projected test year.
What amount of Net Operating Income should be approved for the 2025 projected test year?
Recommendation:
Staff recommends that the appropriate Net Operating Income is $1,673,316 for the 2025 projected test year. (G. Kelley)
Staff Analysis:
This is a fall-out issue consisting of the difference between projected test year revenues in Issue 27 and Total Operating Expense in Issue 42. On MFR Schedule C-1 (2025), FPUC requested a total Net Operating Income of $991,558 for the 2025 projected test year.[131] Based on the previous adjustments in Issues 32, 43, and 45, staff recommends an increase of $681,759, resulting in a total Net Operating Income of $1,673,316 for the 2025 projected test year.
CONCLUSION
Staff recommends that the Commission approve a Net Operating Income of $1,673,316 for the 2025 projected test year.
What revenue expansion factor and net operating income multiplier should be approved for the 2025 projected test year, including the appropriate elements and rates?
Recommendation:
Staff recommends that the appropriate 2025 projected test year revenue expansion factor is 74.2015 percent and the net operating income multiplier is 1.3477. The appropriate elements and rates are discussed in the analysis portion of this recommendation. (G. Kelley)
Staff Analysis:
On MFR Schedule C-44, FPUC calculated a net operating income multiplier of 1.3477.[132] This multiplier is based on a revenue expansion factor of 74.2015 percent, formulated using a 0.0848 percent factor for regulatory assessment fees, a 0.5227 percent bad debt rate, a 5.5 percent state income tax, and a 21.0 percent Federal Income Tax rate. The net operating income multiplier calculation is shown in Table 47-1. Staff agrees that FPUC’s calculation is appropriate and recommends its approval.
Table 47-1
NOI Multiplier
Description |
Value |
Revenue Requirement |
100.0000% |
Less Regulatory Assessment Fee |
0.0848% |
Less Staff Calc. Bad Debt Rate |
0.5227% |
Net Before Income Taxes |
99.3925% |
Less State Income Tax @ 5.5% |
5.4666% |
Net Before Federal Income Tax |
94.9259% |
Less Federal Income Tax @ 21.0% |
19.7244% |
Revenue Expansion Factor |
74.2015% |
NOI Multiplier (100/74.424) |
1.3477 |
Source: MFR Schedule C-44.
CONCLUSION
Staff recommends that the appropriate revenue expansion factor is 74.2015 percent and net operating income multiplier is 1.3477 for the 2025 projected test year, including the elements and rates discussed in the analysis portion of this recommendation.
What amount of annual operating revenue increase should be approved for the 2025 projected test year?
Recommendation:
The amount of annual operating revenue increase that should be approved for the projected 2025 test year is $9,898,162. (G. Kelley)
Staff Analysis:
This is a fall-out issue. In its original filing, FPUC requested a total operating revenue increase of $12,593,450 for the 2025 projected test year.[133] After accounting for changes in service charges and other revenues of ($164,495), the Company’s proposed increase in base rate revenues is $12,428,955.
Based on the previous adjustments to Plant in Service, Cost of Capital, and Net Operating Income, staff is recommending an operating revenue increase of $10,062,657 for the 2025 projected test year. After accounting for changes in service charges and other revenues of ($164,495), staff’s proposed increase in base rate revenues is $9,898,162.
CONCLUSION
Staff recommends that the Commission approve an annual operating revenue increase of $9,898,162 for the 2025 projected test year.
What is the appropriate cost of service methodology to be used in designing FPUC’s rates?
Recommendation:
The appropriate cost of service study methodology utilizes the 12 Monthly Coincident Peak (CP) method for the allocation of transmission costs; non-coincident peak and customer maximum demand for distribution plant; and classifies only the meter, service drop, and customer-service components of the distribution system as customer-related. The appropriate cost of service study is contained in MFR Schedule E and is consistent with FPUC’s last rate case filing. FPUC should file a revised cost of service study, including rates and tariffs, that reflect the Commission vote on all issues by March 10, 2025, close of business. (Hampson)
Staff Analysis:
FPUC is a non-generating utility, therefore, there are no production costs included in the cost of service study. The purpose of a cost of service methodology is to perform three activities. First, it functionalizes costs into transmission, distribution, and customer categories. Second, these functionalized costs are separated into classifications based on the utility service being provided. Since FPUC has no production costs, there are only two principal classifications of costs: (1) demand costs which are costs that vary with the kW demand imposed by the customer and (2) customer costs which are costs that are directly related to the number of customers served. With production costs, typically there would also be an energy allocation. As described in the direct testimony of witness Taylor, the results of the cost of service study are utilized to determine the relative cost to serve each rate class, help determine the individual classes’ revenue responsibility, and provide guidance with rate design.
Witness Taylor states that the proposed cost of service study has been prepared to align with the cost of service study used in FPUC’s previous rate case filing. FPUC explained that in MFR Schedules E-11 and E-17 the demand allocation factors used in FPUC’s cost of service study are based on Gulf Power Company’s (now part of Florida Power & Light Company) load research results. FPUC stated that as a small electric system and because of its non-generating status, the Company has not been required to conduct load research. Due to the similar geography, staff believes that using Gulf Power Company’s load research data is appropriate and consistent with the MFRs filed in FPUC’s 2014 rate case.
CONCLUSION
The appropriate cost of service study methodology utilizes the 12 Monthly Coincident Peak (CP) method for the allocation of transmission costs; non coincident peak and customer maximum demand for distribution plant; and classifies only the meter, service drop, and customer-service components of the distribution system as customer-related. The appropriate cost of service study is contained in MFR Schedule E and is consistent with FPUC’s last rate case filing. FPUC should file a revised cost of service study, including rates and tariffs, that reflect the Commission vote on all issues by March 10, 2025, close of business.
If a revenue increase is granted, how should the increase be allocated to rate classes?
Recommendation:
The appropriate allocation of the increase 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 increase should be allocated to the rate classes in a manner that moves the class rate of return indices as close to parity as practicable based on the approved cost allocation methodology, subject to the following constraints: (1) no class should receive an increase greater than 1.5 times the system average percentage increase in total, and (2) no class should receive a decrease. (Hampson)
Staff Analysis:
FPUC witness Taylor described in direct testimony how the Company allocated the proposed revenue requirement increase among the rate classes. While the Company considered several options, including setting revenues to the cost to serve each class, FPUC has proposed to allocate the revenue requirement using a target system multiplier at equal rates of return. Under the proposed allocation, GS, GSD, and GSLD would receive an increase 1.35 times the system average increase, GSLD1 and Lighting would receive an increase of 0.54 times the system average increase, and the remaining revenue increase was apportioned to the RS class. This resulted in an increase of 0.86 times the system average increase for RS customers.
MFR Schedule E-8 demonstrates how the proposed allocation of the revenue increase moves each customer class closer to parity, where the class rate of return is equal to the system rate of return. As a result of limited base rate increases, FPUC’s customer classes at present rates are far outside of parity, as shown by the present rate of return index on MFR Schedule E-8. Under the Company-proposed allocation, each customer class would move closer to parity with the overall system rate of return. Furthermore, FPUC has complied with Commission practice where each class has not received more than 1.5 times the system average increase nor has any class received a decrease. Table 2 in the direct testimony of witness Taylor provides the proposed revenues by rate division and demonstrates how no class has received an increase greater than 1.5 times the system average increase. Based on the information provided, staff believes that FPUC’s proposed allocation of the revenue increase is appropriate.
CONCLUSION
Based on the above, staff recommends that 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 increase should be allocated to the rate classes in a manner that moves the class rate of return indices as close to parity as practicable based on the approved cost allocation methodology, subject to the following constraints: (1) no class should receive an increase greater than 1.5 times the system average percentage increase in total, and (2) no class should receive a decrease.
What are the appropriate customer facilities charges?
Recommendation:
The final customer facilities charges are a fall-out issue and will be decided at the March 20, 2025 Commission Conference. The calculation of the customer facilities charges is dependent on the Commission’s vote on the final revenue requirement. FPUC should be required to recalculate the customer facilities charges based on the Commission’s vote on all prior issues. (Hampson)
Staff Analysis:
The final customer facilities charges are a fall-out issue and will be decided at the March 20, 2025 Commission Conference. The calculation of the customer facilities charges is dependent on the Commission’s vote on the final revenue requirement. FPUC should be required to recalculate the customer facilities charges based on the Commission’s vote on all prior issues. FPUC should file revised rates and tariffs, that reflect the Commission vote on all issues by March 10, 2025, close of business.
What are the appropriate demand charges?
Recommendation:
The final demand charges are a fall-out issue and will be decided at the March 20, 2025 Commission Conference. The calculation of the customer facilities charges is dependent on the Commission’s vote on the final revenue requirement. FPUC should be required to recalculate the demand charges based on the Commission’s vote on all prior issues. (Hampson)
Staff Analysis:
The final demand charges are a fall-out issue and will be decided at the March 20, 2025 Commission Conference. The calculation of the customer facilities charges is dependent on the Commission’s vote on the final revenue requirement. FPUC should be required to recalculate the demand charges based on the Commission’s vote on all prior issues. FPUC should file revised rates and tariffs, that reflect the Commission vote on all issues by March 10, 2025, close of business.
What are the appropriate energy charges?
Recommendation:
The final energy charges are a fall-out issue and will be decided at the March 20, 2025 Commission Conference. The calculation of the customer facilities charges is dependent on the Commission’s vote on the final revenue requirement. FPUC should be required to recalculate the energy charges based on the Commission’s vote on all prior issues. (Hampson)
Staff Analysis:
The final energy charges are a fall-out issue and will be decided at the March 20, 2025 Commission Conference. The calculation of the customer facilities charges is dependent on the Commission’s vote on the final revenue requirement. FPUC should be required to recalculate the energy charges based on the Commission’s vote on all prior issues. FPUC should file revised rates and tariffs, that reflect the Commission vote on all issues by March 10, 2025, close of business.
Should FPUC’s proposal to delete standby service be approved?
Recommendation:
Yes, FPUC’s proposal to delete standby service should be approved. Accordingly, the standby service tariff should be closed once the Commission’s decision in this docket has become final. (Guffey)
Staff Analysis:
The standby service tariff is applicable only to customers who are self-generators with the capability to meet their entire electric power requirements and require backup or maintenance service on a firm basis. The standby service tariff is not applicable to self-generating customers who require supplemental service. Witness Haffecke stated in his direct testimony that FPUC currently has one large industrial customer taking service under the standby service tariff since 2012.
Witness Haffecke explained that the single large industrial customer is more suited to be served by the GLSD 1 tariff, based upon routine requests for power beyond what is contemplated by the standby service tariff. Witness Haffecke further stated that upon moving this customer to the more appropriate rate class, no customers will be taking service under the standby service tariff, and since the Company has had no other requests for standby service over the life of the tariff, the Company believes that it is administratively efficient to close this tariff. Therefore, FPUC proposes to delete the standby service tariff and move the single industrial customer to the GLSD 1 tariff. The GSLD 1 tariff is applicable to customers who contract for at least 5,000 kilowatts of service and take service at transmission level.
In response to staff’s data request, FPUC stated that it informed the industrial customer of the proposal and currently is working with the customer to answer the customer’s concerns and questions.[134] In a later response to staff’s data request, FPUC stated that it had several conversations with the large industrial customer taking service under the standby service, and that the customer is in favor of being moved to the GSLD-1 rate class. FPUC believes that there are no outstanding customer concerns.[135]
CONCLUSION
Based on the above, staff recommends that FPUC’s proposal to delete standby service should be approved. Accordingly, the standby service tariff should be closed once the Commission’s decision in this docket has become final.
Should the proposed modifications to the temporary service charges be approved?
Recommendation:
Yes, the proposed modifications to the temporary service charges should be approved. (Guffey)
Staff Analysis:
FPUC, upon request by a customer, will supply temporary electric service when the Company’s distribution system is near the requested location. The Company will provide temporary service via an overhead or underground pole and will provide additional poles as requested for additional charges. The temporary service charges are shown on proposed Original Sheet No. 6.023. The proposed service charges will enable the Company to recover its costs related to temporary services requested by its customers.
Table 55-1 below shows the current and proposed temporary service charges.
Table 55-1
Temporary Service Charges
Charge Type |
Current |
Proposed |
Installing and Removing Temporary Service |
$230 |
$415 |
Underground Service |
$200 |
$250 |
Pole with Overhead Service |
$395 |
$835 |
Pole with Underground Service |
$560 |
$1,000 |
Source: Schedules
E-14-Tariff Sheet No. 6.023.
When the requested temporary service requires multiple temporary poles and/or extensive facilities, the Company will estimate the cost of installing and removing the temporary facilities and provide that cost estimate to the customer. The customer has the option to later replace the temporary service with permanent service, in which case the Company will remove the temporary service facilities and install a meter, service drop, and other facilities as may be necessary.
CONCLUSION
Based on the above, staff recommends that the proposed modifications to the temporary service charges should be approved.
Should the proposed modifications to deposit amounts to prepare requested binding cost estimates for new underground construction and overhead conversions be approved?
Recommendation:
Yes. The proposed modifications to deposit amounts to prepare requested binding cost estimates for new underground construction and overhead conversions should be approved. (Guffey)
Staff Analysis:
The current and revised deposit amounts are shown on Original Sheet No. 6.012. This tariff is applicable to customers seeking undergrounding of existing or newly planned electric distribution facilities by the Company. Underground facilities include, but are not limited to, distribution facilities consisting of conductors, switches, and transformers. The purpose of the deposit is to approximate the engineering costs for underground facilities associated with preparing the requested estimates. The non-refundable deposit must be paid to the Company to initiate the estimating process. The deposit is applied towards the calculation of the facility charge required for the installation of underground distribution facilities.
Once the deposit from a customer is received, the Company will begin preparing a binding cost estimate of the amount required to construct or convert overhead facilities to underground facilities. If the applicant does not enter into a contract for the installation of the requested underground facilities within 180 days of providing the binding cost estimate by the Company, the deposit shall be forfeited, and the binding cost estimate provided to the customer shall be considered expired.
Table 56-1
Undergrounding Deposit Amounts
|
Current |
Proposed |
New Construction (Excluding New Residential Subdivisions) |
||
Facilities
Classification |
Deposit Amount (per overhead primary mile) |
|
Urban Commercial |
$3,715 |
$4,540 |
Urban Residential |
$2,565 |
$3,555 |
Rural Residential |
$1,946 |
$3,263 |
|
|
|
Conversions |
||
Facilities Classification |
Deposit Amount (per overhead primary mile) |
|
Urban Commercial |
$5,750 |
$6,815 |
Urban Residential |
$4,511 |
$5,330 |
Rural Residential |
$3,273 |
$4,895 |
Low Density Subdivision |
$18.00 per lot |
$64.00 per lot |
High Density Subdivision |
$17.00 per lot |
$42.00 per lot |
Source: First Revised Sheet
No. 23 (Proposed Original Sheet No. 6.012).
The proposed binding cost estimates approximates the engineering costs for underground facilities and also reflect the changes in labor and transportation costs since FPUC’s last rate case in 2014.[136] FPUC witness Haffecke’s Exhibit WH-4 includes the updated construction and conversion labor costs. The currently approved and the proposed deposits for binding cost estimates are shown in Table 56-1 above.
CONCLUSION
Based on the above, the proposed modifications to the binding cost estimates for new underground construction and overhead conversions should be approved. The proposed binding cost estimates reflect the changes in labor and transportation costs since FPUC’s last rate case in 2014.
What are the appropriate Miscellaneous Service Charges (Tariff Sheet No. 6.027)?
Recommendation:
The appropriate Miscellaneous Service Charges are contained in Table 57-1 below and should be approved. (P. Kelley)
Staff Analysis:
The Miscellaneous Service Charges are fixed charges that are paid when a specified activity occurs, such as the initial connection of a residential or business, a change of account, or a late payment. The Miscellaneous Service Charges are designed to recover the billing, personnel, and other overhead costs associated with the specific charge.
Witness Grimard sponsors the Miscellaneous Service Charge with Exhibit WG-1. Staff’s recommended Miscellaneous Service Charges are contained in the table below. The table also shows FPUC’s present and proposed charges.
Table
57-1
FPUC
Miscellaneous Service Charges
Miscellaneous Service Charges |
Current Amount ($) |
Proposed Amount ($) |
Staff Recommended Amount ($) |
Initial establishment of service |
61 |
125 |
125 |
Re-establishment of service or Change Account |
26 |
45 |
45 |
Temporary disconnect then reconnection of service |
65 |
81 |
81 |
Reconnection - service after disconnection for rule violation (normal hours) |
52 |
70 |
70 |
Reconnection - service after disconnection for rule violation (after normal hours) |
178 |
325 |
325 |
Connect and then disconnect temporary service |
85 |
135 |
135 |
Collection charge |
16 |
50 |
50 |
Source: FPUC Exhibit WG-1.
The cost support for the increase in miscellaneous service charges is shown in Schedule E-7 of the MFRs. Schedule E-7 illustrates that the increased rates are largely driven by inflation over 10 years, which effects increases in the cost of labor and materials. FPUC explained in response to staff’s data request that transportation costs have increased due to a significant rise in vehicle costs, fuel, and insurance.[137] The increase in cost is also due to a switch from service labor to construction labor and the use of bucket trucks over pickup trucks. Bucket trucks are required by the linemen to construct and establish services. To reflect the work done more accurately, FPUC changed the charges on bills to more accurately reflect the type of services being performed
CONCLUSION
Staff recommends that the appropriate Miscellaneous Service Charges are contained in Table 57-1 and should be approved.
Is FPUC’s proposal to close the Non-Firm Energy Program-Experimental (Tariff Sheet No. 7.023) to new customers appropriate?
Recommendation:
Yes, FPUC’s proposal to close the Non-Firm Energy Program-Experimental to new customers and subsequently end the program by September 1, 2025, is appropriate and should be approved. Staff believes it is reasonable to close the program because the program has not benefitted the general body of ratepayers as intended. (P. Kelley)
Staff Analysis:
Initially approved in 2019 as a pilot, which expired on December 31, 2020, the Non-Firm Energy Program was designed for FPUC to purchase non-firm energy from FPL and sell the non-firm energy to qualifying industrial customers.[138] By Order No. PSC-2022-0064-TRF-EI, the program was reinstated permanently to include all eligible General Service Large Demand (GSLD), GSLD-1, or standby customers that own dispatchable self-generation.[139] Currently, there are two customers that qualify for the program.
FPUC witness Haffecke stated in direct testimony that the pilot program was created to incentivize qualifying customers to purchase more power from the grid on a consistent basis to increase the overall load factor. By increasing the system load factor, FPUC intended to reduce the purchased power costs recovered from the general body of ratepayers. Witness Haffecke further stated that while the participating customers did increase their purchase of power somewhat, the increase was not to the extent FPUC needed to achieve the overall pricing benefits contemplated. The additional power purchases did not reduce the system peak demand and as a result, the power costs were still included in the regular monthly purchased power billing, which is recovered by the general body of ratepayers.
As such, FPUC has concluded that the Non-Firm Energy program did not meet expectations and does not provide the Company or the general body of ratepayers any benefits. If approved, the program would close to new customers and expire within 90 days of written notice by FPUC to participating customers and expire in its entirety by September 1, 2025. Staff believes it is reasonable to close the program because the program has not benefited the general body of ratepayers as intended.
CONCLUSION
Based on the above, staff recommends that FPUC’s proposal to close the Non-Firm Energy Program-Experimental to new customers and subsequently end the program by September 1, 2025, is appropriate and should be approved. Staff believes it is reasonable to close the program because the program has not benefitted the general body of ratepayers as intended.
Should the new Technology Cost Recovery Rider and associated Tariff Sheets (Nos. 7.027 through 7.029) be approved?
Recommendation:
No. The new Technology Cost Recovery Rider (TCRR or Rider) and associated Tariff Sheets (Original Sheet Nos. 7.027 through 7.029) should be denied. The proposed TCRR program and associated costs are still in a development stage and are part of the Company’s normal operations and, therefore, more appropriately addressed through traditional ratemaking processes. (Guffey, Ramirez-Abundez)
Staff Analysis:
As explained in the testimony of FPUC witness Napier, the Company is requesting approval of a rider mechanism to recover the cost of newly implemented technology, including a return on the investment and additional operating costs. The TCRR would allow the Company to continue to make significant investments in technology to modernize its current platform and to lay the foundation for technological upgrades. In addition, FPUC witness Napier stated the TCCR would provide certainty in regard to the recovery of its investment as well as ultimately reduce costs for customers. The proposed cost recovery mechanism is based on a 12-month projected recovery period from January 1 to December 31. The Company chose this period to be consistent with its other annual filings such as fuel, conservation, and storm protection cost recovery clause dockets.[140] FPUC proposes to file its first TCRR with the Commission at least 60 days prior to the TCRR going into effect and refile on an annual basis at least 60 days prior to the January 1 effective date.
FPUC stated that at the time of the filing of this petition, all the TCRR programs and projects have not been finalized. FPUC has not provided a specific term of the TCRR nor the initial implementation date of the TCRR. As a result, there are no monthly cost recovery factors or costs to be voted on at this time. Additionally, “the Company is still determining the scope and timing of the Enterprise Resource Planning (ERP) project”[141] which is one of the technology advancements that would be recovered through the TCRR. The ERP is expected to be implemented in 2026. The TCRR is being presented as a way to avoid single-issue rate cases and regulatory lag. FPUC notes that processing a full rate proceeding could add upwards of $1.5 million of additional costs associated with rate case expenses.[142] In response No. 19, to Staff’s First Data Request, FPUC states that if the proposed TCRR is not approved and revised costs are not included in this rate case, the Company most likely would file a limited proceeding to recover the incurred ERP costs.
The ERP system is designed to integrate the general ledger with the CIS which was implemented in 2024 and proposed to be included in base rates in this proceeding. However, there are continuing costs to fine tune the implementation of the new CIS billing system.[143] Additionally, the Company is considering the integration of a Human Resource Information System (HRIS) into the overall ERP system. The Company estimated the cost of the ERP systems to be between $50 million to $70 million.[144] FPUC witness Gadgil characterizes the ERP as a way to integrate and streamline CUC’s core finance, project management, asset management, and procurement processes.[145] The ERP system component is the only project the Company anticipates recovering via the TCRR in the near term. FPUC asserts that the entire project, including HRIS will benefit all of CUC and a portion of the total costs would be allocated to FPUC electric division.[146] The Company states that the proposed Rider would allow it to implement beneficial and prudent technology investments on a more regular basis over time benefitting customers with additional service features and capabilities with technology improvements, which are evolving rapidly.
The Company asserts that the proposed TCRR is similar to the Gas Reliability Infrastructure Program (GRIP), Gas Utility Access and Replacement Directive (GUARD), and Safety, Access, and Facility Enhancement (SAFE) programs, although the underlying purpose differs.[147] Staff disagrees with this characterization because the above listed gas safety riders were a result of Pipeline and Hazardous Safety Administration regulations. TCRR is not a federally mandated Rider nor a response to a safety risk. In the order approving FPUC’s GRIP program, the Commission found that “replacement of bare steel pipelines is in the public interest to improve the safety of Florida’s natural gas infrastructure, thereby reducing the risk to life and property.” [148] In the order approving Florida City Gas’s SAFE program, the Commission stated that the SAFE program “will serve to improve safety, reduce potential damage to property, and impede theft.”[149]
In the GUARD program proposed by FPUC, the Commission approved the components of the GUARD program that “should enhance the safety and accessibility of the natural gas distribution and denied the reliability program components because they are part of the utility’s normal operations and therefore more appropriately addressed through traditional ratemaking processes.” [150]
In 2021 the Commission denied Utilities Inc. of Florida’s (UIF) proposed Sewer and Water Improvement Mechanism (SWIM), which would allow UIF to recover the revenue requirement for the replacement of aging infrastructure through an annual increase in base rates. The Commission found that UIF had provided very little evidence to support a finding that the SWIM should be approved and that “UIF has failed to meet its burden of proof to support the SWIM program.”[151] Similarly, staff believes that FPUC has provided very little detail regarding projected costs, bill impacts, or specific start or completion dates for the proposed Rider.
As discussed above, the Rider is not finalized, is not measurable, is not quantifiable at this time, and its implementation date is beyond the test year. Based on staff’s review, once costs and implementation date are finalized, the technology upgrades should be part of the Company’s normal operations and are more appropriately addressed through traditional ratemaking processes such as through a petition for a limited proceeding or base rate proceeding.
CONCLUSION
The new TCRR and associated Tariff Sheets (Original Sheet Nos. 7.027 through 7.029) should be denied. The proposed TCRR program and associated costs are still in a development stage and are part of the Company’s normal operations and, therefore, more appropriately addressed through traditional ratemaking processes.
Should the Commission approve FPUC’s proposal to recover the Hurricane Michael storm recovery surcharge from General Service - Large Demand 1 (GSLD 1) customers as a fixed charge?
Recommendation:
Yes, the Commission should approve FPUC’s proposal to recover the Hurricane Michael storm recovery surcharge from GSLD 1 customers as a fixed charge, as opposed to a variable energy charge. Recovery of Hurricane Michael costs through a fixed charge should not impact the total recovery of the surcharge. (P. Kelley)
Staff Analysis:
Currently, the Hurricane Michael storm recovery surcharge is a cents per kilowatt-hour (kWh) rate applicable to all rate classes. The GSLD 1 rate class is applicable to commercial and industrial customers contracting for at least 5,000 kW of electric service. The GSLD 1 base rates are calculated using on base transmission demand and excess reactive demand and do not include an energy charge.[152] FPUC explained in response to staff’s data request that the proposal was prompted by GSLD 1 customers using less regular service and more non-firm energy usage through the Non-Firm Energy tariff.[153] As a result, less storm revenue was collected than initially projected in the original Hurricane Michael docket.
There are currently two GSLD 1 customers on FPUC’s system. FPUC explained in response to staff’s data request that the customers are aware of proposed the change.[154] Furthermore, FPUC argued that if the customers’ total usage was to continue at the current level of both their firm and non-firm usage after expiration of the non-firm tariff, this change will benefit the customers.[155]
FPUC has proposed an annual recovery of $190,208 to be allocated across the GSLD 1 rate class. The total annual recovery of $190,208 from GSLD 1 customers is consistent with the recovery amount previously allocated to GSLD 1 customers, as originally approved by the Commission in Order No. PSC-2020-0347-AS-EI.[156] FPUC stated that the change from a variable rate to a fixed charge will have no impact on the total recovery of the surcharge.[157]
In his direct testimony, witness Haffecke also stated that the bills are currently being manually generated, but with this change of the surcharge future bills are going to be automated with the implementation of the new CIS system. Furthermore, witness Haffecke argued that the change from a variable charge to a fixed charge for GSLD 1 customers will have no impact on the total recovery of the surcharge.[158]
CONCLUSION
The Commission should approve FPUC’s proposal to recover the Hurricane Michael storm recovery surcharge from GSLD 1 customers as a fixed charge, as opposed to a variable energy charge. Recovery of Hurricane Michael costs through a fixed charge should not impact the total recovery of the surcharge.
What is the appropriate effective date for FPUC's revised rates and charges?
Recommendation:
This is a fallout issue and will be decided at the March 20, 2025 Commission Conference. (P. Kelley)
Staff Analysis:
This is a fallout issue and will be decided at the March 20, 2025 Commission Conference.
Should the Commission give staff administrative authority to approve tariffs reflecting Commission approved rates and charges?
Recommendation:
This is a fallout issue and will be decided at the March 20, 2025 Commission Conference. (P. Kelley)
Staff Analysis:
This is a fallout issue and will be decided at the March 20, 2025 Commission Conference.
Should any portion of the interim increase granted be refunded to customers?
Recommendation:
No. Based on staff’s recommended final revenue increase; an interim-related refund is not required. Further, upon issuance of the final order in this docket, the corporate undertaking should be released. (Higgins)
Staff Analysis:
By Order No. PSC-2024-0441-PCO-EI, issued October 14, 2024, the Commission authorized the collection of interim rates, subject to refund, pursuant to Section 366.071, F.S. The approved interim revenue requirement increase for FPUC was $1,812,869.[159] The interim rates became effective for all meter readings occurring on or after 30 days from the Commission’s vote on October 1, 2024.
In this proceeding, the test period for establishment of interim rates is the 12-month period ended December 31, 2023. FPUC’s approved interim rates did not include any provisions for pro forma or projected operating expenses. The interim increase was designed to allow recovery of the lower limit of the currently authorized range for return on equity.[160] Because the interim revenue increase granted in Order No. PSC-2024-0441-PCO-EI is less than staff’s recommended final revenue requirement less adjustment for rate case expense, staff recommends that no refund is required. Further, upon issuance of the final order in this docket, the corporate undertaking should be released.
CONCLUSION
Based on staff’s recommended final revenue increase; an interim-related refund is not required. Further, upon issuance of the final order in this docket, the corporate undertaking should be released.
Should FPUC 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?
Recommendation:
Yes. FPUC 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. (Higgins)
Staff Analysis:
Yes. FPUC 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.
CONCLUSION
Staff recommends that FPUC 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?
Recommendation:
No. This docket should remain open for the Commission to make its final determination regarding the requested rate increase at the March 20, 2025 Special Agenda Conference. (Brownless)
Staff Analysis:
This docket should remain open for the Commission to make its final determination regarding the requested rate increase at the March 20, 2025 Special Agenda Conference.
[1] Order No. PSC-14-0517-S-EI, issued September 29, 2014, in Docket No. 20140025-EI, In re: Application for rate increase by Florida Public Utilities Company.
[2] Order No. PSC-2024-0408-PCO-EI, issued September 5,
2024, in Docket No. 20240099-EI, In re:
Petition for rate increase by Florida Public Utilities Company.
[3] Order No. PSC-2024-0441-PCO-EI, issued October 14, 2024, in Docket No. 20240099-EI, In re: Petition for rate increase by Florida Public Utilities Company.
[4] Document No. 10324-2024.
[5] Docket No. 20240099-EI: Petition for approval of rate increase and request for interim rate relief, Document No. 08581-2024.
[6] Response No. 2 in Staff’s Fourth Data Request, Document No. 09634-2024.
[7] Response No. 2 in Staff’s Twenty First Data Request, Document No. 00015-2025.
[8] Response No. 6 in Staff’s Fourth Data Request, Document No. 09634-2024.
[9] MFR Schedule E-6a.
[10] Witness Taylor Direct Testimony, Page 7, lines 2-5, Document No. 08591-2024.
[11] MFR Schedule F-5, page 1 of 3.
[12] Response No. 8 in Staff’s Twenty first Data Request, Document No. 00015-2025.
[13] Response No. 9 in Staff’s Fourth Data Request, Document No. 09634-2024.
[14] MFR Schedule F-5, page 1 of 3.
[15] Response No. 4 in Staff’s Fourth Data Request, Document No. 09634-2025.
[16] MFR Schedule F-5, page 1 of 3
[17] Direct testimony of Michelle Napier, page 20, Document No. 08583-2024.
[18] Direct testimony of Michelle Napier, page 20, Document No. 08583-2024.
[19] Direct testimony of Michelle Napier, page 18, Document No. 08583-2024.
[20] Direct testimony of Michelle Napier, page 19, Document No. 08583-2024.
[21] Response No. 1 in Staff’s 13th Data Request, Document No. 09977-2024.
[22] Direct testimony of Michelle Napier, page 20, Document No. 08583-2024.
[23] Response No. 1 in Staff’s 13th Data Request, Document No. 09977-2024.
[24] Response No. 1 in Staff’s 13th Data Request, Document No. 09977-2024.
[25] Order No. PSC-2023-0103-FOF-GU, issued March 15, 2023, in Docket No. 20220067-GU, In re: Petition for rate increase by Florida Public Utilities Company, Florida Division of Chesapeake Utilities Corporation, Florida Public Utilities Company - Fort Meade, and Florida Public Utilities Company - Indiantown Division.
[26] Response No. 4.a in Staff’s 13th Data Request, Document No. 09977-2024.
[27] MFR Schedule C-33, Page 177, line 15, Document No. 08594-2024.
[28] Attachment 11.1, response to Staff’s 11th Data Request, Document No. 09904-2024.
[29] Direct testimony of Michelle Napier, page 20, Document No. 08583-2024.
[30] There were 138 customer contacts transferred directly to FPUC via the Commission’s Transfer-Connect (Warm-Transfer) System. This system allows the Commission to directly transfer a customer to FPUC’s customer service personnel for resolution.
[31] Response No. 1 in Staff’s Tenth Data Request, Document No. 09893-2024.
[32] Response No. 1 in Staff’s Twenty Ninth Data Request, Document No. 00414-2025.
[33] Response No. 2 in Staff’s Twenty Seventh Data Request, Document No. 00339-2025.
[34] Response No. 3 in Staff’s Twenty Ninth Data Request, Document No. 00414-2025 and Document No. 00652-2025, filed February 3, 2025, in Docket No. 20240099-EI.
[35] Document No. 00905-2025, filed February 10, 2025, in Docket No. 20240099-EI.
[36] Response No. 1 in Staff’s Sixth Data Request, Document No. 09794-2024.
[37] Response No. 4 in Staff’s Twentieth Data Request, Document No. 00017-2025.
[38] Document No. 00396-2025.
[39] Response No. 1 in Staff’s Sixth Data Request, Document No. 09794-2024.
[40] Document No. 08593-2024.
[41] Document No. 09266-2024.
[42] Id.
[43] Response No. 1 in Staff’s Sixth Data Request, Document No. 09794-2024.
[44] Response No. 10 in Staff’s Twentieth Data Request, Document No. 00017-2025.
[45] FPUC is also proposing a related program, the Distribution and Connectivity Automation program, as part of its proposed storm protection plan in Docket No. 20250017-EI. This program consists of the assessment of feeder lines for the installation of feeder ties and additional self-healing equipment beginning in 2028, which when combined with the proposed fault detection equipment would allow automated fault detection and restoration processes.
[46] Response No. 10 in Staff’s Twentieth Data Request, Document No. 00017-2025.
[47] Response No. 25 in Staff’s Sixth Data Request, Document No. 09794-2024.
[48] Response No. 11 in Staff’s Sixth Data Request, Document No. 09794-2024.
[49] Id.
[50] Response No. 4 in Staff’s Tenth Data Request, Document No. 09893-2024.
[51] Response No. 4 in Staff’s Tenth Data Request, Document No. 09893-2024.
[52] Response No. 4 in Staff’s Tenth Data Request, Document No. 09893-2024.
[53] Witness Haffecke Direct Testimony, Page 15, Lines 13-16, Document No. 08582-2024.
[54] Document No. 00570-2025, filed January 30, 2025, in Docket No. 20240099-EI.
[55] Witness Haffecke Direct Testimony, Page 16, Lines 1-5, Document No. 08582-2024.
[56] Response No. 1 in Staff’s 23rd Data Request, Document No. 10388-2024.
[57] Response No. 2 in Staff’s Tenth Data Request, Document No. 09893-2024.
[58] Witness Gadgil Direct Testimony, Page 8, Lines 8-22, Document No. 08588-2024.
[59] Response No. 4 in Staff’s Tenth Data Request, Document No. 09893-2024.
[60] Order No. PSC-2008-0327-FOF-EI, issued on May 19, 2008, in Docket No. 20070300-EI, In re: Review of 2007 Electric Infrastructure Storm Hardening Plan filed pursuant to Rule 25-6.0342, F.A.C., submitted by Florida Public Utilities Company; and Docket No. 20070304-EI, In re: Petition for rate increase by Florida Public Utilities Company.
[61] Response No. 1 in Staff’s Sixteenth Data Request, Document No. 10111-2024.
[62] Witness Napier Direct Testimony, Page 11, Lines 2-4, Document No. 08583-2024.
[63] Witness Haffecke Direct Testimony, Page 12, Lines 5-6. Document No. 08582-2024.
[64] Document No. 08593-2024.
[65] Document No. 09739-2024.
[66] Document No. 00570-2025.
[67] Response No. 2 in Staff’s Sixteenth Data Request, Document No. 10111-2024, Document No. 10111-2024.
[68] Document No. 08593-2024.
[69] Document No. 08596-2024.
[70] Document No. 10324-2024.
[71] Document No. 08594-2024.
[72] Document No. 08596-2024.
[73] Id.
[74] Document No. 10367-2024.
[75] Order No. PSC-2023-0388-FOF-GU, issued December 27, 2023, in Docket No. 20230023-GU, In re: Petition for rate increase by Peoples Gas System, Inc., and Order No. PSC-2025-0038-FOF-EI, issued February 3, 2025, in Docket No. 20240026-EI, In re: Petition for rate increase by Tampa Electric Company.
[76] Blue Chip Financial Forecasts, Vol. 44, No. 2, issued January 31, 2025.
[77] Order No. PSC-2014-0517-S-EI, issued September 29, 2014, in Docket No. 20140025-EI, In re: Application for rate increase by Florida Public Utilities Company.
[78] Order No. PSC-2023-0103-FOF-GU, issued March 15, 2023, in Docket No. 20220067-GU, In re: Petition for rate increase by Florida Public Utilities Company, Florida Division of Chesapeake Utilities Corporation, Florida Public Utilities Company - Fort Meade, and Florida Public Utilities Company - Indiantown Division.
[79] Order No. 2014-0517-S-EI, issued September 29, 2014, in Docket No. 20140025-EI, In re: Application for rate increase by Florida Public Utilities Company.
[80] Bluefield Water Works and Improvement Co. v. Public Service Comm’n, 262 U.S. 679, 692 (1923) (Bluefield) and Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944) (Hope)
[81] Market Capitalization is the stock price multiplied by the number of shares of common stock outstanding.
[82] ALLETE, Inc., Alliant Energy Corporation, Black Hills, Centerpoint Energy, Inc., Evergy, Inc., Hawaiian Electric Industries, Inc., IDA CORP, Inc., MGE Energy, Inc., Northwestern Energy Group, OGE Energy Corp., Otter Tail Corporation, Pinnacle West Capital Corporation, PNM Resources, Inc. Portland General Electric Company, Unitil Corporation.
[83] Atmos Energy Corporation, Chesapeake Utilities Corporation, New Jersey Resources Corporation, Northwest Natural Holding Company, ONE Gas, Inc., Southwest Gas Holdings, Inc.
[84] Document No. 10367-2024, FPUC’s Responses to Staff’s 19th Data Request, No. 17.
[85] Id.
[86] Id.
[87] Id.
[88] John Wiley & Sons, Inc., Ingredion, Kinross Gold Corp., HNI Corporation, Kaman Corporation, Smith & Wesson Brands, Inc., Entravision Communications Corporation, Luxfer Holdings, PLC, Natural Grocers by Vitamin Cottage, Inc., Adams Resources & Energy, Inc., Life Vantage Corporation, Sonoco Products, Sensient Technologies.
[89] FPUC’s Recommended ROE range does not equal the average of the values in the Low and High columns due to his method of finding the central tendency using a standard deviation calculation.
[90] FPUC response to Staff’s 19th Set of Data Requests, No. 14, attached file “DR 19.14 Work Papers”, COE Summary Tab.
[91] Document No. 00338-2025, p. 3.
[92] Security Analysis for Investment and Corporate Finance, Chapter 11, Aswath Damodaran.
[93] Northwestern Energy Corp, and Unitil Corporation.
[94] Blue Chip Financial Forecasts, Vol. 44, No. 2, January 31, 2025.
[95] Document No. 10367-2024, p 15-16. The average of three surveys for the years 2024 and 2025: the Livingston Survey conducted by the Federal Reserve Bank of Philadelphia, the Survey of Consumer Expectations by the University of Michigan, and the Survey of Professional Forecasters also conducted by the Federal Reserve Bank of Philadelphia.
[96] Order No. PSC-2024-0165-PAA-WS, issued May 22, 2024, in Docket No. 20240006-WS, In re: Water and wastewater industry annual reestablishment of authorized range of return on common equity for water and wastewater utilities pursuant to Section 367.081(4)(f), F.S.
[97] The Laubach-Williams model provides estimates of the natural rate of interest, or r-star, and related variables. This approach defines r-star as the real short-term interest rate expected to prevail when an economy is at full strength and inflation is stable.
[98] FPUC witness Russel testified that Chesapeake Utilities Corporation has a credit rating of NAIC-2B which is equivalent to an S&P credit rating of BBB, p. 5.
[99] Order No. PSC-2023-0388-FOF-GU, issued December 27, 2023, in Docket No. 20230023-GU, In re: Petition for rate increase by Peoples Gas System, Inc., and Order No. PSC-2025-0038-FOF-EI, issued February 3, 2025, in Docket No. 20240026-EI, In re: Petition for rate increase by Tampa Electric Company.
[100] Regulatory Research Associates Focus, Major energy rate case decisions in the US January-December 2024, issued February 4, 2025.
[101] Id.
[102] Regulatory Research Associates Focus Notes, issued January 13, 2025, p. 24, Order No. PSC-2025-0038-FOF-EI, issued February 3, 2025, in Docket No. 20240026-EI, In re: Petition for rate increase by Tampa Electric Company.
[103] Order No. PSC-2018-0104-PCO-PU, issued February 26, 2018, in Docket No. 20180013-PU, In re: Petition to establish generic docket to investigate and adjust rates for 2018 tax savings, by Office of Public Counsel, and Order No. PSC-2017-0488-PAA-EI, issued December 26, 2017, In re: Petition for limited proceeding to include reliability and modernization projects in rate base, by Florida Public Utilities Company.
[104] FPUC Responses to Staff’s Fourth Data Request, Document No. 09690-2024.
[105] Direct Testimony of Michelle Napier, Page 15, Lines 18-22, Document No. 08583-2024.
[106] Response No. 27 in Staff’s Sixth Data Request, Document No. 09794-2024.
[107] Order No. PSC-08-0327-FOF-EI, issued May 19, 2008, in Docket No. 070304-EI, In re: Petition for rate increase by Florida Public Utilities Company and Order No. PSC-2019-0114-FOF-EI, issued March 26, 2019, in Docket No. 20180061-EI, In re: Petition for limited proceeding to recover incremental storm restoration costs, by Florida Public Utilities Company.
[108] FPUC Responses to Staff’s First Data Request, Document No. 09266-2024.
[109] Document No. 08594-2024.
[110] FPUC Responses to Staff’s Twenty Second Data Request, Document No. 00016-2025.
[111] Document No. 08594-2024.
[112] Direct Testimony of Michael Galtman, Document No. 08584-2024.
[113] FPUC Responses to Staff’s First Data Request, Document No. 09266-2024.
[114] Witness Devon Direct Testimony, Page 16, Lines 1-4, Document No. 08589-2024.
[115] Response No. 13 in Staff’s Nineteenth Set of Data Requests, Document No. 10367-2024.
[116] Response No. 12 in Staff’s Eleventh Set of Data Requests, Document No. 09904-2024.
[117] Document No. 08594-2024.
[118] Response No. 23 in Staff’s Sixth Data Request, Document No. 09794-2024.
[119] Response No. 1A in Staff’s Fifteenth Data Request, Document No. 10110-2024.
[120] Document No. 08594-2024.
[121] Response No. 1A in Staff’s Fifteenth Set of Data Requests, Document No. 10110-2024.
[122] Document No. 08594-2024.
[123] Order No. PSC-2023-0384-PAA-EI, issued December 21, 2023, in Docket No. 20230079-EI, In re: Petition for approval of 2023 depreciation study by Florida Public Utilities.
[124] Document No. 09739-2024.
[125] Id.
[126] Document No. 10111-2024.
[127] Document No. 08594-2024.
[128] Response No. 5 in Staff’s Nineteenth Data Request, Document No. 10367-2024.
[129] Document No. 08594-2024.
[130] Document No. 09841-2024.
[131] Document No. 08594-2024.
[132] Document No. 08594-2024.
[133] Document No. 08592-2024.
[134] Response No. 12 to Staff’s Third Data Request, Document No. 09593-2024.
[135] Response No. 1 to Staff’s Twenty Fourth Data Request, Document No. 00202-2025.
[136] Response 3 in Staff’s Twelfth Data Request, Document No. 09906-2024 and Exhibit WH-4 in witness Haffecke’s direct testimony.
[137] Response No. 8 to Staff’s Third Data Request, Document No. 09593-2024.
[138]
Order No. PSC-2019-0432-TRF-EI, issued October 22, 2019, in Docket No.
20190132-EI, In re: Petition for
authority for approval of non-firm energy pilot program and tariff by Florida
Public Utilities Company.
[139] Order No. PSC-2022-0064-TRF-EI, issued February 18, 2022, in Docket No. 20210180-EI, In re: Petition for authority to reinstate the non-firm energy program and tariff, Florida Public Utilities Company.
[140] Response No. 6 in Staff’s Eighth Data Request, Document No. 09790-2024.
[141] Response No. 1 in Staff’s Third Data Request, Document No. 09593-2024.
[142] Response No. 3 in Staff’s Eighth Data Request, Document No. 09790-2024.
[143] Response Nos. 8 & 10 in Staff’s Eighth Data Request, Document No. 09790-2024.
[144] Response No. 5 in Staff’s Eighth Data Request, Document No. 09790-2024.
[145] Witness Gadgil Direct Testimony, Page 16, Lines 5-6, document No. 08588-2024.
[146] Response No. 3 in Staff’s Eighteenth Data Request, Document No. 10281-2024.
[147] Response No. 4 in Staff’s Third Data Request, Document No. 09593-2024.
[148]
Order No. PSC-12-0490-TRF-GU, Issued September 24, 2012, in Docket No.
20120036-GU, In re: Joint petition for
approval of Gas Reliability Infrastructure Program (GRIP) by Florida Public
Utilities Company and the Florida Division of Chesapeake Utilities Corporation.
[149]
Order No. PSC-15-0390-TRF-GU, issued on September 15, 2015, in Docket No.
20150116-GU, In re: Petition for approval
of safety, access, and facility enhancement program and associated cost
recovery methodology, by Florida City Gas.
[150] Order No. PSC-2023-0235-PAA-GU, issued August 15, 2023, in Docket No. 20230029-GU, In re: Petition for approval of gas utility access and replacement directive, by Florida Public Utilities Company.
[151]
Order No. PSC-2021-0206-FOF-WS, issued June 4, 2021, in Docket No. 20200139-WS,
In re: Application for increase in water
and wastewater rates Charlotte, Highlands, Lake, Lee, Marion, Orange, Pasco,
Pinellas, Polk, and Seminole Counties, by Utilities, Inc. of Florida.
[152] See page 22 of Document No. 08582-2024.
[153] Responses to Staff’s Thirtieth Data Request, Response No. 1, Document No. 00394-2025.
[154] Responses to Staff’s Thirtieth Data Request, Response No. 4, Document No. 00394-2025.
[155] Id.
[156] Order No. PSC-2020-0347-AS-EI, issued October 8, 2020, in Docket No. 20190156-EI, In re: Petition for a limited proceeding to recover incremental storm restoration costs, capital costs, revenue reduction for permanently lost customers, and regulatory assets related to Hurricane Michael.
[157] Responses to Staff’s Thirtieth Data Request, Response No. 3, Document No. 00394-2025.
[158] See pages 22 and 23 of Document No. 08582-2024.
[159] Order No. PSC-2024-0441-PCO-EI, issued October 14, 2024, in Docket No. 20240099-EI, In re: Petition for rate increase by Florida Public Utilities Company.
[160] Order No. PSC-14-0517-S-EI, issued September 29, 2014, in Docket No. 20140025-EI, In re: Application for rate increase by Florida Public Utilities Company.