Order No. PSC-2023-0177-FOF-GU•Florida Public Service Commission native order document 03568-2023
Florida Public Service Commission native order document 03568-2023
Order No. PSC-2023-0177-FOF-GUFlapubserv
Gesamter Gesetzestext
FILED 6/9/2023
DOCUMENT NO. 03568-2023
FPSC - COMMISSION CLERK
BEFORE THE FLORIDA PUBLIC SERVICE COMMISSION
In re: Petition for rate increase by Florida City
Gas.
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DOCKET NO. 20220069-GU
ORDER NO. PSC-2023-01 77-FOF-GU
ISSUED: June 9, 2023
The following Commissioners participated in the disposition of this matter:
APPEARANCES:
ANDREW GILES FAY , Chairman
MIKE LAROSA
GABRIELLA P ASSIDOMO
CHRISTOPHER T. WRIGHT and JOEL T. BAKER, ESQUIRES, Florida Power
& Light Company, 700 Universe Boulevard, Juno Beach, FL 33408-0420
BETH KEATING, ESQUIRE, Gunster, Yoakley & Stewart, P.A., 215 South
Monroe St., Suite 601, Tallahassee, FL 32301-1804
On behalf of Florida City Gas {FCG).
MARY A. WESSLING and CHARLES REHWINKEL, ESQUIRES, Office of
Public Counsel, c/o The Florida Legislature, 111 West Madison Street, Room
812, Tallahassee, Florida 32399-1400
On behalf of the Citizens of the State of Florida (OPC).
MARCUS DUFFY, CAPT, USAF, HOLLY L. BUCHANAN, MAJOR, USAF,
and THOMAS A. JERNIGAN, ESQUIRES, AF/JAOE-ULFSC, 139 Barnes
Drive, Suite 1, Tyndall Air Force Base, FL 32403
On behalf of Federal Executive Agencies (FEA).
JON C. MOYLE, JR. and KAREN PUTNAL, ESQUIRES, Moyle Law Firm,
P.A., 118 North Gadsden Street, Tallahassee, Florida 32312
On behalf of Florida Industrial Power Users Group (FIPUG).
ADRIA HARPER and TIMOTHY SPARKS, ESQUIRES, Florida Public Service
Commission, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850
On behalf of the Florida Public Service Commission (StafO.
MARY ANNE HELTON, ESQUIRE, Deputy General Counsel, Florida Public
Service Commission, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399
Advisor to the Florida Public Service Commission.
KEITH C. HETRICK, ESQUIRE, General Counsel, Florida Public Service
Commission, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850
Florida Public Service Commission General Counsel.ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 2 ORDER GRANTING IN PART AND DENYING IN PART FLORIDA CITY GAS’ PETITION FOR CERTAIN RATE INCREASES BY THE COMMISSION: Table of Contents Background ............................................................................................................................4 I. Rate Plan Duration Four-year Rate Plan ...............................................................................................................5 II. Test Period and Forecasting Projected Test Year ................................................................................................................7 Customer and Therm Forecasts .............................................................................................8 Estimated Gas Revenues ........................................................................................................9 III. Quality of Service Quality of Service ..................................................................................................................10 IV. Depreciation Depreciation Parameters ........................................................................................................11 Resulting Reserve Imbalances ...............................................................................................14 Corrective Depreciation Measures – RSAM .........................................................................15 Implementation Date for Revised Depreciation Rates...........................................................17 V. Rate Base Adjustments to Reflect SAFE Investments............................................................................18 Advanced Metering Infrastructure (AMI) Pilot .....................................................................18 Plant in Service for LNG Facility ..........................................................................................20 Plant in Service ......................................................................................................................24 Non-Utility Activities ............................................................................................................26 Acquisition Adjustment .........................................................................................................26 Construction Work in Progress (CWIP) ................................................................................27 Gas Plant Accumulated Depreciation and Amortization .......................................................27 Under-Recoveries and Over-Recoveries in Working Capital Allowance .............................28 Unamortized Rate Case Expense ...........................................................................................28 Deferred Pension ....................................................................................................................29 Unbilled Revenues .................................................................................................................30 Working Capital .....................................................................................................................30 Rate Base ...............................................................................................................................31 VI. Cost of Capital Accumulated Deferred Taxes ................................................................................................32 Short-Term Debt ....................................................................................................................33 Long-Term Debt ....................................................................................................................34 Customer Deposits .................................................................................................................36 Equity Ratio ...........................................................................................................................36 Return on Equity (ROE) ........................................................................................................39 Non-Utility Investments.........................................................................................................44 Weighted Average Cost of Capital (WACC).........................................................................44
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 3 VII. Net Operating Income Purchased Gas Adjustment and Natural Gas Conservation Cost Recovery ..........................46 SAFE Investments .................................................................................................................46 Outside Service Costs ............................................................................................................46 Miscellaneous Revenues ........................................................................................................47 Total Operating Revenues for the Projected Test Year .........................................................48 Non-Utility Activities ............................................................................................................48 Salaries and Benefits ..............................................................................................................49 Affiliate Expenses ..................................................................................................................51 Pensions and Post-Retirement Benefits Expenses .................................................................52 Injuries and Damages Expense ..............................................................................................53 Insurance Expense .................................................................................................................54 Projected Contractor Cost ......................................................................................................55 O&M Expenses Adjustment ..................................................................................................55 Storm Damage Reserve..........................................................................................................56 Parent Debt Adjustment (PDA) .............................................................................................57 Rate Case Expense .................................................................................................................58 Uncollectible Accounts and Bad Debt ...................................................................................59 O&M Expenses ......................................................................................................................60 Taxes Other Than Income (TOTI) .........................................................................................60 Test Year Income Tax Expense .............................................................................................61 Operating Expenses ...............................................................................................................62 Net Operating Income ............................................................................................................62 VIII. Revenue Requirements Revenue Expansion Factor and Net Operating Income Multiplier ........................................62 Annual Operating Revenue Increase .....................................................................................63 IX. Cost of Service and Rate Design Cost of Service Study (COSS) ...............................................................................................64 Revenue Increase Allocation ................................................................................................66 Proposed Customer Charges ..................................................................................................68 Distribution Charges ..............................................................................................................69 Demand Charges ....................................................................................................................69 Connect and Reconnection Charges ......................................................................................69 Transportation Customer Charge Application to Third Party Suppliers ...............................70 Effective Date for Revised Rates and Charges ......................................................................70 Approval of Tariffs Reflecting Approved Rates and Charges ...............................................70 X. Other Issues Proposal For Addressing A Potential Change In Tax Law ....................................................71 SAFE Program Expansion for Mains and Services ...............................................................72 SAFE Program Expansion for “Orange Pipe” .......................................................................72 Description of Adjustments ...................................................................................................73 Attachment 1 ..........................................................................................................................76 Attachment 2 ..........................................................................................................................77 Attachment 3 ..........................................................................................................................78 Attachment 4 ..........................................................................................................................80
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 4 Attachment 5 ..........................................................................................................................81 Attachment 6 ..........................................................................................................................82 Background On May 31, 2022, Florida City Gas (FCG or Company) filed a petition seeking the Florida Public Service Commission’s (Commission) approval of a rate increase and associated depreciation rates based on a projected test year ending December 31, 2023. FCG is a natural gas local distribution company providing sales and transportation of natural gas, and is a public utility subject to this Commission’s regulatory jurisdiction under Chapter 366, Florida Statutes (F.S.). As a subsidiary of Florida Power & Light Company (FPL), FCG currently serves approximately 116,000 residential, commercial, and industrial natural gas customers in Miami- Dade, Broward, St. Lucie, Indian River, Brevard, Palm Beach, Hendry, and Martin counties. Specifically, FCG’s request consists of: (a) an increase in base rates and charges sufficient to generate a total base revenue increase of $29.0 million based on a projected 2023 Test Year, which includes (i) an incremental base rate revenue requirement of $18.8 million, (ii) the revenue requirements for the previously approved Liquefied Natural Gas (LNG) Facility, and (iii) the reclassification of the Safety, Access, and Facility Enhancement (SAFE) program revenues from clause to base rates; (b) a 10.75 percent mid-point return on equity (ROE) and an equity ratio of 59.6 percent from investor sources for all regulatory purposes; (c) implementation of a reserve surplus amortization mechanism (RSAM), which is a critical and essential component of FCG’s four-year rate plan; (d) approval of RSAM-adjusted depreciation rates, which is necessary to support the RSAM and decreases the incremental revenue requirement by $2.7 million; (e) the continuation of the Storm Damage Reserve provision approved as part of FCG’s 2018 Settlement Agreement, as modified to reflect the Commission’s new storm rule for gas utilities; (f) a mechanism that will allow FCG to adjust base rates in the event tax laws change during or after the conclusion of this proceeding; (g) continuation and expansion of the existing SAFE program, which will allow FCG to further improve safe and reliable service to customers and the communities it serves; and (h) implementation of a new limited advanced metering infrastructure pilot program (AMI Pilot) that will enable FCG to explore the potential for AMI meters to provide enhanced service to FCG’s customers. FCG initially requested an increase of $29.0 million in additional annual revenues, but reduced its request to $28.3 million. Of that amount, $5.7 million is associated with the reclassification of the Company’s SAFE program revenues from surcharge to base rates and $3.8 million is related to the revenue requirements for the previously approved LNG Facility. Additionally, the remaining $18.8 million is necessary, according to FCG, for the Company to earn a fair return on its investment and to adopt the requested RSAM designed to manage earnings in order to mitigate the need for rate relief during the next four years. FCG based its request on a 13-month average rate base of $489 million for the projected test year ending December 31, 2023. The requested overall rate of return is 7.09 percent based on a mid-point of 10.75 percent return on equity.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 5 The Company’s last rate case was filed on October 23, 2017, and was resolved by the Commission’s approval of a settlement agreement in 2018 (2018 Settlement Agreement). 1 The Commission-approved settlement agreement provided the opportunity for FCG to increase its base rates and charges to generate an additional $11.5 million in revenues for the projected test year ending December 31, 2018. The settlement agreement also authorized a return on equity of 10.19 percent. We acknowledged intervention by the Office of Public Counsel (OPC), and intervention was granted to the Federal Executive Agencies (FEA) and to the Florida Industrial Power Users Group (FIPUG) (collectively “Intervenors”). In a previous order, we suspended the proposed permanent increase in rates and charges. Three virtual and two in-person customer service hearings were held in September of 2022. A total of thirteen customers participated at the virtual service hearings and four customers spoke at the in-person service hearings, and all spoke favorably of FCG’s quality of service, with some also expressing concerns regarding a rate increase. The Commission received letters from six customers that were placed in the docket. All of the customers urged the Commission not to increase their gas rates during these financially challenging times, and one customer commented on the poor customer service that they had experienced. An administrative hearing was held December 12-13, 2022. At the hearing, we approved proposed stipulations on a number of issues, as reflected herein. The parties filed post-hearing briefs which argued their positions on the issues litigated at the administrative hearing. After the parties filed their briefs, we held Special Agenda Conferences on March 28 and April 25, 2023 to address those issues. The Commission has jurisdiction over this matter pursuant to Chapter 366, F.S., including Sections 366.041, 366.06, and 366.071, F.S. Decision I. Rate Plan Duration A. Four-year Rate Plan 1. Parties’ Arguments FCG argued that its requested four-year rate plan would provide rate stability and benefits to customers that would not be available with a single-year rate plan. FCG argued that disapproval of the Company’s proposed four-year rate plan would cost customers more. Additionally, FCG argued that if we approved the four-year plan, our final Order would be both binding and enforceable against all parties to this docket, and thus FCG would be obligated to comply with the requirements and limitations of the four-year plan. 1 Order No. PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate increase by Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 6 OPC argued that, absent a settlement agreement, this Commission does not have authority or precedent for approving a provision requiring a utility to “stay out” of base rate proceedings before this Commission for a set period of time; therefore, it should not approve FCG’s requested four-year rate plan. OPC argued that absent a settlement agreement, this Commission must review each request and determine whether it will result in fair, just, and reasonable rates. OPC also argued that we would have no enforceable way to prevent FCG from requesting a new rate case before the “stay-out” period ended. OPC cited Order No. PSC-2021-0446-S-EI, where a “stay-out” provision was an issue in the proceeding; however, the case was ultimately resolved with a settlement agreement and a ruling by this Commission on the propriety of the provision was never made. OPC also argued that when questioned at the hearing, FCG appeared to waver in its commitment not to request another rate increase for four years, specifically given factors such as inflationary pressures. FIPUG adopted the position of OPC. 2. Analysis Although a significant portion of FCG’s rate plan was FCG’s stated commitment to not request another general base rate increase effective prior to January 1, 2027, FCG acknowledged that, if the rate plan was approved, this Commission would have full regulatory oversight of rates and charges and the Company would continue to provide earnings surveillance reports as required. We agree with OPC that regardless of any assurances to the contrary, FCG cannot guarantee it would not seek a base rate increase before 2026. To ensure fair, just, and reasonable rates are charged, section 366.06(2), F.S., provides that if a utility’s rates are insufficient to yield reasonable compensation, it may request a proceeding in order for the Commission to determine just and reasonable rates. On the other hand, if we find that rates are excessive, the Commission can initiate a proceeding upon a request from an affected person or on its own motion to determine just and reasonable rates. 3. Conclusion Section 366.06(2), F.S., states that if a utility’s rates are insufficient to yield reasonable compensation it may request a proceeding in order for the Commission to determine just and reasonable rates. Likewise, if we find that rates are excessive, we can initiate a proceeding to determine just and reasonable rates. Accordingly, while we have resolved base rate cases in previous years that include multi-year increases to rates, and in settlement agreements we have approved “stay-out” provisions, we continue to recognize our obligation to monitor utility earnings and, if circumstances warrant, require additional proceedings. For these reasons, we acknowledge FCG’s commitment while also noting that approval of FCG’s plan, either in part or its entirety, would not prohibit future proceedings on these matters over the next four years. Thus, this Order addresses whether there is record evidence to support the other elements of FCG’s proposal, including the single incremental base revenue increase, requested ROE and equity ratio, cost of service, an RSAM, the SAFE program, the AMI Pilot program, potential tax law changes, and the Storm Damage Reserve.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 7 II. Test Period and Forecasting A. Projected Test Year 1. Parties’ Arguments FCG witness Campbell argued that the 2023 projected test year used by the Company, based on the 12-month period ending December 31, 2023, best reflects the Company’s revenues, costs, and investments during the year in which new rates are proposed to go into effect. The Company also proposed that new base rates become effective February 1, 2023, at a level “sufficient to recover the Company’s revenue requirements in 2023 with an opportunity to earn a fair and reasonable return.” OPC argued in its brief that FCG failed to meet the burden of demonstrating that the projected 2023 test year is appropriate as the Company has refused to demonstrate that there will be no merger activities that will affect the appropriateness of the test period. OPC further argued that its concerns about potential merger or sale activities are not merely “idle speculation,” citing the acquisition of FCG by NextEra Energy from Southern Company during the Company’s 2017 rate case. OPC continued that this acquisition was done during the 2017 rate case “without informing the Commission or parties to the case and settlement.” OPC stated that, although FCG witnesses Campbell and Fuentes have each denied that there are ongoing merger or sale activities that would affect rates, “neither witness could unequivocally state that they would be in a position to know under all circumstances.” 2. 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. OPC and FIPUG agree that the 2023 test year may be representative of the period of time in which rates will be in effect, with the caveat of “with appropriate adjustments” and “no imminent merger or sale activities.” However, OPC argued that the Company did not adequately demonstrate there will be no merger activities that will affect the appropriateness of the test year, and therefore, the test period ending December 31, 2023 is not appropriate for setting rates. FCG argued that the Intervenors’ concerns about potential merger activities are unsupported by the record and should be rejected, as there is “no evidence of any merger or sale activity, costs, or savings included in FCG’s 2023 Test Year.” 3. Conclusion We find that denying the use of a projected test year based solely upon the possibility of merger activities, as argued by the Intervenors, is not reasonable. With regard to the Intervenors’ assertion that “appropriate adjustments” be made to the 2023 test year, no Intervenors cited any specific adjustments or alternatives to the 2023 test year relating to this issue.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 8 We find that FCG’s proposed 2023 test year will result in a matching of the Company’s revenues to be produced, during the first twelve months in which the new rates would be in effect, with average rate base investment and average expenses for the same period. Therefore, we find the projected test period of the twelve months ending December 31, 2023, is appropriate. B. Customer and Therm Forecasts 1. Parties’ Arguments FCG witness Campbell testified that the Company’s customer and therm forecasts were developed using statistically sound econometric and regression models and included logically reasonable drivers obtained from leading industry experts. Witness Campbell further stated that the Company’s customer and therm forecasts were evaluated for reasonableness by comparing forecasted trends against historical trends and other growth factors. Witness Campbell argued that the forecasting approach used in this case is consistent with the criteria used by the Commission in previous proceedings.2 OPC argued that adjustments should be made with regard to the Company’s customer and therm forecasts, while noting that the forecasts typically become less reliable the further they are projected into the future. 2. Analysis In this case, FCG provided forecast models that detail the Company’s historical and forecasted customer counts and therm sales. FCG witness Campbell stated that the Company’s customer forecasts reflect the total number of active accounts served by FCG and include factors such as estimates of new service installations and changes in the number of inactive accounts, while the Company’s therm sales reflect the amount of natural gas provided to all customers served by FCG. The Company projected a customer count of approximately 117,487 and therm sales of approximately 173,612,198 for the 2023 test year. The Intervenors did not present testimony or evidence to disprove FCG’s test year forecast models or assumptions, and did not propose any adjustments to FCG’s forecasts of customers and therms for the projected test year. 2 In its brief, FCG cited: Order No. PSC-16-0032-FOF-EI, issued January 19, 2016, in Docket No. 20150196-EI, In re: Petition for determination of need for Okeechobee Clean Energy Center Unit 1, by Florida Power & Light Company; Order No. PSC-14-0590-FOF-EI, issued October 21, 2014, in Docket No. 20140111-EI, In re: Petition for determination of cost effective generation alternative to meet need prior to 2018, by Duke Energy Florida, Inc.; Order No. PSC-13- 0505-PAA-EI, issued October 28, 2013, in Docket No. 20130198-EI, In re: Petition for prudence determination regarding new pipeline system by Florida Power & Light Company; Order No. PSC-12-0179-FOF-EI, issued April 3, 2012, in Docket No. 20110138-EI, In re: Petition for increase in rates by Gulf Power Company; Order No. PSC-12- 0187-FOF-EI, issued April 9, 2012, in Docket No. 20110309-EI, In re: Petition to determine need for modernization of Port Everglades Plant, by Florida Power and Light Company; Order No. PSC-09-0375-PAA-GU, issued May 27, 2009, in Docket No. 20080366-GU, In re: Petition for rate increase by Florida Public Utilities Company.; Order No. PSC-04- 0128-PAA-GU, issued February 9, 2004, in Docket No. 20030569-GU, In re: Application for rate increase by City Gas Company of Florida.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 9 3. Conclusion Based on an analysis of FCG’s historical customer and usage data (2010-2021), year-to-date accuracy (2022), and year-over-year growth rates, we find the forecast models and assumptions utilized by FCG provide a reasonable estimate of the Company’s customer counts and therm sales, by rate class, for the 2023 test year. Therefore, we find the Company’s customer and therm sales forecasts for the projected test year are reasonable and appropriate, and no adjustments are necessary. C. Estimated Gas Revenues 1. Parties’ Arguments We next address whether FCG’s estimated revenues from sales of gas by rate class at present rates for the projected test year are appropriate. FCG argued that the same reasonable forecasting methodologies described in section II above were applied in developing its estimated revenues from sales of gas. The Company stated that these methodologies included statistically sound models and logically reasonable drivers obtained from leading industry experts. FCG argued that the record supports finding that the Company’s projected revenues from the sale of gas by rate class have been “calculated based upon reliable, robust, and accepted methods.” OPC noted that witness Campbell stated both that he did not forecast the impact of potential growth in customers on 2024 and 2025 revenues, but he estimated that this growth would result in approximately $200,000 in additional revenues per year. OPC also noted that witness Campbell said that the Company’s customer and therm forecasts typically become progressively less reliable the further they are projected into the future. 2. Analysis FCG provided forecast models which detail the Company’s forecasted customer counts and therm sales for the 2023 test year. Once FCG established these forecasts for the projected test year, the Company multiplied them by current rates for each customer class and combined those results to yield total revenues. The Company forecasted a total of $62,828,352 in revenues from sales of gas at present rates for the 2023 test year. There was an exception to the Company’s revenue forecast process for one customer class - Load Enhancement Service (LES). As detailed in MFR E-1, page 2 of 3, the forecasted revenues include a positive adjustment in the amount of $155,495 to reflect revenues associated with the LES rate class. FCG witness Debose testified that the LES customer class is an existing optional rate available to customers who can provide “verifiable documentation showing a viable alternative fuel or the opportunity to completely bypass FCG’s system.” In an effort to retain these customers on FCG’s system, the Company’s LES customers are eligible for a discounted, negotiated rate. The discount is recovered from the general body of ratepayers through the Competitive Rate Adjustment (CRA) rider. The Company explained that for the purposes of the revenue forecast, the LES customers were forecast at one hundred percent of their otherwise
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 10 applicable rate schedules. FCG argued that this approach “better aligns the revenues and costs incurred to provide service to the LES customers with the appropriate rate schedule, while recognizing that the difference between the revenues under the tariffed rate and the negotiated LES rate are recovered through the CRA.” We find this approach is reasonable for the purposes of estimating test year revenues for LES customers. 3. Conclusion We have confirmed that FCG used the correct current rates and billing determinants consistent with the Company’s forecasts for all customer classes in their calculations of test year revenue. We find that in all instances the revenue forecasts for all customer classes are reasonable. Furthermore, we note that the Intervenors did not present testimony or evidence to rebut FCG’s test year forecast of revenues from sales of gas at current rates. Thus, we find that FCG's estimated revenues from sales of gas by rate class at present rates for the projected test year, totaling $62,828,352, are reasonable and appropriate. This amount includes the Company-noted adjustment of $155,495 to reflect additional revenues associated with the Load Enhancement Service rate class. III. Quality of Service A. Quality of Service 1. Parties’ Arguments FCG argued that it provides safe, reliable, and high-quality service to customers and the communities it serves. The Company argued that none of the customers that participated at the service hearings expressed any negative views of FCG, and were instead complimentary of the Company and its employees. FCG asserted that it has taken steps since its last rate case to implement customer experiences and process improvements. OPC noted that at least one customer submitted a comment expressing dissatisfaction with the quality of service provided by FCG. 2. Analysis Pursuant to Section 366.041, 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. Pursuant to Rule 25-7.018, Florida Administrative Code (F.A.C.), each utility must keep a complete record of all interruptions affecting the lesser of 10 percent or 500 or more of its division meters. Based on FCG’s filing, there were no customer interruptions affecting either 10 percent or 500 meters during the historic test year. The Commission held three virtual service hearings on September 14 and 15, 2022, as well as two in-person service hearings within FCG’s service territory on September 20 and 21,
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 11 2022. These hearings provided an opportunity for FCG’s approximately 116,000 customers to raise concerns regarding the Company’s quality of service and its request for a rate increase. A total of thirteen customers participated at the virtual service hearings, all of whom spoke positively of the Company’s quality of service, although one customer also voiced opposition to the rate increase. Four customers spoke at the in-person service hearings, and all spoke favorably of FCG’s quality of service, while one customer also expressed concerns regarding the size of the rate increase. We also examined the complaints presented in staff witness Calhoun’s testimony and observed that the number of service complaints has continually decreased since 2018. Staff witness Calhoun testified that, from July 1, 2017, to June 30, 2022, 584 complaints were logged with the Commission with 489 of those being transferred to FCG. Of the complaints, approximately 52 percent concerned billing issues and approximately 48 percent involved quality of service issues. Additionally, witness Calhoun testified that four billing complaints and one service quality complaint appeared to demonstrate a violation of Commission Rules. FCG witness Howard testified that the customer comments made at the service hearings were complimentary of the Company and the large majority of the customer contacts received by the Commission were informational in nature. Only 87 of the customer contacts were logged as complaints, with 4 being possible rule violations. Witness Howard testified that efforts had been made since 2018 to update the customer complaint resolution process. These efforts included: (1) creating a process to handle more complex questions from customers that cannot be adequately answered on the initial call; (2) cataloguing and addressing common complaints expressed by customers; (3) identifying and incorporating best practices from FPL’s customer complaint process; (4) implementing a management review process for Commission complaints; (5) instituting a one-call resolution target for Warm-Transfers; and (6) establishing internal goals to reduce complaints. None of the intervenors took issue with FCG’s quality of service. 3. Conclusion Based on a review of all witness and customer testimony, we find that the Company’s quality of service is adequate. IV. Depreciation A. Depreciation Parameters Depreciation rates are calculated using parameters which include the Average Service Life (ASL), curve shape, the remaining life (in years), net salvage percentage, and reserve percentage. In order to arrive at the appropriate resulting depreciation rates, each parameter plays a part in the calculation. In the development of depreciation rates, the first parameter reviewed is the ASL, which denotes the average number of years that the asset is expected to be in-service. While the ASL may be based, at least in part, on historical data, it is prospective in its outlook and
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 12 implementation. Iowa curves are used to determine the remaining life of a particular type of asset by graphically representing the retirement patterns of utility assets. These are well-established depreciation tools. Each curve is denoted by a letter that defines when retirements are more likely to occur. An L curve implies that retirements tend to occur prior to the ASL, while an R curve implies that retirements tend to occur after the ASL. The next parameter is the average remaining life, which is the average number of in- service years left for plant currently in service. FCG presented evidence that “service life estimates in any given depreciation study are, by their nature, estimates of what is expected to occur in the future based on information available at the time of the study.” The third parameter for determining depreciation rates, net salvage, is gross salvage minus cost of removal. Net salvage is based on historical data but is also prospective in outlook. The last parameter needed for calculating depreciation rates is the reserve percentage which represents the portion of the investment accumulated through depreciation expense to date. The reserve percentage is calculated by dividing the book reserve by the original cost of plant. Three proposals were put forward to calculate depreciation rates for each distribution and general plant account: FCG’s traditional 2022 Depreciation Study (2022 Study), OPC’s adjustments to FCG’s 2022 Study, and FCG’s Reserve Surplus Amortization Mechanism (RSAM) adjusted parameters. Each scenario proposed slightly different estimates for service lives and other depreciation parameters across various accounts. 1. Parties’ Arguments While FCG performed a traditional depreciation study as presented by Witness Allis, the Company also advocated for the use of its RSAM-adjusted parameters. FCG argued that the RSAM-adjusted parameters are the appropriate ones to use in conjunction with FCG’s proposed RSAM because they are reasonable and they are the same as those approved through a settlement agreement in Peoples Gas System’s most recent base rate case, with the exception of FCG’s LNG Facility. Furthermore, FCG argued that the RSAM-adjusted parameters are very similar to the ones OPC witness Garrett has proposed in this and similar cases. OPC argued in favor of its own method of calculating depreciation rates, stating that OPC witness Garrett developed his recommended depreciation rates using “the straight-line method, the average life procedure, the remaining life technique, and the broad group model.” OPC witness Garrett used FCG’s aged property data to develop an “observed life table” (OLT), which was then compared to survivor curves. OPC asserted that if all of witness Garrett’s proposed depreciation adjustments were applied to the 2022 Study, projected test year depreciation expense would be reduced by $1,543,130 and projected test year accumulated depreciation would be reduced by $771,565 when compared to witness Allis’ 2022 Study parameters. OPC argued the adjustments to FCG witness Allis’ depreciation parameters, as offered by witness Garrett, should be adopted in this case, and that the remaining life technique should be used to address any resulting reserve
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 13 imbalance. OPC also opposed FCG’s use of the RSAM-adjusted parameters, arguing the Commission lacked the authority to implement the RSAM outside of a settlement agreement. 2. Analysis FCG presented testimony that both the traditional 2022 depreciation study and the RSAM adjusted parameters fell within a “range of reasonableness” when compared to the depreciation studies of other gas utilities. There was also testimony that the traditional 2022 Study parameters and OPC’s proposed depreciation parameters would not result in a large enough reserve for the RSAM to function properly. FCG also offered testimony that depreciation parameters are only estimates of what may occur in the future and therefore it is inevitable that those estimates will result in surpluses and deficits, and thus the RSAM parameters were reasonable. FCG asserted the Commission’s depreciation rule, which requires gas utilities to file a depreciation study every five years, recognizes and accounts for this variability. In support of its RSAM, FCG also offered evidence that the National Association of Regulatory Utility Commissioners (NARUC) states that the true depreciation parameters only become known “after the plant has lived its entire useful life.”3 Additionally, FCG asserted the RSAM-adjusted depreciation parameters are a reasonable alternative given that they are based on a similar utility in the same geographic location with similar assets. FCG witness Campbell stated that the assets and facilities on FCG’s system are similar to the assets used by Peoples Gas System, and are located in similar geographic regions, making the RSAM parameters a reasonable alternative to the depreciation study. Witness Campbell further testified that the RSAM-adjusted parameters themselves are similar to those offered by OPC witness Garrett in this case, arguing this further supports their reasonableness. 3. Conclusion FCG witness Campbell presented credible testimony and we find the appropriate depreciation parameters in this case are the RSAM-adjusted parameters proposed by FCG. Accordingly, we find that the appropriate depreciation parameters and resulting depreciation rates for each distribution and general plant account are those shown on Table 1 below. As a result, the appropriate amount of Depreciation and Amortization Expense for the projected test year is $17,316,573. The resulting reserve imbalance is discussed more fully in the next section. 3 National Association of Regulatory Commissioners Public Utility Depreciation Practices, p. 189
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 14 Table 1 Depreciation Parameters Account Number Account Title Curve Type Average Service Life (yrs) Average Remaining Life (yrs) Reserve (%) Future Net Salvage (%) Remaining Life Rate (%) DISTRIBUTION PLANT 375 Structures & Improvements L0 33 31.00 9.07 0 3.8 376.1 Mains - Steel R1.5 65 50.32 51.42 (50) 2.0 376.2 Mains - Plastic R2 75 65.88 28.33 (33) 1.6 378 Measuring & Regulating Equip. - General R1.5 40 36.88 13.64 (10) 2.6 379 Measuring & Regulating Equip. - City Gate R2.5 50 40.64 28.40 (10) 2.0 380.1 Services - Steel R0.5 52 32.15 89.49 (125) 2.5 380.2 Services - Plastic R1.5 55 46.56 25.68 (68) 3.1 381 Meter R2 19 12.43 30.11 3 6.9 381.1 Meters - ERT R2 19 14.42 21.22 3 9.7 382 Meter Installations R1 44 34.95 28.53 (25) 3.6 382.1 Meter Installations - ERT R1 44 36.23 33.08 (25) 10.3 383 House Regulators S1 42 33.08 24.92 0 2.3 384 House Regulators Installations R1 47 34.93 5.16 (25) 3.4 385 Industrial Measuring & Reg. Station Equip R3 37 17.79 60.92 (2) 2.3 387 OTHER EQUIPMENT L2 24 18.05 20.34 0 4.4 GENERAL PLANT 390 Structures & Improvements L0 25 20.23 18.27 0 4 392 Transportation Equipment L2 12 4.66 33.68 4 13.4 392.1 Transportation Equip. - Auto & Light Trucks L2.5 9 4.19 63.75 11 6.0 392.2 Transportation Equip. - Service Trucks L3 10 6.05 49.13 11 6.6 392.3 Transportation Equip. - Heavy Trucks L2 12 6.53 45.8 4 7.7 394.1 Natural Gas Vehicle Equipment S4 20 13.5 60.18 0 3.0 B. Resulting Reserve Imbalances 1. Parties’ Arguments FCG argued that the appropriate reserve imbalance based on the RSAM-adjusted depreciation rates would be $52.1 million. FCG explained that, under the RSAM scenario, $25 million would be available for the Company to amortize during the 2023-2026 timeframe. FCG contended that even with the $25 million Reserve Amount, FCG would still have to find cost savings to reach the proposed midpoint ROE. OPC witness Garrett testified that when a reserve imbalance exists, the remaining life technique should be used to address the imbalance over the remaining life of the assets. 2. Analysis and Conclusion The formula for the Theoretical Reserve, Book Investment – Future Accruals – Future Net Salvage, is provided in Rule 25-7.045(4)(k), F.A.C. FCG witness Allis also calculated a $50.8 million theoretical reserve surplus for FCG’s distribution accounts and a $1.3 million
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 15 reserve surplus related to its general plant accounts, based on FCG witness Fuentes’ proposed RSAM life and salvage parameters. We agree with witness Allis’ calculations. Using this formula and the values for the life and salvage components that we found above, we calculate a total reserve imbalance of $52,126,500, comprised of $50,813,200 in the Distribution account and $1,313,300 in the General account. C. Corrective Depreciation Measures - RSAM 1. Parties’ Arguments Because the approval of the RSAM parameters will result in a reserve imbalance, we next address what corrective measures should be taken with regard to that reserve imbalance. FCG asserted that its proposed RSAM is an appropriate and critical component of FCG’s proposed rate plan and in conjunction with the other components of the plan, the RSAM will enable FCG to avoid increasing base rates through at least the end of 2026. According to FCG, the expected benefits resulting from the RSAM will provide significant customer benefits and savings including a lower annual revenue requirement, avoiding repetitive and costly rate proceedings, providing customers with rate stability and certainty, and enabling FCG to focus on providing safe, reliable, and affordable service to its customers. Additionally FCG asserted that without the RSAM, it would fall below its proposed ROE range and would need to file an additional rate case in 2024 for a base rate increase in 2025. According to FCG, its RSAM-adjusted depreciation rates are based on the depreciation parameters recently agreed to and approved in the PGS base rate case in Docket No. 20200051- GU and therefore they represent a reasonable alternative to those contained in FCG’s 2022 Depreciation Study. FCG argued that these RSAM-adjusted depreciation parameters are within the range of reasonableness, and are in line with those approved for other similar natural gas utilities in Florida. FCG asserted that the evidence supports a finding that FCG’s proposed RSAM is fair, just, and reasonable and should therefore be approved. OPC argued that use of the RSAM, absent a settlement, is inconsistent with both Rule 25- 7.045, F.A.C., and the statutory requirement to set just and reasonable rates set forth in Chapter 366, F.S. OPC asserted that absent a stipulation of the parties, the Commission lacks the authority to approve an RSAM mechanism that can be utilized in conjunction with the surplus or Reserve Amount. OPC also argued that the proposed RSAM could be used to enhance shareholder earnings and maintain FCG’s earnings at the top of the authorized range, and asserted it would limit the Commission’s and other parties’ ability to review FCG’s rates in the future by creating a self-regulating mechanism. FEA also opposed the RSAM and reiterated OPC’s arguments that the proposed RSAM would be used to respond to changes in underlying revenues and expenses in order to maintain a set ROE. FEA argued that FCG’s proposed RSAM improperly shifts the risk of revenue recovery to customers, and allows FCG to adjust its depreciation expense leading to an artificially inflated rate base by distorting the accurate measurement of assets.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 16 FEA witness Collins also testified the proposed RSAM would lead to potential future costs to FCG customers and would be used to increase the Company’s earnings and its return. FIPUG joined the arguments of FEA. 2. Analysis We recognize that our approval of the RSAM depreciation parameters above will result in a reserve imbalance, which we will address here. Before we do so, we first acknowledge that OPC raised the issue of our statutory authority to approve an RSAM. We disagree with OPC that the Commission lacks authority to approve accounting mechanisms like the proposed RSAM unless it does so in a settlement agreement. Chapter 366, F.S., sets forth the Commission’s jurisdiction and authority to fix fair, just, and reasonable rates. The Commission’s jurisdiction and authority to fix fair, just, and reasonable rates pursuant to Chapter 366, F.S., are not conditioned upon whether the case is litigated or settled. While the standard of review differs in a settlement versus a litigated rate case, it does not change the Commission’s statutory authority or jurisdiction. In other words, a settlement, which operates under the public interest standard, cannot legally grant or change the Commission’s jurisdiction and authority; only the legislature can do that. To hold that the Commission can only approve an RSAM in a settlement but not in a litigated proceeding would mean that the parties to a settlement can somehow circumvent or expand the Commission’s legal jurisdiction and authority beyond what is granted by Chapter 366, F.S. We also recognize that there was competing testimony about whether the RSAM should be approved in this case and whether it will benefit customers. We are persuaded by the testimony that the RSAM would allow FCG to manage its day-to-day fluctuations as well as take on the risk of both actual current as well as potential future increases in interest rates and inflation. FCG proposes having a Reserve Surplus amount of $25 million available for managing these daily fluctuations in revenues and expenses, but FCG did not propose any treatment for the remaining reserve surplus of $27.1 million. Therefore, that remaining surplus would remain on FCG’s books and records until the Company files its next depreciation study. While there was testimony offered that the RSAM would shift risk to customers, FCG offered evidence that its rate plan with the RSAM would result in fair, just, and reasonable rates. By approving the proposed RSAM, we believe FCG is in the best position to maintain its ROE within the approved range and thus reduce the likelihood of additional rate increases in the near future. As we expressed at our Agenda Conference on April 25, 2023, we are mindful of today’s economy and the effects of inflation on customers and their utility bills. FCG offered testimony that adopting the proposal allows FCG to manage typical day-to-day fluctuations associated with running a utility business, while also having to absorb potentially higher costs resulting from inflation and rising interest rates. FCG also offered testimony that the use of the RSAM reduces the average residential bill by approximately $0.94 per month, the average commercial and industrial bill by approximately $5.15 per month, and the average GS-1 bill by approximately $465.83 per month.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 17 FCG’s evidence showed the RSAM will provide customer benefits including rate stability and certainty. There was also FCG testimony that by avoiding repetitive and costly rate proceedings, its rate proposal will save customers an approximate additional $2.0 million in rate case expense while still enabling the company to meet the natural gas needs of existing and new customers while continuing to provide safe, reliable, and high-quality customer service. 3. Conclusion We have the authority to approve an RSAM and accordingly approve FCG’s proposed use of the RSAM along with its Reserve Surplus of $25 million. We find the RSAM will result in a reduction of revenue requirement, save customers money on their utility bills, and give FCG the ability to manage its day-to-day business fluctuations, and allow FCG to take on the risk of increases in interest rates and inflation. FCG did not propose any treatment for the remaining reserve surplus of $27.1 million. Therefore, we find that the remaining surplus shall remain on FCG’s books and records until the Company files its next depreciation study. D. Implementation Date for Revised Depreciation Rates 1. Parties’ Arguments FCG witness Fuentes argued the implementation date for revised depreciation rates should be the effective date of the new base rates. FCG argued that this will be a matching of the new base rates with the new depreciation rates. FCG further argued that, without approval by the Commission for retroactive implementation, the implementation date for new depreciation rates should precede the Order approving such depreciation rates. OPC argued the revised rates should be effective January 1, 2023. 2. Analysis Rule 25-7.045(4)(d), F.A.C., requires that the data submitted in a depreciation study, including plant and reserve balances or Company estimates, “shall be brought to the effective date of the proposed rates.” Our staff confirmed that the plant and reserve balances were as of December 31, 2022, thus matching an implementation date of January 1, 2023. Furthermore, the Projected Test Year MFRs in this case were based on the period January 1, 2023, through December 31, 2023. FCG stated that the company filed its 2022 Study, along with the alternative RSAM-adjusted depreciation rates, direct testimony, and MFRs in compliance with Rule 25- 7.045, F.A.C. 3. Conclusion FCG provided depreciation study data extending through December 31, 2022 and did not provide study data for the month of January 2023. Therefore, in order to comport with Rule 25- 7.045(4)(d), F.A.C., (the Depreciation Rule), the implementation date of the new depreciation rates and amortization schedules shall be January 1, 2023, not February 1, 2023.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 18 V. Rate Base A. Adjustments to Reflect SAFE Investments There is no dispute about the adjustments to properly reflect SAFE investments. At hearing, we approved a stipulation whereby all parties agreed that $5.7 million of SAFE revenue requirements were appropriately transferred from clause recovery to base rates in the 2023 Test Year as required per our previous order.4 B. Advanced Metering Infrastructure (AMI) Pilot 1. Parties’ Arguments FCG is requesting a research and development pilot to evaluate Advanced Metering Infrastructure (AMI) with two-way communication capability. FCG attested that its proposed AMI Pilot will provide information on the potential benefits of deploying AMI with two-way communications system-wide. FCG argued that under the AMI Pilot, it will gather information on the benefits of automated remote readings, and the corrosion resistance and life of the 5,000 new smart meters to be installed under the pilot. FCG argues this is an appropriate sample size to determine benefits for the whole system while potentially reducing the costs. OPC argued that the Commission should not approve FCG’s proposed AMI Pilot because the benefits to customers are unknown, and because FCG did not attempt to estimate potential customer savings. In addition, OPC contended that FCG admitted that AMI technology has only been deployed by a small number of gas utilities in the country, and not at all in Florida. OPC asserted that by including this program in its rate request without any estimation of potential savings, FCG is attempting to recover costs for this program from customers imprudently. Therefore, OPC recommended that the Commission deny the AMI Pilot because FCG has not demonstrated the prudence of this program. 2. Analysis Pilot programs are typically vehicles through which utilities explore new technologies or processes so they can assess the benefits using a sample prior to system-wide implementation. In this case, FCG is planning to replace 5,000 meters under the AMI Pilot, which would provide a large enough sample to test the benefits of smart meters with AMI technology on FCG’s system without creating excessive costs, as this represents less than five percent of FCG’s customer meters. FCG argued in its brief that, as part of the pilot, FCG would collect data on the durability of the proposed smart meters, especially with regard to corrosion, and usage of two-way communications for central control of meter functions, such as remote connects and disconnects, and improved customer information on usage. The proposed pilot would be over a four-year period, with one year of installation and three years of operation, and consist of 5,000 smart 4 Order No. PSC-15-0390-TRF-GU in Docket No. 150116-GU.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 19 devices with related back-office technology support installed in the Brevard County area, where accelerated corrosion has been documented. After the conclusion of the pilot, FCG indicated in discovery it anticipates being able to report a summary of the findings, and provide sample reports with relevant information to the Commission. The estimated total cost of the AMI Pilot is $3.4 million in capital expenditures, with annual O&M expense estimated at $16,896, as corrected by FCG witness Howard. We find an adjustment of ($3,104) shall be made to the originally projected O&M expense for the AMI Pilot to reflect the corrected O&M expense identified in FCG witness Howard’s testimony. The Intervenors do not oppose the AMI Pilot, only its cost recovery, with OPC contending that the technology is both too new and intended to benefit shareholders, not customers. However, FCG maintained that the smart meters and AMI to be deployed are similar to the widely understood AMI technology that is used by electric utilities, and a small number of other gas utilities across the nation. OPC witness Schultz raised concerns due to the newness of the technology to the gas industry, and because FCG did not include estimated benefits in the filing, only the proposed costs. Witness Schultz therefore argued that the Commission should disallow the recovery of expenses for the pilot, which he suggested should be borne by the shareholders, as they may benefit from a potential sale of the Utility. Regarding the newness of the technology, FCG did not dispute that AMI technology, while common in the electric industry, has only been deployed by a limited number of gas utilities in the country, and not by any gas utilities in Florida. However, FCG witness Howard testified to the expected benefits associated with the AMI Pilot, which accrue to customers and the system itself, not shareholders, through improved functionality and potential cost reductions. In addition, FCG provided testimony that pilot projects enable a utility to test new technologies on a limited basis to determine if it would be beneficial to deploy these technologies system- wide, which is why FCG is proposing an AMI Pilot. We are persuaded by FCG’s testimony. We find that the newness of AMI technology to the gas industry, specifically in Florida, lends credibility to FCG’s proposal for a pilot program to allow this technology to be further evaluated prior to full scale implementation. Denying pilot programs with expected customer benefits and reasonable costs would discourage utilities from proposing pilot programs for the Commission’s consideration and negate opportunities for utilities to evaluate technologies that can enhance the service to and benefits for customers. Regarding OPC’s concern that FCG has not attempted to quantify benefits, the Utility has proposed the collection of data to quantify benefits through tasks such as remote meter reading, disconnection, and leak/outage detection, all of which should reduce related expenses. In addition, FCG indicated in discovery that after the conclusion of the pilot it anticipates being able to report a summary of the findings with regard to the project cost, meter installation, maintenance, and corrosion performance, and to provide sample reports including information such as customer daily usage, remote meter communication performance, and billing accuracy impacts.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 20 3. Conclusion Because FCG intends to gather information to determine the feasibility of AMI technology on its system and the appropriateness of system-wide deployment of this technology in the future, we find its potential to result in cost savings for the customers to be credible. For these reasons, we hereby approve the AMI Pilot. An adjustment of ($3,104) shall be made to the originally projected O&M expense provided for the AMI Pilot to reflect the corrected O&M expense identified in FCG witness Howard’s revised testimony. In addition, we order FCG to provide a final report with a summary of the findings described above to the Commission within 90 days of completion of the AMI Pilot. C. Plant in Service for Liquefied Natural Gas (LNG) Facility 1. Parties’ Arguments FCG contended that OPC waived its argument against the Liquefied Natural Gas (LNG) facility when OPC signed off on the 2018 Settlement Agreement. That agreement included provisions on both the need for and construction of the facility. FCG asserted that the Parties were aware that both the in-service date and costs were estimates, and that the terms of the agreement specifically envisioned some of this uncertainty, with rates going into effect at the in- service date of the unit. Although the 2018 agreement estimated $58 million in-service cost, FCG asserted its actual project costs for the total for the LNG facility is $68 million, with an in-service date of March 2023; therefore, only the incremental $10 million is at issue in this proceeding. FCG argued that no party disputed that the LNG facility is needed to serve customers, and OPC agreed to the need for this facility in the 2018 Settlement Agreement. FCG averred that despite its efforts to secure additional capacity, it has been unable to do so at a reasonable cost, and therefore, the LNG facility remains a necessary option to provide capacity during peak periods for the Miami-Dade County area. Although OPC acknowledged that some recovery of expenses associated with the LNG facility were allowed under the 2018 Settlement Agreement, OPC argued that it is unjust that customers have been paying for a facility that is not yet in-service. OPC expressed concerns that funds already received from customers could potentially result in customers overpaying for the LNG facility or otherwise could result in double recovery for the utility. Accordingly, OPC recommended that any funds that have been collected prematurely from ratepayers related to the LNG facility be accounted for in a regulatory liability and returned to ratepayers over five years. Regarding OPC’s implication of possible double recovery, FCG argued that its proposed base rate increase only includes the revenue requirements for the incremental $10 million for the LNG facility, and thus, is net of the $2.5 million in current rates associated with the LNG facility, and the previously approved increase of $3.8 million when the LNG facility enters service. Therefore, FCG asserted that there is no double recovery associated with the LNG facility.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 21 2. Analysis The LNG facility would provide 10,000 Dekatherms/day of pipeline capacity equivalent, and consists of three storage tanks holding 270,000 gallons of LNG and associated vaporization and delivery equipment. The LNG facility was originally proposed as part of FCG’s 2017 base rate proceeding, and was included in several terms of the 2018 Settlement Agreement.5 The 2018 Settlement Agreement determined that the LNG facility was needed to address the peak capacity concerns on FCG’s system in the Miami-Dade County area, and should be allowed in rate base. As part of the 2018 Settlement Agreement, a portion of the revenue requirement associated with the then estimated $58 million in-service cost was included, with a term allowing a base rate increase to recover the full estimated cost upon either the end of 2019 or the in-service date of the facility, whichever was later. Since the approval of the 2018 Settlement Agreement, the estimated in-service date has shifted to March 2023, with a total estimated in-service cost of $68 million. The primary cause of this shift is the loss of the originally proposed site as a viable location for the LNG facility, and the resulting in-service date delay. Due to being unable to acquire the necessary zoning and permitting approvals for the original site, FCG ultimately decided to sell the site and acquire a new site, which took additional time and delayed the in-service date. As part of this record, we reviewed the continued need for the LNG facility, the appropriate amount to include in rate base for the facility, in-service date concerns, and OPC’s refund and cost disallowance proposals, as discussed below. a. Need for the LNG Facility While we previously approved the need for the LNG facility under the 2018 Settlement Agreement, and no party has disputed the continued need for the facility, we have noted in a prior proceeding that prudent utility managers continually reassess the need for a project or facility as circumstances change.6 OPC did not take issue with the need for the LNG facility. Rather, it offered that FCG failed to properly and prudently plan the project and thus, the incremental costs of the LNG facility should be borne by the shareholders, not the customers. FCG provided testimony demonstrating that the LNG facility is fully permitted and was on schedule to begin LNG deliveries in January 2023 and meet its projected March 2023 in- service date and that the LNG is still needed. To further support the need of the LNG facility, FCG witness Howard testified that FCG needs additional interstate pipeline capacity to meet the needs of its Sales and Essential Use Transportation customers primarily in the Miami-Dade County area, and that there is currently a single source of FCG capacity in that area but that source has no additional incremental capacity available. FCG witness Howard argued that to 5 Order No. PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate increase and approval of depreciation study by Florida City Gas. 6 See Order No. PSC-12-0187-FOF-EI, issued April 9, 2012, in Docket No. 20110309-EI, In re: Petition to determine need for modernization of Port Everglades Plant, by Florida Power & Light Company.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 22 date, FCG has been unable to acquire any additional interstate capacity at terms and pricing that are acceptable and reasonable to serve customers in the area. In addition, FCG explained that there are no other existing alternatives to strengthen reliability at the southern-most portion of FCG’s system outside of the FGT pipeline. In addition, FCG witness Howard offered the following testimony to support the continued need for the LNG facility: Reliably serving customers at this portion of its system is becoming increasingly constrained due to customer growth in that area as shown by supporting documentation demonstrating the consumption increase in this area since 2018. The LNG facility will help address specific capacity shortages on its system. It would be prudent to add resiliency to ensure FCG can continue to provide safe and reliable service to customers located at the southern-most portion of its system. The LNG facility appears to be the only cost-effective alternative available and is necessary to help reinforce the southern-most portion of FCG’s system. Accordingly, we find that the LNG facility is still needed for FCG to reliably serve its customers. b. LNG Facility Cost As part of the 2018 Settlement Agreement, we have already approved the inclusion of $58 million in rate base for the LNG facility. The $58 million is not disputed. What is disputed is any costs associated with the LNG facility that are in excess of the $58 million. FCG’s first choice for the site required obtaining a special or unusual use zoning exemption due to its location outside of Miami Dade County’s urban development boundary. Although FCG received support from County staff, FCG was ultimately denied the required exemption, forcing the Company to search for an alternative site. Due to the need to relocate the site and the associated components, such as environmental studies, permitting, and the need to extend the pipeline connection, FCG updated its project cost estimate by an incremental $10 million to a total of $68 million. These increased project costs have already been offset by $2.2 million in benefits from the sale of the original site. No party disputes the selection of the alternative site as an appropriate site to construct the LNG facility. Rather, OPC disputes that the costs of finding the alternate site should be borne by FCG shareholders, not customers. Although OPC witness Schultz acknowledged the difficulties FCG experienced that contributed to the delay in constructing the LNG facility, he recommended that we disallow the additional cost of $10 million for the LNG facility because FCG failed to properly and prudently
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 23 plan the project. Witness Schultz testified that it is not prudent to buy property zoned residential and plan industrial construction in the hopes that a zoning change will be allowed. FCG witness Howard rebutted witness Schultz’s testimony by arguing that the original site for the LNG facility was not zoned as residential, but as agricultural and agricultural accessory uses. He also testified that FCG did not acquire the original site in the hope that the zoning for the site would be changed, but FCG undertook due diligence with the County Planning Director regarding the consistency of the LNG facility within the established zoning requirements. We find that FCG has acted prudently. The Community Council’s decision to deny FCG’s zoning exemption request for the original site, as well as the amount of time the process of locating and acquiring the necessary approvals for a new site took to reach completion, were beyond FCG’s control. As such, we find that the additional cost of $10 million for the LNG facility was prudently incurred. c. In-Service Date FCG projects an in-service date of March 2023 for the LNG facility. In his testimony, OPC witness Schultz expressed concerns regarding whether the LNG facility will be in service when FCG projects since the in-service date for the facility has already been delayed by more than three years. Specifically, witness Schultz argued that it would not be appropriate for customers to again pay for plant not yet in-service. As such, witness Schultz recommended that any projected depreciation included in rates associated with the LNG facility be reflected as a regulatory liability and deferred until FCG’s next rate case, or be reflected as a credit adjustment in one of the Commission’s annual cost recovery clauses at a Weighted Average Cost of Capital (WACC) that recognizes the cost carried in rates. FCG indicated that construction of the LNG facility began in June 2022. In addition, FCG witness Howard testified that construction of the LNG facility was essentially complete. Witness Howard also rebutted witness Schultz’s testimony regarding this issue by outlining the activities completed with regard to the LNG facility from the time of the 2018 Settlement Agreement to this proceeding, as detailed above, in order to demonstrate that FCG has continued to act prudently. Paragraph III(a) of the 2018 Settlement Agreement, of which OPC is a signatory, contemplates that the in-service date of the LNG facility could occur at some point after December 1, 2019.7 In addition, as previously discussed, witness Schultz acknowledged the obstacles encountered by FCG that contributed to the delay of the LNG facility. As construction of the LNG facility is almost complete, we find no adjustments necessary to projected depreciation for the LNG facility. 7 Order No. PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate increase and approval of depreciation study by Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 24 d. LNG Facility Costs in Current Base Rates OPC witness Schultz testified that it was OPC’s understanding that customers would not be paying for the LNG facility until it was in service. FCG witness Fuentes rebutted witness Schultz’s testimony by asserting that OPC agreed to this ratemaking treatment as part of FCG’s 2018 Settlement Agreement. Witness Fuentes disagreed with witness Schultz that funds that have been collected from ratepayers related to the LNG facility should be accounted for in a regulatory liability and returned to ratepayers over five years because this treatment is in direct violation of the 2018 Settlement Agreement. OPC admitted in its brief that some recovery for the LNG facility was allowed under the 2018 Settlement Agreement. The 2018 Settlement Agreement allowed recovery of $29 million in rate base for the LNG facility before it came in-service, and approved an increase to $58 million in rate base upon entering service.8 FCG’s updated total project cost estimate is $68 million. As the $58 million project cost estimate was previously approved in the 2018 Settlement Agreement, FCG is only requesting approval of the incremental $10 million project cost increase in this proceeding; therefore, there is no possibility of double recovery. Since the ratemaking treatment for the LNG facility was agreed upon as part of the 2018 Settlement Agreement and there is no possibility of double recovery, we agree with FCG witness Fuentes that there is no need to set aside funds that have already been collected from ratepayers related to the LNG facility in a regulatory liability and amortized back to ratepayers over five years. 3. Conclusion We find that the LNG facility is still needed for FCG to serve its customers reliably and the additional cost of $10 million for the LNG facility was prudently incurred. We find that no adjustments to projected depreciation for the LNG facility are necessary, and there is no need to set aside funds that have already been collected from ratepayers related to the LNG facility in a regulatory liability and amortized back to ratepayers. Therefore, we find the appropriate amount of plant in service for FCG’s delayed LNG facility, once it is placed in service, is $68 million. D. Plant in Service 1. Parties’ Arguments FCG stated that the appropriate amount of plant in service for the projected test year of 2023 is $664,736,539, including the acquisition adjustment. FCG has projections to invest more than $290 million to support customer growth and enhance both customer service and the safety and reliability of its system. FCG stated that it practices a rigorous and long-standing process for the development of capital expenditure budgets, financial forecasts, and MFRs, and noted that none of the Intervenors disproved of its forecasting methodologies. FCG argued it is able to secure the capital expenditures at the lowest reasonable cost using competitive bidding, contractor quality assurance, and cost tracking. FCG also argued that cost of construction has 8 Id.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 25 increased due to: increases in inflation and material costs; industry market demand for external contractors; supply chain issues; governmental, regulatory, and compliance requirements, including permitting and maintenance of traffic requirements; retirement, removal, and restoration costs; construction safety protocols; and enhanced construction management, inspection, and quality control. OPC argued that FCG overstated its capital additions because capital expenditures were only $36.6 million and $40.9 million for 2019 and 2021, respectively, and the projections for 2022 and 2023 are $89.4 million and $50.6 million, respectively. OPC asserted that the actual 2020 capital expenditures might be an anomaly due to $12 million in major improvements for a new customer and $10 million in system investments, therefore making the increases for 2022 and 2023 more extreme. OPC noted that the 2022 budget-to-actual spending shows an overstatement averaging $36,954,004. OPC acknowledged that unaccounted for SAFE costs in the actuals could cause the $36,954,004 overstatement, but OPC deemed that FCG did not adequately provide information to determine if the overstatement was due to SAFE costs. OPC contended that because FCG did not provide sufficient information to complete an analysis, and, according to FCG witness Howard, the Company is spending $9 million below the projected plant for the capital expenditures for January to September 2022, an adjustment of $9,637,988 should be made. This reduction is based on subtracting the actual three-year average of plant additions from the estimated 2022 plant additions. OPC also recommended a corresponding reduction of $307,256 to depreciation expense and a $460,884 reduction to accumulated depreciation to reflect a year and a half of depreciation. 2. Analysis OPC witness Schultz testified that FCG’s plant additions are overstated. Schultz calculated the three-year actual average of capital expenditures to be $30,951,611, excluding the LNG facility, and determined the projected 2022 and 2023 capital expenditures, excluding the LNG Facility, to be $20,014,315 and $21,542,902, respectively, over the three-year actual. Witness Schultz continued that FCG having an approximate 67 percent increase in projected capital expenditures over the actual average is cause for concern. Witness Schultz also asserted concern that 2020 capital spending may be an anomaly because of high actual costs from $12.2 million for major improvements for a new customer and $10 million for a systems investment. OPC witness Schultz determined there to be an average overstatement of $36,954,004 in a six- month period, between January and June 2022, between the Company’s MFRs and its responses provided in discovery. Witness Schultz conceded that the discrepancy could be due to the SAFE plant not being included in the discovery response, but being included in the MFRs. FCG argued that historical data is useful to evaluate the reasonableness of a forecast, but should not replace a forecast for a growing business in which the Company’s plant additions for the 2023 test year are considered prudent. FCG witness Campbell responded that OPC witness Schultz should not have used historical averages because they are not representative of a prudent forecast for the projected test year, and that he used data that only provided retail base and did not include data for all clause investments. Witness Campbell recalculated the historical averages with the Company’s corrected adjustments, and applying witness Schultz’s methodology, argued
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 26 that there would be a $2,134,806 increase to plant-in-service instead of the $9,637,988 decrease that witness Schultz recommended. 3. Conclusion We find no adjustments to the Company’s projected plant in service are necessary, and the appropriate level of plant in service for the projected test year is $643,079,704. E. Non-Utility Activities At hearing, we approved a stipulation whereby all parties agreed that FCG does not have any non-utility investments, and no adjustments to remove non-utility activities from Plant in Service, Accumulated Depreciation, and Working Capital are necessary. F. Acquisition Adjustment 1. Parties’ Arguments The acquisition adjustment at issue relates to the acquisition of FCG by AGL Resources, Inc., (AGLR) in 2004, which we approved in 2007 via final Order.9 Since the Commission approved this initial acquisition adjustment, the utility has changed ownership twice. In 2016, AGLR was acquired by Southern Gas Company (Southern). The Company was later acquired by NextEra Energy, Inc., (NEE) the parent company of Florida Power & Light Company (FPL), in 2018. FCG continues to amortize the AGLR acquisition adjustment approved in 2007. The amount of the AGLR acquisition adjustment is $21.7 million, and the related accumulated amortization is $13.5 million for a net balance of $8.2 million included in rate base. Amortization expense of $0.7 million is reflected in net operating income in the 2023 Test Year. In its brief, OPC relied on prior Commission orders in support of its argument to deny the acquisition adjustment. Conversely, FCG relied on separate Commission orders in support of Commission approval of the acquisition adjustment. FCG argued that the permanence and continuation of the acquisition adjustment and related amortization were consistent with prior Commission orders.10 FCG further argued that because it carried over the amounts reflected in the balance sheet at the time of the acquisition from Southern in July 2018, as opposed to recording an acquisition adjustment from the transaction, it should be allowed to continue to carry the acquisition adjustment. FCG also argued that OPC’s reliance on prior water and wastewater orders of this Commission is misplaced. 9 Order No. PSC-07-0913-PAA-GU, issued November 13, 2007, in Docket No. 20060657-GU, In re: Petition for approval of acquisition adjustment and recognition of regulatory asset to reflect purchase of Florida City Gas by AGL Resources. Inc. 10 Order No.PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate increase by Florida City.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 27 2. Analysis The Commission approved the adjustment from the 2004 acquisition and required the review of the savings that supported the acquisition adjustment in the next rate proceeding following the acquisition in 2007. The Commission authorized the 30-year amortization period for the acquisition adjustment after analyzing the five factors it has historically reviewed when considering acquisition adjustments for natural gas utilities.11 These factors address the quality of service, operating costs, ability to attract capital for improvements, overall cost of capital, and the professionalism and expertise of the staff. 12 While OPC cited two orders showing that the Commission has an established policy that acquisition adjustments resulting from previous transactions do not survive subsequent purchases of a utility’s assets, FCG presented countervailing testimony regarding Commission orders where the adjustment was continued.13 FCG witness Fuentes testified that, rather than recording a new acquisition adjustment from its acquisition by Southern, it carried over the amounts already reflected in the balance sheet at the time of the acquisition. 3. Conclusion We are persuaded by the testimony of FCG’s witnesses and find that the amortization of the acquisition adjustment shall continue until the next general rate case, at which time FCG will have to support its further continuance under the five factors this Commission has historically reviewed when considering acquisition adjustments for natural gas utilities. G. Construction Work in Progress (CWIP) At hearing, we approved a stipulation whereby all parties agreed that the appropriate amount of Construction Work in Progress (CWIP) is $28,192,440 for the 2023 projected test year. H. Gas Plant Accumulated Depreciation and Amortization 1. Parties’ Arguments FCG stated that the appropriate amount of Accumulated Depreciation for the projected test year, including accumulated amortization associated with the acquisition adjustment, is $221,380,711. FCG argued that OPC’s recommended $13.2 million adjustment to Accumulated Depreciation is unsupported, inappropriate, and should be rejected. 11 Id. 12 Id. 13 Order No. PSC-03-0038-FOF-GU, issued January 6, 2003, in Docket No. 020384, In re: Petition for rate increase by Peoples Gas Systems; and Order No. 23858, issued December 11, 1990, in Docket No. 891353, In re: Application of PEOPLES GAS SYSTEMS, INC. for a rate increase.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 28 OPC maintained that the appropriate level of Accumulated Depreciation and Amortization for the projected test year should be at least $208,172,408, as recommended by OPC witness Schultz. 2. Analysis and Conclusion This issue is determined by our findings on other issues, and based on our findings regarding the Company’s Depreciation Study and the Company’s acquisition adjustment, the appropriate level of Gas Plant Accumulated Depreciation and Amortization is $221,380,711. I. Under-Recoveries and Over-Recoveries in Working Capital Allowance At hearing, we approved a stipulation whereby all parties agreed that under recoveries and over recoveries related to the Purchased Gas Adjustment, Energy Conservation Cost Recovery, and Area Expansion Plan have been appropriately reflected in the Working Capital Allowance. J. Unamortized Rate Case Expense. 1. Parties’ Arguments FCG Witness Fuentes asserted that the inclusion of the unamortized balance of Rate Case Expense of $1,645,732 for the 2023 projected test year in Working Capital is appropriate to avoid an implicit disallowance of reasonable and necessary costs. FCG also argued that its four- year rate plan would reduce the amount of Rate Case Expense that FCG would otherwise incur for multiple rate cases. FCG submitted that it is appropriate to include the unamortized Rate Case Expense in Working Capital. FCG requested that the 13-month average of unamortized Rate Case Expense be allowed in Working Capital. FCG witness Fuentes testified that the Company requested the unamortized balance be included in rate base in order to “avoid an implicit disallowance of reasonable and necessary costs.” She maintained that full recovery of necessary Rate Case Expense is not limited to only recovering the expense and should also include affording FCG the opportunity to earn a return on the unamortized balance of those expenses in Working Capital. OPC asserted that unamortized Rate Case Expense should not be included in Working Capital for a gas company pursuant to Commission policy. OPC witness Schultz proposed a reduction to Working Capital for the deferred Rate Case Expense based on his recommendation to reduce the total Rate Case Expense.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 29 2. Analysis There are electric and gas rate cases that reflect the Commission’s allowance of one-half of Rate Case Expense in Working Capital.14 However, there are no Commission Orders reflecting the full allowance. In Progress Energy Florida, Inc.’s (PEF) 2009 Rate Case, the Commission denied PEF’s request to include unamortized Rate Case Expense in Working Capital.15 The Order in PEF’s 2009 Rate Case stated that customers and shareholders should share the cost of a rate case based on the belief that customers should not be required to pay a return on funds used to increase their rates.16 The Order also cited other electric and gas rate cases where the Commission denied unamortized Rate Case Expense in Working Capital.17 FCG’s justification for full allowance was essentially its assertion that disallowance prevents the Company from fully recovering all necessary and reasonable costs. We are not persuaded that this assertion is enough to contradict Commission policy. We find that FCG has failed to meet the burden to support the inclusion of any unamortized Rate Case Expense in Working Capital, and therefore Working Capital should be decreased by $1,742,227. 3. Conclusion Inclusion of FCG’s requested full unamortized amount of Rate Case Expense in Working Capital would be a departure from Commission practice. As such, Working Capital shall be decreased by $1,742,227. K. Deferred Pension At the hearing, we approved a stipulation whereby all parties agreed that the appropriate amount of deferred pension debit in working capital for FCG to include in rate base is $4,604,263 for the 2023 projected test year. 14 See Order No. PSC-94-0170-FOF-EI, issued on February 10, 1994, in Docket No. 19930400-EI, In re: Application for a Rate Increase for Marianna electric operations by Florida Public Utilities Company; Order No. PSC-08-0327-FOF-EI, issued on May 19, 2008, in Docket Nos. 20070300-EI and 20070304-EI, In re: Petition for rate increase by Florida Public Utilities Company; Order No. PSC-04-0369-AS-EI, issued on July 2, 2004, in Docket No. 20030438-EI, In re: Petition for rate increase by Florida Public Utilities Company; Order No. PSC-04- 1110-PAA-GU, issued on November 8, 2004, in Docket No. 20040216-GU, In re: Application for rate increase by Florida Public Utilities Company; and Order No. PSC-95-0518-FOF-GU, issued on April 26, 1995, in Docket No. 940620-GU, In Re: Application for a rate increase by FLORIDA PUBLIC UTILITIES COMPANY. 15 Order No. PSC-10-0131-FOF-EI, issued on March 5, 2010, in Docket Nos. 20090079-EI, In re: Petition for increase in rates by Progress Energy Florida, Inc.; 20090144-EI, In re: Petition for limited proceeding to include Bartow repowering project in base rates, by Progress Energy Florida, Inc.; and 20090145-EI, In re: Petition for expedited approval of the deferral of pension expenses, authorization to charge storm hardening expenses to the storm damage reserve, and variance from or waiver of Rule 25-6.0143(1)(c), (d), and (f), F.A.C., by Progress Energy Florida, Inc. 16 Order No. PSC-10-0131-FOF-EI. 17 See Order No. 23573, issued October 3, 1990, in Docket No. 891345-EI, In re: Application of Gulf Power Company for a rate increase; Order No. PSC-09-0283-FOF-EI, issued April 30, 2009, in Docket No. 080317-EI, In re: Petition for rate increase by Tampa Electric Company; Order No. PSC-09-0375-PAA-GU, issued May 27, 2009, in Docket No. 080366-GU, In re: Petition for rate increase by Florida Public Utilities Company.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 30 L. Unbilled Revenues At the hearing, we approved a stipulation whereby all parties agreed that unbilled revenues shall be included in working capital. FCG incurs costs to deliver gas to customers, all of which have been accrued or paid. Delivery of that gas gives rise to both customer accounts receivables and a receivable for unbilled revenues. FCG must finance the costs of delivering gas, whether or not the gas sales have yet been billed. For this reason, the Commission has a long- standing practice of including unbilled revenues in working capital. M. Working Capital 1. Parties’ Arguments FCG claimed the appropriate amount of working capital for the 2023 projected test year is $17,357,425. FCG stated that OPC witness Schultz ignored the forecasted Cash Working Capital (CWC), and instead, limited his evaluation to the historical CWC balances. FCG explained the primary reasons for this CWC increase were Cash, Accounts Receivable, Stored Fuel, and Miscellaneous Deferred Debits. FCG has a target minimum for cash of $5 million in projected periods and requests funds as needed for working capital from FPL on an ongoing basis, which establishes the minimum cash balance target. Accounts receivables are increasing in line with increased revenue. Stored fuel increase is due to fuel prices rising and the opening of the LNG facility. Miscellaneous Deferred Debits increased due to a rise in the Company’s pension asset. FCG further stated that the CWC should utilize projections as opposed to historical averages. OPC stated that based on historical balances, the Company’s request for CWC is improperly inflated with increases significantly larger than historical averages. OPC recommended an $800,000 decrease to Accounts Payable. OPC recommended a disallowance of $7,850,000. OPC claimed that these reductions result in a debit balance greater than the three- year average for each expense. 2. Analysis FCG requested $17,357,425 for the total amount of working capital if the RSAM was approved. The parties’ disagreements over working capital are broken down into Cash, Accounts receivable, Stored Fuel, Miscellaneous Deferred Debits, and Accounts Payable. OPC witness Schultz testified that several CWC components were significantly higher than the historical amounts. CWC and working capital allowance are the same. FCG requested $5 million for Cash while the average in prior years was only $2,312,949. The request for Accounts Receivable reflects an increase by $6,225,528 over the three-year average of $9,278,408. The stored fuel is double the three-year average and Miscellaneous Deferred debits is three times the three-year average. In his adjustments, witness Schultz recommended reductions to Cash, Accounts Receivable, Gas Storage, and Miscellaneous deferred Debits. The total amount of adjustment to
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 31 assets in working capital is an $8,650,000 decrease. Witness Schultz also recommended an $800,000 decrease to Accounts Payable. The total of witness Schultz’s adjustments is a $7,850,000 decrease to working capital. FCG witness Howard claimed that witness Schultz ignored the forecasted Cash Working Capital and used historical CWC as the basis for his adjustments. For Cash, FCG witness Howard testified that FCG requests funds from FPL as needed and that this set the minimum cash balance target from FCG. Witness Howard testified that FCG projects accounts receivable using 2021 historical average days’ sales outstanding and then applied that ratio to projected revenues. Witness Howard states that the increase in stored fuel is due to the increase in natural gas prices and the anticipated opening of the LNG facility in March 2023. FCG contended the adjustments proposed by OPC reflect historical amounts while ignoring projected amounts. 3. Conclusion We agree with the Company’s rationale. The use of the historic trends, while a good resource for evaluation, are lacking as a basis for adjustment in the projected test year. Historical data does not account for the changes made in the projected test year nor does it account for FCG’s change in ownership since its last rate case. Based on that premise and using indexed amounts, we looked at working capital as a whole and found the amount to be reasonable. Taking into account our findings regarding accumulated depreciation, under and over recoveries, unamortized rate case expense, deferred pension, unbilled revenues, and insurance expense, the appropriate level of working capital for the projected test year is $15,709,607. N. Rate Base 1. Parties’ Arguments FCG stated that the testimony of its witnesses, information in its MFRs, and discovery responses fully support the amount of rate base requested. Therefore, FCG contended the appropriate amount of rate base for the 2023 projected test year is $487,326,330. OPC stated that the appropriate level of rate base for the projected test year should reflect all OPC adjustments. The appropriate amount of rate base should be no more than $455,035,463. 2. Analysis and Conclusion The appropriate level of rate base depends on the outcome of other issues. Based on our findings regarding the acquisition adjustment, the unamortized rate case expense, and working capital, the appropriate level of rate base for the projected test year is $487,257,875.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 32 VI. Cost of Capital A. Accumulated Deferred Taxes 1. Parties’ Arguments FCG asserted it has incorporated an adjustment to decrease the amount of accumulated deferred income tax (ADITs) included in the calculation of FCG’s weighted average cost of capital as required under Treasury Regulations §1.167(1)-1(h)(6). The calculation of the proration requirement for ADITs for the 2023 projected test year results in a decrease of $46,471. FCG argued that with this adjustment, the appropriate amount of ADITs with the RSAM included in capital structure for the projected test year is $53,898,912. FCG asserted that OPC recommended a $3.6 million decrease to ADITs based on OPC witness Schultz’s recommended rate base adjustments. FCG argued that OPC’s rate base adjustments should be rejected and therefore OPC’s corresponding adjustment to ADIT for the projected test year should also be rejected. While OPC did not address accumulated deferred taxes in its post-hearing brief, OPC recommended a cumulative reduction to rate base of $32,387,362, which corresponds to a decrease of $3,571,766 to ADITs when reconciled to the capital structure pro rata over all sources of capital. OPC argued the appropriate amount of ADITs to include in the capital structure is at least $50,182,538. 2. Analysis The appropriate amount of accumulated deferred taxes in the projected test year capital structure differs slightly between FCG’s and OPC’s recommendations. To derive its deferred tax balance, FCG made a pro rata adjustment of $1,349,743 to its per books balance of $55,150,517, reducing it to reconcile it with the total projected rate base balance. FCG made an additional proration adjustment to remove $46,471 to comply with U.S. Treasury Regulations §1.167(1)- 1(h)(6) which is necessary when calculating rates using a projected test year. None of the parties objected to FCG’s proration adjustment. In addition, FCG made a correction to its revenue requirement which affected the rate base amount, and thus, the capital structure balance. None of the parties made a specific objection to FCG’s calculation of the amount of ADITs included in its MFR Schedule G-3 or FCG’s recalculated ADITs amount in Exhibit LF-12, included with FCG witness Fuentes’ rebuttal testimony. However, OPC recommended a deferred tax balance of $50,182,533, which is based on OPC witness Garrett’s proposed capital structure that includes a ratio of 11.03 percent for deferred taxes. The difference in OPC’s recommended amount arises from OPC’s recommendation to make adjustments to reduce FCG’s rate base and reconcile the lower rate base amount pro rata over all capital sources, which lowers the deferred tax balance proportionately. In the previous section, we approved a total rate base amount of $487,257,875. When this amount is reconciled pro rata over all capital sources to FCG’s capital structure, the corresponding amount of accumulated deferred income taxes based on a ratio of 11.02 percent is $53,717,249.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 33 3. Conclusion For the aforementioned reasons, we find the appropriate amount of accumulated deferred income taxes to include in the projected test year capital structure ending December 31, 2023, is $53,717,249. B. Short-Term Debt 1. Parties’ Arguments FCG argued the appropriate amount and cost rate for short-term debt for the projected test year is $20,203,793 and 1.78 percent, respectively. FCG asserted it utilized FPL’s short-term debt cost because, pursuant to Commission-approved financing orders,18 FCG obtains 100 percent of its debt and equity financing from FPL and the interest rate on any short-term borrowings by FCG from FPL is a pass-through of FPL’s weighted cost for borrowing these funds. FCG argued FPL relies on the forward Intercontinental London Interbank Exchange Offered Rate (LIBOR) curve for its short-term debt cost projections. FCG argued that OPC’s recommended adjustments to increase the amount of short-term debt included in the investor sources of capital by $20,269 should be rejected. FCG also argued that OPC’s recommended adjustment to decrease the total rate base balance should be rejected, and therefore, OPC’s corresponding adjustment to decrease the amount of short-term debt in the capital structure for the projected test year should also be rejected. OPC did not address short-term debt in its post-hearing brief, but OPC witness Garrett testified that the appropriate ratio of short-term debt in the projected test year capital structure is 4.13 percent. This ratio equates to a balance of $18,821,767 for short-term debt in OPC witness Shultz’s cost of capital schedule when reconciled to OPC’s recommended rate base balance of $455,035,463. OPC did not object to FCG’s cost rate of 1.78 percent for short-term debt. 2. Analysis Both FCG and OPC agree the appropriate cost rate for short-term debt is 1.78 percent. We reviewed FCG’s estimate for the short-term debt cost rate based on LIBOR as provided in FCG’s discovery responses and find it to be reasonable. FPL, as FCG’s parent, provides all the investor-provided capital to FCG at the capital structure ratios of FPL. FCG applied the capital structure of FPL, which includes a ratio of 4.69 percent of short-term debt, to its projected test year capital structure and reconciled the amounts to the rate base balance for the projected test year via a pro rata adjustment over all capital sources. After reconciliation with all capital structure components, the ratio of short-term debt in the projected test year capital structure is 4.13 percent. This ratio equates to a short-term debt balance of $20,203,793. 18 Order No. PSC-2022-0354-FOF-EI, Issued October 19, 2022, in Docket No. 20220133-EI, In re: Application for authority to issue and sell securities during calendar year 2023 and 2024, pursuant to Section 366.04, F.S., and Chapter 25-8, F.A.C., by Florida Power & Light Company and Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 34 FCG recalculated its revenue requirement which included a reduction to its requested rate base for the projected test year. As a result, the rate base was reduced by $96,495, which resulted in a corresponding reduction to short-term debt of $3,987. FCG’s final amount of short-term debt included in its projected test year capital structure was $20,137,159. OPC witness Garrett suggested a ratio of 4.13 percent for short-term debt in the projected test year capital structure. When OPC’s recommended capital structure is reconciled to OPC’s recommended lower rate base balance, the corresponding amount of short-term debt is $18,821,767. Previously, we approved a total rate base amount of $487,257,875. When this amount is reconciled pro rata over all capital sources to our approved capital structure, the corresponding amount of short-term debt based on a ratio of 4.13 percent is $20,135,698. 3. Conclusion In conclusion, both FCG and OPC agree on the cost rate of 1.78 percent for short-term debt in the projected test year capital structure and we find it to be a reasonable rate. Based on the aforementioned, we find the appropriate amount and cost rate for short-term debt to include in the projected test year capital structure ending December 31, 2023, is $20,135,698, at a cost rate of 1.78 percent. C. Long-Term Debt 1. Parties’ Arguments FCG argued the appropriate amount and cost rate for long-term debt for the projected test year is $154,025,674 (adjusted) and 4.28 percent, respectively. FCG argued it does not issue its own debt or equity and, pursuant to Commission-approved financing orders,19 FCG obtains 100 percent of its debt and equity financing from FPL, and the interest rate on any short-term or long- term borrowings by FCG from FPL is a pass-through of FPL’s weighted cost for borrowing these funds. FCG witness Campbell contended that this is a significant benefit to FCG’s customers because FPL’s weighted average borrowing costs are significantly lower than FCG could otherwise obtain on its own. FCG argued OPC’s recommended net increase of approximately $54.6 million in long-term debt to reflect OPC’s proposed capital structure should be rejected, and therefore, its corresponding adjustment to long-term debt should also be rejected. OPC did not proffer a specific argument in its post-hearing brief, but recommended an increase of $54.6 million in long-term debt to reflect OPC’s proposed capital structure. OPC also recommended an additional decrease of $13.8 million in long-term debt based on OPC witness Schultz’s recommended rate base adjustments. OPC witness Garrett testified his analysis strongly indicates that FCG’s proposed long-term debt ratio of 40.4 percent is too low to be considered fair for ratemaking. Witness Garrett opined an insufficiently low debt ratio causes the weighted average cost of capital to be unreasonably high. Based on his findings, witness Garrett 19 Order No. PSC-2022-0354-FOF-EI, Issued October 19, 2022, in Docket No. 20220133-EI, In re: Application for authority to issue and sell securities during calendar year 2023 and 2024, pursuant to Section 366.04, F.S., and Chapter 25-8, F.A.C., by Florida Power & Light Company and Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 35 recommended the Commission impute a capital structure for ratemaking purposes consisting of long-term debt of 51.3 percent. 2. Analysis Both FCG and OPC agree the appropriate cost rate for long-term debt is 4.28 percent. The amount of long-term debt in the projected test year capital structure differs between FCG’s and OPC’s recommendations. FPL provides all the investor-provided capital to FCG at the capital structure ratios of FPL. FCG applied the capital structure of FPL, which includes 40.4 percent of long-term debt, to its projected test year capital structure and reconciled the amounts to the rate base balance for the projected test year via a pro rata adjustment over all sources. After reconciliation with all capital structure components, the ratio of long-term debt in the projected test year capital structure is 31.50 percent. This ratio equates to a long-term debt balance of $154,056,074. FCG subsequently recalculated its revenue requirement which included a reduction to its requested rate base for the projected test year. As a result, the rate base was reduced by $96,495, which resulted in a corresponding reduction to long-term debt of $30,400. FCG’s adjusted amount of long-term debt included in its projected test year capital structure was $154,025,674. There was competing testimony about FCG’s requested long term debt ratio of 31.50 percent. FCG Witness Garrett testified that an insufficiently low debt ratio causes the weighted average cost of capital to be unreasonably high and recommended the Commission impute a capital structure for ratemaking purposes consisting of 51.3 percent total debt based on investor sources of capital. OPC witness Shultz used witness Garrett’s recommended long-term debt ratio of 42.7 percent to develop his recommended projected test year capital structure. Reconciling OPC’s recommended capital structure pro rata over all sources to OPC’s recommended rate base balance, the corresponding amount of long-term debt in the projected test year capital structure would be $194,277,560. OPC is proposing an adjustment to increase the amount of long-term debt in the projected test year capital structure as a result of lowering the equity ratio. In rebuttal, FCG witness Nelson contended that increasing the Company’s financial leverage by reference to publicly traded holding companies and other industry capital structures would increase FCG’s financial risk and, as a result, its cost of capital to the detriment of customers. FCG witness Campbell explained the Company utilized FPL’s projected long-term debt rate of 4.28 percent because all long-term financings are provided by FPL. FCG stated FPL relies on the Blue Chip Financial Forecast to project its long-term debt costs, which represents the consensus estimates of more than 40 economists/contributors. FCG’s cost projections for FCG’s long-term borrowings from FPL are shown in MFR G-3, Page 3. FCG’s blended long-term debt cost rate for the projected test year is shown in MFR Schedule G-3, Page 2. We reviewed the aforementioned MFR Schedules and believe the projected long-term debt cost rate of 4.28 percent is reasonable. Previously, we approved a total rate base amount of $477,497,041. When this amount is reconciled pro rata over all capital sources to our approved capital structure, the corresponding amount of long-term debt based on a ratio of 31.50 percent is $153,506,544.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 36 3. Conclusion Both FCG and OPC agree on the cost rate of 4.28 percent for long-term debt in the projected test year capital structure, and we find it to be a reasonable rate. Based on the aforementioned, the appropriate amount of long-term debt to include in the projected test year capital structure ending December 31, 2023, is $153,506,544 at a cost rate of 4.28 percent. D. Customer Deposits 1. Parties’ Arguments FCG argued the appropriate amount for customer deposits for the 2023 Test Year is $3,799,283 (adjusted) at a 2.64 percent cost rate. FCG also argued against OPC witness Schultz’s recommended rate base adjustments, and therefore, OPC’s corresponding adjustment to decrease customer deposits by $251,671 for the projected test year should be rejected. OPC did not address customer deposits in its brief. OPC witness Garrett proposed a ratio of 0.78 percent to include in the projected test year capital structure at a cost rate of 2.64 percent. OPC witness Shultz used witness Garrett’s proposed capital structure to develop OPC’s recommended amounts of the components in the projected test year capital structure. OPC recommended a customer deposit balance of $3,535,924 at a cost rate of 2.64 percent. 2. Analysis Both FCG and OPC agree the appropriate cost rate for customer deposits is 2.64 percent. Both FCG and OPC agree on the ratio of 0.78 percent for customer deposits to include in the projected test year capital structure. FCG did not provide testimony specific to the amount of customer deposits to include in the test year capital structure. We have reviewed the customer deposit balance and effective cost rate as calculated by FCG and find them to be reasonable. FCG recalculated its base revenue requirement, which resulted in a corresponding adjustment to the original customer deposit balance leading to an adjusted balance for customer deposits of $3,799,283. 3. Conclusion Based on the aforementioned, we find the appropriate amount and cost rate for customer deposits to include in the projected test year capital structure is $3,786,477 at a cost rate of 2.64 percent. E. Equity Ratio 1. Parties’ Arguments FCG argued that its requested capital structure consisting of 59.6 percent common equity, which is the same equity ratio as FPL, should be approved because it receives all of its debt and equity financing directly from FPL. FCG opined that its proposal to use the capital structure of
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 37 its parent is fully consistent with FCG’s proposal in FCG’s 2018 rate case, that the Commission has previously approved the use of a parent company’s capital structure where the regulated utility operates as a division and does not issue its own debt, that its proposed equity ratio of 59.6 percent is within the range of the equity ratios of the gas utilities included in the proxy group, and that it is consistent with industry practice. FCG further argued that the Company’s requested equity ratio reflects its specific financing requirements and risk profile, and enables it to maintain its financial strength, which translates into favorable access to capital for the benefit of customers. To assess whether FCG’s requested financial capital structure is consistent with industry practice, FCG witness Nelson calculated the average capital structure (including short-term debt) for each of the proxy group operating companies from 2018 to 2020. The results showed the mean and median three-year average equity ratio of the proxy group is 54.78 percent and 55.85 percent, respectively, within a range of 43.54 percent to 61.78 percent. Therefore, FCG concluded its requested equity ratio of 59.60 percent is within the proxy group range and consistent with industry practice. OPC argued that witness Garrett’s recommended debt ratio would result in an equity ratio of 46.9 percent, and therefore a debt-to-equity ratio of 1.13, which is consistent with the proxy group average. OPC asserted regulated utilities under a rate base rate of return model, where there is no competition, do not have an incentive to minimize their weighted average cost of capital (WACC) because a higher WACC results in higher rates, all else held constant. OPC argued that, because there is no incentive for a regulated utility to minimize its WACC, a Commission standing in the place of competition must ensure that the regulated utility is operating at the lowest reasonable WACC. OPC witness Garrett used the same gas utility proxy group as that of FCG witness Nelson for his cost of capital analysis, and testified the average debt ratio of the proxy group of gas utility companies is 53.1 percent, which correlates to an equity ratio of 46.9 percent. Witness Garrett assessed the reasonableness of his recommendation by comparing other competitive firms with debt ratios above 56 percent from around the country and concluded that the average debt ratio was 64 percent (36 percent equity ratio). From his analyses, witness Garrett opined that FCG’s proposed long-term debt ratio of 40.4 percent is too low to be considered fair for ratemaking and causes the WACC to be unreasonably high. Based on witness Garrett’s testimony, OPC recommended an equity ratio of 46.9 percent from investor-supplied capital which is consistent with the gas utility proxy group average. OPC witness Garrett disagreed with FCG’s assertion that FCG should use the equity ratio of its parent FPL because FPL is the source of FCG’s financing. OPC argued that regulators generally establish capital structures for utilities based on the operational and market risk factors that apply to the individual utility. Witness Garrett asserted that in the FPL 2021 rate case, FPL witness Barrett testified that FPL’s regulatory capital structure included a 59.6 percent equity ratio and has maintained an equity ratio between 59 and 60 percent for over two decades. OPC argued that unlike FPL, FCG had maintained an equity ratio of just over 43 percent for the past twenty years, and it has been 48 percent since only mid-2018.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 38 FEA argued FCG’s requested common equity ratio of 59.6 percent is not appropriate and should be rejected because it exceeds the average authorized equity ratio of 51.4 percent for regulated gas utilities around the country and significantly exceeds the average common equity ratio for the gas utility proxy group of 38.6 percent. FEA argued that witness Walters relied on the same gas utility proxy group developed by FCG witness Nelson, but opined that FCG’s assumed equity ratio of 59.6 percent is nearly eight percentage points higher than that of the gas utility proxy group's comparable equity ratio. Therefore, FEA argued, the Company’s requested common equity ratio should be rejected and the Commission should approve a common equity ratio of no higher than 50.0 percent. FIPUG joined the arguments of FEA. Witness Walters disagreed with witness Nelson’s assessment that an equity ratio of 59.6 percent is reasonable because it is consistent with the source of the investor-supplied capital and it lies within the range of the equity ratios of the gas utility proxy group. 2. Analysis FCG’s current equity ratio is 48 percent, which is based on the consolidated capital structure of its former parent company Southern Company Gas in its 2018 rate case settlement. The revenue requirement associated with increasing the equity ratio from 48 percent to 59.6 percent is approximately $4.1 million. Based on record evidence and past Commission practice of using a capital structure that approximates FCG’s actual sources of capital, FCG’s projected equity ratio of 59.6 percent for the test year ending December 31, 2023, is reasonable and appropriate. FCG presented testimony that the Company’s requested equity ratio reflects its specific financing requirements and risk profile, and enables it to maintain its financial strength, which translates into favorable access to capital for the benefit of customers. FCG offered testimony that its requested financial capital structure is consistent with industry practice. For example, FCG witness Nelson testified the average capital structure (including short-term debt) for each of the proxy group operating companies from 2018 to 2020. The results showed the mean and median three-year average equity ratio of the proxy group is 54.78 percent and 55.85 percent, respectively, within a range of 43.54 percent to 61.78 percent. Therefore, FCG concluded its requested equity ratio of 59.60 percent is within the proxy group range and consistent with industry practice. FCG also offered testimony that its requested equity ratio is appropriate because it is based on its actual financing from its parent, FPL, and is consistent with regulatory precedent and guidance regarding capital structure determinations for companies that do not issue their own debt or have their own credit ratings. While OPC witness Garrett’s testified that using FPL as a gas utility proxy group was flawed, FCG witness Nelson testified that OPC witness Garrett incorrectly used the capital structures of the publicly traded holding companies, not the regulated operating companies that are subsidiaries of the holding companies. FCG argued the proper point of comparison is the mix of investor-supplied capital in place at the regulated utility operating companies, not at the publicly traded holding companies. Witness Nelson testified that the Intervenor witnesses’ recommendations would increase FCG’s financial risk and, in turn, its cost of capital to the detriment of customers. Furthermore, as FCG witness Nelson asserted, adverse
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 39 weather events can happen in Florida, and maintaining a strong balance sheet that enables efficient access to capital when needed regardless of market environments is important. 3. Conclusion Based on record evidence and past Commission practice of using a capital structure that approximates the utility’s actual sources of capital, FCG’s projected equity ratio of 59.6 percent for the test year ending December 31, 2023, is reasonable and appropriate. Accordingly, we find the appropriate equity ratio is 59.6 percent as a percentage of investor-supplied capital. F. Return on Equity (ROE) 1. Parties’ Arguments FCG argued for a 10.75 percent return on common equity (ROE). FCG argued that a fair rate of return should be comparable to returns investors expect to earn on other investments of similar risk, sufficient to assure confidence in the company’s financial integrity, and adequate to maintain and support the company’s credit and to attract capital. FCG argued that this ROE would appropriately account for FCG’s unique risk profile and the Company’s commitment to a strong financial position, while addressing the risk of the Company’s proposed multi-year stay- out. FCG argued that its requested ROE was critical to maintaining its financial strength and flexibility as well as attracting the capital necessary to serve its customers on reasonable terms. OPC argued that the appropriate ROE should be 9.25 percent. OPC argued that since utility stocks are low risk, the return required by equity investors should be relatively low. OPC opined that if the Commission sets the awarded ROE much higher than the true cost of capital, it would run contrary to applicable U.S. Supreme Court precedent and result in an inappropriate transfer of wealth from customers to shareholders. OPC argued that an ROE of 9.25 percent would result in fair, just, and reasonable rates, and would benefit both FCG’s consumers as well as FCG’s shareholders. FEA argued that the appropriate ROE is in the range of 9.00 percent to 9.80 percent, with a midpoint of 9.40 percent. FEA asserted that the purpose of the rate of return testimony provided is to estimate the expected return that investors require on an investment in FCG. FEA argued that a utility should be allowed an ROE sufficient to maintain its financial integrity and to attract capital on reasonable terms, and the return should be commensurate with returns investors could earn in other companies of comparable risk. FEA further argued that market valuations of utility stocks are strong, which is an indication that utilities are able to access equity capital at lower costs and under reasonable terms. FIPUG joined the position and argument of FEA. 2. Analysis The ROE is the allowed cost of common equity. More simply put, ROE is the interest the customers pay to the investors for their equity investments in the utility. The ROE is included in a utility’s regulatory capital structure used to determine the overall rate of return which, in turn,
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 40 is used to establish a revenue requirement. Under section 366.041(1), F.S., no public utility shall be denied a reasonable rate of return. The Hope and Bluefield U.S. Supreme Court cases established that a fair ROE must be (1) commensurate with returns available on investments having comparable risks, (2) sufficient to assure financial soundness and integrity and support reasonable credit quality, and (3) adequate to allow a company to raise capital on reasonable terms.20 Neither case law nor statute mandate that the awarded ROE be tied to the result of a particular financial model. Rather, we must establish a reasonable ROE that is consistent with Hope and Bluefield and supported by competent, substantial evidence in the record. As recognized in this case by OPC witness Schultz, this Commission has a long history of establishing an ROE mid-point and a range of 100 basis points on either side to create a range of reasonableness and ensure rate stability. FCG’s common equity is not publicly traded, and as such a market-based cost rate for the Company cannot be directly observed. Consequently, FCG witness Nelson, OPC witness Garrett and FEA witness Walters (collectively, “Intervenor Witnesses”) all applied cost of equity financial models to a proxy group of publicly traded gas distribution companies (proxy group) with similar risk to FCG to derive estimates of the required ROE. OPC witness Garrett and FEA witness Walters used the same proxy group as that of FCG witness Nelson. All three witnesses used the Discounted Cash Flow (DCF) model and the Capital Asset Pricing Model (CAPM) to estimate the cost of equity. In addition, FCG witnesses Nelson and FEA witness Walters employed a risk premium analysis to estimate the cost of equity. Witness Garrett also applied the Hamada Formula to his CAPM. In general, FCG witness Nelson used inputs and assumptions for things such as projected market returns that produced a higher ROE estimate, while the Intervenor Witnesses used inputs and assumptions that produced a lower ROE estimate. As a result of the respective assumptions used in the cost of equity models, our staff’s recommended ROE is greater than OPC’s and FEA’s recommended ROE of 9.25 percent and 9.4 percent, respectively, and lower than FCG’s requested ROE of 10.75 percent. The range of results of all of the witnesses’ cost of equity models is 7.10 percent to 13.37 percent. The witnesses’ cost of equity model results are summarized in Table 2. 20 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).
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 41 Table 2 ROE Model FCG witness Nelson OPC witness Garrett FEA witness Walters DCF with analyst growth estimates 8.4% - 10.87% 8.00% 9.31% DCF with sustainable growth estimates 8.05% - 10.69% 7.1% 9.02% DCF Multi-stage 7.99% CAPM 10.12% - 10.94% 7.90% 8.08% - 10.97% CAPM with Hamada Formula 9.0% Empirical CAPM 10.67% - 13.15% Risk Premium 9.73% and 9.80% 9.27% - 10.42% Recommended ROE 10.75% 9.25% 9.40% a. Proxy Group of Gas Companies FCG witness Nelson selected six companies from the Value Line Investment Survey to include in the gas utility proxy group. The gas proxy group includes Atmos Energy Corp., New Jersey Resources Corp., NiSource, Inc., Northwest Natural Holding Co., ONE Gas, Inc., and Spire, Inc. The Intervenor Witnesses took no issue with FCG witness Nelson’s selection of gas utilities for the proxy group and used the same proxy group for their respective cost of equity analyses. b. Discounted Cash Flow (DCF) Model The Discounted Cash Flow (DCF) cost of equity model is based on the theory that a stock’s current price represents the present value of all expected future cash flows in the form of dividends discounted at the appropriate risk-adjusted rate of return. In its basic form, the DCF model is expressed as the dividend yield of a stock plus the expected long-term growth rate. Mathematically, the DCF model is expressed as ROE = (dividend ÷ stock price) + growth rate. The differences between FCG witness Nelson’s and the Intervenor Witnesses’ DCF model results are primarily driven by differences in chosen growth rates, as well as witness Nelson’s use of the quarterly compounding dividend yield. FCG witness Nelson used an average growth rate of 6.07 percent in her DCF analysis. FEA witness Walters used three different growth rates of 5.95 percent, 5.67 percent, and 4.35 percent in three variations of the DCF model. OPC witness Garrett used an analyst growth rate of 4.8 percent and a sustainable growth rate of 3.8 percent in two variations of the DCF model. OPC witness Garrett’s DCF results were 7.1 percent and 8.0 percent. We find that OPC witness Garrett’s DCF model result of 7.1 percent is not reasonable because it uses the national GDP as the growth rate and does not reflect the growth rate of regulated natural gas utilities, and shall be given little weight. OPC witness Garrett also used a DCF model using analyst forecasts as the growth rate and obtained a result of 8.0 percent, but asserted that this result should not be considered at all. An objective review of FCG witness Nelson’s DCF results established the
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 42 average of her constant growth DCF model at 9.72 percent and the average of her quarterly growth DCF model at 9.86 percent. The average of the median and mean of FEA witness Walters’ three variations of the DCF model were 9.2 percent, 9.11 percent, and 8.09 percent. The average of FCG and FEA witnesses’ DCF Model results is 9.2 percent. c. Capital Asset Pricing Model (CAPM) The CAPM method of analysis to determine cost of equity is based upon the theory that the market-required rate of return for a security is equal to the risk-free rate plus a risk premium associated with the specific security. The CAPM assumes that all non-market or unsystematic risk can be eliminated through diversification. The risk that cannot be eliminated through diversification is called market, or systematic, risk. Therefore, the CAPM assumes that investors require compensation only for systematic, or market, risk. Non-diversifiable (or systematic) risk is measured by the beta coefficient. 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 equity risk premium (ERP) expressed in this equation: ROE = risk-free rate + Beta × (market return – risk-free rate). Consistent with our prior practices and the evidence presented in this case, we find the application of the market-based DCF Model and CAPM are the best methods to determine the cost of equity because both reflect market-based and utility financial data. The models are not disputed in this case. Rather, there was competing testimony offered by FCG and the Intervenors as to the underlying assumptions and use of the CAPM. FCG Witness Nelson testified that his use of the CAPM results in the long-term arithmetic average historical return on the market of 12.33 percent as an appropriate alternate estimate of the expected market return. However, OPC and FEA offered testimony that countered FCG’s CAPM results. OPC and FEA provided testimony that asserted FCG witness Nelson’s CAPM results are unreasonably high due to her overestimation of the projected market return and ERP. The Intervenors countered FCG’s testimony with: FEA witness Walters testified that FCG witness Nelson’s use of the empirical CAPM utilized an ERP of 70 companies with exceedingly high growth rates, and growth rates for companies in the S&P 500 that are two times the projected growth of the U.S. economy. FEA witness Walters also testified that FCG witness Nelson’s projected market required return of 14.64 percent in the CAPM is overstated and unreasonable, because FCG’s use of the MI beta coefficient of 0.70 in the CAPM is questionable and subject to analyst bias in selecting the inputs to the model.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 43 FEA witness Walters further testified that he calculated nine different applications of the CAPM using a combination of three different beta estimates and three different ERP estimates. Based on these results, FEA recommended a CAPM return estimate of 9.4 percent. OPC witness Garrett testified that the appropriate CAPM yielded an ROE estimate of 7.9 percent. OPC witness Garrett also testified that FCG Witness Nelson’s ERP estimate and sources used to support her estimates were not within the range of reasonableness. The witnesses’ results from the traditional CAPM were 10.12 to 12.94 percent for FCG, 7.9 percent for OPC, and a range of 7.34 to 10.97 percent for FEA. We find that FCG witness Nelson’s highest CAPM results of 12.80 and 12.94 percent arising from her traditional CAPM are not supported. While we agree with the Intervenors that FCG’s traditional CAPM analysis results in an ROE estimate that is too high, we are not persuaded by the ROE estimates offered by OPC and FEA, because those are too low. OPC witness Garrett’s CAPM result of 7.9 percent is unreasonably low because he used a current risk-free rate, which is now stale, and an unreasonably low ERP estimate based on various publications of ERP surveys. Likewise, we find that FEA witness Walters’ use of the MI beta coefficient in his CAPM is questionable and subject to analyst bias, and that his use of Kroll’s ERP and the results of the CAPM using that data are unreasonable. The average of the remaining results from FCG and FEA witnesses’ CAPM analyses is 10.3 percent. FCG witness Nelson argued that FCG’s small size based on market capitalization as compared to the gas utilities in the proxy group supports a small size adjustment to increase the target ROE. The record evidence demonstrates FCG has a much higher equity ratio of 59.6 percent than the average of the gas proxy group of 47 percent. We find FCG’s higher equity ratio and financial strength balance out any risk associated with its smaller size and a numerical adjustment is neither necessary nor reasonable. 3. Conclusion After eliminating some of the witnesses’ results produced by questionable assumptions and inputs used in the DCF and CAPM models as discussed above, the average of the witnesses’ composite DCF model results (9.2 percent) and the composite CAPM results (10.3 percent) is 9.75 percent (10.3 + 9.2 = 19.5 ÷ 2 = 9.75). Both FCG witness Nelson and FEA witness Walters used similar forms of the risk premium model and obtained similar results. FCG witness Nelson’s risk premium results were 9.73 percent and 9.80 percent, and witness Walters’ results ranged from 9.27 percent to 10.42 percent. Consistent with our prior ROE determinations, we have selected an ROE target midpoint and accompanying range of 100 basis points. We find the testimony and evidence supports a mid-point ROE of 9.50 percent with a range of plus or minus 100 basis points. While this result is slightly greater than the national average authorized ROE for gas utilities in 2022 of approximately 9.38 percent, we find this
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 44 ROE will enable FCG to generate the cash flow needed to meet its near term financial obligations, make the capital investments needed to maintain and expand its system, maintain sufficient levels of liquidity to fund unexpected events, and sustain confidence in Florida’s regulatory environment among credit rating agencies and investors. Therefore, our ROE midpoint of 9.50 represents a reasonable middle ground between all of the models and recommendations presented. Based on the analysis of the record evidence discussed above, we find the appropriate authorized ROE midpoint is 9.50 percent with a range of plus or minus 100 basis points. G. Non-Utility Investments At hearing, we approved a stipulation whereby all parties agreed that FCG does not have any non-utility investments and therefore, adjustments to the common equity balance were not required. H. Weighted Average Cost of Capital (WACC) 1. Parties’ Arguments FCG argued the appropriate after-tax Weighted Average Cost of Capital (WACC) for the 2023 Test Year is 7.09 percent as presented in FCG witness Fuentes’ recalculated revenue requirement. FCG witness Campbell asserted that FCG’s proposed regulatory capital structure would produce a total WACC of 7.09 percent in the 2023 Test Year. Witness Campbell contended that a WACC of 7.09 percent is reasonable and reflects the benefit to customers of FCG’s financial strength, including the benefit FCG receives from its parent, FPL. FCG argued the Intervenors’ recommended WACCs are based on their proposed capital structure and midpoint ROE, which should be rejected for the reasons stated in the above discussion of the equity ratio and return on equity. FCG argued that for this reason the Intervenors’ proposed WACCs should be rejected. OPC witness Garrett recommended that we impute a capital structure for ratemaking purposes consisting of long-term 53.1 percent debt, and a 9.25 percent return on equity. This would result in a WACC of 5.75 percent. OPC argued that the three primary components of a company’s WACC are the cost of debt, the cost of equity, and the capital structure. OPC argued the cost of capital is expressed as a weighted average because it is based upon a company’s relative levels of debt and equity, as defined by the particular capital structure of that company. OPC argued pursuant to the standards set forth in Hope and Bluefield, financial integrity should be sufficient to attract capital on reasonable terms under a variety of market and economic conditions. FEA did not specify an appropriate weighted average cost of capital to use in establishing FCG’s projected test year revenue requirement. However, FEA recommended we adopt the cost of capital parameters proposed by FEA witness Walters, including a return on common equity of 9.40 percent and a common equity ratio of 50 percent, which would produce a weighted average cost of capital of approximately 5.95 percent.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 45 2. Analysis The WACC is an issue that incorporates the amounts and cost rates of the capital sources determined in other sections into a final WACC. The amounts and cost rates of the capital components are discussed above. In MFR Schedule G-3, FCG presented its requested projected test year capital structure based on a 13-month average as of December 31, 2023, consisting of common equity in the amount of $256,187,447 (59.6 percent), long-term debt in the amount of $153,552,333 (35.7 percent), and short-term debt in the amount of $20,141,146 (4.7 percent) as a percentage of investor supplied capital. In her rebuttal testimony, FCG witness Fuentes included revised projected 2023 test year cost of capital schedules, but the WACC did not change. FCG witness Campbell explained the ratios of FCG’s investor supplied capital are based on the actual capital structure of FCG’s parent company, FPL. When reconciled to FCG’s rate base which includes customer deposits and deferred taxes, the ratios are reduced to 52.56 percent for common equity, 31.5 percent for long-term debt, and 4.13 percent for short-term debt. OPC recommended reducing the amount of common equity in the projected capital structure and increasing the amount of long-term debt. In his testimony, OPC witness Garrett recommended we reject FCG’s proposal, arguing it has the effect of increasing capital costs beyond a reasonable level for customers. OPC witness Schultz utilized witness Garrett’s recommended capital structure in OPC’s proposed calculations. To reflect OPC’s recommended equity ratio of 46.9 in the capital structure, witness Schultz removed $54,573,294 from the common equity balance in FCG’s projected capital structure and added $54,553,024 to the long- term debt balance and $20,269 to the short-term debt balance. OPC also recommended reducing the total rate base balance by $32,387,362 and making a corresponding adjustment to reduce the capital structure by the same amount pro-rata over all sources of capital. FEA did not recommend a specific capital structure including all the capital component amounts or an overall WACC, only that the equity ratio should not exceed 50 percent. As discussed above, the appropriate amount of: deferred taxes is $52,659,661 at zero cost; short-term debt is $19,730,996 at a cost rate of 1.78 percent; long-term debt is $150,425,423 at a cost rate of 4.28 percent; customer deposits is $3,710,465 at a cost rate of 2.64 percent; and common equity is $250,970,496 at a cost rate of 10.00 percent. Record evidence indicates that using the capital structure of FCG’s parent, FPL, is reasonable, comparable to the equity ratios of other regulated gas utility companies in the gas proxy group, and consistent with prior Commission practice. Therefore, we agree with FCG that the appropriate capital structure consists of 59.60 percent common equity, 35.70 percent long-term debt, and 4.70 percent short- term debt as a percentage of investor sources. 3. Conclusion To reconcile the capital structure with the approved rate base balance of $487,257,875, the appropriate adjustment is a pro rata decrease over all capital sources. After the reconciliation adjustment, the WACC is 6.44 percent.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 46 The appropriate capital structure consists of 59.60 percent common equity, 35.70 percent long-term debt, and 4.70 percent short-term debt as a percentage of investor sources. Based on the proper components, amounts, and cost rates associated with the projected capital structure for the 13-month average test year ending December 31, 2023, as discussed above, the appropriate weighted average cost of capital for FCG for purposes of setting rates in this proceeding is 6.44 percent. The appropriate WACC is presented in Attachment No. 2, which is integrated and attached to this order. VII. Net Operating Income A. Purchased Gas Adjustment and Natural Gas Conservation Cost Recovery At hearing, we approved a stipulation whereby all parties agreed that FCG has properly removed the purchased gas adjustment and natural gas conservation cost recovery revenues, expenses, and taxes other than income from the projected test year. B. SAFE Investments At hearing, we approved a stipulation whereby all parties agreed that FCG has made the appropriate adjustment to Net Operating Income to remove amounts associated with the transfer of SAFE investments as of December 31, 2022, from clause recovery to rate base. C. Outside Service Costs 1. Parties’ Arguments FCG argued that transferring outside service costs incurred for clause dockets from base rates to respective cost recovery clause dockets is consistent with the cost-causation principle. FCG stated that by allowing this proposed method of recovery it will guarantee that ratepayers only pay for the actual cost incurred for outside services required to support the clause proceedings, subject to true-up. FCG asserted that they have made all appropriate adjustments to remove the outside service costs incurred for clause dockets from the projected test year operating revenues and operating expenses. 2. Analysis FCG requested recovery of outside service costs incurred for clause dockets in respective cost recovery clause dockets instead of base rates. FCG witness Fuentes testified that this method is consistent with the cost causation principle and will ensure that customers are only paying for the actual costs incurred, subject to true-up. FCG made an estimate of $57,294 that is based upon the estimated amount of time FPL employees and external legal support will spend working on all of FCG’s cost recovery clauses on an annual basis. The Company stated that if this proposal is accepted by the Commission, it will create a new master data system to track and record outside services for both FPL and external legal support in the appropriate cost recovery clause at the time the cost is incurred. FCG stated that, if approved, this new method will allow the
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 47 amount recorded in each recovery clause to be based on actual time spent for each FPL employee and/or external legal support, and based on contracted rates not on allocation of costs. FCG maintained it does not foresee a large increase in regulatory oversight in each of the applicable cost recovery clause dockets, and FCG proclaimed that the possible incremental regulatory oversight would be beneficial to customers by confirming that they only pay for the actual costs incurred. Even an incremental increase in regulatory oversight is something that should be carefully considered due to the potential complexities from creating additional regulatory oversight. Similar to previous company requests to recover bad debt expense through clauses instead of base rates, this would require additional regulatory oversight. In Order No. PSC-10- 0153-FOF-EI, we denied FPL’s request to recover portions of bad debt through recovery clauses instead of base rates.21 In that case, FCG acknowledged it would need to create additional regulatory oversight by developing a new master data system in order to track and record outside services in the appropriate cost recovery clauses for what FCG estimated to be immaterial expenses for each cost recovery clause. We do not find that FCG has provided a persuasive argument to change Commission practice. 3. Conclusion We find that FCG shall continue to recover outside service costs incurred by clause dockets through base rates and not cost recovery clauses. As such, O&M expense shall be increased by $57,294. D. Miscellaneous Revenues 1. Parties’ Arguments FCG stated that the appropriate amount of miscellaneous revenues is $1,896,516. The Company explained that this amount includes a reduction of $16,071 to correct for a forecasting error. 2. Analysis and Conclusion In its initial filing, FCG reflected $1,912,587 of miscellaneous revenue. However, FCG witness DuBose stated that FCG inadvertently included $16,071 for forecasted billing adjustments that should have been removed from the projected 2023 test year operating revenues. None of the intervenors took a position on this issue nor did they have any adjustments. Aside from the Company’s correction, no other adjustments are necessary. As such, we find for decreasing miscellaneous revenues from FCG’s initial request by $16,071 to the appropriate amount of $1,896,516. 21 Order No. PSC-10-0153-FOF-EI, issued March 17, 2010, in Docket No. 080677, In re: Petition for increase in rates by Florida Power & Light Company, Pg. 142-143.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 48 E. Total Operating Revenues for the Projected Test Year 1. Parties’ Arguments FCG made no argument for this issue, but took the position that the appropriate amount of Total Operating Revenues is $64,724,868 for the 2023 projected test year. As part of its argument that adjustments should be made with regard to the Company’s customer and therm forecasts, OPC cited in its brief an excerpt from staff’s cross examination of FCG witness Campbell. This excerpt included questions related to additional Company revenues in 2024 and 2025 resulting from FCG’s expected growth in customers. OPC noted that witness Campbell stated he did not forecast the impact of this growth in customers but estimated that this growth would result in additional revenues of approximately $200,000 per year. Additionally, OPC noted FCG’s witness admitted that the Company’s customer and therm forecasts typically become progressively less reliable the further they are projected into the future. 2. Analysis This is a fallout issue based on the resolution of other issues. Per our decisions in section I above, there are no recommended adjustments to FCG's forecasts of customers, therms, billing determinants, or revenue from the sales of gas at present rates for the 2023 projected test year. As discussed above, we agree with the Company that miscellaneous revenues at current rates for the projected test year shall be decreased by $16,071 to account for the Company’s forecasting error, resulting in miscellaneous revenues for the projected test year totaling $1,896,516. This adjusted amount of Miscellaneous Revenues, when added to the Total Revenue from Sales of Gas at Current Rates of $62,828,352, results in projected Total Operating Revenues in the amount of $64,724,868 for the projected test year. 3. Conclusion The Intervenors did not present testimony or evidence to disprove FCG’s projected Total Operating Revenues for the projected test year. Therefore, we find that $64,724,868 is the appropriate level of total operating revenues for the 2023 projected test year. F. Non-Utility Activities At hearing, we approved a stipulation whereby all parties agreed that FCG has made the appropriate adjustments to remove all non-utility activities from operation expenses, including depreciation and amortization expense.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 49 G. Salaries and Benefits 1. Parties’ Arguments FCG argued the appropriate amount of salaries and benefits to include in the Test Year is $14,803,183. FCG argued the reasonableness of salary and benefit expense is demonstrated by comparison to the relative comparative market. OPC argued for reductions in base payroll, incentive compensation, benefits, payroll taxes, and other expenses. 2. Analysis a. Salaries and Full Time Employees (FTEs) OPC offered testimony that the number of full time employees (FTEs) is unreasonable because FCG’s forecasts are overly optimistic compared to historical data. Witness Schultz testified that the employee complement of 187 FTEs is inappropriate and does not consider a vacancy factor, and recommended a head count of 173 FTEs. In 2021, actual payroll, excluding recovery clause costs for 2021, was $1,893,794 under budget over the actual of $13,126,569. Witness Schultz also recommended a $49,533 reduction to employee benefits. FCG witness Slattery countered OPC’s arguments and testified that in 2019 and 2020 actual head count exceeded the budgeted headcount to support the replacement of services and functions provided by its acquisition of Southern as well as growth in the business. FCG Witness Slattery testified FCG experienced hiring difficulties, which included limited availability of technical and engineering related labor; desirability of, and competition for, in-demand technology skills; fluctuations in the housing market; and the fiscal restraints the Company has placed on the competitiveness of its pay and benefits package. The witness also testified that there was a skilled labor shortage due in part to the COVID-19 pandemic, “the Great Resignation,” and the rise in remote work, but that despite these factors, FCG put forth significant efforts in 2022 to fill the open positions. As of September 22, 2022, eight positions had been filled, which increased the employee headcount to 180 FTEs. With regards to the vacancy factor, FCG witness Slattery testified that hiring costs and saving associated with vacancies were offset by the cost of overtime and the costs associated with recruiting, onboarding, and training new staff. Likewise, FCG witness Howard testified that FCG provided justification for the increased headcount and explained why each position was required. In broad terms, he asserted the new positions were created due to the physical expansion of FCG’s system and enhancements to the customer information system (CIS) as well as the increase in customer count.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 50 b. Incentive Compensation OPC presented testimony that excessive incentive compensation should be reduced by $524,119, incentive compensation should be reduced by $398,746, and long-term incentive compensation should be reduced by $163,461. OPC witness Schultz pointed to three issues he had with the incentive compensation plan. First, FCG’s amount of incentive compensation declined each year from 2019 to 2021, but for the projected 2023 test year FCG projected $1,772,728. Second, the total projected amount for 2023 is not known because performance and results of operation are not known and no goals are set. Third, since 2018, almost every employee received incentive compensation. He argued that despite the high percentage of employees receiving incentive compensation, FCG failed to meet some of its performance goals, and that half of the met goals were for financial performance, which provide benefits to shareholders and not customers. He further stated that FCG’s incentive compensation plan is discretionary, and that is not what is customarily considered a short-term incentive plan. OPC recommended that $163,461 of the long-term plan costs be excluded and that $922,865 of short- term plan costs be excluded. FCG Witness Slattery addressed incentive compensation in her rebuttal testimony and proposed a reduction of $505,222 associated with executive incentive compensation, noting that FCG removed parts of incentive compensation as required by our 2010 FPL Rate Case Order.22 FCG Witness Slattery testified that the incentive compensation expenses are necessary and reasonable, and are an effective tool in “attracting, retaining, and engaging the required workforce, and play a significant role in delivering value to customers.” She cited Order No. PSC-12-0179-FOF-EI in which we rejected OPC’s recommendation to disallow all incentive compensation and allowed recovery of all of Gulf Power Company’s employee cash compensation.23 Addressing FCG’s incentive compensation compared to the market, FCG witness Slattery stated that FCG’s plan is at or below market. If performance-based cash incentive compensation were eliminated, FCG employees would be compensated roughly 9.6-percent below the market median, and FCG would not be able to compete in the labor market in that scenario, leaving it unable to deliver on its commitments to its customers. FCG Witness Slattery further testified that if incentive compensation were to be removed, it would lead to a reduction in performance-based variable cash incentive compensation and an increase in base salary and other fixed-cost programs. Witness Slattery testified that the reason a high percentage of FCG employees receive performance incentive compensation is to help develop a culture of employees committed to performance. Few employees who stay with FCG fail to meet expectations by the end of the performance period. With regard to company goals, she stated that they are soft goals and reassessed annually. She asserted that while FCG failed to meet some goals in 2020 and 2021, 22 Order No. PSC-10-0153-EI, issued March 17, 2010, n Docket No. 080677-EI, In re: Petition for increase in rates by Florida Power & Light Company. 23 Order No. PSC-12-0179-FOF-EI, issued April 3, 2012, in Docket No. 110138-EI, In re: Petition for increase in rates by Gulf Power Company.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 51 FCG’s performance as of August 2022 exceeded expectations for most goals, and employee cash incentive payouts are expected to be similar to historic levels. Witness Slattery contended that the growth in performance-based cash incentive compensation cost correlates to the growth in head count and the growth in salaries. C. Conclusion Upon review of the testimony presented by FCG, we find FCG has adequately addressed concerns related to staffing levels and incentive compensation. Moreover, the market-based evaluation of FCG’s total compensation further supports not making any further adjustments other than to decrease employee pension and benefits expense by $505,222 to recognize the Company’s adjustment to remove executive incentive compensation.24 Based on this adjustment, the appropriate amount of salaries and benefits to include in the projected test year is $14,803,183. H. Affiliate Expenses 1. Parties’ Arguments FCG claimed that it has included the affiliate services that are necessary to run its business in the 2023 test year, as is consistent with historic practice. FCG stated that OPC recommended that $405,400 of costs allocated as part of FPL’s Corporate Service Charges (CSC) should be excluded. FCG argued that these costs relate to executive incentive compensation, which have already been removed by FCG in its rebuttal adjustments explained in the previous section. OPC claimed that FCG was unable to provide a comparison of affiliate costs included in the 2018 Settlement Agreement to the requested 2023 affiliate costs. OPC argued that the Company has $405,440 of costs that we disallowed in prior dockets. OPC also claimed that $29,576 of Supplemental Executive Retirement Plan (SERP) costs were included in Corporate Service Charges. These costs are considered excessive compensation, therefore OPC recommended they be disallowed. 2. Analysis and Conclusion The Company’s projected test year reflects affiliate expense of $2,982,225. As explained by FCG witness Fuentes, all costs associated with affiliate service provided by FPL are charged according to FPL’s Cost Allocation Manual (CAM). As prescribed by FPL’s CAM, affiliate expense associated with services provided by FPL to FCG are billed as a direct charge or allocated in FPL’s CSC. Of the total affiliate expense in the projected test year, $1,257,227 are direct charges and $1,724,997 are billed through CSC. 24 Order No. PSC-09-0283-FOF-EI, issued April 30, 2009, in Docket 080317-EI, In re: Petition for rate increase by Tampa Electric Company and Order No. PSC-12-0357-PAA-WU, issued July 10, 2012, in Docket 100048-WU, In re: Application for increase in water rates in Marion County by Sunshine Utilities of Central Florida, Inc.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 52 OPC witness Schultz testified that there were several concerns with affiliate expense in the projected test year. The first concern was that FCG was unable to provide a comparison of affiliate costs included in the 2018 Settlement Agreement to the requested 2023 affiliate costs. Second, OPC contended that FCG included $405,400 of costs related to incentive compensation that we have disallowed all or part of in prior dockets. Third, SERP costs in the amount of $29,576 were included in CSC. In its brief, OPC also added AMI O&M expense to its concerns related to affiliate expense. FCG argued it is under new ownership, and as such, any comparison to historic data would not be appropriate. OPC’s concerns are addressed in the discussions of employee compensation above and pensions and benefits below. We find no further adjustments are warranted. Therefore, we find affiliate expense for the projected test year shall be $2,477,003. I. Pensions and Post-Retirement Benefits Expenses 1. Parties’ Arguments FCG argued that no adjustments should be made to remove Supplemental Executive Retirement Plan (SERP) benefit expenses from the corporate service charges. This treatment is consistent with the adjustments made by FPL pursuant to the FPL 2010 Order. As discussed in the previous section, OPC argued that affiliate SERP costs in the amount of $29,576 should be removed. 2. Analysis and Conclusion FCG requested employee pensions and post-retirement benefits expense of $661,618. OPC witness Schultz testified that $29,576 of SERP costs included in pension and post- retirement benefits expense should be disallowed as those costs are considered to be excessive compensation. FCG witness Slattery stated that consistent with the FPL 2010 rate case order, no adjustments are necessary to remove SERP benefit expenses from the Corporate Services Charge (CSC).25 In the FPL 2010 rate case order, we declined to adjust FPL’s forecast for affiliate expense. We find OPC’s arguments for reducing SERP lack support and therefore are unpersuasive. We find FCG’s request to be reasonable, and therefore, we find the appropriate amount of pensions and post-retirement benefits expense to include in the projected test year is $661,618. 25 Order No. PSC-10-0153-EI, issued March 17, 2010, in Docket No. 080677-EI, In re: Petition for increase in rates by Florida Power & Light Company.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 53 J. Injuries and Damages Expense 1. Parties’ Arguments FCG stated that its core values emphasize a commitment to safety. FCG goes on to explain that because of this emphasis on safety, the appropriate injuries and damages expense for the 2023 Test Year is $515,304. FCG refuted claims by OPC witness Schultz that FCG’s safety performance needs improvement as well as his recommendation that injuries and damages expense be reduced by $212,790. FCG stated that OPC’s claims are without merit and should be rejected. FCG asserted that OPC’s reliance on OSHA-recordable events is misplaced and that while they are a useful metric, they do not necessarily demonstrate overall workplace safety. FCG’s main assertion was that OSHA-recordable events alone do not provide sufficient information as FCG encourages its staff to report all injuries regardless of severity. FCG stated that since its last rate case there have been no recorded incidents that OSHA flagged as “Serious Injuries or Fatalities,” with most of FCG’s OSHA-recordable incidents being of a less severe variety, like sprains and strains. FCG additionally stated that since 2019, the Company has never had more than three recordable incidents within a year. FCG also explained that the increase in the cost is the result of increases in insurance premiums across the industry and the reclassification of expenses. FCG then reiterated that the amount requested for injuries and damages expense is reasonable and should be approved. OPC stated that injuries and damages expense doubled each year from 2019 to 2021. During that period, the cost increased from $111,135 to $243,888 to $552,519. OPC also stated that the Company requested $515,304. OPC stated that the increases, which took place under the ownership of FPL, are largely related to: insurance or reserve accruals to protect the service company against injuries and damages claims by employees or others, losses of such character not covered by insurance, and expenses incurred from settlements of such claims. It should be noted that in both 2020 and 2021, the Company failed to meet its goals for the number of OSHA- recordables (per 200,000 hours). OPC recommended using a three-year average for injuries and damages expense, a reduction of $212,790. 2. Analysis FCG requested $515,304 for injuries and damages expense. OPC witness Schultz stated that the expense doubled each year from 2019 to 2021 from $111,135 to $243,888 to $552,519. He contended that FCG has a trend of safety concerns and that this has led to the increase in injuries and damage expense. He stated the number of OSHA-recordables were worse than FCG’s goal in 2020 and 2021. Witness Schultz recommended a decrease of $212,790, leaving $302,514. This adjustment is based on the three-year average from 2019 to 2021. FCG stated that OSHA-recordable events do not necessarily demonstrate overall workplace safety, or the severity of the injuries sustained. Witness Howard asserted that FCG has not recorded any incidents that OSHA flagged as serious injuries or fatalities and that most
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 54 recorded incidents were minor injuries. FCG witness Howard testified that since 2019, FCG has not had over three OSHA-recordable incidents in a year and had none in 2019 and the first half of 2022. The main increases to injuries and damages expense come from two factors: increases in the cost of insurance and a reclassification of expense from Account 924 (Property Insurance) to Account 925 (Injuries and Damages) from 2020. In its brief, FCG explained the reclassification, stating that in 2020, certain liability expenses were incorrectly recorded in Account 924 and were subsequently reclassified to Account 925 in 2021. 3. Conclusion We find FCG’s justification adequately explains the increase in this expense and we do not find a need for any adjustments. We find injuries and damages expense in the amount of $515,304 in the projected test year is reasonable. K. Insurance Expense 1. Parties’ Arguments FCG stated that the appropriate injuries and damages expense (Account 925) and property insurance expense (Account 924) for the 2023 Test Year are $515,304 and $503,407, respectively. FCG opined that these insurance costs are incurred by FCG to provide service to its customers and benefit customers by not leaving them with potential exposure to costs associated with injuries and damages, property damage, and vehicle accidents. The Company also mentioned the imprudence of foregoing such coverage. FCG challenged OPC witness Schultz's assertion that insurance expense should be reduced by $9,431 to remove Directors & Officers Liability (DOL) Insurance because this expense provides no benefits to customers. The Company stated that DOL insurance is a necessary and reasonable expense for FCG to provide service to its customers, as it is essential to recruiting and retaining talented and competent leadership. FCG stated that because of the above- mentioned reasons, FCG’s DOL insurance expense is appropriately included in the 2023 Test Year revenue requirements. OPC stated that as DOL insurance protects the Company’s officers and directors from lawsuits that arise from their own questionable decisions, and the lawsuits are generally brought by shareholders, the customers receive no benefit from this insurance; as DOL insurance offers no benefit to customers it should be disallowed completely. OPC argued that if we do not disallow this cost, we should at least remove 50 percent of the requested amount. 2. Analysis FCG requested $503,407 for insurance expense. OPC recommended a disallowance of $9,431 associated with DOL insurance expense. OPC witness Schultz testified that DOL insurance is to protect directors and officers and the only claims that make DOL insurance necessary come from shareholders, not customers. Witness Schultz also testified that this issue has been addressed by this Commission in prior cases which determined that DOL insurance
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 55 expense should be shared equally between customers and shareholders. OPC recommended that the full amount of DOL be removed. Witness Shultz stated that if all of DOL insurance expense is not disallowed, then there should be an equal sharing of the cost between shareholders and customers. In rebuttal testimony, FCG witness Howard testified that DOL insurance plays an important part in attracting and retaining skilled leadership which does benefit customers. He claimed that without DOL insurance, it would be impossible for FCG to attract and retain experienced directors and officers. By Order No. PSC-10-0131-FOF-EI, the Commission reaffirmed its prior decisions that DOL “has become a necessary part of conducting business for any publicly owned company and it would be difficult for companies to attract and retain competent directors and officers without it.”26 The Commission also recognized that “ratepayers receive benefits from being part of a large public company including, among other things, easier access to capital.”27 Because both shareholders and ratepayers benefit from DOL, the Commission split the cost of insurance between both groups. 3. Conclusion Consistent with our prior decisions, we find that ratepayers and shareholders should share the DOL expense. With a reduction of half of DOL insurance expense, insurance expense shall be decreased by $4,716. Thus, we find insurance expense of $498,691 in the projected test year. L. Projected Contractor Cost At hearing, we approved a stipulation whereby all parties agreed that yes the projected contractor cost is reasonable. FCG does not separately identify or track contractor costs on its books and records, or in its forecast. However, FCG does track outside services, which includes contractor costs. As reflected on page 4 of MFR E-6, the reasonable, appropriate, and justified Test Year expense for Account 923 (Outside Services Employed) is $3,993,307 (adjusted). M. O&M Expenses Adjustment At hearing, we approved a stipulation whereby all parties agreed that there is no adjustment needed to the projected test year O&M expenses to reflect changes to the non-labor trend factors for inflation and customer growth. 26 Order No. PSC-10-0131-FOF-EI, issued March 5, 2010, at p. 99, in Docket No. 090079-EI, In re: Petition for increase in rates by Progress Energy Florida, Inc. 27 Id.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 56 N. Storm Damage Reserve 1. Parties’ Arguments FCG argued that its current storm reserve was authorized in the 2018 Settlement Agreement, and the storm reserve could be revisited in the future if the reserve amount of $800,000 was exceeded. As of December 31, 2022, the Company’s reserve balance was $205,415, thus it was unnecessary to reevaluate. Additionally, FCG argued that it submitted a Storm Damage Self-Insurance Reserve Study (Reserve Study) as required by Rule 25-7.0143, F.A.C., which concluded the storm reserve mechanism should be continued at its current levels. OPC argued the storm reserve at present was adequately funded over the last 46 months, FCG had only charged costs against the reserve for two storms totaling $58,127. This resulted in an estimated annual average cost of $15,164. Given the current $162,290 reserve balance as of March 31, 2022, OPC argued that the storm reserve was sufficient for more than 10 years if costs were incurred at historic levels. OPC also argued that the Company’s Reserve Study estimated the annual storm cost to be $190,000. OPC argued that the annual accrual of $57,500 should be discontinued as of January 1, 2023. 2. Analysis FCG witness Campbell testified that the Company was authorized to implement a storm reserve as a part its 2018 Settlement Agreement, setting the annual accrual at $57,500 and a target reserve of $800,000. Witness Campbell testified that the 2018 Settlement Agreement established that FCG’s storm related costs could be recovered consistent with Rule 25-6.0143, F.A.C., which is this Commission’s storm rule applicable to electric utilities. We have since adopted Rule 25-7.0143, F.A.C., which is specific to gas utilities. This rule allows the establishment of a storm reserve account and outlines the types of storm related costs that an investor-owned natural gas utility can charge to the storm reserve. Witness Campbell testified that the Company is proposing to calculate and recover any storm related costs consistent with Rule 25-7.0143, F.A.C. However, FCG is not requesting any changes to the annual accrual or target reserve amounts. In support of its argument that the storm reserve was adequately funded and OPC argued that the annual accrual of $57,500 should be discontinued, OPC witness Schultz testified that the Company’s storm reserve balance was $162,290 as of March 31, 2022. He stated that over a period of 46 months, $58,127 had been charged against the reserve for two storms, the largest cost being $48,626 in 2020. Witness Schultz calculated that over the 46 month period, the $58,127 amount charged to the reserve averaged $1,264 a month or $15,164 annually. Therefore, FCG could charge $15,164 to the storm reserve every year for more than 10 years before the storm reserve was fully depleted. In rebuttal, FCG witness Howard testified that per Commission Rule 25-7.0143, F.A.C., FCG had retained an independent, third-party consultant to prepare its Reserve Study and that the Reserve Study had found that continuing the storm reserve mechanism at a target of $800,000 was reasonable and appropriate considering the potential for future storms.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 57 Furthermore, witness Howard testified that witness Schultz instead used “a few periods of historical data to base his entire conclusion that the current Storm Damage Reserve balance is adequate for future periods.” Witness Howard asserted that witness Schultz’s testimony ignored the purpose of the Commission-required Reserve Study and only used select storm data as a predictor of future storm damage to the Company’s system. Witness Howard also testified that Florida is a hurricane-prone state, and FCG must plan and prepare for storms that may impact its service areas and facilities. Finally, OPC witness Schultz’s recommendation to reduce the storm reserve by almost 75 percent was based on limited historical storm damage data and is not persuasive. Having reviewed the conclusions of the Reserve Study, we find the storm reserve mechanism shall be continued at a target of $800,000, as approved in the 2018 Settlement Agreement. The historic storm data laid out by witness Schultz was limited in scope, only examining a 46-month period. Utilizing a 46-month period of data to predict future storm damage costs over the next ten years is not a sufficient basis. As a part of the Reserve Study’s analysis, hurricane data from 1900 to 2017 was used, as well as information from other sources such as the National Oceanic and Atmospheric Administration. The Reserve Study estimated that the Company’s expected annual cost due to storm damage was $190,000, although the annual cost could be as high as $2,500,000, compared to $15,164 as calculated by witness Schultz. Thus, the Reserve Study relied on a more expansive amount of data to reach its conclusions, which supported the reserve target of $800,000. 3. Conclusion We are not persuaded by OPC that FCG’s previously approved storm reserve mechanism should be discontinued or modifications made to the annual storm damage accrual and target reserve amounts. Further, if the Company’s storm damage accrual and target reserve amounts remain in place as approved in the 2018 Settlement Agreement, there is no incremental increase in cost to customers. We approve the continuation of FCG’s Storm Damage Reserve provision as included in the 2018 Settlement Agreement, which is consistent with Commission Rule 25- 7.0143, F.A.C. No change shall be made to either the annual storm damage accrual of $57,500 or the target reserve amount of $800,000. O. Parent Debt Adjustment (PDA) 1. Parties’ Arguments FCG witness Campbell testified that FCG has received 100 percent of its debt and equity financing from FPL’s pool of funds which was available based on FPL’s capital structure. Thus, a parent debt adjustment is not applicable in this case as the parent company, FPL, holds a lower percentage of debt in its capital structure than FCG, and no additional interest expense tax benefit exists at the parent company level. Furthermore, FCG has proposed a 2023 test year financing capital structure equal to the capital structure of FCG’s parent which consists of 59.6 percent common equity and 40.4 percent debt as a percentage of investor sources of funds.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 58 OPC argued this Commission has Rule 25-14.004, F.A.C. (Parent Debt Adjustment or PDA Rule) that has not been waived pursuant to Section 120.542, F. S., which mandates the required application of the PDA Rule unless the utility rebuts the presumption that debt of the parent may be invested in the equity of the subsidiary. OPC further argued that the overwhelming evidence is that debt is affirmatively shown to be embedded in FPL’s investment in FCG and Federal income tax expense should be reduced by $382,452. 2. Analysis The parent debt adjustment provides that the income tax expense of a regulated utility will be adjusted to reflect the tax benefit of the interest expense of the parent company where the parent company’s debt may be invested in the equity of the regulated utility and both join in the filing of a consolidated income tax return. NextEra Energy transferred FCG to FPL on July 29, 2018. Upon acquisition by FPL, there was no significant change in FCG’s total per book capital structure value as inherited from Southern Gas Company, on a Commission-regulated basis. FCG has proposed a 2023 test year capital structure equal to the capital structure of FPL, which consists of investor sources of funds of 59.6 percent common equity and 40.4 percent debt. Additionally, FCG does not issue its own debt or equity in the marketplace. Because FCG does not issue its own debt, there is no double leverage. Because FCG does not issue its own debt or equity in the marketplace, it is reasonable to allocate FPL’s investor sources of funds, debt and equity, to FCG for the purpose of setting FCG’s rates. This approach recognizes that FPL’s investor sources of funds are FCG’s investor sources of funds, and therefore, the debt of FPL is not invested in the equity of FCG. 3. Conclusion Because the investor sources of funds, and in essence, the capital structures, are one and the same, the debt of FPL is not invested in the equity of FCG and we find a parent debt adjustment is neither necessary nor appropriate under the PDA Rule. P. Rate Case Expense 1. Parties’ Arguments FCG stated that an update to its estimated Rate Case Expense reflected a reduction in rate case expense of $0.1 million from the original estimate $1.9 million. The Company stated that consistent with its 2018 Settlement Agreement, it requested a four-year amortization period for Rate Case Expense, resulting in an annual amortized amount of $470,209. FCG pointed out that no parties opposed the four-year amortization period. FCG opined that the primary driver of Rate Case Expense is the amount of work involved to litigate the case. FCG stated that it took a bottom-up approach to estimate the work involved to prepare, file, and litigate. The Company emphasized the amount of work involved with a rate case is due to factors largely out of the control of the Company.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 59 FCG asserted that its decision to include FPL affiliate support was not to replace FCG’s in-house resources, but instead to support a wide array of services necessary for a rate case. As a result, OPC witness Schultz’s and FEA witness Collins’ recommendations to limit the amount of Rate Case Expense is unsupported and without merit. OPC stated that the test year costs have increased by $769,350 or 62.97 percent over the costs from FCG’s previous rate case. OPC stated that while the scope of the study has increased, the requested amount is still excessive. OPC asserted that the $1,564,981 attributed to FPL replacement cost is unwarranted. OPC pointed out that these costs are higher than the benchmark Rate Case Expense of $1,476,260 applicable to the previous rate case. OPC stated an additional concern that the Company failed to take advantage of the Proposed Agency Action method, which burdened customers and benefited shareholders. FEA witness Collins testified that the Rate Case Expense is over $700,000 more and 63 percent higher than expenses for FCG’s previous rate case. He also asserted that the increase was not justified. FEA witness Collins stated that the lions-share of costs come from FPL’s affiliate support; however, FCG does not demonstrate what support FPL provided or why this level of support was not needed in earlier rate cases. FEA witness Collins argued that we should limit FCG’s rate case expense to previously approved amounts with an adjustment for inflation or $1.427 million. FEA stated that this would lower amortization expense by approximately $141,000 and lower the deferred Rate Case Expense in rate base by approximately $494,000. FIPUG joined the argument of FEA. 2. Analysis and Conclusion FCG’s initial filing included Rate Case Expenses of $1,991,116. FCG stated OPC’s and FEA’s arguments are without merit and unreasonable due to the nature of the costs associated with a fully litigated rate case. Through discovery, FCG updated the amount of Rate Case Expense, lowering the total amount of Rate Case Expense by $110,280, resulting in the updated amount of $1,880,836. We have examined the requested actual and estimated expenses, along with supporting documentation, and find these expenses are reasonable for a rate case on the hearing track. FCG also requested a four-year amortization period. The four-year amortization period requested by FCG is not disputed by any of the intervenors, and we find it is reasonable. The appropriate annual amount of Rate Case Expense is $470,209. The appropriate amortization period is four years. Q. Uncollectible Accounts and Bad Debt At the hearing, we approved a stipulation whereby all parties agreed that no adjustment shall be made to Uncollectible Accounts for Bad Debt in the Revenue Expansion Factor.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 60 R. O&M Expenses 1. Parties’ Arguments FCG’s O&M expenses have increased by $5.8 million in the 2023 Test Year revenue requirement. FCG stated that approximately $2.4 million of the increase in operating costs is attributable to inflation. The remainder of the additional increase is due to customer growth, system expansion, increased damage prevention efforts, and implementation of certain technologies and initiatives that are necessary to continue to provide safe and reliable natural gas service. OPC argued that it would be inappropriate for customers to pay for the experimental AMI program, considering FCG was not able to provide proof of how FCG customers would benefit from the program. OPC also noted that even though FCG claimed there would be costs savings, FCG was unable to support this claim. 2. Analysis and Conclusion This issue is determined by our findings concerning other issues. Based on prior findings, the appropriate amount of projected test year O&M expense is $25,497,650. S. Taxes Other Than Income (TOTI) 1. Parties’ Arguments FCG stated that because OPC’s recommended adjustment to head count for the 2023 Test Year should be rejected, OPC’s flow through adjustment (payroll tax) to Taxes Other Than Income Taxes should also be rejected. OPC witness Schultz addressed this issue in his testimony and exhibits. The total amount of Taxes Other than Income should be reduced to no more than $6,263,843, after the payroll tax adjustment of $122,767. 2. Analysis In MFR Schedule G-6, FCG states that property tax was projected by multiplying a composite millage rate of 1.8 percent by the net plant at year end. During discovery, FCG provided a more detailed calculation of the methodology used to estimate property taxes. The Company additionally provided updated property tax expense for 2022, which reflected a $1.1 million disparity between the actual and projected expense for 2022. We find that this large of a disparity warrants an adjustment to update the Company’s estimated property tax expense to include the actual data for 2022. Using FCG’s methodology, we included the actual taxable value and composite tax rate from 2022 to recalculate the estimated 2023 property tax expense. This results in a decrease of $510,886.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 61 3. Conclusion Based on our findings in previous issues, additional corresponding adjustments to TOTI are necessary. An adjustment to Load Enhancement Services (LES) revenue in section I results in an increase of $777 for corresponding regulatory assessment fees (RAFs). A reduction to forecasted miscellaneous revenue in Section IV results in a decrease of $80 for corresponding RAFs. A reduction to incentive compensation, also in Section IV, results in a corresponding reduction of $32,995 to payroll taxes. Therefore, we find that TOTI be reduced by a total of $543,184. Accordingly, we find the appropriate amount of TOTI for the projected test year is $5,843,427. T. Test Year Income Tax Expense 1. Parties’ Arguments FCG stated that the appropriate amount of Income Tax Expense for the projected test year is $1,804,203. FCG noted that OPC recommended an adjustment to increase Income Tax Expense for the projected test year by $1.4 million, as reflected in OPC witness Schultz’s testimony. FCG argued that OPC’s recommended increase is based on the proposed adjustments to net operating income, which should be rejected, as addressed in previous issues. OPC stated that the appropriate amount of Income Tax Expense is no more than $241,372, as addressed by OPC witness Schultz. OPC’s recommended amount of Income Tax Expense does not include $1,530,280 of deferred income tax as reflected in witness Schultz’s Exhibit 46. 2. Analysis and Conclusion Based on our findings in previous issues, the appropriate amount of projected test year Income Tax Expense, including current and deferred income taxes and interest synchronization, is $1,934,574, as reflected in Table 3 below. Table 3 Adjusted Income Tax Expense MFR Amount Requested $1,632,690 Adjustments: Interest Synchronization Adjustment $6,381 Fall-Out Adj Federal Income Taxes $231,378 Fall-Out Adj State Income Taxes $64,126 Total Adjustments $301,884 Adjusted Amount $1,934,574
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 62 U. Operating Expenses 1. Parties’ Arguments FCG Stated that OPC’s recommended reduction to the Total Operating Expenses is based on OPC witness Schultz’s proposed adjustments to the individual components of net operating income, which are addressed in section VII. OPC witness Schultz addressed this issue in his testimony and exhibits including, but not limited to, Exhibit 46, Schedule C. Total Operating Expenses should be reduced to no more than $49,398,824. 2. Analysis and Conclusion Based on our findings in previous issues regarding net operating income, the appropriate amount of Total Operating Expenses for the projected test year is $50,592,224. V. Net Operating Income 1. Parties’ Arguments FCG argued that OPC’s recommended increase to Net Operating Income is based on OPC witness Schultz’s proposed adjustments to the individual components of net operating income, which should be rejected for the reasons stated in previous issues. OPC stated that Net Operating Income should be increased to at least $15,342,115. OPC also claimed that a credit should be reflected to prevent a double recovery of the plant cost for the LNG facility because revenue projections are understated, and the Company has already recovered $11,596,631 from ratepayers for the unused facility. 2. Analysis and Conclusion Based on our findings in previous issues, the appropriate amount of Net Operating Income for the projected test year is $14,132,644. VIII. Revenue Requirements A. Revenue Expansion Factor and Net Operating Income Multiplier At hearing, we approved a stipulation whereby all parties agreed that, as reflected in MFR G-4, the revenue expansion factor and net operating income multiplier for the 2023 projected test year are 73.9255 and 1.3527, respectively.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 63 B. Annual Operating Revenue Increase 1. Parties’ Arguments FCG requested a rate plan with a total base rate revenue increase of $28.3 million based on the projected 2023 test year. This amount included an incremental base rate revenue requirement of $18.8 million, a previously approved increase of $3.8 million for the LNG facility, and $5.7 million to transfer the SAFE investments from clause recovery to base rates. FCG argued that the proposed four-year rate plan and incremental increase of $18.8 million would provide rate stability and certainty to customers, as such providing customers with savings and benefits lasting all four years. FCG stated that it has earned below the bottom of the current authorized ROE range since the previous rate case and without base rate relief FCG will continue to earn below the current authorized ROE range. By FCG not earning in the authorized ROE range, FCG has not been fully recovering its reasonable and prudent costs of providing service to its customers. FCG stated that inflation, interest rates, capital costs, and overall market risk are not only higher since its last base rate case, but also greater than since FCG filed this base rate case on May 31, 2022. OPC proposed a total base revenue increase of no more than $4,805,981, based on OPC witness recommended adjustments; FCG asserted that those recommended adjustments should not be considered based on explanations provided above. FCG asserted that the recommended increase by OPC would not allow FCG to earn at the bottom end of its current authorized ROE range and therefore would not allow FCG to earn within the proposed 2023 ROE range. OPC stated that the base rate revenue increase should be no more than $4,805,981. OPC argued that the increase should be reduced due to the impact of revenue projections being understated and to reflect that the Company already recovered over $11,596,631 from customers for the LNG facility. 2. Analysis and Conclusion Based on our findings above, the appropriate total annual operating revenue increase for the projected test year is $23,308,073. This amount includes an incremental increase of $14,149,121 and revenue associated with the transfer of SAFE investments and the LNG facility, as reflected Table 4 below. Table 4 Annual Operating Revenue Increase Operating Revenue Increase $23,308,073 LNG Revenue (3,828,493) Transfer of SAFE Investments (5,330,459) Incremental Revenue Increase $14,149,121
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 64 IX. Cost of Service and Rate Design A. Cost of Service Study (COSS) 1. Parties’ Arguments FCG witness DuBose testified that the purpose of the COSS is to allocate the Company’s costs among the different rate schedules based on cost causation principles. When developing a COSS, costs are first grouped by function (such as distribution or production), then costs are classified into the four main classifications: customer, commodity, demand, and revenue. Capacity costs include mains, regulator stations, and LNG storage. Customer costs include meters, house regulators, and services. Capacity and customer-related costs represent the majority of the total cost of service. Finally, there is an allocation of costs to the various rate classes based upon allocation factors. FCG argued its COSS is appropriate and consistent with the methodologies used by the Company in prior rate cases, and follows the presentation format of the prescribed MFR forms and schedules. FCG further argued that FEA witness Collins’ proposed COSS would significantly shift costs from C&I classes to the residential customer classes if adopted. FEA witness Collins testified that FCG’s Class Cost of Service Study (CCOSS) is not appropriate and does not accurately reflect class cost causation because it uses the Peak and Average (P&A) method to allocate the cost of mains to customer classes and also fails to allocate any distribution mains costs on a customer basis. FEA asserted in its brief that the COSS provided by its witness better reflects how capacity costs are incurred, which more accurately reflects cost causation. FEA further argued that FCG’s cost of service study is flawed because: (1) it does not reflect cost causation; (2) FCG’s P&A method is not a traditional P&A method; and (3) FCG’s P&A method improperly allocated the costs of distribution mains to customer classes primarily on a volumetric basis and fails to classify and allocate any distribution mains costs on a customer basis. FEA contended that in order to correct these flaws, the Company should classify mains on both a demand and customer basis. FIPUG joined the position of FEA. 2. Analysis FCG contended that the primary difference between its proposed COSS and the COSS proposed by FEA is that the Company used the P&A methodology, whereas witness Collins proposed allocating distribution mains based on design day demand and number of customers. FCG further asserted that witness Collins’ proposal is essentially a minimum distribution system allocation. FCG explained that FEA’s proposal related to design day may be appropriate for a utility located in a colder climate where winter peaks occur due to residential gas heating load. FCG, however, serves 49 percent of its customers in Miami, and therefore FCG’s system is not as peak-sensitive as a gas utility in a colder climate. Additionally, FCG stated that although residential customers make up 93 percent of its customers, residential customers flow 14 percent of the gas while C&I customers flow 86
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 65 percent of the gas on FCG’s system on an annual basis. FCG asserted that the allocation method proposed by FEA would inappropriately shift costs away from the C&I customers who use FCG’s system the most during the year to residential customers who use it the least. FCG argued FEA’s proposal does not account for the actual utilization of the mains by different classes of customers, with C&I utilization over six times that of residential customers. FCG argued that despite that, FEA witness Collins’ proposal would allocate 70 percent of the total revenue requirements to the residential customers, while only 29 percent would be assigned to the C&I classes. FCG further noted that the Company’s COSS assigns 37 percent of costs to residential customers and 62 percent to the C&I classes. FCG argues that its proposed cost allocation methodology better reflects how customers use FCG’s system than FEA’s proposed methodology and is more consistent with cost causation theory, considering that the actual usage of the system by residential classes is 14 percent and the actual usage of the system by C&I customer classes is 86 percent. Finally, FCG argued that FEA also overlooks that the P&A cost allocation methodology has been widely used by investor-owned natural gas utilities in Florida, including FCG, Peoples Gas System, and Florida Public Utilities. FEA emphasized in its brief that a fundamental question when selecting a COSS is whether the methodology reflects cost causation. Accordingly, FEA witness Collins testified that when a gas utility installs a new distribution main to expand capacity on its system, it must consider customers’ demand on a system peak day, or design day, and the number of customers being served. Thus, FEA concluded, the costs the utility incurs to provide service are driven by peak day demand and the number of customers. FEA concluded that FCG’s proposed COSS is inconsistent with cost allocation since it fails to allocate costs based on how they are incurred. FEA witness Collins further argued that, based on his experience, in a traditional P&A cost of service study, capacity class allocators are determined by each class’s contribution to the system design day demand, weighted by (1 - system load factor) and by each class’s contribution to system annual usage, weighted by the system load factor. Witness Collins notes that instead of this methodology, FCG based the peak allocator on the monthly maximum volume of a class in the test year. Witness Collins contended that by using the sum of 13 months of volumes for its class P&A allocators (12 actual monthly usages plus the maximum monthly volumes), FCG is essentially allocating capacity-related costs on annual usage and not the traditional P&A method. We reviewed FCG’s three prior rate cases in 2017, 2003, and 2000 to determine how the capacity costs were allocated to the rate classes. In all three rate cases, FCG proposed and we approved the P&A method, consistent with the allocation of capacity-related costs in the instant case. We agree with FCG’s position that the Company used the same cost classification methodology as in its previous three rate cases. In addition, FEA provided no support to justify their assertion that a traditional P&A COSS employs a different allocation than FCG’s proposed P&A methodology. Witness Collins stated that FCG designs its system to meet the design day demands of its customer classes and must allocate some of its distribution costs based on design day demand. However, witness DuBose argued that while design day may be a factor in system design, the
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 66 guidance provided by the National Association of Regulatory Utility Commissioners Gas Distribution Rate Design Manual acknowledges that there are other factors to consider when allocating distribution costs that are unique to each gas utility. Witness DuBose further stated that witness Collins’ proposal related to design day could be appropriate for a utility located in a colder climate that builds and operates its system to serve high and extended winter peaks that occur due to increased residential gas heating load. While we acknowledge that there are different methodologies to allocate costs, we find that FCG provided a reasonable basis for continuing the P&A method, as proposed, for allocating capacity-related costs. Witness DuBose testified that although residential customers make up 93 percent of FCG’s customers, the residential customers flow only 14 percent of the gas on an annual basis while commercial and industrial (C&I) customers flow 86 percent of the gas. FCG’s COSS methodology assigns 37 percent of the cost to residential customers and 62 percent to the C&I customers. Witness Collins allocated 70 percent of the total revenue requirement to residential customers and only 29 percent to C&I customers. We find that FCG’s P&A method produces a cost allocation that more closely matches how customers utilize the distribution system. FEA’s proposed method, on the other hand, unduly shifts costs from C&I customers to residential customers. 3. Conclusion Based on review of the record, FCG’s proposed cost of service study is appropriate and is hereby approved for all regulatory purposes until base rates are reset in FCG’s next general base rate proceeding. B. Revenue Increase Allocation Amongst Rate Classes 1. Parties’ Arguments FCG argued in its brief that the Company allocated the proposed revenues by rate class to improve parity among the rate classes as much as possible, while following our practice of gradualism and considering the competitive nature of the natural gas industry. FCG further asserted that the Company’s proposed rates practice gradualism, because no class would receive an increase greater than 1.5 times the system average increase in total operating revenues, including adjustment clauses. Moreover, FCG argued that it is appropriate to consider the competitive nature of the natural gas industry when designing rates, to mitigate the potential for fuel switching and bypass. FCG contended that moving all rate classes to parity, even when applying gradualism, could result in a disproportionate increase to certain large C&I customer classes, which could make fuel switching or bypass more economical than continuing to receive service from the Company. FCG stated that the Company slightly reduced the proposed increase to rate classes GS-120K and GS-1250K to address the potential for fuel switching and bypass. Finally, FCG argued that FEA’s proposed revenue allocation should be rejected, because it relies on FEA’s proposed cost of service study methodology, as discussed above, which is
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 67 inconsistent with Commission practice and not reflective of how FCG operates and provides service to its customers. In its brief, FEA stated that the Company’s class revenue allocation should be distributed to the rate classes using the results of witness Collins’ cost of service study, because the Company’s proposed cost of service study does not accurately reflect class cost causation. FEA further argued that witness Collins’ class revenue allocation proposal moves each class’s revenue increase to no greater than 1.5 times the system average increase, with no class receiving a rate decrease. FIPUG joined the arguments of FEA. 2. Analysis Witness DuBose testified that FCG proposed revenues by rate class to improve parity among the rate classes to the greatest extent possible, while applying gradualism and considering the competitive nature of the natural gas industry. Parity is calculated by dividing the class rate of return (ROR) by the system ROR. A rate class with a parity index of 100 percent earns the same ROR as the system average and is at parity. A rate class with a parity index of less than 100 percent is below parity; a rate class above 100 percent is above parity. The ROR by rate class shows which classes are over- or under-earning relative to the system ROR, or stated differently, which class is covering their cost to serve and which class is not. Witness DuBose stated that FCG’s COSS shows that parity indices vary by rate class, with some class indices above parity while others fall below parity. Assessing parity at present rates provides a starting point in allocating any increase in revenue requirements. Gradualism is a concept that is applied to prevent a class from receiving an overly-large rate increase. When a rate increase limit is imposed on a rate class, the remaining classes will have to absorb that difference. In previous electric and natural gas rate cases, we have applied the policy of limiting rate increases in total operating revenues for an individual rate class to no greater than 1.5 times the system average increase, and that no rate class receives a revenue decrease. As witness DuBose explained, the allocation of any revenue requirement increase should be assessed in terms of its impact on the ROR and parity index for the respective rate class. Witness DuBose testified that FCG is requesting a 44 percent increase in total revenues for the 2023 test year. Under our guideline of gradualism, any increase to a rate class would be limited to 66 percent, or 1.5 times the proposed system increase of 44 percent. Witness DuBose’s calculations show that under FCG’s proposed increase, no class would receive more than a 56 percent increase, including the transfer of SAFE revenue requirements from clause to base rates and the addition of the previously-approved LNG project. MFR Schedule H-1, with RSAM, page 2 of 6, similarly shows that no class would receive an increase of more than 56 percent, with percent increases ranging from 34 percent to 56 percent. The same MFR Schedule also shows parity indexes at present and proposed rates. With the exception of the GS-120K rate class, which is discussed below, FCG has proposed revenues by rate class that improve parity to the greatest extent possible, as asserted by witness DuBose.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 68 With respect to large C&I customers, witness DuBose explained that if natural gas service becomes uneconomical, large C&I customers can bypass FCG’s system or locate their business outside of FCG’s service territory or even the state of Florida. Therefore, to address the potential for fuel switching and bypass, FCG slightly reduced the proposed increases to rate classes GS-120K and GS-1250K. Rate class GS-120K is available to non-residential customers using between 120,000 and 1,249,999 therms per year; rate class GS-1250K is available to non- residential customers using between 1,250,000 and 10,999,999 therms per year. We agree with FCG’s approach to consider the risk of large C&I customers choosing an alternate fuel supply or leaving FCG’s service area, resulting in a loss of revenues and load. The retention of large C&I customers benefits the general body of ratepayers as their revenues contribute to FCG’s fixed costs. Witness Collins does not agree with the Company’s class revenue allocation and asserted that FCG’s COSS does not accurately reflect class cost causation and that FEA’s COSS should be used to allocate the increase to the rate classes. Witness Collins did not testify that FCG proposed an increase greater than 1.5 times to any rate classes, and FEA only objected to FCG’s COSS methodology. 3. Conclusion Each rate class’s COSS determines the allocation of any revenue requirements increase for each rate class. Therefore, differing COSS methodologies such as those proposed by FCG and FEA result in different increase allocations to the rate classes. In rebuttal testimony, witness DuBose summarized the difference between FCG and FEA’s proposed revenue increase allocations, based in their respective COSS. FEA’s proposed revenue increase to the residential RS-1 and RS-100 rate classes is 66.64 percent, while for the commercial rate classes it is 24.81 percent. We do not believe that FEA’s proposed increases provide a balanced approach. Based on the foregoing, and considering prior Commission practice of using gradualism to allocate an approved increase to the rate classes, we are persuaded by FCG’s proposed allocation of the rate increase as shown by the testimony of witness DuBose. FCG’s proposed revenue increase to the rate classes limits the increase in total revenues to any rate class to 1.5 times the system increase, reflecting our guidelines on gradualism and improving parity among the rate classes. C. Proposed Customer Charges 1. Parties’ Arguments FCG did not provide an argument, but adopted the position that the appropriate customer charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). 2. Analysis and Conclusion We find the customer charges discussed here, in combination with the per therm distribution charges and the demand charges discussed below, are designed to allow the
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 69 Company to recover the total Commission-approved revenue requirement. Further, we approved above both the Company’s proposed cost of service methodology and the allocation of the revenue increase to rate classes. The customer charges reflect the appropriate revenue requirement and cost of service methodology; therefore, proposed charges provided in the tariffs in Attachment 6 are approved. D. Distribution Charges 1. Parties’ Arguments FCG did not provide an argument but adopted the position that the appropriate per therm Distribution Charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). 2. Analysis and Conclusion We have reviewed the Company’s revised cost of service filing and it reflects the Commission-approved total Company revenue requirement. Further, we approved above the Company’s proposed cost of service methodology and the allocation of the revenue increase to rate classes. The proposed per therm distribution charges reflect the approved revenue requirements and cost of service methodology; therefore, the proposed charges provided in the tariffs in Attachment 6 are approved. E. Demand Charges 1. Parties’ Arguments FCG did not provide an argument, but took the position that the appropriate Demand Charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). 2. Analysis and Conclusion We have reviewed the Company’s revised cost of service filing and it reflects the Commission-approved total Company revenue requirement. Further, we approved above the Company’s proposed cost of service methodology and the allocation of the revenue increase to rate classes. The proposed demand charges reflect the approved revenue requirements and cost of service methodology; therefore, the proposed charges provided in the tariffs in Attachment 6 are hereby approved. F. Connect and Reconnection Charges At hearing, we approved a stipulation whereby all parties agreed that the appropriate service, connect, and reconnection charges are those shown in 2023 Test Year MFR H-1 (2 of 2).
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 70 G. Transportation Customer Charge Application to Third Party Suppliers At hearing, we approved a stipulation whereby all parties agreed that the appropriate per transportation customer charge applicable to Third Party Suppliers is shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). H. Effective Date for Revised Rates and Charges 1. Parties’ Arguments FCG’s filing requested a February 1, 2023 effective date for new base rates. OPC took the position that the effective date of FCG’s revised rates and charges should allow for time for implementation promptly after our final Order in this matter. FIPUG adopted the position of OPC. 2. Analysis and Conclusion FCG provided a notification of the proposed rate increase to its customers during the month of August 2022, and also posted notice of the rate increase on its website. The notification included a comparison between current and proposed rates, and that the rates ultimately approved by this Commission will not exceed those identified in the notice. FCG also provided a direct notice to customers during May 2023, which identified the final, Commission-approved rates and charges. Our staff reviewed the direct notice and believe the notice reflects our approved rates and charges. We find that the approved rates and charges should become effective May 1, 2023. We further find the tariffs as provided in Attachment 6 are approved. I. Approval of Tariffs Reflecting Approved Rates and Charges 1. Parties’ Arguments FCG did not provide an argument but took the position that we should approve tariffs reflecting our approved rates and charges and should direct our staff to verify that the revised tariffs are consistent with our decision. 2. Analysis and Conclusion We have reviewed the cost of service study and associated tariffs which were revised to reflect our final approved revenue requirement in accordance with our vote from the March 28, 2023, Special Agenda Conference. The tariffs are approved and are hereby incorporated into this Order as Attachment 6.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 71 X. Other Issues A. Proposal For Addressing A Potential Change In Tax Law 1. Parties’ Arguments FCG argued that in light of the continuing debate surrounding tax law in the United States, there exists the possibility for a change in tax law either during or after the conclusion of the rate case that could have a material impact on the four-year proposal being presented by FCG. FCG would not be able to quantify the impacts until such time as a final bill is passed and signed into law. FCG’s proposed tax adjustment mechanism would allow FCG to adjust base rates in the event tax laws change during or after the conclusion of this proceeding. FCG argued the proposed tax adjustment mechanism would ensure that the impact of future tax laws is promptly and appropriately reflected in base rates, whether that is an increase or decrease to tax expense. FCG argued this Commission has previously approved nearly identical tax adjustment mechanisms. OPC argued that, by Order No. PSC-2017-0099-PCO-EI (2017 Gulf Tax Decision), we established a policy that a rate case is not the proper venue for establishing a prospective change in rates as a result of a future change in federal income tax rates. OPC also argued that as a matter of policy, we should decline to authorize the tax change provision because it is single issue ratemaking that would ignore the other relevant conditions that might exist at a time when tax laws might change in the future. FIPUG adopted the position of OPC. OPC argued that for FCG to demand to receive a Commission-ordered tax adjustment mechanism on top of a fully litigated revenue requirement award violates prior Commission policy. OPC argued that since the company conceded that there is no impact of the August 2022 Inflation Reduction Act (IRA) on the company, it is undisputed that the purpose of the proposal is premature for some future, unknown (and purely speculative) tax law change. 2. Analysis At issue is whether FCG’s proposed tax adjustment mechanism (to adjust base rates in the event tax laws change during or after the conclusion of this proceeding) should be approved. The bulk of FCG’s testimony relies on its FCG witness Campbell’s testimony that FCG filed its rate case under the assumption that there was the potential for an increase in the Federal corporate tax rate either during the case itself or during the four year period when FCG’s rate plan proposes no adjustments to base rates. FCG has not accounted for or included any potential tax law changes in its current filing, and FCG witness Campbell agreed that in August 2022, a change in tax law was passed but did not have any immediate impact on FCG. Witness Campbell testified that FCG is still assessing the changes, but doesn’t foresee anything affecting FCG. Further, witness Campbell admitted that he does not know of any new tax law changes that are pending or that the Company expects to be adopted in the near future.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 72 3. Conclusion We find that a tax law change provision in this case is unnecessary because there is no evidence supporting a need for it. Should there be a tax law that comes into effect that will affect the rates set forth in this order, a limited proceeding pursuant to Section 366.076, F.S., is available for FCG or OPC to address any potential future State or Federal income tax law changes, which would provide an opportunity to consider all of the issues arising from such tax law changes and to establish the appropriate rates at that time. As discussed above, we find that FCG’s assurance to not initiate another rate proceeding before us over the next four years, or its “stay out” promise, is unenforceable. Accordingly, the tax law change provision is unnecessary. For this reasons, we hereby deny FCG’s request for a tax law change provision. B. SAFE Program Expansion for Mains and Services At hearing, we approved a stipulation whereby all parties agreed that this Commission should approve the continuation and expansion of the SAFE program to include additional mains and services. The current SAFE program is set to expire in 2025 based on an original estimate of 254.3 miles of mains and services to be relocated from rear property easements to the street front over the ten-year program. FCG has subsequently identified approximately 150 miles of additional mains and services that are located in rear property easements and eligible for replacement under the SAFE program. As we have previously found, mains and services located in rear property easements present operational and safety concerns, including the age of the facilities, limitations on the Company’s access to the facilities due to vegetation overgrowth, landscaping and construction in the easements, and potential gas theft or diversion and damages to the facilities. Therefore, continuation of the SAFE program beyond its 2025 expiration date and inclusion of an additional approximately 150 miles of mains and services is reasonable. FCG must propose a new investment/construction schedule and term for the SAFE program in its next applicable annual SAFE filing. C. SAFE Program Expansion for “Orange Pipe” At hearing, we approved a stipulation whereby all parties agreed that orange pipe is a specific plastic material that was used in the 1970s and 1980s that has been studied by the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and shown through industry research to exhibit premature failure in the form of cracking. The potentially compromised nature of the piping makes responding to leaks more hazardous since responders cannot safely squeeze the pipe without it cracking. In order to address this safety risk in a timely manner, FCG is seeking approval to expand the SAFE program cost recovery mechanism to include the capital investments necessary for the expedited replacement of approximately 160 miles of orange pipe installed before 1990. FCG must propose a new investment/construction schedule and term for the SAFE program in its next applicable annual SAFE filing.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 73 D. Description of Adjustments At hearing, we approved a stipulation whereby all parties agreed that FCG shall 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. Based on the foregoing, it is ORDERED by the Florida Public Service Commission that Florida City Gas’ Petition for Rate Increase is granted in part and denied in part as set forth herein. It is further ORDERED that each of the findings made in the body of this order is hereby approved in every respect. It is further ORDERED that all matters contained in the attachments and schedules appended hereto are incorporated herein by reference. It is further ORDERED that the revised tariffs submitted by Florida City Gas, and the final rates and charges contained therein, as incorporated and attached to this Order, are hereby approved. It is further ORDERED that the approved rates and charges for Florida City Gas shall be effective May 1, 2023. It is further ORDERED that Florida City Gas shall file, within 90 days after the issuance of this order, 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 our findings in this rate case. It is further ORDERED that after this final Order is issued this docket shall be closed.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 74 By ORDER of the Public Service Commission this 9th day of June, 2023. TPS }j Commission Cler Florida Public Set ice Commission 2540 Shumard Oak Boulevard Tallahassee, Florida 32399 (850) 413-6770 wv'iw.floridapsc.com Copies furnished: A copy of this document is provided to the parties of record at the time of issuance and, if applicable, interested persons.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU PAGE 75 NOTICE OF FURTHER PROCEEDINGS OR JUDICIAL REVIEW The Florida Public Service Commission is required by Section 120.569(1), Florida Statutes, to notify parties of any administrative hearing or judicial review of Commission orders that is available under Sections 120.57 or 120.68, Florida Statutes, as well as the procedures and time limits that apply. This notice should not be construed to mean all requests for an administrative hearing or judicial review will be granted or result in the relief sought. Any party adversely affected by the Commission's final action in this matter may request: 1) reconsideration of the decision by filing a motion for reconsideration with the Office of Commission Clerk, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850, within fifteen (15) days of the issuance of this order in the form prescribed by Rule 25-22.060, Florida Administrative Code; or 2) judicial review by the Florida Supreme Court in the case of an electric, gas or telephone utility or the First District Court of Appeal in the case of a water and/or wastewater utility by filing a notice of appeal with the Office of Commission Clerk, and filing a copy of the notice of appeal and the filing fee with the appropriate court. This filing must be completed within thirty (30) days after the issuance of this order, pursuant to Rule 9.110, Florida Rules of Appellate Procedure. The notice of appeal must be in the form specified in Rule 9.900(a), Florida Rules of Appellate Procedure.
ORDER NO. PSC-2023-0177-FOF-GU DOCKET NO. 20220069-GU Attachment 1 PAGE 76 ISSUE TOTAL COMPANY COMPANY COMMISSION COMMISSION NO. PER BOOKS ADJS. ADJUSTED UTILITY PLANT PLANT IN SERVICE $659,463,015 Remove SAFE Assets (49,408,313) Remove Capital Lease Assets (9,677,542) SAFE Transfer to Base Rates 42,702,544 Total Plant-In-Service $659,463,015 ($16,383,311) $643,079,704 $0 $643,079,704 ACQUISITION ADJUSTMENT $21,656,835 Total Acquisition Adjustment $21,656,835 $0 $21,656,835 $0 $21,656,835 CONSTRUCTION WORK IN PROGRESS $30,868,480 Remove SAFE Assets (3,555,214) SAFE Transfer to Base Rates 879,174 Total Construction Work In Progress $30,868,480 ($2,676,040) $28,192,440 $0 $28,192,440 TOTAL UTILITY PLANT $711,988,330 ($19,059,351) $692,928,979 $0 $692,928,979 DEDUCTIONS ACCUM. DEPR.- PLANT IN SERVICE ($224,359,876) Remove SAFE Assets 2,709,929 Remove Capital Lease Assets 1,703,882 SAFE Transfer to Base Rates (2,523,229) 2022 Depreciation Study 1,088,583 Total Accum. Depr.- Plant In Service ($224,359,876) $2,979,165 ($221,380,711) $0 ($221,380,711) TOTAL DEDUCTIONS ($224,359,876) $2,979,165 ($221,380,711) $0 ($221,380,711) NET UTILITY PLANT $487,628,454 ($16,080,186) $471,548,268 $0 $471,548,268 WORKING CAPITAL ALLOWANCE $19,889,261 AEP Regulatory Asset (1,132,457) Clause Net Underrecoveries (1,053,994) Unamortized Rate Case Expense (248,890) 19 To Remove Unamortized Rate Case Expense (1,742,227) 22 Half of D&O Liability Insurance (2,086) Total Working Capital Allowance 19,889,261 (2,435,341) 17,453,920 (1,744,313) 15,709,607 TOTAL RATE BASE $507,517,715 ($18,515,527) $489,002,188 ($1,744,313) $487,257,875 PTY 12/31/23 DOCKET NO. 20220069-GU \ COMPARATIVE AVERAGE RATE BASE FLORIDA CITY GAS ATTACHMENT 1
ORDER NO. PSC-2023-0177-FOF-GU Attachment 2 DOCKET NO. 20220069-GU PAGE 77 FLORIDA CITY GAS Docket No. 20220069-GU PTY 12/31/23 13 Month Average COMPANY POSITION FCG PER FCG COST WEIGHTED BOOKS SPECIFIC PRO RATA ADJUSTED RATIO RATE COST COMMON EQUITY $262,522,369 $47,385 ($5,541,003) $257,028,751 52.56% 10.75% 5.65% LONG TERM DEBT 165,323,588 (7,946,387) (3,321,127) 154,056,074 31.50% 4.28% 1.35% SHORT TERM DEBT 20,639,971 3,447 (435,638) 20,207,781 4.13% 1.78% 0.07% CUSTOMER DEPOSITS 3,881,270 683 (81,921) 3,800,033 0.78% 2.64% 0.02% DEFERRED TAXES 55,150,517 (78,791) (1,162,177) 53,909,550 11.03% 0.00% 0.00% TOTAL $507,517,715 ($7,973,663) ($10,541,866) $489,002,189 100% 7.09% STAFF POSITION ADJUSTED PER STAFF COST WEIGHTED BOOKS SPECIFIC PRO RATA ADJUSTED RATIO RATE COST COMMON EQUITY $262,522,369 $47,385 ($6,457,846) $256,111,908 52.56% 9.50% 4.99% LONG TERM DEBT 165,323,588 (7,946,386) ($3,870,658) 153,506,544 31.50% 4.28% 1.35% SHORT TERM DEBT 20,639,971 3,447 ($507,720) 20,135,698 4.13% 1.78% 0.07% CUSTOMER DEPOSITS 3,881,270 683 ($95,476) 3,786,477 0.78% 2.64% 0.02% DEFERRED TAXES 55,150,517 (78,791) ($1,354,477) 53,717,249 11.02% 0.00% 0.00% TOTAL $507,517,715 ($7,973,662) ($12,286,178) $487,257,875 100% 6.44% ATTACHMENT 2
ORDER NO. PSC-2023-0177-FOF-GU Attachment 3 DOCKET NO. 20220069-GU Page 1 of 2 PAGE 78 Page 1 of 2 ISSUE TOTAL COMPANY COMPANY COMMISSION COMMISSION NO. PER BOOKS ADJS. ADJUSTED ADJS. ADJUSTED OPERATING REVENUES Operating Revenues $116,217,009 Change in Unbilled Revenues 40,041 PGA (34,053,742) AEP Revenues (726,069) SAFE Revenues (6,736,104) Conservation (6,997,154) Franchise and Gross Receipts Tax Revenues (3,158,626) 3 LES Revenues 155,495 35 Forecasted Misc. Revenues (16,071) TOTAL REVENUES $116,257,139 ($51,671,695) $64,585,444 $139,424 $64,724,868 OPERATING EXPENSES: COST OF GAS $34,075,912 Eliminate Fuel Expense (34,075,912) Total Cost of Gas $34,075,912 ($34,075,912) $0 $0 $0 OPERATION & MAINTENANCE EXPENSE $32,720,885 Conservation (6,901,558) Rate Case Expense Amortization 497,779 Economic Development (3,217) Industry Dues Associated with Lobbying (25,000) Transfer of Support Costs to Clauses (57,294) Regulatory Commission Expenses/Fees (250,628) 11 Corrected AMI O&M Expense (3,104) 34 To Maintain Clause Support Costs in Base Rates 57,294 38 Exclusion of Executive Incentive Compensation (505,222) 42 Remove Half of D&O Liability Insurance (4,716) 47 Updated Rate Case Expense (27,570) TOTAL O & M EXPENSE $32,720,885 ($6,739,918) $25,980,967 ($483,318) $25,497,650 DEPRECIATION & AMORTIZATION $20,276,958 AEP Amortization (679,200) To remove SAFE assets (1,273,253) To transfer SAFE assets to base rates 1,189,568 2022 Depreciation Study (2,197,500) TOTAL DEPRECIATION & AMORTIZATION $20,276,958 ($2,960,385) $17,316,573 $0 $17,316,573 FLORIDA CITY GAS COMPARATIVE NET OPERATING INCOME ATTACHMENT 3 DOCKET NO. 20220069-GU PTY 12/31/23
ORDER NO. PSC-2023-0177-FOF-GU Attachment 3 DOCKET NO. 20220069-GU Page 2 of 2 PAGE 79 Page 2 of 2 ISSUE TOTAL COMPANY COMPANY COMMISSION COMMISSION NO. PER BOOKS ADJS. ADJUSTED ADJS. ADJUSTED TAXES OTHER THAN INCOME $9,740,548 To Remove SAFE Assets (992,616) To Transfer SAFE Assets into Base Rates 797,305 Franchise and Gross Receipts Expense (3,158,626) 52 LES Revenue RAF 777 52 Forecasted Miscellaneous Revenue RAF (80) 52 Executive Incentive Compensation Payroll Taxes (32,995) 52 Updated Property Tax Estimate (510,886) TOTAL TAXES OTHER THAN INCOME $9,740,548 ($3,353,937) $6,386,611 ($543,184) $5,843,427 INCOME TAX EXPENSE Income Taxes $1,176,607 Income Taxes - Deferred 1,504,301 Taxes Corresponding to Adjustments (1,151,104) Interest Synchronization 38,247 2022 Depreciation Study 64,639 53 Interest Synchronization 6,381 53 Fallout Adj. Federal Income Taxes 231,378 53 Fallout Adj. State Income Taxes 64,126 TOTAL INCOME TAXES $2,680,908 ($1,048,218) $1,632,690 $301,884 $1,934,574 TOTAL OPERATING EXPENSES 215,752,350 (48,178,370) 51,316,841 (724,617) 50,592,224 NET OPERATING INCOME ($99,495,300) ($3,493,325) $13,268,603 $864,041 $14,132,644 DOCKET NO. 20220069-GU PTY 12/31/23 COMPARATIVE NET OPERATING INCOME FLORIDA CITY GAS ATTACHMENT 3 COMPANY STAFF
ORDER NO. PSC-2023-0177-FOF-GU Attachment 4 DOCKET NO. 20220069-GU PAGE 80 COMPANY DESCRIPTION PER FILING STIPULATION REVENUE REQUIREMENT 100.0000% 100.0000% REGULATORY ASSESSMENT RATE 0.5000% 0.5000% BAD DEBT RATE 0.4771% 0.4771% NET BEFORE INCOME TAXES 99.0229% 99.0229% STATE INCOME TAX RATE 5.5000% 5.5000% STATE INCOME TAX 5.4463% 5.4463% NET BEFORE FEDERAL INCOME TAXES 93.5766% 93.5766% FEDERAL INCOME TAX RATE 21.0000% 21.0000% FEDERAL INCOME TAX 19.6511% 19.6511% REVENUE EXPANSION FACTOR 73.9255% 73.9255% NET OPERATING INCOME MULTIPLIER 1.3527 1.3527 NET OPERATING INCOME MULTIPLIER FLORIDA CITY GAS DOCKET NO. 20220069-GU PTY 12/31/23 ATTACHMENT 4
ORDER NO. PSC-2023-0177-FOF-GU Attachment 5 DOCKET NO. 20220069-GU PAGE 81 COMPANY COMMISSION ADJUSTED APPROVED $489,002,189 $487,257,875 RATE OF RETURN X 7.09% X 6.44% REQUIRED NOI $34,688,400 $31,363,264 ACHIEVED NOI 13,268,605 14,132,644 21,419,795 17,230,620 1.3527 1.3527 28,974,822 23,308,073 LNG Revenue (3,828,493) (3,828,493) Transfer of SAFE Investments (5,696,211) (5,330,459) INCREMENTAL REVENUE INCREASE $19,450,118 $14,149,121 COMPARATIVE REVENUE DEFICIENCY CALCULATIONS REVENUE DEFICIENCY RATE BASE (AVERAGE) REVENUE EXPANSION FACTOR NET REVENUE DEFICIENCY PTY 12/31/23 FLORIDA CITY GAS DOCKET NO. 20220069-GU ATTACHMENT 5
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OCR transcription for search; preserved printed pages are authoritative
FILED 6/9/2023
DOCUMENT NO. 03568-2023
FPSC - COMMISSION CLERK
BEFORE THE FLORIDA PUBLIC SERVICE COMMISSION
DOCKET NO. 20220069-GU
ORDER NO. PSC-2023-0177-FOF-GU
ISSUED: June 9, 2023
In re: Petition for rate increase by Florida City
Gas.
The following Commissioners participated in the disposition of this matter:
ANDREW GILES FAY, Chairman
MIKE LA ROSA
GABRIELLA PASSIDOMO
APPEARANCES:
CHRISTOPHER T. WRIGHT and JOEL T. BAKER, ESQUIRES, Florida Power
& Light Company, 700 Universe Boulevard, Juno Beach, FL 33408-0420
BETH KEATING, ESQUIRE, Gunster, Yoakley & Stewart, P.A., 215 South
Monroe St., Suite 601, Tallahassee, FL 32301-1804
On behalf of Florida City Gas (FCG).
MARY A. WESSLING and CHARLES REHWINKEL, ESQUIRES, Office of
Public Counsel, c/o The Florida Legislature, 111 West Madison Street, Room
812, Tallahassee, Florida 32399-1400
On behalf of the Citizens of the State of Florida (OPC).
MARCUS DUFFY, CAPT, USAF, HOLLY L. BUCHANAN, MAJOR, USAF,
and THOMAS A. JERNIGAN, ESQUIRES, AF/JAOE-ULFSC, 139 Barnes
Drive, Suite 1, Tyndall Air Force Base, FL 32403
On behalf of Federal Executive Agencies (FEA).
JON C. MOYLE, JR. and KAREN PUTNAL, ESQUIRES, Moyle Law Firm,
P.A., 118 North Gadsden Street, Tallahassee, Florida 32312
On behalf of Florida Industrial Power Users Group (FIPUG).
ADRIA HARPER and TIMOTHY SPARKS, ESQUIRES, Florida Public Service
Commission, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850
On behalf of the Florida Public Service Commission (Staff).
MARY ANNE HELTON, ESQUIRE, Deputy General Counsel, Florida Public
Service Commission, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399
Advisor to the Florida Public Service Commission.
KEITH C. HETRICK, ESQUIRE, General Counsel, Florida Public Service
Commission, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850
Florida Public Service Commission General Counsel.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 2
ORDER GRANTING IN PART AND DENYING IN PART
FLORIDA CITY GAS’ PETITION FOR CERTAIN RATE INCREASES
BY THE COMMISSION:
Table of Contents
Background ............................................................................................................................4
I. Rate Plan Duration
Four-year Rate Plan ...............................................................................................................5
II. Test Period and Forecasting
Projected Test Year ................................................................................................................7
Customer and Therm Forecasts .............................................................................................8
Estimated Gas Revenues ........................................................................................................9
III. Quality of Service
Quality of Service ..................................................................................................................10
IV. Depreciation
Depreciation Parameters ........................................................................................................11
Resulting Reserve Imbalances ...............................................................................................14
Corrective Depreciation Measures – RSAM .........................................................................15
Implementation Date for Revised Depreciation Rates...........................................................17
V. Rate Base
Adjustments to Reflect SAFE Investments............................................................................18
Advanced Metering Infrastructure (AMI) Pilot .....................................................................18
Plant in Service for LNG Facility ..........................................................................................20
Plant in Service ......................................................................................................................24
Non-Utility Activities ............................................................................................................26
Acquisition Adjustment .........................................................................................................26
Construction Work in Progress (CWIP) ................................................................................27
Gas Plant Accumulated Depreciation and Amortization .......................................................27
Under-Recoveries and Over-Recoveries in Working Capital Allowance .............................28
Unamortized Rate Case Expense ...........................................................................................28
Deferred Pension ....................................................................................................................29
Unbilled Revenues .................................................................................................................30
Working Capital .....................................................................................................................30
Rate Base ...............................................................................................................................31
VI. Cost of Capital
Accumulated Deferred Taxes ................................................................................................32
Short-Term Debt ....................................................................................................................33
Long-Term Debt ....................................................................................................................34
Customer Deposits .................................................................................................................36
Equity Ratio ...........................................................................................................................36
Return on Equity (ROE) ........................................................................................................39
Non-Utility Investments.........................................................................................................44
Weighted Average Cost of Capital (WACC).........................................................................44
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 3
VII. Net Operating Income
Purchased Gas Adjustment and Natural Gas Conservation Cost Recovery ..........................46
SAFE Investments .................................................................................................................46
Outside Service Costs ............................................................................................................46
Miscellaneous Revenues ........................................................................................................47
Total Operating Revenues for the Projected Test Year .........................................................48
Non-Utility Activities ............................................................................................................48
Salaries and Benefits ..............................................................................................................49
Affiliate Expenses ..................................................................................................................51
Pensions and Post-Retirement Benefits Expenses .................................................................52
Injuries and Damages Expense ..............................................................................................53
Insurance Expense .................................................................................................................54
Projected Contractor Cost ......................................................................................................55
O&M Expenses Adjustment ..................................................................................................55
Storm Damage Reserve..........................................................................................................56
Parent Debt Adjustment (PDA) .............................................................................................57
Rate Case Expense .................................................................................................................58
Uncollectible Accounts and Bad Debt ...................................................................................59
O&M Expenses ......................................................................................................................60
Taxes Other Than Income (TOTI) .........................................................................................60
Test Year Income Tax Expense .............................................................................................61
Operating Expenses ...............................................................................................................62
Net Operating Income ............................................................................................................62
VIII. Revenue Requirements
Revenue Expansion Factor and Net Operating Income Multiplier ........................................62
Annual Operating Revenue Increase .....................................................................................63
IX. Cost of Service and Rate Design
Cost of Service Study (COSS) ...............................................................................................64
Revenue Increase Allocation ................................................................................................66
Proposed Customer Charges ..................................................................................................68
Distribution Charges ..............................................................................................................69
Demand Charges ....................................................................................................................69
Connect and Reconnection Charges ......................................................................................69
Transportation Customer Charge Application to Third Party Suppliers ...............................70
Effective Date for Revised Rates and Charges ......................................................................70
Approval of Tariffs Reflecting Approved Rates and Charges ...............................................70
X. Other Issues
Proposal For Addressing A Potential Change In Tax Law ....................................................71
SAFE Program Expansion for Mains and Services ...............................................................72
SAFE Program Expansion for “Orange Pipe” .......................................................................72
Description of Adjustments ...................................................................................................73
Attachment 1 ..........................................................................................................................76
Attachment 2 ..........................................................................................................................77
Attachment 3 ..........................................................................................................................78
Attachment 4 ..........................................................................................................................80
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 4
Attachment 5 ..........................................................................................................................81
Attachment 6 ..........................................................................................................................82
Background
On May 31, 2022, Florida City Gas (FCG or Company) filed a petition seeking the
Florida Public Service Commission’s (Commission) approval of a rate increase and associated
depreciation rates based on a projected test year ending December 31, 2023. FCG is a natural gas
local distribution company providing sales and transportation of natural gas, and is a public
utility subject to this Commission’s regulatory jurisdiction under Chapter 366, Florida Statutes
(F.S.). As a subsidiary of Florida Power & Light Company (FPL), FCG currently serves
approximately 116,000 residential, commercial, and industrial natural gas customers in Miami-
Dade, Broward, St. Lucie, Indian River, Brevard, Palm Beach, Hendry, and Martin counties.
Specifically, FCG’s request consists of: (a) an increase in base rates and charges
sufficient to generate a total base revenue increase of $29.0 million based on a projected 2023
Test Year, which includes (i) an incremental base rate revenue requirement of $18.8 million, (ii)
the revenue requirements for the previously approved Liquefied Natural Gas (LNG) Facility, and
(iii) the reclassification of the Safety, Access, and Facility Enhancement (SAFE) program
revenues from clause to base rates; (b) a 10.75 percent mid-point return on equity (ROE) and an
equity ratio of 59.6 percent from investor sources for all regulatory purposes; (c) implementation
of a reserve surplus amortization mechanism (RSAM), which is a critical and essential
component of FCG’s four-year rate plan; (d) approval of RSAM-adjusted depreciation rates,
which is necessary to support the RSAM and decreases the incremental revenue requirement by
$2.7 million; (e) the continuation of the Storm Damage Reserve provision approved as part of
FCG’s 2018 Settlement Agreement, as modified to reflect the Commission’s new storm rule for
gas utilities; (f) a mechanism that will allow FCG to adjust base rates in the event tax laws
change during or after the conclusion of this proceeding; (g) continuation and expansion of the
existing SAFE program, which will allow FCG to further improve safe and reliable service to
customers and the communities it serves; and (h) implementation of a new limited advanced
metering infrastructure pilot program (AMI Pilot) that will enable FCG to explore the potential
for AMI meters to provide enhanced service to FCG’s customers.
FCG initially requested an increase of $29.0 million in additional annual revenues, but
reduced its request to $28.3 million. Of that amount, $5.7 million is associated with the
reclassification of the Company’s SAFE program revenues from surcharge to base rates and $3.8
million is related to the revenue requirements for the previously approved LNG Facility.
Additionally, the remaining $18.8 million is necessary, according to FCG, for the Company to
earn a fair return on its investment and to adopt the requested RSAM designed to manage
earnings in order to mitigate the need for rate relief during the next four years. FCG based its
request on a 13-month average rate base of $489 million for the projected test year ending
December 31, 2023. The requested overall rate of return is 7.09 percent based on a mid-point of
10.75 percent return on equity.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 5
The Company’s last rate case was filed on October 23, 2017, and was resolved by the
Commission’s approval of a settlement agreement in 2018 (2018 Settlement Agreement). 1 The
Commission-approved settlement agreement provided the opportunity for FCG to increase its
base rates and charges to generate an additional $11.5 million in revenues for the projected test
year ending December 31, 2018. The settlement agreement also authorized a return on equity of
10.19 percent.
We acknowledged intervention by the Office of Public Counsel (OPC), and intervention
was granted to the Federal Executive Agencies (FEA) and to the Florida Industrial Power Users
Group (FIPUG) (collectively “Intervenors”). In a previous order, we suspended the proposed
permanent increase in rates and charges.
Three virtual and two in-person customer service hearings were held in September of
2022. A total of thirteen customers participated at the virtual service hearings and four customers
spoke at the in-person service hearings, and all spoke favorably of FCG’s quality of service, with
some also expressing concerns regarding a rate increase. The Commission received letters from
six customers that were placed in the docket. All of the customers urged the Commission not to
increase their gas rates during these financially challenging times, and one customer commented
on the poor customer service that they had experienced.
An administrative hearing was held December 12-13, 2022. At the hearing, we approved
proposed stipulations on a number of issues, as reflected herein. The parties filed post-hearing
briefs which argued their positions on the issues litigated at the administrative hearing. After the
parties filed their briefs, we held Special Agenda Conferences on March 28 and April 25, 2023 to
address those issues.
The Commission has jurisdiction over this matter pursuant to Chapter 366, F.S.,
including Sections 366.041, 366.06, and 366.071, F.S.
Decision
I. Rate Plan Duration
A. Four-year Rate Plan
1. Parties’ Arguments
FCG argued that its requested four-year rate plan would provide rate stability and
benefits to customers that would not be available with a single-year rate plan. FCG argued that
disapproval of the Company’s proposed four-year rate plan would cost customers more.
Additionally, FCG argued that if we approved the four-year plan, our final Order would be both
binding and enforceable against all parties to this docket, and thus FCG would be obligated to
comply with the requirements and limitations of the four-year plan.
1 Order No. PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate
increase by Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 6
OPC argued that, absent a settlement agreement, this Commission does not have
authority or precedent for approving a provision requiring a utility to “stay out” of base rate
proceedings before this Commission for a set period of time; therefore, it should not approve
FCG’s requested four-year rate plan. OPC argued that absent a settlement agreement, this
Commission must review each request and determine whether it will result in fair, just, and
reasonable rates.
OPC also argued that we would have no enforceable way to prevent FCG from requesting
a new rate case before the “stay-out” period ended. OPC cited Order No. PSC-2021-0446-S-EI,
where a “stay-out” provision was an issue in the proceeding; however, the case was ultimately
resolved with a settlement agreement and a ruling by this Commission on the propriety of the
provision was never made. OPC also argued that when questioned at the hearing, FCG appeared
to waver in its commitment not to request another rate increase for four years, specifically given
factors such as inflationary pressures. FIPUG adopted the position of OPC.
2. Analysis
Although a significant portion of FCG’s rate plan was FCG’s stated commitment to not
request another general base rate increase effective prior to January 1, 2027, FCG acknowledged
that, if the rate plan was approved, this Commission would have full regulatory oversight of rates
and charges and the Company would continue to provide earnings surveillance reports as
required. We agree with OPC that regardless of any assurances to the contrary, FCG cannot
guarantee it would not seek a base rate increase before 2026. To ensure fair, just, and reasonable
rates are charged, section 366.06(2), F.S., provides that if a utility’s rates are insufficient to yield
reasonable compensation, it may request a proceeding in order for the Commission to determine
just and reasonable rates. On the other hand, if we find that rates are excessive, the Commission
can initiate a proceeding upon a request from an affected person or on its own motion to
determine just and reasonable rates.
3. Conclusion
Section 366.06(2), F.S., states that if a utility’s rates are insufficient to yield reasonable
compensation it may request a proceeding in order for the Commission to determine just and
reasonable rates. Likewise, if we find that rates are excessive, we can initiate a proceeding to
determine just and reasonable rates. Accordingly, while we have resolved base rate cases in
previous years that include multi-year increases to rates, and in settlement agreements we have
approved “stay-out” provisions, we continue to recognize our obligation to monitor utility
earnings and, if circumstances warrant, require additional proceedings. For these reasons, we
acknowledge FCG’s commitment while also noting that approval of FCG’s plan, either in part or
its entirety, would not prohibit future proceedings on these matters over the next four years.
Thus, this Order addresses whether there is record evidence to support the other elements of
FCG’s proposal, including the single incremental base revenue increase, requested ROE and
equity ratio, cost of service, an RSAM, the SAFE program, the AMI Pilot program, potential tax
law changes, and the Storm Damage Reserve.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 7
II. Test Period and Forecasting
A. Projected Test Year
1. Parties’ Arguments
FCG witness Campbell argued that the 2023 projected test year used by the Company,
based on the 12-month period ending December 31, 2023, best reflects the Company’s revenues,
costs, and investments during the year in which new rates are proposed to go into effect. The
Company also proposed that new base rates become effective February 1, 2023, at a level
“sufficient to recover the Company’s revenue requirements in 2023 with an opportunity to earn a
fair and reasonable return.”
OPC argued in its brief that FCG failed to meet the burden of demonstrating that the
projected 2023 test year is appropriate as the Company has refused to demonstrate that there will
be no merger activities that will affect the appropriateness of the test period. OPC further argued
that its concerns about potential merger or sale activities are not merely “idle speculation,” citing
the acquisition of FCG by NextEra Energy from Southern Company during the Company’s 2017
rate case. OPC continued that this acquisition was done during the 2017 rate case “without
informing the Commission or parties to the case and settlement.” OPC stated that, although FCG
witnesses Campbell and Fuentes have each denied that there are ongoing merger or sale activities
that would affect rates, “neither witness could unequivocally state that they would be in a
position to know under all circumstances.”
2. 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. OPC and FIPUG
agree that the 2023 test year may be representative of the period of time in which rates will be in
effect, with the caveat of “with appropriate adjustments” and “no imminent merger or sale
activities.” However, OPC argued that the Company did not adequately demonstrate there will
be no merger activities that will affect the appropriateness of the test year, and therefore, the test
period ending December 31, 2023 is not appropriate for setting rates. FCG argued that the
Intervenors’ concerns about potential merger activities are unsupported by the record and should
be rejected, as there is “no evidence of any merger or sale activity, costs, or savings included in
FCG’s 2023 Test Year.”
3. Conclusion
We find that denying the use of a projected test year based solely upon the possibility of
merger activities, as argued by the Intervenors, is not reasonable. With regard to the Intervenors’
assertion that “appropriate adjustments” be made to the 2023 test year, no Intervenors cited any
specific adjustments or alternatives to the 2023 test year relating to this issue.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 8
We find that FCG’s proposed 2023 test year will result in a matching of the Company’s
revenues to be produced, during the first twelve months in which the new rates would be in
effect, with average rate base investment and average expenses for the same period. Therefore,
we find the projected test period of the twelve months ending December 31, 2023, is appropriate.
B. Customer and Therm Forecasts
1. Parties’ Arguments
FCG witness Campbell testified that the Company’s customer and therm forecasts were
developed using statistically sound econometric and regression models and included logically
reasonable drivers obtained from leading industry experts. Witness Campbell further stated that the
Company’s customer and therm forecasts were evaluated for reasonableness by comparing
forecasted trends against historical trends and other growth factors. Witness Campbell argued that
the forecasting approach used in this case is consistent with the criteria used by the Commission in
previous proceedings.2
OPC argued that adjustments should be made with regard to the Company’s customer
and therm forecasts, while noting that the forecasts typically become less reliable the further they
are projected into the future.
2. Analysis
In this case, FCG provided forecast models that detail the Company’s historical and
forecasted customer counts and therm sales. FCG witness Campbell stated that the Company’s
customer forecasts reflect the total number of active accounts served by FCG and include factors
such as estimates of new service installations and changes in the number of inactive accounts, while
the Company’s therm sales reflect the amount of natural gas provided to all customers served by
FCG. The Company projected a customer count of approximately 117,487 and therm sales of
approximately 173,612,198 for the 2023 test year. The Intervenors did not present testimony or
evidence to disprove FCG’s test year forecast models or assumptions, and did not propose any
adjustments to FCG’s forecasts of customers and therms for the projected test year.
2 In its brief, FCG cited: Order No. PSC-16-0032-FOF-EI, issued January 19, 2016, in Docket No. 20150196-EI, In re:
Petition for determination of need for Okeechobee Clean Energy Center Unit 1, by Florida Power & Light Company;
Order No. PSC-14-0590-FOF-EI, issued October 21, 2014, in Docket No. 20140111-EI, In re: Petition for determination
of cost effective generation alternative to meet need prior to 2018, by Duke Energy Florida, Inc.; Order No. PSC-13-
0505-PAA-EI, issued October 28, 2013, in Docket No. 20130198-EI, In re: Petition for prudence determination
regarding new pipeline system by Florida Power & Light Company; Order No. PSC-12-0179-FOF-EI, issued April 3,
2012, in Docket No. 20110138-EI, In re: Petition for increase in rates by Gulf Power Company; Order No. PSC-12-
0187-FOF-EI, issued April 9, 2012, in Docket No. 20110309-EI, In re: Petition to determine need for modernization of
Port Everglades Plant, by Florida Power and Light Company; Order No. PSC-09-0375-PAA-GU, issued May 27, 2009,
in Docket No. 20080366-GU, In re: Petition for rate increase by Florida Public Utilities Company.; Order No. PSC-04-
0128-PAA-GU, issued February 9, 2004, in Docket No. 20030569-GU, In re: Application for rate increase by City Gas
Company of Florida.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 9
3. Conclusion
Based on an analysis of FCG’s historical customer and usage data (2010-2021), year-to-date
accuracy (2022), and year-over-year growth rates, we find the forecast models and assumptions
utilized by FCG provide a reasonable estimate of the Company’s customer counts and therm sales,
by rate class, for the 2023 test year. Therefore, we find the Company’s customer and therm sales
forecasts for the projected test year are reasonable and appropriate, and no adjustments are
necessary.
C. Estimated Gas Revenues
1. Parties’ Arguments
We next address whether FCG’s estimated revenues from sales of gas by rate class at
present rates for the projected test year are appropriate. FCG argued that the same reasonable
forecasting methodologies described in section II above were applied in developing its estimated
revenues from sales of gas. The Company stated that these methodologies included statistically
sound models and logically reasonable drivers obtained from leading industry experts. FCG
argued that the record supports finding that the Company’s projected revenues from the sale of
gas by rate class have been “calculated based upon reliable, robust, and accepted methods.”
OPC noted that witness Campbell stated both that he did not forecast the impact of
potential growth in customers on 2024 and 2025 revenues, but he estimated that this growth
would result in approximately $200,000 in additional revenues per year. OPC also noted that
witness Campbell said that the Company’s customer and therm forecasts typically become
progressively less reliable the further they are projected into the future.
2. Analysis
FCG provided forecast models which detail the Company’s forecasted customer counts
and therm sales for the 2023 test year. Once FCG established these forecasts for the projected
test year, the Company multiplied them by current rates for each customer class and combined
those results to yield total revenues. The Company forecasted a total of $62,828,352 in revenues
from sales of gas at present rates for the 2023 test year.
There was an exception to the Company’s revenue forecast process for one customer
class - Load Enhancement Service (LES). As detailed in MFR E-1, page 2 of 3, the forecasted
revenues include a positive adjustment in the amount of $155,495 to reflect revenues associated
with the LES rate class. FCG witness Debose testified that the LES customer class is an existing
optional rate available to customers who can provide “verifiable documentation showing a viable
alternative fuel or the opportunity to completely bypass FCG’s system.” In an effort to retain
these customers on FCG’s system, the Company’s LES customers are eligible for a discounted,
negotiated rate. The discount is recovered from the general body of ratepayers through the
Competitive Rate Adjustment (CRA) rider. The Company explained that for the purposes of the
revenue forecast, the LES customers were forecast at one hundred percent of their otherwise
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 10
applicable rate schedules. FCG argued that this approach “better aligns the revenues and costs
incurred to provide service to the LES customers with the appropriate rate schedule, while
recognizing that the difference between the revenues under the tariffed rate and the negotiated
LES rate are recovered through the CRA.” We find this approach is reasonable for the purposes
of estimating test year revenues for LES customers.
3. Conclusion
We have confirmed that FCG used the correct current rates and billing determinants
consistent with the Company’s forecasts for all customer classes in their calculations of test year
revenue. We find that in all instances the revenue forecasts for all customer classes are
reasonable. Furthermore, we note that the Intervenors did not present testimony or evidence to
rebut FCG’s test year forecast of revenues from sales of gas at current rates.
Thus, we find that FCG's estimated revenues from sales of gas by rate class at present
rates for the projected test year, totaling $62,828,352, are reasonable and appropriate. This
amount includes the Company-noted adjustment of $155,495 to reflect additional revenues
associated with the Load Enhancement Service rate class.
III. Quality of Service
A. Quality of Service
1. Parties’ Arguments
FCG argued that it provides safe, reliable, and high-quality service to customers and the
communities it serves. The Company argued that none of the customers that participated at the
service hearings expressed any negative views of FCG, and were instead complimentary of the
Company and its employees. FCG asserted that it has taken steps since its last rate case to
implement customer experiences and process improvements.
OPC noted that at least one customer submitted a comment expressing dissatisfaction
with the quality of service provided by FCG.
2. Analysis
Pursuant to Section 366.041, 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. Pursuant to Rule 25-7.018, Florida Administrative Code
(F.A.C.), each utility must keep a complete record of all interruptions affecting the lesser of 10
percent or 500 or more of its division meters. Based on FCG’s filing, there were no customer
interruptions affecting either 10 percent or 500 meters during the historic test year.
The Commission held three virtual service hearings on September 14 and 15, 2022, as
well as two in-person service hearings within FCG’s service territory on September 20 and 21,
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 11
2022. These hearings provided an opportunity for FCG’s approximately 116,000 customers to
raise concerns regarding the Company’s quality of service and its request for a rate increase. A
total of thirteen customers participated at the virtual service hearings, all of whom spoke
positively of the Company’s quality of service, although one customer also voiced opposition to
the rate increase. Four customers spoke at the in-person service hearings, and all spoke favorably
of FCG’s quality of service, while one customer also expressed concerns regarding the size of
the rate increase.
We also examined the complaints presented in staff witness Calhoun’s testimony and
observed that the number of service complaints has continually decreased since 2018. Staff
witness Calhoun testified that, from July 1, 2017, to June 30, 2022, 584 complaints were logged
with the Commission with 489 of those being transferred to FCG. Of the complaints,
approximately 52 percent concerned billing issues and approximately 48 percent involved
quality of service issues. Additionally, witness Calhoun testified that four billing complaints and
one service quality complaint appeared to demonstrate a violation of Commission Rules.
FCG witness Howard testified that the customer comments made at the service hearings
were complimentary of the Company and the large majority of the customer contacts received by
the Commission were informational in nature. Only 87 of the customer contacts were logged as
complaints, with 4 being possible rule violations. Witness Howard testified that efforts had been
made since 2018 to update the customer complaint resolution process. These efforts included: (1)
creating a process to handle more complex questions from customers that cannot be adequately
answered on the initial call; (2) cataloguing and addressing common complaints expressed by
customers; (3) identifying and incorporating best practices from FPL’s customer complaint
process; (4) implementing a management review process for Commission complaints; (5)
instituting a one-call resolution target for Warm-Transfers; and (6) establishing internal goals to
reduce complaints. None of the intervenors took issue with FCG’s quality of service.
3. Conclusion
Based on a review of all witness and customer testimony, we find that the Company’s
quality of service is adequate.
IV. Depreciation
A. Depreciation Parameters
Depreciation rates are calculated using parameters which include the Average Service
Life (ASL), curve shape, the remaining life (in years), net salvage percentage, and reserve
percentage. In order to arrive at the appropriate resulting depreciation rates, each parameter plays
a part in the calculation.
In the development of depreciation rates, the first parameter reviewed is the ASL, which
denotes the average number of years that the asset is expected to be in-service. While the ASL
may be based, at least in part, on historical data, it is prospective in its outlook and
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 12
implementation. Iowa curves are used to determine the remaining life of a particular type of asset
by graphically representing the retirement patterns of utility assets. These are well-established
depreciation tools. Each curve is denoted by a letter that defines when retirements are more
likely to occur. An L curve implies that retirements tend to occur prior to the ASL, while an R
curve implies that retirements tend to occur after the ASL.
The next parameter is the average remaining life, which is the average number of in-
service years left for plant currently in service. FCG presented evidence that “service life
estimates in any given depreciation study are, by their nature, estimates of what is expected to
occur in the future based on information available at the time of the study.” The third parameter
for determining depreciation rates, net salvage, is gross salvage minus cost of removal. Net
salvage is based on historical data but is also prospective in outlook. The last parameter needed
for calculating depreciation rates is the reserve percentage which represents the portion of the
investment accumulated through depreciation expense to date. The reserve percentage is
calculated by dividing the book reserve by the original cost of plant.
Three proposals were put forward to calculate depreciation rates for each distribution and
general plant account: FCG’s traditional 2022 Depreciation Study (2022 Study), OPC’s
adjustments to FCG’s 2022 Study, and FCG’s Reserve Surplus Amortization Mechanism
(RSAM) adjusted parameters. Each scenario proposed slightly different estimates for service
lives and other depreciation parameters across various accounts.
1. Parties’ Arguments
While FCG performed a traditional depreciation study as presented by Witness Allis, the
Company also advocated for the use of its RSAM-adjusted parameters. FCG argued that the
RSAM-adjusted parameters are the appropriate ones to use in conjunction with FCG’s proposed
RSAM because they are reasonable and they are the same as those approved through a settlement
agreement in Peoples Gas System’s most recent base rate case, with the exception of FCG’s
LNG Facility. Furthermore, FCG argued that the RSAM-adjusted parameters are very similar to
the ones OPC witness Garrett has proposed in this and similar cases.
OPC argued in favor of its own method of calculating depreciation rates, stating that OPC
witness Garrett developed his recommended depreciation rates using “the straight-line method,
the average life procedure, the remaining life technique, and the broad group model.” OPC
witness Garrett used FCG’s aged property data to develop an “observed life table” (OLT), which
was then compared to survivor curves.
OPC asserted that if all of witness Garrett’s proposed depreciation adjustments were
applied to the 2022 Study, projected test year depreciation expense would be reduced by
$1,543,130 and projected test year accumulated depreciation would be reduced by $771,565
when compared to witness Allis’ 2022 Study parameters. OPC argued the adjustments to FCG
witness Allis’ depreciation parameters, as offered by witness Garrett, should be adopted in this
case, and that the remaining life technique should be used to address any resulting reserve
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 13
imbalance. OPC also opposed FCG’s use of the RSAM-adjusted parameters, arguing the
Commission lacked the authority to implement the RSAM outside of a settlement agreement.
2. Analysis
FCG presented testimony that both the traditional 2022 depreciation study and the RSAM
adjusted parameters fell within a “range of reasonableness” when compared to the depreciation
studies of other gas utilities. There was also testimony that the traditional 2022 Study parameters
and OPC’s proposed depreciation parameters would not result in a large enough reserve for the
RSAM to function properly.
FCG also offered testimony that depreciation parameters are only estimates of what may
occur in the future and therefore it is inevitable that those estimates will result in surpluses and
deficits, and thus the RSAM parameters were reasonable. FCG asserted the Commission’s
depreciation rule, which requires gas utilities to file a depreciation study every five years,
recognizes and accounts for this variability. In support of its RSAM, FCG also offered evidence
that the National Association of Regulatory Utility Commissioners (NARUC) states that the true
depreciation parameters only become known “after the plant has lived its entire useful life.”3
Additionally, FCG asserted the RSAM-adjusted depreciation parameters are a reasonable
alternative given that they are based on a similar utility in the same geographic location with
similar assets. FCG witness Campbell stated that the assets and facilities on FCG’s system are
similar to the assets used by Peoples Gas System, and are located in similar geographic regions,
making the RSAM parameters a reasonable alternative to the depreciation study. Witness
Campbell further testified that the RSAM-adjusted parameters themselves are similar to those
offered by OPC witness Garrett in this case, arguing this further supports their reasonableness.
3. Conclusion
FCG witness Campbell presented credible testimony and we find the appropriate
depreciation parameters in this case are the RSAM-adjusted parameters proposed by FCG.
Accordingly, we find that the appropriate depreciation parameters and resulting depreciation
rates for each distribution and general plant account are those shown on Table 1 below. As a
result, the appropriate amount of Depreciation and Amortization Expense for the projected test
year is $17,316,573. The resulting reserve imbalance is discussed more fully in the next section.
3 National Association of Regulatory Commissioners Public Utility Depreciation Practices, p. 189
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 14
Table 1
Depreciation Parameters
Account Number Account Title
Curve
Type
Average
Service
Life
(yrs)
Average
Remaining
Life
(yrs)
Reserve
(%)
Future
Net
Salvage
(%)
Remaining
Life Rate
(%)
DISTRIBUTION
PLANT
375 Structures & Improvements L0 33 31.00 9.07 0 3.8
376.1 Mains - Steel R1.5 65 50.32 51.42 (50) 2.0
376.2 Mains - Plastic R2 75 65.88 28.33 (33) 1.6
378 Measuring & Regulating Equip. - General R1.5 40 36.88 13.64 (10) 2.6
379 Measuring & Regulating Equip. - City Gate R2.5 50 40.64 28.40 (10) 2.0
380.1 Services - Steel R0.5 52 32.15 89.49 (125) 2.5
380.2 Services - Plastic R1.5 55 46.56 25.68 (68) 3.1
381 Meter R2 19 12.43 30.11 3 6.9
381.1 Meters - ERT R2 19 14.42 21.22 3 9.7
382 Meter Installations R1 44 34.95 28.53 (25) 3.6
382.1 Meter Installations - ERT R1 44 36.23 33.08 (25) 10.3
383 House Regulators S1 42 33.08 24.92 0 2.3
384 House Regulators Installations R1 47 34.93 5.16 (25) 3.4
385 Industrial Measuring & Reg. Station Equip R3 37 17.79 60.92 (2) 2.3
387 OTHER EQUIPMENT L2 24 18.05 20.34 0 4.4
GENERAL
PLANT
390 Structures & Improvements L0 25 20.23 18.27 0 4
392 Transportation Equipment L2 12 4.66 33.68 4 13.4
392.1 Transportation Equip. - Auto & Light Trucks L2.5 9 4.19 63.75 11 6.0
392.2 Transportation Equip. - Service Trucks L3 10 6.05 49.13 11 6.6
392.3 Transportation Equip. - Heavy Trucks L2 12 6.53 45.8 4 7.7
394.1 Natural Gas Vehicle Equipment S4 20 13.5 60.18 0 3.0
B. Resulting Reserve Imbalances
1. Parties’ Arguments
FCG argued that the appropriate reserve imbalance based on the RSAM-adjusted
depreciation rates would be $52.1 million. FCG explained that, under the RSAM scenario, $25
million would be available for the Company to amortize during the 2023-2026 timeframe. FCG
contended that even with the $25 million Reserve Amount, FCG would still have to find cost
savings to reach the proposed midpoint ROE.
OPC witness Garrett testified that when a reserve imbalance exists, the remaining life
technique should be used to address the imbalance over the remaining life of the assets.
2. Analysis and Conclusion
The formula for the Theoretical Reserve, Book Investment – Future Accruals – Future
Net Salvage, is provided in Rule 25-7.045(4)(k), F.A.C. FCG witness Allis also calculated a
$50.8 million theoretical reserve surplus for FCG’s distribution accounts and a $1.3 million
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 15
reserve surplus related to its general plant accounts, based on FCG witness Fuentes’ proposed
RSAM life and salvage parameters. We agree with witness Allis’ calculations. Using this
formula and the values for the life and salvage components that we found above, we calculate a
total reserve imbalance of $52,126,500, comprised of $50,813,200 in the Distribution account
and $1,313,300 in the General account.
C. Corrective Depreciation Measures - RSAM
1. Parties’ Arguments
Because the approval of the RSAM parameters will result in a reserve imbalance, we next
address what corrective measures should be taken with regard to that reserve imbalance. FCG
asserted that its proposed RSAM is an appropriate and critical component of FCG’s proposed
rate plan and in conjunction with the other components of the plan, the RSAM will enable FCG
to avoid increasing base rates through at least the end of 2026. According to FCG, the expected
benefits resulting from the RSAM will provide significant customer benefits and savings
including a lower annual revenue requirement, avoiding repetitive and costly rate proceedings,
providing customers with rate stability and certainty, and enabling FCG to focus on providing
safe, reliable, and affordable service to its customers.
Additionally FCG asserted that without the RSAM, it would fall below its proposed ROE
range and would need to file an additional rate case in 2024 for a base rate increase in 2025.
According to FCG, its RSAM-adjusted depreciation rates are based on the depreciation
parameters recently agreed to and approved in the PGS base rate case in Docket No. 20200051-
GU and therefore they represent a reasonable alternative to those contained in FCG’s 2022
Depreciation Study. FCG argued that these RSAM-adjusted depreciation parameters are within
the range of reasonableness, and are in line with those approved for other similar natural gas
utilities in Florida. FCG asserted that the evidence supports a finding that FCG’s proposed
RSAM is fair, just, and reasonable and should therefore be approved.
OPC argued that use of the RSAM, absent a settlement, is inconsistent with both Rule 25-
7.045, F.A.C., and the statutory requirement to set just and reasonable rates set forth in Chapter
366, F.S. OPC asserted that absent a stipulation of the parties, the Commission lacks the
authority to approve an RSAM mechanism that can be utilized in conjunction with the surplus or
Reserve Amount. OPC also argued that the proposed RSAM could be used to enhance
shareholder earnings and maintain FCG’s earnings at the top of the authorized range, and
asserted it would limit the Commission’s and other parties’ ability to review FCG’s rates in the
future by creating a self-regulating mechanism.
FEA also opposed the RSAM and reiterated OPC’s arguments that the proposed RSAM
would be used to respond to changes in underlying revenues and expenses in order to maintain a
set ROE. FEA argued that FCG’s proposed RSAM improperly shifts the risk of revenue recovery
to customers, and allows FCG to adjust its depreciation expense leading to an artificially inflated
rate base by distorting the accurate measurement of assets.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 16
FEA witness Collins also testified the proposed RSAM would lead to potential future
costs to FCG customers and would be used to increase the Company’s earnings and its return.
FIPUG joined the arguments of FEA.
2. Analysis
We recognize that our approval of the RSAM depreciation parameters above will result
in a reserve imbalance, which we will address here. Before we do so, we first acknowledge that
OPC raised the issue of our statutory authority to approve an RSAM.
We disagree with OPC that the Commission lacks authority to approve accounting
mechanisms like the proposed RSAM unless it does so in a settlement agreement. Chapter 366,
F.S., sets forth the Commission’s jurisdiction and authority to fix fair, just, and reasonable rates.
The Commission’s jurisdiction and authority to fix fair, just, and reasonable rates pursuant to
Chapter 366, F.S., are not conditioned upon whether the case is litigated or settled.
While the standard of review differs in a settlement versus a litigated rate case, it does not
change the Commission’s statutory authority or jurisdiction. In other words, a settlement, which
operates under the public interest standard, cannot legally grant or change the Commission’s
jurisdiction and authority; only the legislature can do that. To hold that the Commission can only
approve an RSAM in a settlement but not in a litigated proceeding would mean that the parties to
a settlement can somehow circumvent or expand the Commission’s legal jurisdiction and
authority beyond what is granted by Chapter 366, F.S.
We also recognize that there was competing testimony about whether the RSAM should
be approved in this case and whether it will benefit customers. We are persuaded by the
testimony that the RSAM would allow FCG to manage its day-to-day fluctuations as well as take
on the risk of both actual current as well as potential future increases in interest rates and
inflation. FCG proposes having a Reserve Surplus amount of $25 million available for managing
these daily fluctuations in revenues and expenses, but FCG did not propose any treatment for the
remaining reserve surplus of $27.1 million. Therefore, that remaining surplus would remain on
FCG’s books and records until the Company files its next depreciation study.
While there was testimony offered that the RSAM would shift risk to customers, FCG
offered evidence that its rate plan with the RSAM would result in fair, just, and reasonable rates.
By approving the proposed RSAM, we believe FCG is in the best position to maintain its ROE
within the approved range and thus reduce the likelihood of additional rate increases in the near
future. As we expressed at our Agenda Conference on April 25, 2023, we are mindful of today’s
economy and the effects of inflation on customers and their utility bills. FCG offered testimony
that adopting the proposal allows FCG to manage typical day-to-day fluctuations associated with
running a utility business, while also having to absorb potentially higher costs resulting from
inflation and rising interest rates. FCG also offered testimony that the use of the RSAM reduces
the average residential bill by approximately $0.94 per month, the average commercial and
industrial bill by approximately $5.15 per month, and the average GS-1 bill by approximately
$465.83 per month.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 17
FCG’s evidence showed the RSAM will provide customer benefits including rate
stability and certainty. There was also FCG testimony that by avoiding repetitive and costly rate
proceedings, its rate proposal will save customers an approximate additional $2.0 million in rate
case expense while still enabling the company to meet the natural gas needs of existing and new
customers while continuing to provide safe, reliable, and high-quality customer service.
3. Conclusion
We have the authority to approve an RSAM and accordingly approve FCG’s proposed
use of the RSAM along with its Reserve Surplus of $25 million. We find the RSAM will result
in a reduction of revenue requirement, save customers money on their utility bills, and give FCG
the ability to manage its day-to-day business fluctuations, and allow FCG to take on the risk of
increases in interest rates and inflation. FCG did not propose any treatment for the remaining
reserve surplus of $27.1 million. Therefore, we find that the remaining surplus shall remain on
FCG’s books and records until the Company files its next depreciation study.
D. Implementation Date for Revised Depreciation Rates
1. Parties’ Arguments
FCG witness Fuentes argued the implementation date for revised depreciation rates
should be the effective date of the new base rates. FCG argued that this will be a matching of the
new base rates with the new depreciation rates. FCG further argued that, without approval by the
Commission for retroactive implementation, the implementation date for new depreciation rates
should precede the Order approving such depreciation rates. OPC argued the revised rates should
be effective January 1, 2023.
2. Analysis
Rule 25-7.045(4)(d), F.A.C., requires that the data submitted in a depreciation study,
including plant and reserve balances or Company estimates, “shall be brought to the effective
date of the proposed rates.” Our staff confirmed that the plant and reserve balances were as of
December 31, 2022, thus matching an implementation date of January 1, 2023. Furthermore, the
Projected Test Year MFRs in this case were based on the period January 1, 2023, through
December 31, 2023. FCG stated that the company filed its 2022 Study, along with the alternative
RSAM-adjusted depreciation rates, direct testimony, and MFRs in compliance with Rule 25-
7.045, F.A.C.
3. Conclusion
FCG provided depreciation study data extending through December 31, 2022 and did not
provide study data for the month of January 2023. Therefore, in order to comport with Rule 25-
7.045(4)(d), F.A.C., (the Depreciation Rule), the implementation date of the new depreciation
rates and amortization schedules shall be January 1, 2023, not February 1, 2023.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 18
V. Rate Base
A. Adjustments to Reflect SAFE Investments
There is no dispute about the adjustments to properly reflect SAFE investments. At
hearing, we approved a stipulation whereby all parties agreed that $5.7 million of SAFE revenue
requirements were appropriately transferred from clause recovery to base rates in the 2023 Test
Year as required per our previous order.4
B. Advanced Metering Infrastructure (AMI) Pilot
1. Parties’ Arguments
FCG is requesting a research and development pilot to evaluate Advanced Metering
Infrastructure (AMI) with two-way communication capability. FCG attested that its proposed
AMI Pilot will provide information on the potential benefits of deploying AMI with two-way
communications system-wide. FCG argued that under the AMI Pilot, it will gather information
on the benefits of automated remote readings, and the corrosion resistance and life of the 5,000
new smart meters to be installed under the pilot. FCG argues this is an appropriate sample size to
determine benefits for the whole system while potentially reducing the costs.
OPC argued that the Commission should not approve FCG’s proposed AMI Pilot because
the benefits to customers are unknown, and because FCG did not attempt to estimate potential
customer savings. In addition, OPC contended that FCG admitted that AMI technology has only
been deployed by a small number of gas utilities in the country, and not at all in Florida. OPC
asserted that by including this program in its rate request without any estimation of potential
savings, FCG is attempting to recover costs for this program from customers imprudently.
Therefore, OPC recommended that the Commission deny the AMI Pilot because FCG has not
demonstrated the prudence of this program.
2. Analysis
Pilot programs are typically vehicles through which utilities explore new technologies or
processes so they can assess the benefits using a sample prior to system-wide implementation. In
this case, FCG is planning to replace 5,000 meters under the AMI Pilot, which would provide a
large enough sample to test the benefits of smart meters with AMI technology on FCG’s system
without creating excessive costs, as this represents less than five percent of FCG’s customer
meters.
FCG argued in its brief that, as part of the pilot, FCG would collect data on the durability
of the proposed smart meters, especially with regard to corrosion, and usage of two-way
communications for central control of meter functions, such as remote connects and disconnects,
and improved customer information on usage. The proposed pilot would be over a four-year
period, with one year of installation and three years of operation, and consist of 5,000 smart
4 Order No. PSC-15-0390-TRF-GU in Docket No. 150116-GU.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 19
devices with related back-office technology support installed in the Brevard County area, where
accelerated corrosion has been documented. After the conclusion of the pilot, FCG indicated in
discovery it anticipates being able to report a summary of the findings, and provide sample
reports with relevant information to the Commission. The estimated total cost of the AMI Pilot is
$3.4 million in capital expenditures, with annual O&M expense estimated at $16,896, as
corrected by FCG witness Howard. We find an adjustment of ($3,104) shall be made to the
originally projected O&M expense for the AMI Pilot to reflect the corrected O&M expense
identified in FCG witness Howard’s testimony.
The Intervenors do not oppose the AMI Pilot, only its cost recovery, with OPC
contending that the technology is both too new and intended to benefit shareholders, not
customers. However, FCG maintained that the smart meters and AMI to be deployed are similar
to the widely understood AMI technology that is used by electric utilities, and a small number of
other gas utilities across the nation.
OPC witness Schultz raised concerns due to the newness of the technology to the gas
industry, and because FCG did not include estimated benefits in the filing, only the proposed
costs. Witness Schultz therefore argued that the Commission should disallow the recovery of
expenses for the pilot, which he suggested should be borne by the shareholders, as they may
benefit from a potential sale of the Utility.
Regarding the newness of the technology, FCG did not dispute that AMI technology,
while common in the electric industry, has only been deployed by a limited number of gas
utilities in the country, and not by any gas utilities in Florida. However, FCG witness Howard
testified to the expected benefits associated with the AMI Pilot, which accrue to customers and
the system itself, not shareholders, through improved functionality and potential cost reductions.
In addition, FCG provided testimony that pilot projects enable a utility to test new technologies
on a limited basis to determine if it would be beneficial to deploy these technologies system-
wide, which is why FCG is proposing an AMI Pilot.
We are persuaded by FCG’s testimony. We find that the newness of AMI technology to
the gas industry, specifically in Florida, lends credibility to FCG’s proposal for a pilot program
to allow this technology to be further evaluated prior to full scale implementation. Denying pilot
programs with expected customer benefits and reasonable costs would discourage utilities from
proposing pilot programs for the Commission’s consideration and negate opportunities for
utilities to evaluate technologies that can enhance the service to and benefits for customers.
Regarding OPC’s concern that FCG has not attempted to quantify benefits, the Utility has
proposed the collection of data to quantify benefits through tasks such as remote meter reading,
disconnection, and leak/outage detection, all of which should reduce related expenses. In
addition, FCG indicated in discovery that after the conclusion of the pilot it anticipates being
able to report a summary of the findings with regard to the project cost, meter installation,
maintenance, and corrosion performance, and to provide sample reports including information
such as customer daily usage, remote meter communication performance, and billing accuracy
impacts.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 20
3. Conclusion
Because FCG intends to gather information to determine the feasibility of AMI
technology on its system and the appropriateness of system-wide deployment of this technology
in the future, we find its potential to result in cost savings for the customers to be credible. For
these reasons, we hereby approve the AMI Pilot. An adjustment of ($3,104) shall be made to the
originally projected O&M expense provided for the AMI Pilot to reflect the corrected O&M
expense identified in FCG witness Howard’s revised testimony. In addition, we order FCG to
provide a final report with a summary of the findings described above to the Commission within
90 days of completion of the AMI Pilot.
C. Plant in Service for Liquefied Natural Gas (LNG) Facility
1. Parties’ Arguments
FCG contended that OPC waived its argument against the Liquefied Natural Gas (LNG)
facility when OPC signed off on the 2018 Settlement Agreement. That agreement included
provisions on both the need for and construction of the facility. FCG asserted that the Parties
were aware that both the in-service date and costs were estimates, and that the terms of the
agreement specifically envisioned some of this uncertainty, with rates going into effect at the in-
service date of the unit.
Although the 2018 agreement estimated $58 million in-service cost, FCG asserted its
actual project costs for the total for the LNG facility is $68 million, with an in-service date of
March 2023; therefore, only the incremental $10 million is at issue in this proceeding. FCG
argued that no party disputed that the LNG facility is needed to serve customers, and OPC
agreed to the need for this facility in the 2018 Settlement Agreement. FCG averred that despite
its efforts to secure additional capacity, it has been unable to do so at a reasonable cost, and
therefore, the LNG facility remains a necessary option to provide capacity during peak periods
for the Miami-Dade County area.
Although OPC acknowledged that some recovery of expenses associated with the LNG
facility were allowed under the 2018 Settlement Agreement, OPC argued that it is unjust that
customers have been paying for a facility that is not yet in-service. OPC expressed concerns that
funds already received from customers could potentially result in customers overpaying for the
LNG facility or otherwise could result in double recovery for the utility. Accordingly, OPC
recommended that any funds that have been collected prematurely from ratepayers related to the
LNG facility be accounted for in a regulatory liability and returned to ratepayers over five years.
Regarding OPC’s implication of possible double recovery, FCG argued that its proposed
base rate increase only includes the revenue requirements for the incremental $10 million for the
LNG facility, and thus, is net of the $2.5 million in current rates associated with the LNG
facility, and the previously approved increase of $3.8 million when the LNG facility enters
service. Therefore, FCG asserted that there is no double recovery associated with the LNG
facility.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 21
2. Analysis
The LNG facility would provide 10,000 Dekatherms/day of pipeline capacity equivalent,
and consists of three storage tanks holding 270,000 gallons of LNG and associated vaporization
and delivery equipment. The LNG facility was originally proposed as part of FCG’s 2017 base
rate proceeding, and was included in several terms of the 2018 Settlement Agreement.5 The 2018
Settlement Agreement determined that the LNG facility was needed to address the peak capacity
concerns on FCG’s system in the Miami-Dade County area, and should be allowed in rate base.
As part of the 2018 Settlement Agreement, a portion of the revenue requirement associated with
the then estimated $58 million in-service cost was included, with a term allowing a base rate
increase to recover the full estimated cost upon either the end of 2019 or the in-service date of
the facility, whichever was later.
Since the approval of the 2018 Settlement Agreement, the estimated in-service date has
shifted to March 2023, with a total estimated in-service cost of $68 million. The primary cause of
this shift is the loss of the originally proposed site as a viable location for the LNG facility, and
the resulting in-service date delay. Due to being unable to acquire the necessary zoning and
permitting approvals for the original site, FCG ultimately decided to sell the site and acquire a
new site, which took additional time and delayed the in-service date. As part of this record, we
reviewed the continued need for the LNG facility, the appropriate amount to include in rate base
for the facility, in-service date concerns, and OPC’s refund and cost disallowance proposals, as
discussed below.
a. Need for the LNG Facility
While we previously approved the need for the LNG facility under the 2018 Settlement
Agreement, and no party has disputed the continued need for the facility, we have noted in a
prior proceeding that prudent utility managers continually reassess the need for a project or
facility as circumstances change.6
OPC did not take issue with the need for the LNG facility. Rather, it offered that FCG
failed to properly and prudently plan the project and thus, the incremental costs of the LNG
facility should be borne by the shareholders, not the customers.
FCG provided testimony demonstrating that the LNG facility is fully permitted and was
on schedule to begin LNG deliveries in January 2023 and meet its projected March 2023 in-
service date and that the LNG is still needed. To further support the need of the LNG facility,
FCG witness Howard testified that FCG needs additional interstate pipeline capacity to meet the
needs of its Sales and Essential Use Transportation customers primarily in the Miami-Dade
County area, and that there is currently a single source of FCG capacity in that area but that
source has no additional incremental capacity available. FCG witness Howard argued that to
5 Order No. PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate
increase and approval of depreciation study by Florida City Gas.
6 See Order No. PSC-12-0187-FOF-EI, issued April 9, 2012, in Docket No. 20110309-EI, In re: Petition to
determine need for modernization of Port Everglades Plant, by Florida Power & Light Company.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 22
date, FCG has been unable to acquire any additional interstate capacity at terms and pricing that
are acceptable and reasonable to serve customers in the area. In addition, FCG explained that
there are no other existing alternatives to strengthen reliability at the southern-most portion of
FCG’s system outside of the FGT pipeline.
In addition, FCG witness Howard offered the following testimony to support the
continued need for the LNG facility:
Reliably serving customers at this portion of its system is becoming increasingly
constrained due to customer growth in that area as shown by supporting
documentation demonstrating the consumption increase in this area since 2018.
The LNG facility will help address specific capacity shortages on its system.
It would be prudent to add resiliency to ensure FCG can continue to provide safe
and reliable service to customers located at the southern-most portion of its
system.
The LNG facility appears to be the only cost-effective alternative available and is
necessary to help reinforce the southern-most portion of FCG’s system.
Accordingly, we find that the LNG facility is still needed for FCG to reliably serve its
customers.
b. LNG Facility Cost
As part of the 2018 Settlement Agreement, we have already approved the inclusion of
$58 million in rate base for the LNG facility. The $58 million is not disputed. What is disputed is
any costs associated with the LNG facility that are in excess of the $58 million. FCG’s first
choice for the site required obtaining a special or unusual use zoning exemption due to its
location outside of Miami Dade County’s urban development boundary. Although FCG received
support from County staff, FCG was ultimately denied the required exemption, forcing the
Company to search for an alternative site.
Due to the need to relocate the site and the associated components, such as environmental
studies, permitting, and the need to extend the pipeline connection, FCG updated its project cost
estimate by an incremental $10 million to a total of $68 million. These increased project costs
have already been offset by $2.2 million in benefits from the sale of the original site.
No party disputes the selection of the alternative site as an appropriate site to construct
the LNG facility. Rather, OPC disputes that the costs of finding the alternate site should be borne
by FCG shareholders, not customers.
Although OPC witness Schultz acknowledged the difficulties FCG experienced that
contributed to the delay in constructing the LNG facility, he recommended that we disallow the
additional cost of $10 million for the LNG facility because FCG failed to properly and prudently
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 23
plan the project. Witness Schultz testified that it is not prudent to buy property zoned residential
and plan industrial construction in the hopes that a zoning change will be allowed.
FCG witness Howard rebutted witness Schultz’s testimony by arguing that the original
site for the LNG facility was not zoned as residential, but as agricultural and agricultural
accessory uses. He also testified that FCG did not acquire the original site in the hope that the
zoning for the site would be changed, but FCG undertook due diligence with the County
Planning Director regarding the consistency of the LNG facility within the established zoning
requirements.
We find that FCG has acted prudently. The Community Council’s decision to deny
FCG’s zoning exemption request for the original site, as well as the amount of time the process
of locating and acquiring the necessary approvals for a new site took to reach completion, were
beyond FCG’s control. As such, we find that the additional cost of $10 million for the LNG
facility was prudently incurred.
c. In-Service Date
FCG projects an in-service date of March 2023 for the LNG facility. In his testimony,
OPC witness Schultz expressed concerns regarding whether the LNG facility will be in service
when FCG projects since the in-service date for the facility has already been delayed by more
than three years. Specifically, witness Schultz argued that it would not be appropriate for
customers to again pay for plant not yet in-service. As such, witness Schultz recommended that
any projected depreciation included in rates associated with the LNG facility be reflected as a
regulatory liability and deferred until FCG’s next rate case, or be reflected as a credit adjustment
in one of the Commission’s annual cost recovery clauses at a Weighted Average Cost of Capital
(WACC) that recognizes the cost carried in rates.
FCG indicated that construction of the LNG facility began in June 2022. In addition,
FCG witness Howard testified that construction of the LNG facility was essentially complete.
Witness Howard also rebutted witness Schultz’s testimony regarding this issue by outlining the
activities completed with regard to the LNG facility from the time of the 2018 Settlement
Agreement to this proceeding, as detailed above, in order to demonstrate that FCG has continued
to act prudently.
Paragraph III(a) of the 2018 Settlement Agreement, of which OPC is a signatory,
contemplates that the in-service date of the LNG facility could occur at some point after
December 1, 2019.7 In addition, as previously discussed, witness Schultz acknowledged the
obstacles encountered by FCG that contributed to the delay of the LNG facility. As construction
of the LNG facility is almost complete, we find no adjustments necessary to projected
depreciation for the LNG facility.
7 Order No. PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate
increase and approval of depreciation study by Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 24
d. LNG Facility Costs in Current Base Rates
OPC witness Schultz testified that it was OPC’s understanding that customers would not
be paying for the LNG facility until it was in service. FCG witness Fuentes rebutted witness
Schultz’s testimony by asserting that OPC agreed to this ratemaking treatment as part of FCG’s
2018 Settlement Agreement. Witness Fuentes disagreed with witness Schultz that funds that
have been collected from ratepayers related to the LNG facility should be accounted for in a
regulatory liability and returned to ratepayers over five years because this treatment is in direct
violation of the 2018 Settlement Agreement.
OPC admitted in its brief that some recovery for the LNG facility was allowed under the
2018 Settlement Agreement. The 2018 Settlement Agreement allowed recovery of $29 million in
rate base for the LNG facility before it came in-service, and approved an increase to $58 million
in rate base upon entering service.8 FCG’s updated total project cost estimate is $68 million. As
the $58 million project cost estimate was previously approved in the 2018 Settlement
Agreement, FCG is only requesting approval of the incremental $10 million project cost increase
in this proceeding; therefore, there is no possibility of double recovery. Since the ratemaking
treatment for the LNG facility was agreed upon as part of the 2018 Settlement Agreement and
there is no possibility of double recovery, we agree with FCG witness Fuentes that there is no
need to set aside funds that have already been collected from ratepayers related to the LNG
facility in a regulatory liability and amortized back to ratepayers over five years.
3. Conclusion
We find that the LNG facility is still needed for FCG to serve its customers reliably and
the additional cost of $10 million for the LNG facility was prudently incurred. We find that no
adjustments to projected depreciation for the LNG facility are necessary, and there is no need to
set aside funds that have already been collected from ratepayers related to the LNG facility in a
regulatory liability and amortized back to ratepayers. Therefore, we find the appropriate amount
of plant in service for FCG’s delayed LNG facility, once it is placed in service, is $68 million.
D. Plant in Service
1. Parties’ Arguments
FCG stated that the appropriate amount of plant in service for the projected test year of
2023 is $664,736,539, including the acquisition adjustment. FCG has projections to invest more
than $290 million to support customer growth and enhance both customer service and the safety
and reliability of its system. FCG stated that it practices a rigorous and long-standing process for
the development of capital expenditure budgets, financial forecasts, and MFRs, and noted that
none of the Intervenors disproved of its forecasting methodologies. FCG argued it is able to
secure the capital expenditures at the lowest reasonable cost using competitive bidding,
contractor quality assurance, and cost tracking. FCG also argued that cost of construction has
8 Id.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 25
increased due to: increases in inflation and material costs; industry market demand for external
contractors; supply chain issues; governmental, regulatory, and compliance requirements,
including permitting and maintenance of traffic requirements; retirement, removal, and
restoration costs; construction safety protocols; and enhanced construction management,
inspection, and quality control.
OPC argued that FCG overstated its capital additions because capital expenditures were
only $36.6 million and $40.9 million for 2019 and 2021, respectively, and the projections for
2022 and 2023 are $89.4 million and $50.6 million, respectively. OPC asserted that the actual
2020 capital expenditures might be an anomaly due to $12 million in major improvements for a
new customer and $10 million in system investments, therefore making the increases for 2022
and 2023 more extreme. OPC noted that the 2022 budget-to-actual spending shows an
overstatement averaging $36,954,004. OPC acknowledged that unaccounted for SAFE costs in
the actuals could cause the $36,954,004 overstatement, but OPC deemed that FCG did not
adequately provide information to determine if the overstatement was due to SAFE costs.
OPC contended that because FCG did not provide sufficient information to complete an
analysis, and, according to FCG witness Howard, the Company is spending $9 million below the
projected plant for the capital expenditures for January to September 2022, an adjustment of
$9,637,988 should be made. This reduction is based on subtracting the actual three-year average
of plant additions from the estimated 2022 plant additions. OPC also recommended a
corresponding reduction of $307,256 to depreciation expense and a $460,884 reduction to
accumulated depreciation to reflect a year and a half of depreciation.
2. Analysis
OPC witness Schultz testified that FCG’s plant additions are overstated. Schultz
calculated the three-year actual average of capital expenditures to be $30,951,611, excluding the
LNG facility, and determined the projected 2022 and 2023 capital expenditures, excluding the
LNG Facility, to be $20,014,315 and $21,542,902, respectively, over the three-year actual.
Witness Schultz continued that FCG having an approximate 67 percent increase in projected
capital expenditures over the actual average is cause for concern. Witness Schultz also asserted
concern that 2020 capital spending may be an anomaly because of high actual costs from $12.2
million for major improvements for a new customer and $10 million for a systems investment.
OPC witness Schultz determined there to be an average overstatement of $36,954,004 in a six-
month period, between January and June 2022, between the Company’s MFRs and its responses
provided in discovery. Witness Schultz conceded that the discrepancy could be due to the SAFE
plant not being included in the discovery response, but being included in the MFRs.
FCG argued that historical data is useful to evaluate the reasonableness of a forecast, but
should not replace a forecast for a growing business in which the Company’s plant additions for
the 2023 test year are considered prudent. FCG witness Campbell responded that OPC witness
Schultz should not have used historical averages because they are not representative of a prudent
forecast for the projected test year, and that he used data that only provided retail base and did
not include data for all clause investments. Witness Campbell recalculated the historical averages
with the Company’s corrected adjustments, and applying witness Schultz’s methodology, argued
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 26
that there would be a $2,134,806 increase to plant-in-service instead of the $9,637,988 decrease
that witness Schultz recommended.
3. Conclusion
We find no adjustments to the Company’s projected plant in service are necessary, and
the appropriate level of plant in service for the projected test year is $643,079,704.
E. Non-Utility Activities
At hearing, we approved a stipulation whereby all parties agreed that FCG does not have
any non-utility investments, and no adjustments to remove non-utility activities from Plant in
Service, Accumulated Depreciation, and Working Capital are necessary.
F. Acquisition Adjustment
1. Parties’ Arguments
The acquisition adjustment at issue relates to the acquisition of FCG by AGL Resources,
Inc., (AGLR) in 2004, which we approved in 2007 via final Order.9 Since the Commission
approved this initial acquisition adjustment, the utility has changed ownership twice. In 2016,
AGLR was acquired by Southern Gas Company (Southern). The Company was later acquired by
NextEra Energy, Inc., (NEE) the parent company of Florida Power & Light Company (FPL), in
2018. FCG continues to amortize the AGLR acquisition adjustment approved in 2007. The
amount of the AGLR acquisition adjustment is $21.7 million, and the related accumulated
amortization is $13.5 million for a net balance of $8.2 million included in rate base.
Amortization expense of $0.7 million is reflected in net operating income in the 2023 Test Year.
In its brief, OPC relied on prior Commission orders in support of its argument to deny the
acquisition adjustment. Conversely, FCG relied on separate Commission orders in support of
Commission approval of the acquisition adjustment.
FCG argued that the permanence and continuation of the acquisition adjustment and
related amortization were consistent with prior Commission orders.10 FCG further argued that
because it carried over the amounts reflected in the balance sheet at the time of the acquisition
from Southern in July 2018, as opposed to recording an acquisition adjustment from the
transaction, it should be allowed to continue to carry the acquisition adjustment. FCG also
argued that OPC’s reliance on prior water and wastewater orders of this Commission is
misplaced.
9 Order No. PSC-07-0913-PAA-GU, issued November 13, 2007, in Docket No. 20060657-GU, In re: Petition for
approval of acquisition adjustment and recognition of regulatory asset to reflect purchase of Florida City Gas by
AGL Resources. Inc.
10 Order No.PSC-2018-0190-FOF-GU, issued April 20, 2018, in Docket No. 20170179-GU, In re: Petition for rate
increase by Florida City.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 27
2. Analysis
The Commission approved the adjustment from the 2004 acquisition and required the
review of the savings that supported the acquisition adjustment in the next rate proceeding
following the acquisition in 2007. The Commission authorized the 30-year amortization period
for the acquisition adjustment after analyzing the five factors it has historically reviewed when
considering acquisition adjustments for natural gas utilities.11 These factors address the quality of
service, operating costs, ability to attract capital for improvements, overall cost of capital, and
the professionalism and expertise of the staff. 12
While OPC cited two orders showing that the Commission has an established policy that
acquisition adjustments resulting from previous transactions do not survive subsequent purchases
of a utility’s assets, FCG presented countervailing testimony regarding Commission orders
where the adjustment was continued.13 FCG witness Fuentes testified that, rather than recording
a new acquisition adjustment from its acquisition by Southern, it carried over the amounts
already reflected in the balance sheet at the time of the acquisition.
3. Conclusion
We are persuaded by the testimony of FCG’s witnesses and find that the amortization of
the acquisition adjustment shall continue until the next general rate case, at which time FCG will
have to support its further continuance under the five factors this Commission has historically
reviewed when considering acquisition adjustments for natural gas utilities.
G. Construction Work in Progress (CWIP)
At hearing, we approved a stipulation whereby all parties agreed that the appropriate
amount of Construction Work in Progress (CWIP) is $28,192,440 for the 2023 projected test
year.
H. Gas Plant Accumulated Depreciation and Amortization
1. Parties’ Arguments
FCG stated that the appropriate amount of Accumulated Depreciation for the projected
test year, including accumulated amortization associated with the acquisition adjustment, is
$221,380,711. FCG argued that OPC’s recommended $13.2 million adjustment to Accumulated
Depreciation is unsupported, inappropriate, and should be rejected.
11 Id.
12 Id.
13 Order No. PSC-03-0038-FOF-GU, issued January 6, 2003, in Docket No. 020384, In re: Petition for rate increase
by Peoples Gas Systems; and Order No. 23858, issued December 11, 1990, in Docket No. 891353, In re:
Application of PEOPLES GAS SYSTEMS, INC. for a rate increase.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 28
OPC maintained that the appropriate level of Accumulated Depreciation and
Amortization for the projected test year should be at least $208,172,408, as recommended by
OPC witness Schultz.
2. Analysis and Conclusion
This issue is determined by our findings on other issues, and based on our findings
regarding the Company’s Depreciation Study and the Company’s acquisition adjustment, the
appropriate level of Gas Plant Accumulated Depreciation and Amortization is $221,380,711.
I. Under-Recoveries and Over-Recoveries in Working Capital Allowance
At hearing, we approved a stipulation whereby all parties agreed that under recoveries
and over recoveries related to the Purchased Gas Adjustment, Energy Conservation Cost
Recovery, and Area Expansion Plan have been appropriately reflected in the Working Capital
Allowance.
J. Unamortized Rate Case Expense.
1. Parties’ Arguments
FCG Witness Fuentes asserted that the inclusion of the unamortized balance of Rate Case
Expense of $1,645,732 for the 2023 projected test year in Working Capital is appropriate to
avoid an implicit disallowance of reasonable and necessary costs. FCG also argued that its four-
year rate plan would reduce the amount of Rate Case Expense that FCG would otherwise incur
for multiple rate cases. FCG submitted that it is appropriate to include the unamortized Rate Case
Expense in Working Capital.
FCG requested that the 13-month average of unamortized Rate Case Expense be allowed
in Working Capital. FCG witness Fuentes testified that the Company requested the unamortized
balance be included in rate base in order to “avoid an implicit disallowance of reasonable and
necessary costs.” She maintained that full recovery of necessary Rate Case Expense is not
limited to only recovering the expense and should also include affording FCG the opportunity to
earn a return on the unamortized balance of those expenses in Working Capital.
OPC asserted that unamortized Rate Case Expense should not be included in Working
Capital for a gas company pursuant to Commission policy. OPC witness Schultz proposed a
reduction to Working Capital for the deferred Rate Case Expense based on his recommendation
to reduce the total Rate Case Expense.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 29
2. Analysis
There are electric and gas rate cases that reflect the Commission’s allowance of one-half
of Rate Case Expense in Working Capital.14 However, there are no Commission Orders
reflecting the full allowance. In Progress Energy Florida, Inc.’s (PEF) 2009 Rate Case, the
Commission denied PEF’s request to include unamortized Rate Case Expense in Working
Capital.15 The Order in PEF’s 2009 Rate Case stated that customers and shareholders should
share the cost of a rate case based on the belief that customers should not be required to pay a
return on funds used to increase their rates.16 The Order also cited other electric and gas rate
cases where the Commission denied unamortized Rate Case Expense in Working Capital.17
FCG’s justification for full allowance was essentially its assertion that disallowance
prevents the Company from fully recovering all necessary and reasonable costs. We are not
persuaded that this assertion is enough to contradict Commission policy. We find that FCG has
failed to meet the burden to support the inclusion of any unamortized Rate Case Expense in
Working Capital, and therefore Working Capital should be decreased by $1,742,227.
3. Conclusion
Inclusion of FCG’s requested full unamortized amount of Rate Case Expense in Working
Capital would be a departure from Commission practice. As such, Working Capital shall be
decreased by $1,742,227.
K. Deferred Pension
At the hearing, we approved a stipulation whereby all parties agreed that the appropriate
amount of deferred pension debit in working capital for FCG to include in rate base is
$4,604,263 for the 2023 projected test year.
14 See Order No. PSC-94-0170-FOF-EI, issued on February 10, 1994, in Docket No. 19930400-EI, In re:
Application for a Rate Increase for Marianna electric operations by Florida Public Utilities Company; Order No.
PSC-08-0327-FOF-EI, issued on May 19, 2008, in Docket Nos. 20070300-EI and 20070304-EI, In re: Petition for
rate increase by Florida Public Utilities Company; Order No. PSC-04-0369-AS-EI, issued on July 2, 2004, in
Docket No. 20030438-EI, In re: Petition for rate increase by Florida Public Utilities Company; Order No. PSC-04-
1110-PAA-GU, issued on November 8, 2004, in Docket No. 20040216-GU, In re: Application for rate increase by
Florida Public Utilities Company; and Order No. PSC-95-0518-FOF-GU, issued on April 26, 1995, in Docket No.
940620-GU, In Re: Application for a rate increase by FLORIDA PUBLIC UTILITIES COMPANY.
15 Order No. PSC-10-0131-FOF-EI, issued on March 5, 2010, in Docket Nos. 20090079-EI, In re: Petition for
increase in rates by Progress Energy Florida, Inc.; 20090144-EI, In re: Petition for limited proceeding to include
Bartow repowering project in base rates, by Progress Energy Florida, Inc.; and 20090145-EI, In re: Petition for
expedited approval of the deferral of pension expenses, authorization to charge storm hardening expenses to the
storm damage reserve, and variance from or waiver of Rule 25-6.0143(1)(c), (d), and (f), F.A.C., by Progress
Energy Florida, Inc.
16 Order No. PSC-10-0131-FOF-EI.
17 See Order No. 23573, issued October 3, 1990, in Docket No. 891345-EI, In re: Application of Gulf Power
Company for a rate increase; Order No. PSC-09-0283-FOF-EI, issued April 30, 2009, in Docket No. 080317-EI, In
re: Petition for rate increase by Tampa Electric Company; Order No. PSC-09-0375-PAA-GU, issued May 27, 2009,
in Docket No. 080366-GU, In re: Petition for rate increase by Florida Public Utilities Company.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 30
L. Unbilled Revenues
At the hearing, we approved a stipulation whereby all parties agreed that unbilled
revenues shall be included in working capital. FCG incurs costs to deliver gas to customers, all
of which have been accrued or paid. Delivery of that gas gives rise to both customer accounts
receivables and a receivable for unbilled revenues. FCG must finance the costs of delivering gas,
whether or not the gas sales have yet been billed. For this reason, the Commission has a long-
standing practice of including unbilled revenues in working capital.
M. Working Capital
1. Parties’ Arguments
FCG claimed the appropriate amount of working capital for the 2023 projected test year
is $17,357,425. FCG stated that OPC witness Schultz ignored the forecasted Cash Working
Capital (CWC), and instead, limited his evaluation to the historical CWC balances. FCG
explained the primary reasons for this CWC increase were Cash, Accounts Receivable, Stored
Fuel, and Miscellaneous Deferred Debits. FCG has a target minimum for cash of $5 million in
projected periods and requests funds as needed for working capital from FPL on an ongoing
basis, which establishes the minimum cash balance target. Accounts receivables are increasing in
line with increased revenue. Stored fuel increase is due to fuel prices rising and the opening of
the LNG facility. Miscellaneous Deferred Debits increased due to a rise in the Company’s
pension asset. FCG further stated that the CWC should utilize projections as opposed to
historical averages.
OPC stated that based on historical balances, the Company’s request for CWC is
improperly inflated with increases significantly larger than historical averages. OPC
recommended an $800,000 decrease to Accounts Payable. OPC recommended a disallowance of
$7,850,000. OPC claimed that these reductions result in a debit balance greater than the three-
year average for each expense.
2. Analysis
FCG requested $17,357,425 for the total amount of working capital if the RSAM was
approved. The parties’ disagreements over working capital are broken down into Cash, Accounts
receivable, Stored Fuel, Miscellaneous Deferred Debits, and Accounts Payable.
OPC witness Schultz testified that several CWC components were significantly higher
than the historical amounts. CWC and working capital allowance are the same. FCG requested
$5 million for Cash while the average in prior years was only $2,312,949. The request for
Accounts Receivable reflects an increase by $6,225,528 over the three-year average of
$9,278,408. The stored fuel is double the three-year average and Miscellaneous Deferred debits
is three times the three-year average.
In his adjustments, witness Schultz recommended reductions to Cash, Accounts
Receivable, Gas Storage, and Miscellaneous deferred Debits. The total amount of adjustment to
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 31
assets in working capital is an $8,650,000 decrease. Witness Schultz also recommended an
$800,000 decrease to Accounts Payable. The total of witness Schultz’s adjustments is a
$7,850,000 decrease to working capital.
FCG witness Howard claimed that witness Schultz ignored the forecasted Cash Working
Capital and used historical CWC as the basis for his adjustments. For Cash, FCG witness
Howard testified that FCG requests funds from FPL as needed and that this set the minimum
cash balance target from FCG. Witness Howard testified that FCG projects accounts receivable
using 2021 historical average days’ sales outstanding and then applied that ratio to projected
revenues. Witness Howard states that the increase in stored fuel is due to the increase in natural
gas prices and the anticipated opening of the LNG facility in March 2023. FCG contended the
adjustments proposed by OPC reflect historical amounts while ignoring projected amounts.
3. Conclusion
We agree with the Company’s rationale. The use of the historic trends, while a good
resource for evaluation, are lacking as a basis for adjustment in the projected test year. Historical
data does not account for the changes made in the projected test year nor does it account for
FCG’s change in ownership since its last rate case. Based on that premise and using indexed
amounts, we looked at working capital as a whole and found the amount to be reasonable.
Taking into account our findings regarding accumulated depreciation, under and over recoveries,
unamortized rate case expense, deferred pension, unbilled revenues, and insurance expense, the
appropriate level of working capital for the projected test year is $15,709,607.
N. Rate Base
1. Parties’ Arguments
FCG stated that the testimony of its witnesses, information in its MFRs, and discovery
responses fully support the amount of rate base requested. Therefore, FCG contended the
appropriate amount of rate base for the 2023 projected test year is $487,326,330.
OPC stated that the appropriate level of rate base for the projected test year should reflect
all OPC adjustments. The appropriate amount of rate base should be no more than $455,035,463.
2. Analysis and Conclusion
The appropriate level of rate base depends on the outcome of other issues. Based on our
findings regarding the acquisition adjustment, the unamortized rate case expense, and working
capital, the appropriate level of rate base for the projected test year is $487,257,875.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 32
VI. Cost of Capital
A. Accumulated Deferred Taxes
1. Parties’ Arguments
FCG asserted it has incorporated an adjustment to decrease the amount of accumulated
deferred income tax (ADITs) included in the calculation of FCG’s weighted average cost of
capital as required under Treasury Regulations §1.167(1)-1(h)(6). The calculation of the
proration requirement for ADITs for the 2023 projected test year results in a decrease of
$46,471. FCG argued that with this adjustment, the appropriate amount of ADITs with the
RSAM included in capital structure for the projected test year is $53,898,912. FCG asserted that
OPC recommended a $3.6 million decrease to ADITs based on OPC witness Schultz’s
recommended rate base adjustments. FCG argued that OPC’s rate base adjustments should be
rejected and therefore OPC’s corresponding adjustment to ADIT for the projected test year
should also be rejected.
While OPC did not address accumulated deferred taxes in its post-hearing brief, OPC
recommended a cumulative reduction to rate base of $32,387,362, which corresponds to a
decrease of $3,571,766 to ADITs when reconciled to the capital structure pro rata over all
sources of capital. OPC argued the appropriate amount of ADITs to include in the capital
structure is at least $50,182,538.
2. Analysis
The appropriate amount of accumulated deferred taxes in the projected test year capital
structure differs slightly between FCG’s and OPC’s recommendations. To derive its deferred tax
balance, FCG made a pro rata adjustment of $1,349,743 to its per books balance of $55,150,517,
reducing it to reconcile it with the total projected rate base balance. FCG made an additional
proration adjustment to remove $46,471 to comply with U.S. Treasury Regulations §1.167(1)-
1(h)(6) which is necessary when calculating rates using a projected test year. None of the parties
objected to FCG’s proration adjustment.
In addition, FCG made a correction to its revenue requirement which affected the rate
base amount, and thus, the capital structure balance. None of the parties made a specific
objection to FCG’s calculation of the amount of ADITs included in its MFR Schedule G-3 or
FCG’s recalculated ADITs amount in Exhibit LF-12, included with FCG witness Fuentes’
rebuttal testimony. However, OPC recommended a deferred tax balance of $50,182,533, which
is based on OPC witness Garrett’s proposed capital structure that includes a ratio of 11.03
percent for deferred taxes. The difference in OPC’s recommended amount arises from OPC’s
recommendation to make adjustments to reduce FCG’s rate base and reconcile the lower rate
base amount pro rata over all capital sources, which lowers the deferred tax balance
proportionately. In the previous section, we approved a total rate base amount of $487,257,875.
When this amount is reconciled pro rata over all capital sources to FCG’s capital structure, the
corresponding amount of accumulated deferred income taxes based on a ratio of 11.02 percent is
$53,717,249.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 33
3. Conclusion
For the aforementioned reasons, we find the appropriate amount of accumulated deferred
income taxes to include in the projected test year capital structure ending December 31, 2023, is
$53,717,249.
B. Short-Term Debt
1. Parties’ Arguments
FCG argued the appropriate amount and cost rate for short-term debt for the projected
test year is $20,203,793 and 1.78 percent, respectively. FCG asserted it utilized FPL’s short-term
debt cost because, pursuant to Commission-approved financing orders,18 FCG obtains 100
percent of its debt and equity financing from FPL and the interest rate on any short-term
borrowings by FCG from FPL is a pass-through of FPL’s weighted cost for borrowing these
funds. FCG argued FPL relies on the forward Intercontinental London Interbank Exchange
Offered Rate (LIBOR) curve for its short-term debt cost projections. FCG argued that OPC’s
recommended adjustments to increase the amount of short-term debt included in the investor
sources of capital by $20,269 should be rejected. FCG also argued that OPC’s recommended
adjustment to decrease the total rate base balance should be rejected, and therefore, OPC’s
corresponding adjustment to decrease the amount of short-term debt in the capital structure for
the projected test year should also be rejected.
OPC did not address short-term debt in its post-hearing brief, but OPC witness Garrett
testified that the appropriate ratio of short-term debt in the projected test year capital structure is
4.13 percent. This ratio equates to a balance of $18,821,767 for short-term debt in OPC witness
Shultz’s cost of capital schedule when reconciled to OPC’s recommended rate base balance of
$455,035,463. OPC did not object to FCG’s cost rate of 1.78 percent for short-term debt.
2. Analysis
Both FCG and OPC agree the appropriate cost rate for short-term debt is 1.78 percent.
We reviewed FCG’s estimate for the short-term debt cost rate based on LIBOR as provided in
FCG’s discovery responses and find it to be reasonable. FPL, as FCG’s parent, provides all the
investor-provided capital to FCG at the capital structure ratios of FPL. FCG applied the capital
structure of FPL, which includes a ratio of 4.69 percent of short-term debt, to its projected test
year capital structure and reconciled the amounts to the rate base balance for the projected test
year via a pro rata adjustment over all capital sources. After reconciliation with all capital
structure components, the ratio of short-term debt in the projected test year capital structure is
4.13 percent. This ratio equates to a short-term debt balance of $20,203,793.
18 Order No. PSC-2022-0354-FOF-EI, Issued October 19, 2022, in Docket No. 20220133-EI, In re: Application for
authority to issue and sell securities during calendar year 2023 and 2024, pursuant to Section 366.04, F.S., and
Chapter 25-8, F.A.C., by Florida Power & Light Company and Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 34
FCG recalculated its revenue requirement which included a reduction to its requested rate
base for the projected test year. As a result, the rate base was reduced by $96,495, which resulted
in a corresponding reduction to short-term debt of $3,987. FCG’s final amount of short-term debt
included in its projected test year capital structure was $20,137,159. OPC witness Garrett
suggested a ratio of 4.13 percent for short-term debt in the projected test year capital structure.
When OPC’s recommended capital structure is reconciled to OPC’s recommended lower rate
base balance, the corresponding amount of short-term debt is $18,821,767. Previously, we
approved a total rate base amount of $487,257,875. When this amount is reconciled pro rata over
all capital sources to our approved capital structure, the corresponding amount of short-term debt
based on a ratio of 4.13 percent is $20,135,698.
3. Conclusion
In conclusion, both FCG and OPC agree on the cost rate of 1.78 percent for short-term
debt in the projected test year capital structure and we find it to be a reasonable rate. Based on
the aforementioned, we find the appropriate amount and cost rate for short-term debt to include
in the projected test year capital structure ending December 31, 2023, is $20,135,698, at a cost
rate of 1.78 percent.
C. Long-Term Debt
1. Parties’ Arguments
FCG argued the appropriate amount and cost rate for long-term debt for the projected test
year is $154,025,674 (adjusted) and 4.28 percent, respectively. FCG argued it does not issue its
own debt or equity and, pursuant to Commission-approved financing orders,19 FCG obtains 100
percent of its debt and equity financing from FPL, and the interest rate on any short-term or long-
term borrowings by FCG from FPL is a pass-through of FPL’s weighted cost for borrowing these
funds. FCG witness Campbell contended that this is a significant benefit to FCG’s customers
because FPL’s weighted average borrowing costs are significantly lower than FCG could
otherwise obtain on its own. FCG argued OPC’s recommended net increase of approximately
$54.6 million in long-term debt to reflect OPC’s proposed capital structure should be rejected,
and therefore, its corresponding adjustment to long-term debt should also be rejected.
OPC did not proffer a specific argument in its post-hearing brief, but recommended an
increase of $54.6 million in long-term debt to reflect OPC’s proposed capital structure. OPC also
recommended an additional decrease of $13.8 million in long-term debt based on OPC witness
Schultz’s recommended rate base adjustments. OPC witness Garrett testified his analysis
strongly indicates that FCG’s proposed long-term debt ratio of 40.4 percent is too low to be
considered fair for ratemaking. Witness Garrett opined an insufficiently low debt ratio causes the
weighted average cost of capital to be unreasonably high. Based on his findings, witness Garrett
19 Order No. PSC-2022-0354-FOF-EI, Issued October 19, 2022, in Docket No. 20220133-EI, In re: Application for
authority to issue and sell securities during calendar year 2023 and 2024, pursuant to Section 366.04, F.S., and
Chapter 25-8, F.A.C., by Florida Power & Light Company and Florida City Gas.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 35
recommended the Commission impute a capital structure for ratemaking purposes consisting of
long-term debt of 51.3 percent.
2. Analysis
Both FCG and OPC agree the appropriate cost rate for long-term debt is 4.28 percent.
The amount of long-term debt in the projected test year capital structure differs between FCG’s
and OPC’s recommendations. FPL provides all the investor-provided capital to FCG at the
capital structure ratios of FPL. FCG applied the capital structure of FPL, which includes 40.4
percent of long-term debt, to its projected test year capital structure and reconciled the amounts
to the rate base balance for the projected test year via a pro rata adjustment over all sources.
After reconciliation with all capital structure components, the ratio of long-term debt in the
projected test year capital structure is 31.50 percent. This ratio equates to a long-term debt
balance of $154,056,074. FCG subsequently recalculated its revenue requirement which included
a reduction to its requested rate base for the projected test year. As a result, the rate base was
reduced by $96,495, which resulted in a corresponding reduction to long-term debt of $30,400.
FCG’s adjusted amount of long-term debt included in its projected test year capital structure was
$154,025,674.
There was competing testimony about FCG’s requested long term debt ratio of 31.50
percent. FCG Witness Garrett testified that an insufficiently low debt ratio causes the weighted
average cost of capital to be unreasonably high and recommended the Commission impute a
capital structure for ratemaking purposes consisting of 51.3 percent total debt based on investor
sources of capital. OPC witness Shultz used witness Garrett’s recommended long-term debt ratio
of 42.7 percent to develop his recommended projected test year capital structure. Reconciling
OPC’s recommended capital structure pro rata over all sources to OPC’s recommended rate base
balance, the corresponding amount of long-term debt in the projected test year capital structure
would be $194,277,560.
OPC is proposing an adjustment to increase the amount of long-term debt in the projected
test year capital structure as a result of lowering the equity ratio. In rebuttal, FCG witness Nelson
contended that increasing the Company’s financial leverage by reference to publicly traded
holding companies and other industry capital structures would increase FCG’s financial risk and,
as a result, its cost of capital to the detriment of customers.
FCG witness Campbell explained the Company utilized FPL’s projected long-term debt
rate of 4.28 percent because all long-term financings are provided by FPL. FCG stated FPL relies
on the Blue Chip Financial Forecast to project its long-term debt costs, which represents the
consensus estimates of more than 40 economists/contributors. FCG’s cost projections for FCG’s
long-term borrowings from FPL are shown in MFR G-3, Page 3. FCG’s blended long-term debt
cost rate for the projected test year is shown in MFR Schedule G-3, Page 2. We reviewed the
aforementioned MFR Schedules and believe the projected long-term debt cost rate of 4.28
percent is reasonable. Previously, we approved a total rate base amount of $477,497,041. When
this amount is reconciled pro rata over all capital sources to our approved capital structure, the
corresponding amount of long-term debt based on a ratio of 31.50 percent is $153,506,544.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 36
3. Conclusion
Both FCG and OPC agree on the cost rate of 4.28 percent for long-term debt in the
projected test year capital structure, and we find it to be a reasonable rate. Based on the
aforementioned, the appropriate amount of long-term debt to include in the projected test year
capital structure ending December 31, 2023, is $153,506,544 at a cost rate of 4.28 percent.
D. Customer Deposits
1. Parties’ Arguments
FCG argued the appropriate amount for customer deposits for the 2023 Test Year is
$3,799,283 (adjusted) at a 2.64 percent cost rate. FCG also argued against OPC witness Schultz’s
recommended rate base adjustments, and therefore, OPC’s corresponding adjustment to decrease
customer deposits by $251,671 for the projected test year should be rejected.
OPC did not address customer deposits in its brief. OPC witness Garrett proposed a ratio
of 0.78 percent to include in the projected test year capital structure at a cost rate of 2.64 percent.
OPC witness Shultz used witness Garrett’s proposed capital structure to develop OPC’s
recommended amounts of the components in the projected test year capital structure. OPC
recommended a customer deposit balance of $3,535,924 at a cost rate of 2.64 percent.
2. Analysis
Both FCG and OPC agree the appropriate cost rate for customer deposits is 2.64 percent.
Both FCG and OPC agree on the ratio of 0.78 percent for customer deposits to include in the
projected test year capital structure. FCG did not provide testimony specific to the amount of
customer deposits to include in the test year capital structure. We have reviewed the customer
deposit balance and effective cost rate as calculated by FCG and find them to be reasonable.
FCG recalculated its base revenue requirement, which resulted in a corresponding adjustment to
the original customer deposit balance leading to an adjusted balance for customer deposits of
$3,799,283.
3. Conclusion
Based on the aforementioned, we find the appropriate amount and cost rate for customer
deposits to include in the projected test year capital structure is $3,786,477 at a cost rate of 2.64
percent.
E. Equity Ratio
1. Parties’ Arguments
FCG argued that its requested capital structure consisting of 59.6 percent common equity,
which is the same equity ratio as FPL, should be approved because it receives all of its debt and
equity financing directly from FPL. FCG opined that its proposal to use the capital structure of
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 37
its parent is fully consistent with FCG’s proposal in FCG’s 2018 rate case, that the Commission
has previously approved the use of a parent company’s capital structure where the regulated
utility operates as a division and does not issue its own debt, that its proposed equity ratio of 59.6
percent is within the range of the equity ratios of the gas utilities included in the proxy group,
and that it is consistent with industry practice. FCG further argued that the Company’s requested
equity ratio reflects its specific financing requirements and risk profile, and enables it to maintain
its financial strength, which translates into favorable access to capital for the benefit of
customers.
To assess whether FCG’s requested financial capital structure is consistent with industry
practice, FCG witness Nelson calculated the average capital structure (including short-term debt)
for each of the proxy group operating companies from 2018 to 2020. The results showed the
mean and median three-year average equity ratio of the proxy group is 54.78 percent and 55.85
percent, respectively, within a range of 43.54 percent to 61.78 percent. Therefore, FCG
concluded its requested equity ratio of 59.60 percent is within the proxy group range and
consistent with industry practice.
OPC argued that witness Garrett’s recommended debt ratio would result in an equity ratio
of 46.9 percent, and therefore a debt-to-equity ratio of 1.13, which is consistent with the proxy
group average. OPC asserted regulated utilities under a rate base rate of return model, where
there is no competition, do not have an incentive to minimize their weighted average cost of
capital (WACC) because a higher WACC results in higher rates, all else held constant. OPC
argued that, because there is no incentive for a regulated utility to minimize its WACC, a
Commission standing in the place of competition must ensure that the regulated utility is
operating at the lowest reasonable WACC.
OPC witness Garrett used the same gas utility proxy group as that of FCG witness Nelson
for his cost of capital analysis, and testified the average debt ratio of the proxy group of gas
utility companies is 53.1 percent, which correlates to an equity ratio of 46.9 percent. Witness
Garrett assessed the reasonableness of his recommendation by comparing other competitive
firms with debt ratios above 56 percent from around the country and concluded that the average
debt ratio was 64 percent (36 percent equity ratio). From his analyses, witness Garrett opined
that FCG’s proposed long-term debt ratio of 40.4 percent is too low to be considered fair for
ratemaking and causes the WACC to be unreasonably high. Based on witness Garrett’s
testimony, OPC recommended an equity ratio of 46.9 percent from investor-supplied capital
which is consistent with the gas utility proxy group average.
OPC witness Garrett disagreed with FCG’s assertion that FCG should use the equity ratio
of its parent FPL because FPL is the source of FCG’s financing. OPC argued that regulators
generally establish capital structures for utilities based on the operational and market risk factors
that apply to the individual utility. Witness Garrett asserted that in the FPL 2021 rate case, FPL
witness Barrett testified that FPL’s regulatory capital structure included a 59.6 percent equity
ratio and has maintained an equity ratio between 59 and 60 percent for over two decades. OPC
argued that unlike FPL, FCG had maintained an equity ratio of just over 43 percent for the past
twenty years, and it has been 48 percent since only mid-2018.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
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FEA argued FCG’s requested common equity ratio of 59.6 percent is not appropriate and
should be rejected because it exceeds the average authorized equity ratio of 51.4 percent for
regulated gas utilities around the country and significantly exceeds the average common equity
ratio for the gas utility proxy group of 38.6 percent. FEA argued that witness Walters relied on
the same gas utility proxy group developed by FCG witness Nelson, but opined that FCG’s
assumed equity ratio of 59.6 percent is nearly eight percentage points higher than that of the gas
utility proxy group's comparable equity ratio. Therefore, FEA argued, the Company’s requested
common equity ratio should be rejected and the Commission should approve a common equity
ratio of no higher than 50.0 percent. FIPUG joined the arguments of FEA.
Witness Walters disagreed with witness Nelson’s assessment that an equity ratio of 59.6
percent is reasonable because it is consistent with the source of the investor-supplied capital and
it lies within the range of the equity ratios of the gas utility proxy group.
2. Analysis
FCG’s current equity ratio is 48 percent, which is based on the consolidated capital
structure of its former parent company Southern Company Gas in its 2018 rate case settlement.
The revenue requirement associated with increasing the equity ratio from 48 percent to 59.6
percent is approximately $4.1 million.
Based on record evidence and past Commission practice of using a capital structure that
approximates FCG’s actual sources of capital, FCG’s projected equity ratio of 59.6 percent for
the test year ending December 31, 2023, is reasonable and appropriate. FCG presented testimony
that the Company’s requested equity ratio reflects its specific financing requirements and risk
profile, and enables it to maintain its financial strength, which translates into favorable access to
capital for the benefit of customers. FCG offered testimony that its requested financial capital
structure is consistent with industry practice. For example, FCG witness Nelson testified the
average capital structure (including short-term debt) for each of the proxy group operating
companies from 2018 to 2020. The results showed the mean and median three-year average
equity ratio of the proxy group is 54.78 percent and 55.85 percent, respectively, within a range of
43.54 percent to 61.78 percent. Therefore, FCG concluded its requested equity ratio of 59.60
percent is within the proxy group range and consistent with industry practice.
FCG also offered testimony that its requested equity ratio is appropriate because it is
based on its actual financing from its parent, FPL, and is consistent with regulatory precedent
and guidance regarding capital structure determinations for companies that do not issue their
own debt or have their own credit ratings. While OPC witness Garrett’s testified that using FPL
as a gas utility proxy group was flawed, FCG witness Nelson testified that OPC witness Garrett
incorrectly used the capital structures of the publicly traded holding companies, not the regulated
operating companies that are subsidiaries of the holding companies. FCG argued the proper point
of comparison is the mix of investor-supplied capital in place at the regulated utility operating
companies, not at the publicly traded holding companies. Witness Nelson testified that the
Intervenor witnesses’ recommendations would increase FCG’s financial risk and, in turn, its cost
of capital to the detriment of customers. Furthermore, as FCG witness Nelson asserted, adverse
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 39
weather events can happen in Florida, and maintaining a strong balance sheet that enables
efficient access to capital when needed regardless of market environments is important.
3. Conclusion
Based on record evidence and past Commission practice of using a capital structure that
approximates the utility’s actual sources of capital, FCG’s projected equity ratio of 59.6 percent
for the test year ending December 31, 2023, is reasonable and appropriate. Accordingly, we find
the appropriate equity ratio is 59.6 percent as a percentage of investor-supplied capital.
F. Return on Equity (ROE)
1. Parties’ Arguments
FCG argued for a 10.75 percent return on common equity (ROE). FCG argued that a fair
rate of return should be comparable to returns investors expect to earn on other investments of
similar risk, sufficient to assure confidence in the company’s financial integrity, and adequate to
maintain and support the company’s credit and to attract capital. FCG argued that this ROE
would appropriately account for FCG’s unique risk profile and the Company’s commitment to a
strong financial position, while addressing the risk of the Company’s proposed multi-year stay-
out. FCG argued that its requested ROE was critical to maintaining its financial strength and
flexibility as well as attracting the capital necessary to serve its customers on reasonable terms.
OPC argued that the appropriate ROE should be 9.25 percent. OPC argued that since
utility stocks are low risk, the return required by equity investors should be relatively low. OPC
opined that if the Commission sets the awarded ROE much higher than the true cost of capital, it
would run contrary to applicable U.S. Supreme Court precedent and result in an inappropriate
transfer of wealth from customers to shareholders. OPC argued that an ROE of 9.25 percent
would result in fair, just, and reasonable rates, and would benefit both FCG’s consumers as well
as FCG’s shareholders.
FEA argued that the appropriate ROE is in the range of 9.00 percent to 9.80 percent, with
a midpoint of 9.40 percent. FEA asserted that the purpose of the rate of return testimony
provided is to estimate the expected return that investors require on an investment in FCG. FEA
argued that a utility should be allowed an ROE sufficient to maintain its financial integrity and to
attract capital on reasonable terms, and the return should be commensurate with returns investors
could earn in other companies of comparable risk. FEA further argued that market valuations of
utility stocks are strong, which is an indication that utilities are able to access equity capital at
lower costs and under reasonable terms. FIPUG joined the position and argument of FEA.
2. Analysis
The ROE is the allowed cost of common equity. More simply put, ROE is the interest the
customers pay to the investors for their equity investments in the utility. The ROE is included in
a utility’s regulatory capital structure used to determine the overall rate of return which, in turn,
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is used to establish a revenue requirement. Under section 366.041(1), F.S., no public utility shall
be denied a reasonable rate of return.
The Hope and Bluefield U.S. Supreme Court cases established that a fair ROE must be
(1) commensurate with returns available on investments having comparable risks, (2) sufficient
to assure financial soundness and integrity and support reasonable credit quality, and (3)
adequate to allow a company to raise capital on reasonable terms.20 Neither case law nor statute
mandate that the awarded ROE be tied to the result of a particular financial model. Rather, we
must establish a reasonable ROE that is consistent with Hope and Bluefield and supported by
competent, substantial evidence in the record. As recognized in this case by OPC witness
Schultz, this Commission has a long history of establishing an ROE mid-point and a range of
100 basis points on either side to create a range of reasonableness and ensure rate stability.
FCG’s common equity is not publicly traded, and as such a market-based cost rate for the
Company cannot be directly observed. Consequently, FCG witness Nelson, OPC witness Garrett
and FEA witness Walters (collectively, “Intervenor Witnesses”) all applied cost of equity
financial models to a proxy group of publicly traded gas distribution companies (proxy group)
with similar risk to FCG to derive estimates of the required ROE. OPC witness Garrett and FEA
witness Walters used the same proxy group as that of FCG witness Nelson. All three witnesses
used the Discounted Cash Flow (DCF) model and the Capital Asset Pricing Model (CAPM) to
estimate the cost of equity.
In addition, FCG witnesses Nelson and FEA witness Walters employed a risk premium
analysis to estimate the cost of equity. Witness Garrett also applied the Hamada Formula to his
CAPM. In general, FCG witness Nelson used inputs and assumptions for things such as
projected market returns that produced a higher ROE estimate, while the Intervenor Witnesses
used inputs and assumptions that produced a lower ROE estimate. As a result of the respective
assumptions used in the cost of equity models, our staff’s recommended ROE is greater than
OPC’s and FEA’s recommended ROE of 9.25 percent and 9.4 percent, respectively, and lower
than FCG’s requested ROE of 10.75 percent. The range of results of all of the witnesses’ cost of
equity models is 7.10 percent to 13.37 percent. The witnesses’ cost of equity model results are
summarized in Table 2.
20 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).
ORDER NO. PSC-2023-0177-FOF-GU
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Table 2
ROE Model FCG witness Nelson OPC witness Garrett FEA witness Walters
DCF with analyst
growth estimates
8.4% - 10.87% 8.00% 9.31%
DCF with sustainable
growth estimates
8.05% - 10.69% 7.1% 9.02%
DCF Multi-stage 7.99%
CAPM 10.12% - 10.94% 7.90% 8.08% - 10.97%
CAPM with Hamada
Formula
9.0%
Empirical CAPM 10.67% - 13.15%
Risk Premium 9.73% and 9.80% 9.27% - 10.42%
Recommended ROE 10.75% 9.25% 9.40%
a. Proxy Group of Gas Companies
FCG witness Nelson selected six companies from the Value Line Investment Survey to
include in the gas utility proxy group. The gas proxy group includes Atmos Energy Corp., New
Jersey Resources Corp., NiSource, Inc., Northwest Natural Holding Co., ONE Gas, Inc., and
Spire, Inc. The Intervenor Witnesses took no issue with FCG witness Nelson’s selection of gas
utilities for the proxy group and used the same proxy group for their respective cost of equity
analyses.
b. Discounted Cash Flow (DCF) Model
The Discounted Cash Flow (DCF) cost of equity model is based on the theory that a
stock’s current price represents the present value of all expected future cash flows in the form of
dividends discounted at the appropriate risk-adjusted rate of return. In its basic form, the DCF
model is expressed as the dividend yield of a stock plus the expected long-term growth rate.
Mathematically, the DCF model is expressed as ROE = (dividend ÷ stock price) + growth rate.
The differences between FCG witness Nelson’s and the Intervenor Witnesses’ DCF
model results are primarily driven by differences in chosen growth rates, as well as witness
Nelson’s use of the quarterly compounding dividend yield. FCG witness Nelson used an average
growth rate of 6.07 percent in her DCF analysis. FEA witness Walters used three different
growth rates of 5.95 percent, 5.67 percent, and 4.35 percent in three variations of the DCF
model. OPC witness Garrett used an analyst growth rate of 4.8 percent and a sustainable growth
rate of 3.8 percent in two variations of the DCF model.
OPC witness Garrett’s DCF results were 7.1 percent and 8.0 percent. We find that OPC
witness Garrett’s DCF model result of 7.1 percent is not reasonable because it uses the national
GDP as the growth rate and does not reflect the growth rate of regulated natural gas utilities, and
shall be given little weight. OPC witness Garrett also used a DCF model using analyst forecasts
as the growth rate and obtained a result of 8.0 percent, but asserted that this result should not be
considered at all. An objective review of FCG witness Nelson’s DCF results established the
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average of her constant growth DCF model at 9.72 percent and the average of her quarterly
growth DCF model at 9.86 percent. The average of the median and mean of FEA witness
Walters’ three variations of the DCF model were 9.2 percent, 9.11 percent, and 8.09 percent. The
average of FCG and FEA witnesses’ DCF Model results is 9.2 percent.
c. Capital Asset Pricing Model (CAPM)
The CAPM method of analysis to determine cost of equity is based upon the theory that
the market-required rate of return for a security is equal to the risk-free rate plus a risk premium
associated with the specific security. The CAPM assumes that all non-market or unsystematic
risk can be eliminated through diversification. The risk that cannot be eliminated through
diversification is called market, or systematic, risk. Therefore, the CAPM assumes that investors
require compensation only for systematic, or market, risk. Non-diversifiable (or systematic) risk
is measured by the beta coefficient. 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 equity risk premium (ERP)
expressed in this equation: ROE = risk-free rate + Beta × (market return – risk-free rate).
Consistent with our prior practices and the evidence presented in this case, we find the
application of the market-based DCF Model and CAPM are the best methods to determine the
cost of equity because both reflect market-based and utility financial data. The models are not
disputed in this case. Rather, there was competing testimony offered by FCG and the Intervenors
as to the underlying assumptions and use of the CAPM.
FCG Witness Nelson testified that his use of the CAPM results in the long-term
arithmetic average historical return on the market of 12.33 percent as an appropriate alternate
estimate of the expected market return. However, OPC and FEA offered testimony that
countered FCG’s CAPM results. OPC and FEA provided testimony that asserted FCG witness
Nelson’s CAPM results are unreasonably high due to her overestimation of the projected market
return and ERP. The Intervenors countered FCG’s testimony with:
FEA witness Walters testified that FCG witness Nelson’s use of the empirical CAPM
utilized an ERP of 70 companies with exceedingly high growth rates, and growth
rates for companies in the S&P 500 that are two times the projected growth of the
U.S. economy.
FEA witness Walters also testified that FCG witness Nelson’s projected market
required return of 14.64 percent in the CAPM is overstated and unreasonable, because
FCG’s use of the MI beta coefficient of 0.70 in the CAPM is questionable and subject
to analyst bias in selecting the inputs to the model.
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FEA witness Walters further testified that he calculated nine different applications of
the CAPM using a combination of three different beta estimates and three different
ERP estimates. Based on these results, FEA recommended a CAPM return estimate
of 9.4 percent.
OPC witness Garrett testified that the appropriate CAPM yielded an ROE estimate of
7.9 percent. OPC witness Garrett also testified that FCG Witness Nelson’s ERP
estimate and sources used to support her estimates were not within the range of
reasonableness.
The witnesses’ results from the traditional CAPM were 10.12 to 12.94 percent for FCG,
7.9 percent for OPC, and a range of 7.34 to 10.97 percent for FEA. We find that FCG witness
Nelson’s highest CAPM results of 12.80 and 12.94 percent arising from her traditional CAPM
are not supported. While we agree with the Intervenors that FCG’s traditional CAPM analysis
results in an ROE estimate that is too high, we are not persuaded by the ROE estimates offered
by OPC and FEA, because those are too low. OPC witness Garrett’s CAPM result of 7.9 percent
is unreasonably low because he used a current risk-free rate, which is now stale, and an
unreasonably low ERP estimate based on various publications of ERP surveys.
Likewise, we find that FEA witness Walters’ use of the MI beta coefficient in his CAPM
is questionable and subject to analyst bias, and that his use of Kroll’s ERP and the results of the
CAPM using that data are unreasonable. The average of the remaining results from FCG and
FEA witnesses’ CAPM analyses is 10.3 percent.
FCG witness Nelson argued that FCG’s small size based on market capitalization as
compared to the gas utilities in the proxy group supports a small size adjustment to increase the
target ROE. The record evidence demonstrates FCG has a much higher equity ratio of 59.6
percent than the average of the gas proxy group of 47 percent. We find FCG’s higher equity ratio
and financial strength balance out any risk associated with its smaller size and a numerical
adjustment is neither necessary nor reasonable.
3. Conclusion
After eliminating some of the witnesses’ results produced by questionable assumptions
and inputs used in the DCF and CAPM models as discussed above, the average of the witnesses’
composite DCF model results (9.2 percent) and the composite CAPM results (10.3 percent) is
9.75 percent (10.3 + 9.2 = 19.5 ÷ 2 = 9.75). Both FCG witness Nelson and FEA witness Walters
used similar forms of the risk premium model and obtained similar results. FCG witness
Nelson’s risk premium results were 9.73 percent and 9.80 percent, and witness Walters’ results
ranged from 9.27 percent to 10.42 percent. Consistent with our prior ROE determinations, we
have selected an ROE target midpoint and accompanying range of 100 basis points.
We find the testimony and evidence supports a mid-point ROE of 9.50 percent with a
range of plus or minus 100 basis points. While this result is slightly greater than the national
average authorized ROE for gas utilities in 2022 of approximately 9.38 percent, we find this
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ROE will enable FCG to generate the cash flow needed to meet its near term financial
obligations, make the capital investments needed to maintain and expand its system, maintain
sufficient levels of liquidity to fund unexpected events, and sustain confidence in Florida’s
regulatory environment among credit rating agencies and investors. Therefore, our ROE
midpoint of 9.50 represents a reasonable middle ground between all of the models and
recommendations presented.
Based on the analysis of the record evidence discussed above, we find the appropriate
authorized ROE midpoint is 9.50 percent with a range of plus or minus 100 basis points.
G. Non-Utility Investments
At hearing, we approved a stipulation whereby all parties agreed that FCG does not have
any non-utility investments and therefore, adjustments to the common equity balance were not
required.
H. Weighted Average Cost of Capital (WACC)
1. Parties’ Arguments
FCG argued the appropriate after-tax Weighted Average Cost of Capital (WACC) for the
2023 Test Year is 7.09 percent as presented in FCG witness Fuentes’ recalculated revenue
requirement. FCG witness Campbell asserted that FCG’s proposed regulatory capital structure
would produce a total WACC of 7.09 percent in the 2023 Test Year. Witness Campbell
contended that a WACC of 7.09 percent is reasonable and reflects the benefit to customers of
FCG’s financial strength, including the benefit FCG receives from its parent, FPL. FCG argued
the Intervenors’ recommended WACCs are based on their proposed capital structure and
midpoint ROE, which should be rejected for the reasons stated in the above discussion of the
equity ratio and return on equity. FCG argued that for this reason the Intervenors’ proposed
WACCs should be rejected.
OPC witness Garrett recommended that we impute a capital structure for ratemaking
purposes consisting of long-term 53.1 percent debt, and a 9.25 percent return on equity. This
would result in a WACC of 5.75 percent. OPC argued that the three primary components of a
company’s WACC are the cost of debt, the cost of equity, and the capital structure. OPC argued
the cost of capital is expressed as a weighted average because it is based upon a company’s
relative levels of debt and equity, as defined by the particular capital structure of that company.
OPC argued pursuant to the standards set forth in Hope and Bluefield, financial integrity should
be sufficient to attract capital on reasonable terms under a variety of market and economic
conditions.
FEA did not specify an appropriate weighted average cost of capital to use in establishing
FCG’s projected test year revenue requirement. However, FEA recommended we adopt the cost
of capital parameters proposed by FEA witness Walters, including a return on common equity of
9.40 percent and a common equity ratio of 50 percent, which would produce a weighted average
cost of capital of approximately 5.95 percent.
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2. Analysis
The WACC is an issue that incorporates the amounts and cost rates of the capital sources
determined in other sections into a final WACC. The amounts and cost rates of the capital
components are discussed above. In MFR Schedule G-3, FCG presented its requested projected
test year capital structure based on a 13-month average as of December 31, 2023, consisting of
common equity in the amount of $256,187,447 (59.6 percent), long-term debt in the amount of
$153,552,333 (35.7 percent), and short-term debt in the amount of $20,141,146 (4.7 percent) as a
percentage of investor supplied capital. In her rebuttal testimony, FCG witness Fuentes included
revised projected 2023 test year cost of capital schedules, but the WACC did not change. FCG
witness Campbell explained the ratios of FCG’s investor supplied capital are based on the actual
capital structure of FCG’s parent company, FPL. When reconciled to FCG’s rate base which
includes customer deposits and deferred taxes, the ratios are reduced to 52.56 percent for
common equity, 31.5 percent for long-term debt, and 4.13 percent for short-term debt.
OPC recommended reducing the amount of common equity in the projected capital
structure and increasing the amount of long-term debt. In his testimony, OPC witness Garrett
recommended we reject FCG’s proposal, arguing it has the effect of increasing capital costs
beyond a reasonable level for customers. OPC witness Schultz utilized witness Garrett’s
recommended capital structure in OPC’s proposed calculations. To reflect OPC’s recommended
equity ratio of 46.9 in the capital structure, witness Schultz removed $54,573,294 from the
common equity balance in FCG’s projected capital structure and added $54,553,024 to the long-
term debt balance and $20,269 to the short-term debt balance. OPC also recommended reducing
the total rate base balance by $32,387,362 and making a corresponding adjustment to reduce the
capital structure by the same amount pro-rata over all sources of capital.
FEA did not recommend a specific capital structure including all the capital component
amounts or an overall WACC, only that the equity ratio should not exceed 50 percent.
As discussed above, the appropriate amount of: deferred taxes is $52,659,661 at zero
cost; short-term debt is $19,730,996 at a cost rate of 1.78 percent; long-term debt is
$150,425,423 at a cost rate of 4.28 percent; customer deposits is $3,710,465 at a cost rate of 2.64
percent; and common equity is $250,970,496 at a cost rate of 10.00 percent. Record evidence
indicates that using the capital structure of FCG’s parent, FPL, is reasonable, comparable to the
equity ratios of other regulated gas utility companies in the gas proxy group, and consistent with
prior Commission practice. Therefore, we agree with FCG that the appropriate capital structure
consists of 59.60 percent common equity, 35.70 percent long-term debt, and 4.70 percent short-
term debt as a percentage of investor sources.
3. Conclusion
To reconcile the capital structure with the approved rate base balance of $487,257,875,
the appropriate adjustment is a pro rata decrease over all capital sources. After the reconciliation
adjustment, the WACC is 6.44 percent.
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DOCKET NO. 20220069-GU
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The appropriate capital structure consists of 59.60 percent common equity, 35.70 percent
long-term debt, and 4.70 percent short-term debt as a percentage of investor sources. Based on
the proper components, amounts, and cost rates associated with the projected capital structure for
the 13-month average test year ending December 31, 2023, as discussed above, the appropriate
weighted average cost of capital for FCG for purposes of setting rates in this proceeding is 6.44
percent. The appropriate WACC is presented in Attachment No. 2, which is integrated and
attached to this order.
VII. Net Operating Income
A. Purchased Gas Adjustment and Natural Gas Conservation Cost Recovery
At hearing, we approved a stipulation whereby all parties agreed that FCG has properly
removed the purchased gas adjustment and natural gas conservation cost recovery revenues,
expenses, and taxes other than income from the projected test year.
B. SAFE Investments
At hearing, we approved a stipulation whereby all parties agreed that FCG has made the
appropriate adjustment to Net Operating Income to remove amounts associated with the transfer
of SAFE investments as of December 31, 2022, from clause recovery to rate base.
C. Outside Service Costs
1. Parties’ Arguments
FCG argued that transferring outside service costs incurred for clause dockets from base
rates to respective cost recovery clause dockets is consistent with the cost-causation principle.
FCG stated that by allowing this proposed method of recovery it will guarantee that ratepayers
only pay for the actual cost incurred for outside services required to support the clause
proceedings, subject to true-up. FCG asserted that they have made all appropriate adjustments to
remove the outside service costs incurred for clause dockets from the projected test year
operating revenues and operating expenses.
2. Analysis
FCG requested recovery of outside service costs incurred for clause dockets in respective
cost recovery clause dockets instead of base rates. FCG witness Fuentes testified that this method
is consistent with the cost causation principle and will ensure that customers are only paying for
the actual costs incurred, subject to true-up. FCG made an estimate of $57,294 that is based upon
the estimated amount of time FPL employees and external legal support will spend working on
all of FCG’s cost recovery clauses on an annual basis. The Company stated that if this proposal
is accepted by the Commission, it will create a new master data system to track and record
outside services for both FPL and external legal support in the appropriate cost recovery clause
at the time the cost is incurred. FCG stated that, if approved, this new method will allow the
ORDER NO. PSC-2023-0177-FOF-GU
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amount recorded in each recovery clause to be based on actual time spent for each FPL employee
and/or external legal support, and based on contracted rates not on allocation of costs.
FCG maintained it does not foresee a large increase in regulatory oversight in each of the
applicable cost recovery clause dockets, and FCG proclaimed that the possible incremental
regulatory oversight would be beneficial to customers by confirming that they only pay for the
actual costs incurred. Even an incremental increase in regulatory oversight is something that
should be carefully considered due to the potential complexities from creating additional
regulatory oversight.
Similar to previous company requests to recover bad debt expense through clauses
instead of base rates, this would require additional regulatory oversight. In Order No. PSC-10-
0153-FOF-EI, we denied FPL’s request to recover portions of bad debt through recovery clauses
instead of base rates.21 In that case, FCG acknowledged it would need to create additional
regulatory oversight by developing a new master data system in order to track and record outside
services in the appropriate cost recovery clauses for what FCG estimated to be immaterial
expenses for each cost recovery clause. We do not find that FCG has provided a persuasive
argument to change Commission practice.
3. Conclusion
We find that FCG shall continue to recover outside service costs incurred by clause
dockets through base rates and not cost recovery clauses. As such, O&M expense shall be
increased by $57,294.
D. Miscellaneous Revenues
1. Parties’ Arguments
FCG stated that the appropriate amount of miscellaneous revenues is $1,896,516. The
Company explained that this amount includes a reduction of $16,071 to correct for a forecasting
error.
2. Analysis and Conclusion
In its initial filing, FCG reflected $1,912,587 of miscellaneous revenue. However, FCG
witness DuBose stated that FCG inadvertently included $16,071 for forecasted billing
adjustments that should have been removed from the projected 2023 test year operating
revenues. None of the intervenors took a position on this issue nor did they have any
adjustments. Aside from the Company’s correction, no other adjustments are necessary. As such,
we find for decreasing miscellaneous revenues from FCG’s initial request by $16,071 to the
appropriate amount of $1,896,516.
21 Order No. PSC-10-0153-FOF-EI, issued March 17, 2010, in Docket No. 080677, In re: Petition for increase in
rates by Florida Power & Light Company, Pg. 142-143.
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E. Total Operating Revenues for the Projected Test Year
1. Parties’ Arguments
FCG made no argument for this issue, but took the position that the appropriate amount
of Total Operating Revenues is $64,724,868 for the 2023 projected test year.
As part of its argument that adjustments should be made with regard to the Company’s
customer and therm forecasts, OPC cited in its brief an excerpt from staff’s cross examination of
FCG witness Campbell. This excerpt included questions related to additional Company revenues
in 2024 and 2025 resulting from FCG’s expected growth in customers. OPC noted that witness
Campbell stated he did not forecast the impact of this growth in customers but estimated that this
growth would result in additional revenues of approximately $200,000 per year. Additionally,
OPC noted FCG’s witness admitted that the Company’s customer and therm forecasts typically
become progressively less reliable the further they are projected into the future.
2. Analysis
This is a fallout issue based on the resolution of other issues. Per our decisions in section
I above, there are no recommended adjustments to FCG's forecasts of customers, therms, billing
determinants, or revenue from the sales of gas at present rates for the 2023 projected test year.
As discussed above, we agree with the Company that miscellaneous revenues at current rates for
the projected test year shall be decreased by $16,071 to account for the Company’s forecasting
error, resulting in miscellaneous revenues for the projected test year totaling $1,896,516. This
adjusted amount of Miscellaneous Revenues, when added to the Total Revenue from Sales of
Gas at Current Rates of $62,828,352, results in projected Total Operating Revenues in the
amount of $64,724,868 for the projected test year.
3. Conclusion
The Intervenors did not present testimony or evidence to disprove FCG’s projected Total
Operating Revenues for the projected test year. Therefore, we find that $64,724,868 is the
appropriate level of total operating revenues for the 2023 projected test year.
F. Non-Utility Activities
At hearing, we approved a stipulation whereby all parties agreed that FCG has made the
appropriate adjustments to remove all non-utility activities from operation expenses, including
depreciation and amortization expense.
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G. Salaries and Benefits
1. Parties’ Arguments
FCG argued the appropriate amount of salaries and benefits to include in the Test Year is
$14,803,183. FCG argued the reasonableness of salary and benefit expense is demonstrated by
comparison to the relative comparative market.
OPC argued for reductions in base payroll, incentive compensation, benefits, payroll
taxes, and other expenses.
2. Analysis
a. Salaries and Full Time Employees (FTEs)
OPC offered testimony that the number of full time employees (FTEs) is unreasonable
because FCG’s forecasts are overly optimistic compared to historical data. Witness Schultz
testified that the employee complement of 187 FTEs is inappropriate and does not consider a
vacancy factor, and recommended a head count of 173 FTEs. In 2021, actual payroll, excluding
recovery clause costs for 2021, was $1,893,794 under budget over the actual of $13,126,569.
Witness Schultz also recommended a $49,533 reduction to employee benefits.
FCG witness Slattery countered OPC’s arguments and testified that in 2019 and 2020
actual head count exceeded the budgeted headcount to support the replacement of services and
functions provided by its acquisition of Southern as well as growth in the business. FCG Witness
Slattery testified FCG experienced hiring difficulties, which included limited availability of
technical and engineering related labor; desirability of, and competition for, in-demand
technology skills; fluctuations in the housing market; and the fiscal restraints the Company has
placed on the competitiveness of its pay and benefits package. The witness also testified that
there was a skilled labor shortage due in part to the COVID-19 pandemic, “the Great
Resignation,” and the rise in remote work, but that despite these factors, FCG put forth
significant efforts in 2022 to fill the open positions. As of September 22, 2022, eight positions
had been filled, which increased the employee headcount to 180 FTEs.
With regards to the vacancy factor, FCG witness Slattery testified that hiring costs and
saving associated with vacancies were offset by the cost of overtime and the costs associated
with recruiting, onboarding, and training new staff. Likewise, FCG witness Howard testified that
FCG provided justification for the increased headcount and explained why each position was
required. In broad terms, he asserted the new positions were created due to the physical
expansion of FCG’s system and enhancements to the customer information system (CIS) as well
as the increase in customer count.
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b. Incentive Compensation
OPC presented testimony that excessive incentive compensation should be reduced by
$524,119, incentive compensation should be reduced by $398,746, and long-term incentive
compensation should be reduced by $163,461. OPC witness Schultz pointed to three issues he
had with the incentive compensation plan. First, FCG’s amount of incentive compensation
declined each year from 2019 to 2021, but for the projected 2023 test year FCG projected
$1,772,728. Second, the total projected amount for 2023 is not known because performance and
results of operation are not known and no goals are set. Third, since 2018, almost every
employee received incentive compensation. He argued that despite the high percentage of
employees receiving incentive compensation, FCG failed to meet some of its performance goals,
and that half of the met goals were for financial performance, which provide benefits to
shareholders and not customers. He further stated that FCG’s incentive compensation plan is
discretionary, and that is not what is customarily considered a short-term incentive plan. OPC
recommended that $163,461 of the long-term plan costs be excluded and that $922,865 of short-
term plan costs be excluded.
FCG Witness Slattery addressed incentive compensation in her rebuttal testimony and
proposed a reduction of $505,222 associated with executive incentive compensation, noting that
FCG removed parts of incentive compensation as required by our 2010 FPL Rate Case Order.22
FCG Witness Slattery testified that the incentive compensation expenses are necessary and
reasonable, and are an effective tool in “attracting, retaining, and engaging the required
workforce, and play a significant role in delivering value to customers.” She cited Order No.
PSC-12-0179-FOF-EI in which we rejected OPC’s recommendation to disallow all incentive
compensation and allowed recovery of all of Gulf Power Company’s employee cash
compensation.23
Addressing FCG’s incentive compensation compared to the market, FCG witness Slattery
stated that FCG’s plan is at or below market. If performance-based cash incentive compensation
were eliminated, FCG employees would be compensated roughly 9.6-percent below the market
median, and FCG would not be able to compete in the labor market in that scenario, leaving it
unable to deliver on its commitments to its customers. FCG Witness Slattery further testified that
if incentive compensation were to be removed, it would lead to a reduction in performance-based
variable cash incentive compensation and an increase in base salary and other fixed-cost
programs.
Witness Slattery testified that the reason a high percentage of FCG employees receive
performance incentive compensation is to help develop a culture of employees committed to
performance. Few employees who stay with FCG fail to meet expectations by the end of the
performance period. With regard to company goals, she stated that they are soft goals and
reassessed annually. She asserted that while FCG failed to meet some goals in 2020 and 2021,
22 Order No. PSC-10-0153-EI, issued March 17, 2010, n Docket No. 080677-EI, In re: Petition for increase in rates
by Florida Power & Light Company.
23 Order No. PSC-12-0179-FOF-EI, issued April 3, 2012, in Docket No. 110138-EI, In re: Petition for increase in
rates by Gulf Power Company.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 51
FCG’s performance as of August 2022 exceeded expectations for most goals, and employee cash
incentive payouts are expected to be similar to historic levels. Witness Slattery contended that
the growth in performance-based cash incentive compensation cost correlates to the growth in
head count and the growth in salaries.
C. Conclusion
Upon review of the testimony presented by FCG, we find FCG has adequately addressed
concerns related to staffing levels and incentive compensation. Moreover, the market-based
evaluation of FCG’s total compensation further supports not making any further adjustments
other than to decrease employee pension and benefits expense by $505,222 to recognize the
Company’s adjustment to remove executive incentive compensation.24 Based on this adjustment,
the appropriate amount of salaries and benefits to include in the projected test year is
$14,803,183.
H. Affiliate Expenses
1. Parties’ Arguments
FCG claimed that it has included the affiliate services that are necessary to run its
business in the 2023 test year, as is consistent with historic practice. FCG stated that OPC
recommended that $405,400 of costs allocated as part of FPL’s Corporate Service Charges
(CSC) should be excluded. FCG argued that these costs relate to executive incentive
compensation, which have already been removed by FCG in its rebuttal adjustments explained in
the previous section.
OPC claimed that FCG was unable to provide a comparison of affiliate costs included in
the 2018 Settlement Agreement to the requested 2023 affiliate costs. OPC argued that the
Company has $405,440 of costs that we disallowed in prior dockets. OPC also claimed that
$29,576 of Supplemental Executive Retirement Plan (SERP) costs were included in Corporate
Service Charges. These costs are considered excessive compensation, therefore OPC
recommended they be disallowed.
2. Analysis and Conclusion
The Company’s projected test year reflects affiliate expense of $2,982,225. As explained
by FCG witness Fuentes, all costs associated with affiliate service provided by FPL are charged
according to FPL’s Cost Allocation Manual (CAM). As prescribed by FPL’s CAM, affiliate
expense associated with services provided by FPL to FCG are billed as a direct charge or
allocated in FPL’s CSC. Of the total affiliate expense in the projected test year, $1,257,227 are
direct charges and $1,724,997 are billed through CSC.
24 Order No. PSC-09-0283-FOF-EI, issued April 30, 2009, in Docket 080317-EI, In re: Petition for rate increase by
Tampa Electric Company and Order No. PSC-12-0357-PAA-WU, issued July 10, 2012, in Docket 100048-WU, In
re: Application for increase in water rates in Marion County by Sunshine Utilities of Central Florida, Inc.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 52
OPC witness Schultz testified that there were several concerns with affiliate expense in
the projected test year. The first concern was that FCG was unable to provide a comparison of
affiliate costs included in the 2018 Settlement Agreement to the requested 2023 affiliate costs.
Second, OPC contended that FCG included $405,400 of costs related to incentive compensation
that we have disallowed all or part of in prior dockets. Third, SERP costs in the amount of
$29,576 were included in CSC. In its brief, OPC also added AMI O&M expense to its concerns
related to affiliate expense. FCG argued it is under new ownership, and as such, any comparison
to historic data would not be appropriate. OPC’s concerns are addressed in the discussions of
employee compensation above and pensions and benefits below. We find no further adjustments
are warranted. Therefore, we find affiliate expense for the projected test year shall be
$2,477,003.
I. Pensions and Post-Retirement Benefits Expenses
1. Parties’ Arguments
FCG argued that no adjustments should be made to remove Supplemental Executive
Retirement Plan (SERP) benefit expenses from the corporate service charges. This treatment is
consistent with the adjustments made by FPL pursuant to the FPL 2010 Order.
As discussed in the previous section, OPC argued that affiliate SERP costs in the amount
of $29,576 should be removed.
2. Analysis and Conclusion
FCG requested employee pensions and post-retirement benefits expense of $661,618.
OPC witness Schultz testified that $29,576 of SERP costs included in pension and post-
retirement benefits expense should be disallowed as those costs are considered to be excessive
compensation. FCG witness Slattery stated that consistent with the FPL 2010 rate case order, no
adjustments are necessary to remove SERP benefit expenses from the Corporate Services Charge
(CSC).25 In the FPL 2010 rate case order, we declined to adjust FPL’s forecast for affiliate
expense.
We find OPC’s arguments for reducing SERP lack support and therefore are
unpersuasive. We find FCG’s request to be reasonable, and therefore, we find the appropriate
amount of pensions and post-retirement benefits expense to include in the projected test year is
$661,618.
25 Order No. PSC-10-0153-EI, issued March 17, 2010, in Docket No. 080677-EI, In re: Petition for increase in rates
by Florida Power & Light Company.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 53
J. Injuries and Damages Expense
1. Parties’ Arguments
FCG stated that its core values emphasize a commitment to safety. FCG goes on to
explain that because of this emphasis on safety, the appropriate injuries and damages expense for
the 2023 Test Year is $515,304.
FCG refuted claims by OPC witness Schultz that FCG’s safety performance needs
improvement as well as his recommendation that injuries and damages expense be reduced by
$212,790. FCG stated that OPC’s claims are without merit and should be rejected. FCG asserted
that OPC’s reliance on OSHA-recordable events is misplaced and that while they are a useful
metric, they do not necessarily demonstrate overall workplace safety. FCG’s main assertion was
that OSHA-recordable events alone do not provide sufficient information as FCG encourages its
staff to report all injuries regardless of severity. FCG stated that since its last rate case there have
been no recorded incidents that OSHA flagged as “Serious Injuries or Fatalities,” with most of
FCG’s OSHA-recordable incidents being of a less severe variety, like sprains and strains. FCG
additionally stated that since 2019, the Company has never had more than three recordable
incidents within a year. FCG also explained that the increase in the cost is the result of increases
in insurance premiums across the industry and the reclassification of expenses. FCG then
reiterated that the amount requested for injuries and damages expense is reasonable and should
be approved.
OPC stated that injuries and damages expense doubled each year from 2019 to 2021.
During that period, the cost increased from $111,135 to $243,888 to $552,519. OPC also stated
that the Company requested $515,304. OPC stated that the increases, which took place under the
ownership of FPL, are largely related to: insurance or reserve accruals to protect the service
company against injuries and damages claims by employees or others, losses of such character
not covered by insurance, and expenses incurred from settlements of such claims. It should be
noted that in both 2020 and 2021, the Company failed to meet its goals for the number of OSHA-
recordables (per 200,000 hours). OPC recommended using a three-year average for injuries and
damages expense, a reduction of $212,790.
2. Analysis
FCG requested $515,304 for injuries and damages expense. OPC witness Schultz stated
that the expense doubled each year from 2019 to 2021 from $111,135 to $243,888 to $552,519.
He contended that FCG has a trend of safety concerns and that this has led to the increase in
injuries and damage expense. He stated the number of OSHA-recordables were worse than
FCG’s goal in 2020 and 2021. Witness Schultz recommended a decrease of $212,790, leaving
$302,514. This adjustment is based on the three-year average from 2019 to 2021.
FCG stated that OSHA-recordable events do not necessarily demonstrate overall
workplace safety, or the severity of the injuries sustained. Witness Howard asserted that FCG has
not recorded any incidents that OSHA flagged as serious injuries or fatalities and that most
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 54
recorded incidents were minor injuries. FCG witness Howard testified that since 2019, FCG has
not had over three OSHA-recordable incidents in a year and had none in 2019 and the first half
of 2022. The main increases to injuries and damages expense come from two factors: increases
in the cost of insurance and a reclassification of expense from Account 924 (Property Insurance)
to Account 925 (Injuries and Damages) from 2020. In its brief, FCG explained the
reclassification, stating that in 2020, certain liability expenses were incorrectly recorded in
Account 924 and were subsequently reclassified to Account 925 in 2021.
3. Conclusion
We find FCG’s justification adequately explains the increase in this expense and we do
not find a need for any adjustments. We find injuries and damages expense in the amount of
$515,304 in the projected test year is reasonable.
K. Insurance Expense
1. Parties’ Arguments
FCG stated that the appropriate injuries and damages expense (Account 925) and
property insurance expense (Account 924) for the 2023 Test Year are $515,304 and $503,407,
respectively. FCG opined that these insurance costs are incurred by FCG to provide service to its
customers and benefit customers by not leaving them with potential exposure to costs associated
with injuries and damages, property damage, and vehicle accidents. The Company also
mentioned the imprudence of foregoing such coverage.
FCG challenged OPC witness Schultz's assertion that insurance expense should be
reduced by $9,431 to remove Directors & Officers Liability (DOL) Insurance because this
expense provides no benefits to customers. The Company stated that DOL insurance is a
necessary and reasonable expense for FCG to provide service to its customers, as it is essential to
recruiting and retaining talented and competent leadership. FCG stated that because of the above-
mentioned reasons, FCG’s DOL insurance expense is appropriately included in the 2023 Test
Year revenue requirements.
OPC stated that as DOL insurance protects the Company’s officers and directors from
lawsuits that arise from their own questionable decisions, and the lawsuits are generally brought
by shareholders, the customers receive no benefit from this insurance; as DOL insurance offers
no benefit to customers it should be disallowed completely. OPC argued that if we do not
disallow this cost, we should at least remove 50 percent of the requested amount.
2. Analysis
FCG requested $503,407 for insurance expense. OPC recommended a disallowance of
$9,431 associated with DOL insurance expense. OPC witness Schultz testified that DOL
insurance is to protect directors and officers and the only claims that make DOL insurance
necessary come from shareholders, not customers. Witness Schultz also testified that this issue
has been addressed by this Commission in prior cases which determined that DOL insurance
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 55
expense should be shared equally between customers and shareholders. OPC recommended that
the full amount of DOL be removed. Witness Shultz stated that if all of DOL insurance expense
is not disallowed, then there should be an equal sharing of the cost between shareholders and
customers.
In rebuttal testimony, FCG witness Howard testified that DOL insurance plays an
important part in attracting and retaining skilled leadership which does benefit customers. He
claimed that without DOL insurance, it would be impossible for FCG to attract and retain
experienced directors and officers.
By Order No. PSC-10-0131-FOF-EI, the Commission reaffirmed its prior decisions that
DOL “has become a necessary part of conducting business for any publicly owned company and
it would be difficult for companies to attract and retain competent directors and officers without
it.”26 The Commission also recognized that “ratepayers receive benefits from being part of a
large public company including, among other things, easier access to capital.”27 Because both
shareholders and ratepayers benefit from DOL, the Commission split the cost of insurance
between both groups.
3. Conclusion
Consistent with our prior decisions, we find that ratepayers and shareholders should share
the DOL expense. With a reduction of half of DOL insurance expense, insurance expense shall
be decreased by $4,716. Thus, we find insurance expense of $498,691 in the projected test year.
L. Projected Contractor Cost
At hearing, we approved a stipulation whereby all parties agreed that yes the projected
contractor cost is reasonable. FCG does not separately identify or track contractor costs on its
books and records, or in its forecast. However, FCG does track outside services, which includes
contractor costs. As reflected on page 4 of MFR E-6, the reasonable, appropriate, and justified
Test Year expense for Account 923 (Outside Services Employed) is $3,993,307 (adjusted).
M. O&M Expenses Adjustment
At hearing, we approved a stipulation whereby all parties agreed that there is no
adjustment needed to the projected test year O&M expenses to reflect changes to the non-labor
trend factors for inflation and customer growth.
26 Order No. PSC-10-0131-FOF-EI, issued March 5, 2010, at p. 99, in Docket No. 090079-EI, In re: Petition for
increase in rates by Progress Energy Florida, Inc.
27 Id.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 56
N. Storm Damage Reserve
1. Parties’ Arguments
FCG argued that its current storm reserve was authorized in the 2018 Settlement
Agreement, and the storm reserve could be revisited in the future if the reserve amount of
$800,000 was exceeded. As of December 31, 2022, the Company’s reserve balance was
$205,415, thus it was unnecessary to reevaluate. Additionally, FCG argued that it submitted a
Storm Damage Self-Insurance Reserve Study (Reserve Study) as required by Rule 25-7.0143,
F.A.C., which concluded the storm reserve mechanism should be continued at its current levels.
OPC argued the storm reserve at present was adequately funded over the last 46 months,
FCG had only charged costs against the reserve for two storms totaling $58,127. This resulted in
an estimated annual average cost of $15,164. Given the current $162,290 reserve balance as of
March 31, 2022, OPC argued that the storm reserve was sufficient for more than 10 years if costs
were incurred at historic levels. OPC also argued that the Company’s Reserve Study estimated
the annual storm cost to be $190,000. OPC argued that the annual accrual of $57,500 should be
discontinued as of January 1, 2023.
2. Analysis
FCG witness Campbell testified that the Company was authorized to implement a storm
reserve as a part its 2018 Settlement Agreement, setting the annual accrual at $57,500 and a
target reserve of $800,000. Witness Campbell testified that the 2018 Settlement Agreement
established that FCG’s storm related costs could be recovered consistent with Rule 25-6.0143,
F.A.C., which is this Commission’s storm rule applicable to electric utilities. We have since
adopted Rule 25-7.0143, F.A.C., which is specific to gas utilities. This rule allows the
establishment of a storm reserve account and outlines the types of storm related costs that an
investor-owned natural gas utility can charge to the storm reserve. Witness Campbell testified
that the Company is proposing to calculate and recover any storm related costs consistent with
Rule 25-7.0143, F.A.C. However, FCG is not requesting any changes to the annual accrual or
target reserve amounts.
In support of its argument that the storm reserve was adequately funded and OPC argued
that the annual accrual of $57,500 should be discontinued, OPC witness Schultz testified that the
Company’s storm reserve balance was $162,290 as of March 31, 2022. He stated that over a
period of 46 months, $58,127 had been charged against the reserve for two storms, the largest
cost being $48,626 in 2020. Witness Schultz calculated that over the 46 month period, the
$58,127 amount charged to the reserve averaged $1,264 a month or $15,164 annually. Therefore,
FCG could charge $15,164 to the storm reserve every year for more than 10 years before the
storm reserve was fully depleted.
In rebuttal, FCG witness Howard testified that per Commission Rule 25-7.0143, F.A.C.,
FCG had retained an independent, third-party consultant to prepare its Reserve Study and that
the Reserve Study had found that continuing the storm reserve mechanism at a target of
$800,000 was reasonable and appropriate considering the potential for future storms.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 57
Furthermore, witness Howard testified that witness Schultz instead used “a few periods of
historical data to base his entire conclusion that the current Storm Damage Reserve balance is
adequate for future periods.” Witness Howard asserted that witness Schultz’s testimony ignored
the purpose of the Commission-required Reserve Study and only used select storm data as a
predictor of future storm damage to the Company’s system. Witness Howard also testified that
Florida is a hurricane-prone state, and FCG must plan and prepare for storms that may impact its
service areas and facilities. Finally, OPC witness Schultz’s recommendation to reduce the storm
reserve by almost 75 percent was based on limited historical storm damage data and is not
persuasive.
Having reviewed the conclusions of the Reserve Study, we find the storm reserve
mechanism shall be continued at a target of $800,000, as approved in the 2018 Settlement
Agreement. The historic storm data laid out by witness Schultz was limited in scope, only
examining a 46-month period. Utilizing a 46-month period of data to predict future storm
damage costs over the next ten years is not a sufficient basis. As a part of the Reserve Study’s
analysis, hurricane data from 1900 to 2017 was used, as well as information from other sources
such as the National Oceanic and Atmospheric Administration. The Reserve Study estimated that
the Company’s expected annual cost due to storm damage was $190,000, although the annual
cost could be as high as $2,500,000, compared to $15,164 as calculated by witness Schultz.
Thus, the Reserve Study relied on a more expansive amount of data to reach its conclusions,
which supported the reserve target of $800,000.
3. Conclusion
We are not persuaded by OPC that FCG’s previously approved storm reserve mechanism
should be discontinued or modifications made to the annual storm damage accrual and target
reserve amounts. Further, if the Company’s storm damage accrual and target reserve amounts
remain in place as approved in the 2018 Settlement Agreement, there is no incremental increase
in cost to customers. We approve the continuation of FCG’s Storm Damage Reserve provision as
included in the 2018 Settlement Agreement, which is consistent with Commission Rule 25-
7.0143, F.A.C. No change shall be made to either the annual storm damage accrual of $57,500 or
the target reserve amount of $800,000.
O. Parent Debt Adjustment (PDA)
1. Parties’ Arguments
FCG witness Campbell testified that FCG has received 100 percent of its debt and equity
financing from FPL’s pool of funds which was available based on FPL’s capital structure. Thus,
a parent debt adjustment is not applicable in this case as the parent company, FPL, holds a lower
percentage of debt in its capital structure than FCG, and no additional interest expense tax
benefit exists at the parent company level. Furthermore, FCG has proposed a 2023 test year
financing capital structure equal to the capital structure of FCG’s parent which consists of 59.6
percent common equity and 40.4 percent debt as a percentage of investor sources of funds.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 58
OPC argued this Commission has Rule 25-14.004, F.A.C. (Parent Debt Adjustment or
PDA Rule) that has not been waived pursuant to Section 120.542, F. S., which mandates the
required application of the PDA Rule unless the utility rebuts the presumption that debt of the
parent may be invested in the equity of the subsidiary. OPC further argued that the
overwhelming evidence is that debt is affirmatively shown to be embedded in FPL’s investment
in FCG and Federal income tax expense should be reduced by $382,452.
2. Analysis
The parent debt adjustment provides that the income tax expense of a regulated utility
will be adjusted to reflect the tax benefit of the interest expense of the parent company where the
parent company’s debt may be invested in the equity of the regulated utility and both join in the
filing of a consolidated income tax return.
NextEra Energy transferred FCG to FPL on July 29, 2018. Upon acquisition by FPL,
there was no significant change in FCG’s total per book capital structure value as inherited from
Southern Gas Company, on a Commission-regulated basis. FCG has proposed a 2023 test year
capital structure equal to the capital structure of FPL, which consists of investor sources of funds
of 59.6 percent common equity and 40.4 percent debt. Additionally, FCG does not issue its own
debt or equity in the marketplace. Because FCG does not issue its own debt, there is no double
leverage. Because FCG does not issue its own debt or equity in the marketplace, it is reasonable
to allocate FPL’s investor sources of funds, debt and equity, to FCG for the purpose of setting
FCG’s rates. This approach recognizes that FPL’s investor sources of funds are FCG’s investor
sources of funds, and therefore, the debt of FPL is not invested in the equity of FCG.
3. Conclusion
Because the investor sources of funds, and in essence, the capital structures, are one and
the same, the debt of FPL is not invested in the equity of FCG and we find a parent debt
adjustment is neither necessary nor appropriate under the PDA Rule.
P. Rate Case Expense
1. Parties’ Arguments
FCG stated that an update to its estimated Rate Case Expense reflected a reduction in rate
case expense of $0.1 million from the original estimate $1.9 million. The Company stated that
consistent with its 2018 Settlement Agreement, it requested a four-year amortization period for
Rate Case Expense, resulting in an annual amortized amount of $470,209. FCG pointed out that
no parties opposed the four-year amortization period.
FCG opined that the primary driver of Rate Case Expense is the amount of work involved
to litigate the case. FCG stated that it took a bottom-up approach to estimate the work involved
to prepare, file, and litigate. The Company emphasized the amount of work involved with a rate
case is due to factors largely out of the control of the Company.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 59
FCG asserted that its decision to include FPL affiliate support was not to replace FCG’s
in-house resources, but instead to support a wide array of services necessary for a rate case. As a
result, OPC witness Schultz’s and FEA witness Collins’ recommendations to limit the amount of
Rate Case Expense is unsupported and without merit.
OPC stated that the test year costs have increased by $769,350 or 62.97 percent over the
costs from FCG’s previous rate case. OPC stated that while the scope of the study has increased,
the requested amount is still excessive. OPC asserted that the $1,564,981 attributed to FPL
replacement cost is unwarranted. OPC pointed out that these costs are higher than the benchmark
Rate Case Expense of $1,476,260 applicable to the previous rate case. OPC stated an additional
concern that the Company failed to take advantage of the Proposed Agency Action method,
which burdened customers and benefited shareholders.
FEA witness Collins testified that the Rate Case Expense is over $700,000 more and 63
percent higher than expenses for FCG’s previous rate case. He also asserted that the increase was
not justified. FEA witness Collins stated that the lions-share of costs come from FPL’s affiliate
support; however, FCG does not demonstrate what support FPL provided or why this level of
support was not needed in earlier rate cases. FEA witness Collins argued that we should limit
FCG’s rate case expense to previously approved amounts with an adjustment for inflation or
$1.427 million. FEA stated that this would lower amortization expense by approximately
$141,000 and lower the deferred Rate Case Expense in rate base by approximately $494,000.
FIPUG joined the argument of FEA.
2. Analysis and Conclusion
FCG’s initial filing included Rate Case Expenses of $1,991,116. FCG stated OPC’s and
FEA’s arguments are without merit and unreasonable due to the nature of the costs associated
with a fully litigated rate case. Through discovery, FCG updated the amount of Rate Case
Expense, lowering the total amount of Rate Case Expense by $110,280, resulting in the updated
amount of $1,880,836.
We have examined the requested actual and estimated expenses, along with supporting
documentation, and find these expenses are reasonable for a rate case on the hearing track. FCG
also requested a four-year amortization period. The four-year amortization period requested by
FCG is not disputed by any of the intervenors, and we find it is reasonable. The appropriate
annual amount of Rate Case Expense is $470,209. The appropriate amortization period is four
years.
Q. Uncollectible Accounts and Bad Debt
At the hearing, we approved a stipulation whereby all parties agreed that no adjustment
shall be made to Uncollectible Accounts for Bad Debt in the Revenue Expansion Factor.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 60
R. O&M Expenses
1. Parties’ Arguments
FCG’s O&M expenses have increased by $5.8 million in the 2023 Test Year revenue
requirement. FCG stated that approximately $2.4 million of the increase in operating costs is
attributable to inflation. The remainder of the additional increase is due to customer growth,
system expansion, increased damage prevention efforts, and implementation of certain
technologies and initiatives that are necessary to continue to provide safe and reliable natural gas
service.
OPC argued that it would be inappropriate for customers to pay for the experimental AMI
program, considering FCG was not able to provide proof of how FCG customers would benefit
from the program. OPC also noted that even though FCG claimed there would be costs savings,
FCG was unable to support this claim.
2. Analysis and Conclusion
This issue is determined by our findings concerning other issues. Based on prior findings,
the appropriate amount of projected test year O&M expense is $25,497,650.
S. Taxes Other Than Income (TOTI)
1. Parties’ Arguments
FCG stated that because OPC’s recommended adjustment to head count for the 2023 Test
Year should be rejected, OPC’s flow through adjustment (payroll tax) to Taxes Other Than
Income Taxes should also be rejected.
OPC witness Schultz addressed this issue in his testimony and exhibits. The total amount
of Taxes Other than Income should be reduced to no more than $6,263,843, after the payroll tax
adjustment of $122,767.
2. Analysis
In MFR Schedule G-6, FCG states that property tax was projected by multiplying a
composite millage rate of 1.8 percent by the net plant at year end. During discovery, FCG
provided a more detailed calculation of the methodology used to estimate property taxes. The
Company additionally provided updated property tax expense for 2022, which reflected a $1.1
million disparity between the actual and projected expense for 2022. We find that this large of a
disparity warrants an adjustment to update the Company’s estimated property tax expense to
include the actual data for 2022. Using FCG’s methodology, we included the actual taxable value
and composite tax rate from 2022 to recalculate the estimated 2023 property tax expense. This
results in a decrease of $510,886.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 61
3. Conclusion
Based on our findings in previous issues, additional corresponding adjustments to TOTI
are necessary. An adjustment to Load Enhancement Services (LES) revenue in section I results
in an increase of $777 for corresponding regulatory assessment fees (RAFs). A reduction to
forecasted miscellaneous revenue in Section IV results in a decrease of $80 for corresponding
RAFs. A reduction to incentive compensation, also in Section IV, results in a corresponding
reduction of $32,995 to payroll taxes. Therefore, we find that TOTI be reduced by a total of
$543,184. Accordingly, we find the appropriate amount of TOTI for the projected test year is
$5,843,427.
T. Test Year Income Tax Expense
1. Parties’ Arguments
FCG stated that the appropriate amount of Income Tax Expense for the projected test
year is $1,804,203. FCG noted that OPC recommended an adjustment to increase Income Tax
Expense for the projected test year by $1.4 million, as reflected in OPC witness Schultz’s
testimony. FCG argued that OPC’s recommended increase is based on the proposed adjustments
to net operating income, which should be rejected, as addressed in previous issues.
OPC stated that the appropriate amount of Income Tax Expense is no more than
$241,372, as addressed by OPC witness Schultz. OPC’s recommended amount of Income Tax
Expense does not include $1,530,280 of deferred income tax as reflected in witness Schultz’s
Exhibit 46.
2. Analysis and Conclusion
Based on our findings in previous issues, the appropriate amount of projected test year
Income Tax Expense, including current and deferred income taxes and interest synchronization,
is $1,934,574, as reflected in Table 3 below.
Table 3
Adjusted Income Tax Expense
MFR Amount Requested $1,632,690
Adjustments:
Interest Synchronization Adjustment $6,381
Fall-Out Adj Federal Income Taxes $231,378
Fall-Out Adj State Income Taxes $64,126
Total Adjustments $301,884
Adjusted Amount $1,934,574
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 62
U. Operating Expenses
1. Parties’ Arguments
FCG Stated that OPC’s recommended reduction to the Total Operating Expenses is based
on OPC witness Schultz’s proposed adjustments to the individual components of net operating
income, which are addressed in section VII.
OPC witness Schultz addressed this issue in his testimony and exhibits including, but not
limited to, Exhibit 46, Schedule C. Total Operating Expenses should be reduced to no more than
$49,398,824.
2. Analysis and Conclusion
Based on our findings in previous issues regarding net operating income, the appropriate
amount of Total Operating Expenses for the projected test year is $50,592,224.
V. Net Operating Income
1. Parties’ Arguments
FCG argued that OPC’s recommended increase to Net Operating Income is based on
OPC witness Schultz’s proposed adjustments to the individual components of net operating
income, which should be rejected for the reasons stated in previous issues.
OPC stated that Net Operating Income should be increased to at least $15,342,115. OPC
also claimed that a credit should be reflected to prevent a double recovery of the plant cost for
the LNG facility because revenue projections are understated, and the Company has already
recovered $11,596,631 from ratepayers for the unused facility.
2. Analysis and Conclusion
Based on our findings in previous issues, the appropriate amount of Net Operating
Income for the projected test year is $14,132,644.
VIII. Revenue Requirements
A. Revenue Expansion Factor and Net Operating Income Multiplier
At hearing, we approved a stipulation whereby all parties agreed that, as reflected in
MFR G-4, the revenue expansion factor and net operating income multiplier for the 2023
projected test year are 73.9255 and 1.3527, respectively.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 63
B. Annual Operating Revenue Increase
1. Parties’ Arguments
FCG requested a rate plan with a total base rate revenue increase of $28.3 million based
on the projected 2023 test year. This amount included an incremental base rate revenue
requirement of $18.8 million, a previously approved increase of $3.8 million for the LNG
facility, and $5.7 million to transfer the SAFE investments from clause recovery to base rates.
FCG argued that the proposed four-year rate plan and incremental increase of $18.8 million
would provide rate stability and certainty to customers, as such providing customers with savings
and benefits lasting all four years.
FCG stated that it has earned below the bottom of the current authorized ROE range since
the previous rate case and without base rate relief FCG will continue to earn below the current
authorized ROE range. By FCG not earning in the authorized ROE range, FCG has not been
fully recovering its reasonable and prudent costs of providing service to its customers. FCG
stated that inflation, interest rates, capital costs, and overall market risk are not only higher since
its last base rate case, but also greater than since FCG filed this base rate case on May 31, 2022.
OPC proposed a total base revenue increase of no more than $4,805,981, based on OPC
witness recommended adjustments; FCG asserted that those recommended adjustments should
not be considered based on explanations provided above. FCG asserted that the recommended
increase by OPC would not allow FCG to earn at the bottom end of its current authorized ROE
range and therefore would not allow FCG to earn within the proposed 2023 ROE range.
OPC stated that the base rate revenue increase should be no more than $4,805,981. OPC
argued that the increase should be reduced due to the impact of revenue projections being
understated and to reflect that the Company already recovered over $11,596,631 from customers
for the LNG facility.
2. Analysis and Conclusion
Based on our findings above, the appropriate total annual operating revenue increase for
the projected test year is $23,308,073. This amount includes an incremental increase of
$14,149,121 and revenue associated with the transfer of SAFE investments and the LNG facility,
as reflected Table 4 below.
Table 4
Annual Operating Revenue Increase
Operating Revenue Increase $23,308,073
LNG Revenue (3,828,493)
Transfer of SAFE Investments (5,330,459)
Incremental Revenue Increase $14,149,121
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 64
IX. Cost of Service and Rate Design
A. Cost of Service Study (COSS)
1. Parties’ Arguments
FCG witness DuBose testified that the purpose of the COSS is to allocate the Company’s
costs among the different rate schedules based on cost causation principles. When developing a
COSS, costs are first grouped by function (such as distribution or production), then costs are
classified into the four main classifications: customer, commodity, demand, and revenue.
Capacity costs include mains, regulator stations, and LNG storage. Customer costs include
meters, house regulators, and services. Capacity and customer-related costs represent the
majority of the total cost of service. Finally, there is an allocation of costs to the various rate
classes based upon allocation factors. FCG argued its COSS is appropriate and consistent with
the methodologies used by the Company in prior rate cases, and follows the presentation format
of the prescribed MFR forms and schedules. FCG further argued that FEA witness Collins’
proposed COSS would significantly shift costs from C&I classes to the residential customer
classes if adopted.
FEA witness Collins testified that FCG’s Class Cost of Service Study (CCOSS) is not
appropriate and does not accurately reflect class cost causation because it uses the Peak and
Average (P&A) method to allocate the cost of mains to customer classes and also fails to allocate
any distribution mains costs on a customer basis. FEA asserted in its brief that the COSS
provided by its witness better reflects how capacity costs are incurred, which more accurately
reflects cost causation.
FEA further argued that FCG’s cost of service study is flawed because: (1) it does not
reflect cost causation; (2) FCG’s P&A method is not a traditional P&A method; and (3) FCG’s
P&A method improperly allocated the costs of distribution mains to customer classes primarily
on a volumetric basis and fails to classify and allocate any distribution mains costs on a customer
basis. FEA contended that in order to correct these flaws, the Company should classify mains on
both a demand and customer basis. FIPUG joined the position of FEA.
2. Analysis
FCG contended that the primary difference between its proposed COSS and the COSS
proposed by FEA is that the Company used the P&A methodology, whereas witness Collins
proposed allocating distribution mains based on design day demand and number of customers.
FCG further asserted that witness Collins’ proposal is essentially a minimum distribution system
allocation. FCG explained that FEA’s proposal related to design day may be appropriate for a
utility located in a colder climate where winter peaks occur due to residential gas heating load.
FCG, however, serves 49 percent of its customers in Miami, and therefore FCG’s system is not
as peak-sensitive as a gas utility in a colder climate.
Additionally, FCG stated that although residential customers make up 93 percent of its
customers, residential customers flow 14 percent of the gas while C&I customers flow 86
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 65
percent of the gas on FCG’s system on an annual basis. FCG asserted that the allocation method
proposed by FEA would inappropriately shift costs away from the C&I customers who use
FCG’s system the most during the year to residential customers who use it the least. FCG argued
FEA’s proposal does not account for the actual utilization of the mains by different classes of
customers, with C&I utilization over six times that of residential customers. FCG argued that
despite that, FEA witness Collins’ proposal would allocate 70 percent of the total revenue
requirements to the residential customers, while only 29 percent would be assigned to the C&I
classes.
FCG further noted that the Company’s COSS assigns 37 percent of costs to residential
customers and 62 percent to the C&I classes. FCG argues that its proposed cost allocation
methodology better reflects how customers use FCG’s system than FEA’s proposed
methodology and is more consistent with cost causation theory, considering that the actual usage
of the system by residential classes is 14 percent and the actual usage of the system by C&I
customer classes is 86 percent. Finally, FCG argued that FEA also overlooks that the P&A cost
allocation methodology has been widely used by investor-owned natural gas utilities in Florida,
including FCG, Peoples Gas System, and Florida Public Utilities.
FEA emphasized in its brief that a fundamental question when selecting a COSS is
whether the methodology reflects cost causation. Accordingly, FEA witness Collins testified that
when a gas utility installs a new distribution main to expand capacity on its system, it must
consider customers’ demand on a system peak day, or design day, and the number of customers
being served. Thus, FEA concluded, the costs the utility incurs to provide service are driven by
peak day demand and the number of customers. FEA concluded that FCG’s proposed COSS is
inconsistent with cost allocation since it fails to allocate costs based on how they are incurred.
FEA witness Collins further argued that, based on his experience, in a traditional P&A
cost of service study, capacity class allocators are determined by each class’s contribution to the
system design day demand, weighted by (1 - system load factor) and by each class’s contribution
to system annual usage, weighted by the system load factor. Witness Collins notes that instead of
this methodology, FCG based the peak allocator on the monthly maximum volume of a class in
the test year. Witness Collins contended that by using the sum of 13 months of volumes for its
class P&A allocators (12 actual monthly usages plus the maximum monthly volumes), FCG is
essentially allocating capacity-related costs on annual usage and not the traditional P&A method.
We reviewed FCG’s three prior rate cases in 2017, 2003, and 2000 to determine how the
capacity costs were allocated to the rate classes. In all three rate cases, FCG proposed and we
approved the P&A method, consistent with the allocation of capacity-related costs in the instant
case. We agree with FCG’s position that the Company used the same cost classification
methodology as in its previous three rate cases. In addition, FEA provided no support to justify
their assertion that a traditional P&A COSS employs a different allocation than FCG’s proposed
P&A methodology.
Witness Collins stated that FCG designs its system to meet the design day demands of its
customer classes and must allocate some of its distribution costs based on design day demand.
However, witness DuBose argued that while design day may be a factor in system design, the
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 66
guidance provided by the National Association of Regulatory Utility Commissioners Gas
Distribution Rate Design Manual acknowledges that there are other factors to consider when
allocating distribution costs that are unique to each gas utility. Witness DuBose further stated
that witness Collins’ proposal related to design day could be appropriate for a utility located in a
colder climate that builds and operates its system to serve high and extended winter peaks that
occur due to increased residential gas heating load. While we acknowledge that there are
different methodologies to allocate costs, we find that FCG provided a reasonable basis for
continuing the P&A method, as proposed, for allocating capacity-related costs.
Witness DuBose testified that although residential customers make up 93 percent of
FCG’s customers, the residential customers flow only 14 percent of the gas on an annual basis
while commercial and industrial (C&I) customers flow 86 percent of the gas. FCG’s COSS
methodology assigns 37 percent of the cost to residential customers and 62 percent to the C&I
customers. Witness Collins allocated 70 percent of the total revenue requirement to residential
customers and only 29 percent to C&I customers. We find that FCG’s P&A method produces a
cost allocation that more closely matches how customers utilize the distribution system. FEA’s
proposed method, on the other hand, unduly shifts costs from C&I customers to residential
customers.
3. Conclusion
Based on review of the record, FCG’s proposed cost of service study is appropriate and is
hereby approved for all regulatory purposes until base rates are reset in FCG’s next general base
rate proceeding.
B. Revenue Increase Allocation Amongst Rate Classes
1. Parties’ Arguments
FCG argued in its brief that the Company allocated the proposed revenues by rate class to
improve parity among the rate classes as much as possible, while following our practice of
gradualism and considering the competitive nature of the natural gas industry. FCG further
asserted that the Company’s proposed rates practice gradualism, because no class would receive
an increase greater than 1.5 times the system average increase in total operating revenues,
including adjustment clauses.
Moreover, FCG argued that it is appropriate to consider the competitive nature of the
natural gas industry when designing rates, to mitigate the potential for fuel switching and bypass.
FCG contended that moving all rate classes to parity, even when applying gradualism, could
result in a disproportionate increase to certain large C&I customer classes, which could make
fuel switching or bypass more economical than continuing to receive service from the Company.
FCG stated that the Company slightly reduced the proposed increase to rate classes GS-120K
and GS-1250K to address the potential for fuel switching and bypass.
Finally, FCG argued that FEA’s proposed revenue allocation should be rejected, because
it relies on FEA’s proposed cost of service study methodology, as discussed above, which is
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 67
inconsistent with Commission practice and not reflective of how FCG operates and provides
service to its customers.
In its brief, FEA stated that the Company’s class revenue allocation should be distributed
to the rate classes using the results of witness Collins’ cost of service study, because the
Company’s proposed cost of service study does not accurately reflect class cost causation. FEA
further argued that witness Collins’ class revenue allocation proposal moves each class’s revenue
increase to no greater than 1.5 times the system average increase, with no class receiving a rate
decrease. FIPUG joined the arguments of FEA.
2. Analysis
Witness DuBose testified that FCG proposed revenues by rate class to improve parity
among the rate classes to the greatest extent possible, while applying gradualism and considering
the competitive nature of the natural gas industry. Parity is calculated by dividing the class rate
of return (ROR) by the system ROR. A rate class with a parity index of 100 percent earns the
same ROR as the system average and is at parity. A rate class with a parity index of less than 100
percent is below parity; a rate class above 100 percent is above parity. The ROR by rate class
shows which classes are over- or under-earning relative to the system ROR, or stated differently,
which class is covering their cost to serve and which class is not. Witness DuBose stated that
FCG’s COSS shows that parity indices vary by rate class, with some class indices above parity
while others fall below parity. Assessing parity at present rates provides a starting point in
allocating any increase in revenue requirements.
Gradualism is a concept that is applied to prevent a class from receiving an overly-large
rate increase. When a rate increase limit is imposed on a rate class, the remaining classes will
have to absorb that difference. In previous electric and natural gas rate cases, we have applied the
policy of limiting rate increases in total operating revenues for an individual rate class to no
greater than 1.5 times the system average increase, and that no rate class receives a revenue
decrease.
As witness DuBose explained, the allocation of any revenue requirement increase should
be assessed in terms of its impact on the ROR and parity index for the respective rate class.
Witness DuBose testified that FCG is requesting a 44 percent increase in total revenues for the
2023 test year. Under our guideline of gradualism, any increase to a rate class would be limited
to 66 percent, or 1.5 times the proposed system increase of 44 percent. Witness DuBose’s
calculations show that under FCG’s proposed increase, no class would receive more than a 56
percent increase, including the transfer of SAFE revenue requirements from clause to base rates
and the addition of the previously-approved LNG project.
MFR Schedule H-1, with RSAM, page 2 of 6, similarly shows that no class would
receive an increase of more than 56 percent, with percent increases ranging from 34 percent to
56 percent. The same MFR Schedule also shows parity indexes at present and proposed rates.
With the exception of the GS-120K rate class, which is discussed below, FCG has proposed
revenues by rate class that improve parity to the greatest extent possible, as asserted by witness
DuBose.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 68
With respect to large C&I customers, witness DuBose explained that if natural gas
service becomes uneconomical, large C&I customers can bypass FCG’s system or locate their
business outside of FCG’s service territory or even the state of Florida. Therefore, to address the
potential for fuel switching and bypass, FCG slightly reduced the proposed increases to rate
classes GS-120K and GS-1250K. Rate class GS-120K is available to non-residential customers
using between 120,000 and 1,249,999 therms per year; rate class GS-1250K is available to non-
residential customers using between 1,250,000 and 10,999,999 therms per year. We agree with
FCG’s approach to consider the risk of large C&I customers choosing an alternate fuel supply or
leaving FCG’s service area, resulting in a loss of revenues and load. The retention of large C&I
customers benefits the general body of ratepayers as their revenues contribute to FCG’s fixed
costs.
Witness Collins does not agree with the Company’s class revenue allocation and asserted
that FCG’s COSS does not accurately reflect class cost causation and that FEA’s COSS should
be used to allocate the increase to the rate classes. Witness Collins did not testify that FCG
proposed an increase greater than 1.5 times to any rate classes, and FEA only objected to FCG’s
COSS methodology.
3. Conclusion
Each rate class’s COSS determines the allocation of any revenue requirements increase
for each rate class. Therefore, differing COSS methodologies such as those proposed by FCG
and FEA result in different increase allocations to the rate classes. In rebuttal testimony, witness
DuBose summarized the difference between FCG and FEA’s proposed revenue increase
allocations, based in their respective COSS. FEA’s proposed revenue increase to the residential
RS-1 and RS-100 rate classes is 66.64 percent, while for the commercial rate classes it is 24.81
percent. We do not believe that FEA’s proposed increases provide a balanced approach.
Based on the foregoing, and considering prior Commission practice of using gradualism
to allocate an approved increase to the rate classes, we are persuaded by FCG’s proposed
allocation of the rate increase as shown by the testimony of witness DuBose. FCG’s proposed
revenue increase to the rate classes limits the increase in total revenues to any rate class to 1.5
times the system increase, reflecting our guidelines on gradualism and improving parity among
the rate classes.
C. Proposed Customer Charges
1. Parties’ Arguments
FCG did not provide an argument, but adopted the position that the appropriate customer
charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2).
2. Analysis and Conclusion
We find the customer charges discussed here, in combination with the per therm
distribution charges and the demand charges discussed below, are designed to allow the
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 69
Company to recover the total Commission-approved revenue requirement. Further, we approved
above both the Company’s proposed cost of service methodology and the allocation of the
revenue increase to rate classes. The customer charges reflect the appropriate revenue
requirement and cost of service methodology; therefore, proposed charges provided in the tariffs
in Attachment 6 are approved.
D. Distribution Charges
1. Parties’ Arguments
FCG did not provide an argument but adopted the position that the appropriate per therm
Distribution Charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2).
2. Analysis and Conclusion
We have reviewed the Company’s revised cost of service filing and it reflects the
Commission-approved total Company revenue requirement. Further, we approved above the
Company’s proposed cost of service methodology and the allocation of the revenue increase to
rate classes. The proposed per therm distribution charges reflect the approved revenue
requirements and cost of service methodology; therefore, the proposed charges provided in the
tariffs in Attachment 6 are approved.
E. Demand Charges
1. Parties’ Arguments
FCG did not provide an argument, but took the position that the appropriate Demand
Charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2).
2. Analysis and Conclusion
We have reviewed the Company’s revised cost of service filing and it reflects the
Commission-approved total Company revenue requirement. Further, we approved above the
Company’s proposed cost of service methodology and the allocation of the revenue increase to
rate classes. The proposed demand charges reflect the approved revenue requirements and cost of
service methodology; therefore, the proposed charges provided in the tariffs in Attachment 6 are
hereby approved.
F. Connect and Reconnection Charges
At hearing, we approved a stipulation whereby all parties agreed that the appropriate
service, connect, and reconnection charges are those shown in 2023 Test Year MFR H-1 (2 of 2).
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 70
G. Transportation Customer Charge Application to Third Party Suppliers
At hearing, we approved a stipulation whereby all parties agreed that the appropriate per
transportation customer charge applicable to Third Party Suppliers is shown in 2023 Test Year
MFRs E-2 and H-1 (1 of 2).
H. Effective Date for Revised Rates and Charges
1. Parties’ Arguments
FCG’s filing requested a February 1, 2023 effective date for new base rates.
OPC took the position that the effective date of FCG’s revised rates and charges should
allow for time for implementation promptly after our final Order in this matter. FIPUG adopted
the position of OPC.
2. Analysis and Conclusion
FCG provided a notification of the proposed rate increase to its customers during the
month of August 2022, and also posted notice of the rate increase on its website. The notification
included a comparison between current and proposed rates, and that the rates ultimately
approved by this Commission will not exceed those identified in the notice. FCG also provided a
direct notice to customers during May 2023, which identified the final, Commission-approved
rates and charges. Our staff reviewed the direct notice and believe the notice reflects our
approved rates and charges. We find that the approved rates and charges should become effective
May 1, 2023. We further find the tariffs as provided in Attachment 6 are approved.
I. Approval of Tariffs Reflecting Approved Rates and Charges
1. Parties’ Arguments
FCG did not provide an argument but took the position that we should approve tariffs
reflecting our approved rates and charges and should direct our staff to verify that the revised
tariffs are consistent with our decision.
2. Analysis and Conclusion
We have reviewed the cost of service study and associated tariffs which were revised to
reflect our final approved revenue requirement in accordance with our vote from the March 28,
2023, Special Agenda Conference. The tariffs are approved and are hereby incorporated into this
Order as Attachment 6.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 71
X. Other Issues
A. Proposal For Addressing A Potential Change In Tax Law
1. Parties’ Arguments
FCG argued that in light of the continuing debate surrounding tax law in the United
States, there exists the possibility for a change in tax law either during or after the conclusion of
the rate case that could have a material impact on the four-year proposal being presented by
FCG. FCG would not be able to quantify the impacts until such time as a final bill is passed and
signed into law. FCG’s proposed tax adjustment mechanism would allow FCG to adjust base
rates in the event tax laws change during or after the conclusion of this proceeding. FCG argued
the proposed tax adjustment mechanism would ensure that the impact of future tax laws is
promptly and appropriately reflected in base rates, whether that is an increase or decrease to tax
expense. FCG argued this Commission has previously approved nearly identical tax adjustment
mechanisms.
OPC argued that, by Order No. PSC-2017-0099-PCO-EI (2017 Gulf Tax Decision), we
established a policy that a rate case is not the proper venue for establishing a prospective change
in rates as a result of a future change in federal income tax rates. OPC also argued that as a
matter of policy, we should decline to authorize the tax change provision because it is single
issue ratemaking that would ignore the other relevant conditions that might exist at a time when
tax laws might change in the future. FIPUG adopted the position of OPC.
OPC argued that for FCG to demand to receive a Commission-ordered tax adjustment
mechanism on top of a fully litigated revenue requirement award violates prior Commission
policy. OPC argued that since the company conceded that there is no impact of the August 2022
Inflation Reduction Act (IRA) on the company, it is undisputed that the purpose of the proposal
is premature for some future, unknown (and purely speculative) tax law change.
2. Analysis
At issue is whether FCG’s proposed tax adjustment mechanism (to adjust base rates in
the event tax laws change during or after the conclusion of this proceeding) should be approved.
The bulk of FCG’s testimony relies on its FCG witness Campbell’s testimony that FCG filed its
rate case under the assumption that there was the potential for an increase in the Federal
corporate tax rate either during the case itself or during the four year period when FCG’s rate
plan proposes no adjustments to base rates.
FCG has not accounted for or included any potential tax law changes in its current filing,
and FCG witness Campbell agreed that in August 2022, a change in tax law was passed but did
not have any immediate impact on FCG. Witness Campbell testified that FCG is still assessing
the changes, but doesn’t foresee anything affecting FCG. Further, witness Campbell admitted
that he does not know of any new tax law changes that are pending or that the Company expects
to be adopted in the near future.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 72
3. Conclusion
We find that a tax law change provision in this case is unnecessary because there is no
evidence supporting a need for it. Should there be a tax law that comes into effect that will affect
the rates set forth in this order, a limited proceeding pursuant to Section 366.076, F.S., is
available for FCG or OPC to address any potential future State or Federal income tax law
changes, which would provide an opportunity to consider all of the issues arising from such tax
law changes and to establish the appropriate rates at that time. As discussed above, we find that
FCG’s assurance to not initiate another rate proceeding before us over the next four years, or its
“stay out” promise, is unenforceable. Accordingly, the tax law change provision is unnecessary.
For this reasons, we hereby deny FCG’s request for a tax law change provision.
B. SAFE Program Expansion for Mains and Services
At hearing, we approved a stipulation whereby all parties agreed that this Commission
should approve the continuation and expansion of the SAFE program to include additional mains
and services. The current SAFE program is set to expire in 2025 based on an original estimate of
254.3 miles of mains and services to be relocated from rear property easements to the street front
over the ten-year program. FCG has subsequently identified approximately 150 miles of
additional mains and services that are located in rear property easements and eligible for
replacement under the SAFE program. As we have previously found, mains and services located
in rear property easements present operational and safety concerns, including the age of the
facilities, limitations on the Company’s access to the facilities due to vegetation overgrowth,
landscaping and construction in the easements, and potential gas theft or diversion and damages
to the facilities. Therefore, continuation of the SAFE program beyond its 2025 expiration date
and inclusion of an additional approximately 150 miles of mains and services is reasonable. FCG
must propose a new investment/construction schedule and term for the SAFE program in its next
applicable annual SAFE filing.
C. SAFE Program Expansion for “Orange Pipe”
At hearing, we approved a stipulation whereby all parties agreed that orange pipe is a
specific plastic material that was used in the 1970s and 1980s that has been studied by the United
States Department of Transportation Pipeline and Hazardous Materials Safety Administration
(“PHMSA”) and shown through industry research to exhibit premature failure in the form of
cracking. The potentially compromised nature of the piping makes responding to leaks more
hazardous since responders cannot safely squeeze the pipe without it cracking. In order to
address this safety risk in a timely manner, FCG is seeking approval to expand the SAFE
program cost recovery mechanism to include the capital investments necessary for the expedited
replacement of approximately 160 miles of orange pipe installed before 1990. FCG must propose
a new investment/construction schedule and term for the SAFE program in its next applicable
annual SAFE filing.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 73
D. Description of Adjustments
At hearing, we approved a stipulation whereby all parties agreed that FCG shall 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.
Based on the foregoing, it is
ORDERED by the Florida Public Service Commission that Florida City Gas’ Petition for
Rate Increase is granted in part and denied in part as set forth herein. It is further
ORDERED that each of the findings made in the body of this order is hereby approved in
every respect. It is further
ORDERED that all matters contained in the attachments and schedules appended hereto
are incorporated herein by reference. It is further
ORDERED that the revised tariffs submitted by Florida City Gas, and the final rates and
charges contained therein, as incorporated and attached to this Order, are hereby approved. It is
further
ORDERED that the approved rates and charges for Florida City Gas shall be effective
May 1, 2023. It is further
ORDERED that Florida City Gas shall file, within 90 days after the issuance of this
order, 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 our findings in this rate case. It is further
ORDERED that after this final Order is issued this docket shall be closed.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 74
By ORDER
of
the Public Service Commission this 9th day
of
June, 2023.
TPS
}j
Commission Cler
Florida Public Set ice Commission
2540 Shumard Oak Boulevard
Tallahassee, Florida 32399
(850) 413-6770
wv'iw.floridapsc.com
Copies furnished: A copy
of
this document is
provided to the parties
of
record at the time
of
issuance and,
if
applicable, interested persons.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU
PAGE 75
NOTICE OF FURTHER PROCEEDINGS OR JUDICIAL REVIEW
The Florida Public Service Commission is required by Section 120.569(1), Florida
Statutes, to notify parties of any administrative hearing or judicial review of Commission orders
that is available under Sections 120.57 or 120.68, Florida Statutes, as well as the procedures and
time limits that apply. This notice should not be construed to mean all requests for an
administrative hearing or judicial review will be granted or result in the relief sought.
Any party adversely affected by the Commission's final action in this matter may request:
1) reconsideration of the decision by filing a motion for reconsideration with the Office of
Commission Clerk, 2540 Shumard Oak Boulevard, Tallahassee, Florida 32399-0850, within
fifteen (15) days of the issuance of this order in the form prescribed by Rule 25-22.060, Florida
Administrative Code; or 2) judicial review by the Florida Supreme Court in the case of an
electric, gas or telephone utility or the First District Court of Appeal in the case of a water and/or
wastewater utility by filing a notice of appeal with the Office of Commission Clerk, and filing a
copy of the notice of appeal and the filing fee with the appropriate court. This filing must be
completed within thirty (30) days after the issuance of this order, pursuant to Rule 9.110, Florida
Rules of Appellate Procedure. The notice of appeal must be in the form specified in Rule
9.900(a), Florida Rules of Appellate Procedure.
ORDER NO. PSC-2023-0177-FOF-GU
DOCKET NO. 20220069-GU Attachment 1
PAGE 76
ISSUE TOTAL COMPANY COMPANY COMMISSION COMMISSION
NO. PER BOOKS ADJS. ADJUSTED
UTILITY PLANT
PLANT IN SERVICE $659,463,015
Remove SAFE Assets (49,408,313)
Remove Capital Lease Assets (9,677,542)
SAFE Transfer to Base Rates 42,702,544
Total Plant-In-Service $659,463,015 ($16,383,311) $643,079,704 $0 $643,079,704
ACQUISITION ADJUSTMENT $21,656,835
Total Acquisition Adjustment $21,656,835 $0 $21,656,835 $0 $21,656,835
CONSTRUCTION WORK IN PROGRESS $30,868,480
Remove SAFE Assets (3,555,214)
SAFE Transfer to Base Rates 879,174
Total Construction Work In Progress $30,868,480 ($2,676,040) $28,192,440 $0 $28,192,440
TOTAL UTILITY PLANT $711,988,330 ($19,059,351) $692,928,979 $0 $692,928,979
DEDUCTIONS
ACCUM. DEPR.- PLANT IN SERVICE ($224,359,876)
Remove SAFE Assets 2,709,929
Remove Capital Lease Assets 1,703,882
SAFE Transfer to Base Rates (2,523,229)
2022 Depreciation Study 1,088,583
Total Accum. Depr.- Plant In Service ($224,359,876) $2,979,165 ($221,380,711) $0 ($221,380,711)
TOTAL DEDUCTIONS ($224,359,876) $2,979,165 ($221,380,711) $0 ($221,380,711)
NET UTILITY PLANT $487,628,454 ($16,080,186) $471,548,268 $0 $471,548,268
WORKING CAPITAL ALLOWANCE $19,889,261
AEP Regulatory Asset (1,132,457)
Clause Net Underrecoveries (1,053,994)
Unamortized Rate Case Expense (248,890)
19 To Remove Unamortized Rate Case Expense (1,742,227)
22 Half of D&O Liability Insurance (2,086)
Total Working Capital Allowance 19,889,261 (2,435,341) 17,453,920 (1,744,313) 15,709,607
TOTAL RATE BASE $507,517,715 ($18,515,527) $489,002,188 ($1,744,313) $487,257,875
PTY 12/31/23
DOCKET NO. 20220069-GU
\
COMPARATIVE AVERAGE RATE BASE
FLORIDA CITY GAS ATTACHMENT 1
ORDER NO. PSC-2023-0177-FOF-GU Attachment 2
DOCKET NO. 20220069-GU
PAGE 77
FLORIDA CITY GAS
Docket No. 20220069-GU
PTY 12/31/23
13 Month Average
COMPANY POSITION FCG
PER FCG COST WEIGHTED
BOOKS SPECIFIC PRO RATA ADJUSTED RATIO RATE COST
COMMON EQUITY $262,522,369 $47,385 ($5,541,003) $257,028,751 52.56% 10.75% 5.65%
LONG TERM DEBT 165,323,588 (7,946,387) (3,321,127) 154,056,074 31.50% 4.28% 1.35%
SHORT TERM DEBT 20,639,971 3,447 (435,638) 20,207,781 4.13% 1.78% 0.07%
CUSTOMER DEPOSITS 3,881,270 683 (81,921) 3,800,033 0.78% 2.64% 0.02%
DEFERRED TAXES 55,150,517 (78,791) (1,162,177) 53,909,550 11.03% 0.00% 0.00%
TOTAL $507,517,715 ($7,973,663) ($10,541,866) $489,002,189 100% 7.09%
STAFF POSITION ADJUSTED
PER STAFF COST WEIGHTED
BOOKS SPECIFIC PRO RATA ADJUSTED RATIO RATE COST
COMMON EQUITY $262,522,369 $47,385 ($6,457,846) $256,111,908 52.56% 9.50% 4.99%
LONG TERM DEBT 165,323,588 (7,946,386) ($3,870,658) 153,506,544 31.50% 4.28% 1.35%
SHORT TERM DEBT 20,639,971 3,447 ($507,720) 20,135,698 4.13% 1.78% 0.07%
CUSTOMER DEPOSITS 3,881,270 683 ($95,476) 3,786,477 0.78% 2.64% 0.02%
DEFERRED TAXES 55,150,517 (78,791) ($1,354,477) 53,717,249 11.02% 0.00% 0.00%
TOTAL $507,517,715 ($7,973,662) ($12,286,178) $487,257,875 100% 6.44%
ATTACHMENT 2
ORDER NO. PSC-2023-0177-FOF-GU Attachment 3
DOCKET NO. 20220069-GU Page 1 of 2
PAGE 78
Page 1 of 2
ISSUE TOTAL COMPANY COMPANY COMMISSION COMMISSION
NO. PER BOOKS ADJS. ADJUSTED ADJS. ADJUSTED
OPERATING REVENUES
Operating Revenues $116,217,009
Change in Unbilled Revenues 40,041
PGA (34,053,742)
AEP Revenues (726,069)
SAFE Revenues (6,736,104)
Conservation (6,997,154)
Franchise and Gross Receipts Tax Revenues (3,158,626)
3 LES Revenues 155,495
35 Forecasted Misc. Revenues (16,071)
TOTAL REVENUES $116,257,139 ($51,671,695) $64,585,444 $139,424 $64,724,868
OPERATING EXPENSES:
COST OF GAS $34,075,912
Eliminate Fuel Expense (34,075,912)
Total Cost of Gas $34,075,912 ($34,075,912) $0 $0 $0
OPERATION & MAINTENANCE EXPENSE $32,720,885
Conservation (6,901,558)
Rate Case Expense Amortization 497,779
Economic Development (3,217)
Industry Dues Associated with Lobbying (25,000)
Transfer of Support Costs to Clauses (57,294)
Regulatory Commission Expenses/Fees (250,628)
11 Corrected AMI O&M Expense (3,104)
34 To Maintain Clause Support Costs in Base Rates 57,294
38 Exclusion of Executive Incentive Compensation (505,222)
42 Remove Half of D&O Liability Insurance (4,716)
47 Updated Rate Case Expense (27,570)
TOTAL O & M EXPENSE $32,720,885 ($6,739,918) $25,980,967 ($483,318) $25,497,650
DEPRECIATION & AMORTIZATION $20,276,958
AEP Amortization (679,200)
To remove SAFE assets (1,273,253)
To transfer SAFE assets to base rates 1,189,568
2022 Depreciation Study (2,197,500)
TOTAL DEPRECIATION & AMORTIZATION $20,276,958 ($2,960,385) $17,316,573 $0 $17,316,573
FLORIDA CITY GAS
COMPARATIVE NET OPERATING INCOME
ATTACHMENT 3
DOCKET NO. 20220069-GU
PTY 12/31/23
ORDER NO. PSC-2023-0177-FOF-GU Attachment 3
DOCKET NO. 20220069-GU Page 2 of 2
PAGE 79
Page 2 of 2
ISSUE TOTAL COMPANY COMPANY COMMISSION COMMISSION
NO. PER BOOKS ADJS. ADJUSTED ADJS. ADJUSTED
TAXES OTHER THAN INCOME $9,740,548
To Remove SAFE Assets (992,616)
To Transfer SAFE Assets into Base Rates 797,305
Franchise and Gross Receipts Expense (3,158,626)
52 LES Revenue RAF 777
52 Forecasted Miscellaneous Revenue RAF (80)
52 Executive Incentive Compensation Payroll Taxes (32,995)
52 Updated Property Tax Estimate (510,886)
TOTAL TAXES OTHER THAN INCOME $9,740,548 ($3,353,937) $6,386,611 ($543,184) $5,843,427
INCOME TAX EXPENSE
Income Taxes $1,176,607
Income Taxes - Deferred 1,504,301
Taxes Corresponding to Adjustments (1,151,104)
Interest Synchronization 38,247
2022 Depreciation Study 64,639
53 Interest Synchronization 6,381
53 Fallout Adj. Federal Income Taxes 231,378
53 Fallout Adj. State Income Taxes 64,126
TOTAL INCOME TAXES $2,680,908 ($1,048,218) $1,632,690 $301,884 $1,934,574
TOTAL OPERATING EXPENSES 215,752,350 (48,178,370) 51,316,841 (724,617) 50,592,224
NET OPERATING INCOME ($99,495,300) ($3,493,325) $13,268,603 $864,041 $14,132,644
DOCKET NO. 20220069-GU
PTY 12/31/23
COMPARATIVE NET OPERATING INCOME
FLORIDA CITY GAS ATTACHMENT 3
COMPANY STAFF
ORDER NO. PSC-2023-0177-FOF-GU Attachment 4
DOCKET NO. 20220069-GU
PAGE 80
COMPANY
DESCRIPTION PER FILING STIPULATION
REVENUE REQUIREMENT 100.0000% 100.0000%
REGULATORY ASSESSMENT RATE 0.5000% 0.5000%
BAD DEBT RATE 0.4771% 0.4771%
NET BEFORE INCOME TAXES 99.0229% 99.0229%
STATE INCOME TAX RATE 5.5000% 5.5000%
STATE INCOME TAX 5.4463% 5.4463%
NET BEFORE FEDERAL INCOME TAXES 93.5766% 93.5766%
FEDERAL INCOME TAX RATE 21.0000% 21.0000%
FEDERAL INCOME TAX 19.6511% 19.6511%
REVENUE EXPANSION FACTOR 73.9255% 73.9255%
NET OPERATING INCOME MULTIPLIER 1.3527 1.3527
NET OPERATING INCOME MULTIPLIER
FLORIDA CITY GAS
DOCKET NO. 20220069-GU
PTY 12/31/23
ATTACHMENT 4
ORDER NO. PSC-2023-0177-FOF-GU Attachment 5
DOCKET NO. 20220069-GU
PAGE 81
COMPANY COMMISSION
ADJUSTED APPROVED
$489,002,189 $487,257,875
RATE OF RETURN X 7.09% X 6.44%
REQUIRED NOI $34,688,400 $31,363,264
ACHIEVED NOI 13,268,605 14,132,644
21,419,795 17,230,620
1.3527 1.3527
28,974,822 23,308,073
LNG Revenue (3,828,493) (3,828,493)
Transfer of SAFE Investments (5,696,211) (5,330,459)
INCREMENTAL REVENUE INCREASE $19,450,118 $14,149,121
COMPARATIVE REVENUE DEFICIENCY CALCULATIONS
REVENUE DEFICIENCY
RATE BASE (AVERAGE)
REVENUE EXPANSION FACTOR
NET REVENUE DEFICIENCY
PTY 12/31/23
FLORIDA CITY GAS
DOCKET NO. 20220069-GU
ATTACHMENT 5
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page | of 17
PAGE 82
Florida City Gas
FPSC Natural Gas Tariff First Revised Sheet No. 13
Volume No. 10 Cancels Original Sheet No. 13
RULES AND REGULATIONS (Continued)
3. AS Ss
The Customer shall give immediate notice to the Company of leakage of gas. No
deduction on account of leakage shall be required to be made from Customer's bills unless such
leakage occurs as the result of fault or neglect of agents of the Company. In case of leakage or
fire, the stopcock at the meter should be closed without delay and no light or flame used in the
vicinity of the leak.
4. CONNECT CHARGE
| A charge of $89-09-90.00 for Residential service or $150.00 for Non-Residential service
will be made on the Customer's next bill when gas service is initiated, connected or turned-on. If
service is performed, at Customer request, outside of normal business hours the charges shall
| be $409-09110.00 for Residential service or $200.00 for Non-Residentialservice.
5. RECONNECTION CHARGE
| A charge of $40.00-90.00 for Residential service or $80-00-105.00 for Non-Residential
service will be made on the Customer's next bill when gas service is reconnected after
disconnection for non- payment of bills. If service is performed, at Customer request, outside of
| normal business hours the charges shall be $60-00105.00 for Residential service or
$499.091 20.00 for Non-Residential service.
6. FAILED TRIP CHARGE
A charge of $20 for Residential and Non-Residential service will be made on the
Customer's next bill when the Customer fails to keep a scheduled appointment with the
The service charge for each returned check shall be determined in accordance with
section 68.065, Florida Statutes. Payment of the full amount of the dishonored payment, plus a
service charge of $25 if the face value does not exceed $50, $30 if the face value exceeds $50
but does not exceed $300, $40 if the face value exceeds $300, or 5 percent of the face amount
of the dishonored instrument, whichever is greater.
Issued by: GarelyaBernudezKurt Howard Effective: August-4+42048
Vice-PresidentGeneral Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 2 of 17
PAGE 83
Florida City Gas
FPSC Natural Gas Tariff Second Third Revised Sheet No. 29
Volume No. 10 Cancels SecondFirst Revised Sheet No. 29
RESIDENTIAL SERVICE — 1 (RS-1)
APPLICABILITY
Service is available to Residential Customers using between 0 and 99 therms per year as
determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas delivered by the Company with a heating value on the
order of 1,100 British Thermal Units per cubicfoot.
*MONTHLY RATE
Customer Charge $42.0018.00
Distribution Charge, per therm $0-464200.67667
Commodity Charge Per Rider“A"
SPECIAL CONDITIONS OF SERVICE
1. Application of this rate is subject to the general Rules and Regulations of the
Company as they may be in effect from time to time and as filed with the regulatory authorities.
2. Each year the Company shall re-determine each Customer's eligibility based on
their annual usage. If reclassification to another schedule is appropriate such reclassification shall
be prospective only and shall not be retroactive.
Issued by: Kurt Howard Effective: January $2024
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 3 of 17
PAGE 84
Florida City Gas
FPSC Natural Gas Tariff Secend Third Revised Sheet No. 30
Volume No. 10 Cancels SecondFirst Revised Sheet No. 30
RESIDENTIAL SERVICE - 100 (RS-100)
APPLICABILITY
Service is available to Residential Customers using between 100 and 599 therms per year
as determined by the Company.
CHARACTER OF SERVICE
Afirm delivery service of gas delivered by the Companywith a heating value on
the order of 1,100 British Thermal Units per cubicfoot.
“MONTHLY RATE
Customer Charge $45.0019.00
Distribution Charge, per therm $0-403830.57421
Commodity Charge Per Rider"“A”
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company.
MINIMUM BILL
The minimum monthly bill shall be the Customer Charge.
2: Each year the Company shall re-determine each Customer's eligibility based on
their annual usage. If reclassification to another schedule is appropriate such reclassification shall
be prospective only and shall not be retroactive.
Issued by: Kurt Howard Effective: January-5,2024-
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 4 of 17
PAGE 85
Florida City Gas
FPSC Natural Gas Tariff Second-Third Revised Sheet No. 31
Volume No. 10 Cancels SecondFirst Revised Sheet No. 31
RESIDENTIAL SERVICE - 600 (RS-600)
APPLICABILITY
Service is available to Residential Customers using 600 or more therms per year as
determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas delivered by the Company with a heating value on the order of
1,100 British Thermal Units per cubic foot.
*MONTHLY RATE
Customer Charge $20.0025.00
Distribution Charge, per therm $0.526980.70799
Commodity Charge Per Rider"A”
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company.
MINIMUM BILL
The minimum monthly bill shall be the Customer Charae.
2. Each year the Company shall re-determine each Customer's eligibility based on
their annual usage. If reclassification to another schedule is appropriate such reclassification shall
be prospective only and shall not beretroactive.
Issued by: Kurt Howard Effective: January+s2024
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 5 of 17
PAGE 86
Florida City Gas
FPSC Natural Gas Tariff Second-Third Revised Sheet No. 32
Volume No. 10 Cancels SecondFirst Revised Sheet No. 32
GENERAL SERVICE - 1 (GS-1)
APPLICABILITY
Service is available to Non-Residential Customers using between 0 and 5,999 therms per
year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's
system by any customer, delivered by the Company or Customers’ Third Party Supplier
(‘TPS”) with a heating value on the order of 1,100 British Thermal Units per cubic foot.
“MONTHLY RATE
Gas Supply fromPGA Gas Supply fromTPS
Customer Charge $28-0031.00 $25-0631.00
Distribution Charge, per therm $0.376640.57949 $0.376640.57949
Commodity Charge Per Rider “A” Per TPS Agreement
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company. A Customer that receives gas supply from a TPS will be charged by the TPS for
commodity according to any agreement between the Customer and the TPS. Only Non-
Residential Customers are eligible to receive gas supply froma TPS.
1. Application of this rate is subject to the general Rules and Regulations of the
Company as they may be in effect from time to time and as filed with the regulatory authorities.
2, Each year the Company shall re-determine each Customer's eligibility based on
their annual usage. If reclassification to another schedule is appropriate such reclassification shall
be prospective only and shall not beretroactive.
Issued by: Kurt Howard Effective: wee
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 6 of 17
PAGE 87
Florida City Gas
FPSC Natural Gas Tariff second-Third Revised Sheet No. 34
Volume No. 10 Cancels SecondFitst Revised Sheet No. 34
GENERAL SERVICE - 6K (GS-6)
APPLICABILITY
Service is available to Non-Residential Customers using between 6,000 and 24,999 therms
per year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's system by
any customer, delivered by the Company or Customers’ Third Party Supplier ("TPS") with a
heating value on the order of 1,100 British Thermal Units per cubic foot.
“MONTHLY RATE
Gas Supply from PGA Gas Su fromTPS
Customer Charge $35.0044.00 $35.0044.00
Distribution Charge, per therm $0.339600.48722 $0.33960-0.48722
Commodity Charge Per Rider"A” Per TPS Agreement
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company. A Customer that receives gas supply from a TPS will be charged by the TPS for
commodity according to any agreement between the Customer and the TPS. Only Non-
Residential Customers are eligible to receive gas supply froma TPS.
1. Application of this rate is subject to the general Rules and Regulations of the
Company as they may be in effect from time to time and as filed with the regulatory authorities.
2. Each year the Company shall re-determine each Customer's eligibility based on
their annual usage. If reclassification to another schedule is appropriate such reclassification shall
be prospective only and shall not be retroactive.
Issued by: Kurt Howard Effective: Januar52024+
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 7 of 17
PAGE 88
Florida City Gas
FPSC Natural Gas Tariff firstSecond Revised Sheet No. 36
Volume No. 10 Cancels First RevisedOrginal Sheet No. 36
GENERAL SERVICE - 25K (GS-25k)
APPLICABILITY
Service is available to Non-Residential Customers using between 25,000 and 119,999
therms per year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's system by any
customer, delivered by the Company or Customers’ Third Party Supplier ("TPS") with a heating value
on the order of 1,100 British Thermal Units per cubic foot.
“MONTHLY RATE
as Su fromPG Gas ly fromTPS
Customer Charge $450,00188.00 $450.00188.00
Distribution Charge, per therm $0-325090.44046 $0.325080.44046
Commodity Charge Per Rider “A" Per TPS Agreement
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and anv additinnal tavac accacemante ar cimilar eharnac that are lavdiulhs iranacad hw tha
SPECIAL CONDITIONS OF SERVICE
1: Application of this rate is subject to the general Rules and Regulations of the
Company as they may be in effect from time to time and as filed with the regulatory authorities.
2. Each year the Company shall re-determine each Customer's eligibility based on
their annual usage. If reclassification to another schedule is appropriate such reclassification shall
be prospective only and shall not beretroactive.
Issued by: Kurt Howard Effective: January+202+
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 8 of 17
PAGE 89
Florida City Gas
FPSC Natural Gas Tariff Second Third Revised Sheet No. 38
Volume No. 10 Cancels SecondFisst Revised Sheet No. 38
GENERAL SERVICE - 120K (GS -120K)
APPLICABILITY
Service is available to Non-Residential Customers using between 120,000 and 1,249,999
therms per year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's system by
any customer, delivered by the Company or Customers’ Third Party Supplier ("TPS") with a
heating value on the order of 1,100 British Thermal Units per cubic foot.
eens Gas Supply from PGA Gas Supply from TPS
Customer Charge $399.09375.00 $309.08375.00
Demand Charge, per DCQ $0.5750.719 $0.5760.719
Distribution Charge, per therm $0.193790.28336 $0493790.28336
Commodity Charge Per Rider “A” Per TPS Agreement
at ee ta te bi ed el ba ee lt tL LF
The Billing DCQ will be determined annually by the Company based on the DCQ history, as
determined above. The Customer's Billing DCQ shall be adjusted to reflect the maximum
recorded DCQ. Adjustments will be made in April except the Company shall not increase such a
Customer's Billing DCQ unless the Customer has had at least three (3) occurrences of DCQ’s in
excess of their current Billing DCQ.
Issued by: Kurt Howard Effective: Janvarys,202+-
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 9 of 17
PAGE 90
Florida City Gas
FPSC Natural Gas Tariff Second Third Revised Sheet No. 40
Volume No. 10 Cancels SecondFirst Revised Sheet No. 40
GENERAL SERVICE - 1,250K (GS -1,250K)
APPLICABILITY
Service is available to Non-Residential Customers using between 1,250,000 and
10,999,999 therms per year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's system by any
customer, delivered by the Company or Customers’ Third Party Supplier ("TPS") with a heating
value on the order of 1,100 British Thermal Units per cubic foot.
“MONTHLY RATE
Gas Supply from PGA Gas Supply from TPS
Customer Charge $390.00625.00 $590.00625.00
Demand Charge, per DCQ $0-9790.719 $0.5750.719
Distribution Charge, per therm $0-093640.14073 $0-083640.14073
Commodity Charge Per Rider “A" Per TPS Agreement
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company. A Customer that receives gas supply from a TPS will be charged by the TPS for
commodity according to any agreement between the Customer and the TPS. Only Non-
Residential Customers are eligible to receive gas supply froma TPS.
recorded DCQ. Adjustments will be made in April except the Company shall not increase such a
Customer's Billing DCQ unless the Customer has had at least three (3) occurrences of DCQ's in
excess of their current Billing DCQ.
Issued by: Kurt Howard Effective: January52024
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 10 of 17
PAGE 91
Florida City Gas
FPSC Natural Gas Tariff FirstSecond Revised Sheet No. 42
Volume No. 10 Cancels Original-First Revised Sheet No. 42
GENERAL SERVICE — 11M (GS - 11M)
APPLICABILITY
Service is available to Non-Residential Customers using between 11,000,000 and
24,999,999 therms per year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's system by any
customer, delivered by the Company or Customers’ Third Party Supplier (‘TPS") with a heating
value on the order of 1,100 British Thermal Units per cubic foot.
“MONTHLY RATE
Gas Supply from PGA Gas Supply from TPS
Customer Charge $4,000.001 250.00 $4,000.001 250.00
Demand Charge, per DCQ $0-8780.719 $0-8750.719
Distribution Charge, per therm $9.08000.10320 $0.08000.10320
Commodity Charge Per Rider "A” Per TPS Agreement
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company. A Customer that receives gas supply from a TPS will be charged by the TPS for
commodity according to any agreement between the Customer and the TPS. Only Non-
Residential Customers are eligible to receive gas supply froma TPS.
DETERMINATION OF THE DEMAND CHARGE QUANTITY (DCQ)
Tha AMO ta he tiead in cattina tha Ciuctamar'c Rillinga AMO wall ha datarminad hw tha
@xcess OT Inelr CUITENT BIIlINg WU.
Issued by: Kurt Howard Effective: JanuaryS,2024
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 11 of 17
PAGE 92
Florida City Gas
FPSC Natural Gas Tariff FirstSecond Revised Sheet No. 44
Volume No. 10 Cancels Oxginal-First Revised Sheet No. 44
GENERAL SERVICE — 25M (GS - 25M)
APPLICABILITY
Service is available to Non-Residential Customers using 25,000,000 or more therms per
year as determined by the Company.
CHARACTER OF SERVICE
A firm delivery service of gas, including RNG delivered into the Company's system by any
customer, delivered by the Company or Customers’ Third Party Supplier (“TPS") with a heating
value on the order of 1,100 British Thermal Units per cubic foot.
“MONTHLY RATE
Gas Su from PGA Gas Supply from TPS
Customer Charge $2,090.002,500.00 $2,090.002.500.00
Demand Charge, per DCQ $9-5780.719 $0-8750.719
Distribution Charge, per therm $0-04000.05160 - 05160
Commodity Charge Per Rider “A” Per TPS Agreement
*The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Comnanv A Customer that receives aas sunnlv from a TPS will be charned bv the TPS for
VELEN aVOVE, TMS VUSLUITIET S DINING We Sila Ve AUJUSLEU LO TETECL UWE NIRA TeCorued
DCQ. Adjustments will be made in April except the Company shall not increase such a Customer's
Billing DCQ unless the Customer has had at least three (3) occurrences of DCQ's in excess of
their current Billing DCQ.
Issued by: Kurt Howard Effective: JanuaryS202+
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 12 of 17
PAGE 93
Florida City Gas
FPSC Natural Gas Tariff Secend-Third Revised Sheet No. 46
Volume No. 10 Cancels SecondFiret Revised Sheet No. 46
GAS LIGHTING SERVICE (GL)
AVAILABILITY
See “Limitations of Service” below.
APPLICABILITY
Firm gas service for continuous street or outdoor lighting devices installed
upstream of the Customer's meter.
LIMITATIONS OF SERVICE
This Rate Schedule is closed and is restricted to Customers who were served prior to
March 17, 1975.
*MONTHLY RATE
Distribution Charge $10.6610.69 per lamp
($0-592340.59363 per therm X 18 therms)
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of this
Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by the
Company. For the purpose of applying Riders or other billing adjustments usage of eighteen
therms per lamp per month will be assumed.
MINIMUM BILL
The minimum monthly bill shall be the Monthly Rate.
Issued by: Kurt Howard Effective: January-s-202+
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 13 of 17
PAGE 94
Florida City Gas
FPSC Natural Gas Tariff First Second Revised Sheet No. 47
Volume No. 10 Cancels First RevisedQriginal Sheet No. 47
IDENTIAL STANDBY GENER. VIC
APPLICABILITY
Service is available to Residential Customers whose only gas usage is for a standby
electric generator.
CHARACTER OF SERVICE
A firm delivery service of gas delivered by the Company with a heating value on the
order of 1,100 British Thermal Units per cubicfoot.
“MONTHLY RATE
| Customer Charge: $46-8425.00
Distribution Charge: 0-14 therms $0.00000 per therm
| More than 14 therms 57421 per therm
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders
of this Tariff and any additional taxes, assessments or similar charges that are lawfully imposed
by the Company.
MINIMUM BILL
The minimum monthly bill shall be the Customer Charge.
TERMS OF PAYMENT
Customer will be billed the minimum bill for the remaining months of the service.
3; If the customer installs an additional gas appliance at the premise at which service
is provided, then the customer will be transferred to the applicable rate schedule based on total
therms.
4. Application of this rate is subject to the general Rules and Regulations of the
Company as they may be in effect from time to time and as filed with the regulatory authorities.
Issued by: Kurt Howard Effective: Januarn$2024+
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 14 of 17
PAGE 95
Florida City Gas
FPSC Natural Gas Tariff First Second Revised Sheet No. 48
Volume No. 10 Cancels First RevisedOriginal Sheet No. 48
COMMERCIAL STANDBY GENERATOR SERVICE (CSG)
APPLICABILITY
Service is available to Non-residential Customers whose only gas usage is for a standby
electric generator with annual consumption of less than 120,000 therms.
CHARACTER OF SERVICE
A firm delivery service of gas delivered by the Company with a heating value on the
order of 1,100 British Thermal Units per cubicfoot.
“MONTHLY RATE
| Customer Charge: $24.0036.00
Distribution Charge: 0 - 26 therms $0.00000 per therm
| More than 26 therms $0-495310.57949 per therm
*The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders
of this Tariff and any additional taxes, assessments or similar charges that are lawfully imposed
by the Company. A customer that receives gas supply from a TPS will be charged by the TPS
for commodity according to any agreement between the Customer and the TPS.
MINIMUM BILL
The minimum monthly bill shall be the Customer Charge.
TERMS OF PAYMENT
Customer will be billed the minimum bill for the remaining months of the service.
3. If the Customer installs an additional gas appliance at the premise at which service
is provided, then the Customer will be transferred to the applicable rate schedule based on total
therms.
4. Application of this rate is subject to the general Rules and Regulations of the
Company as they may be in effect from time to time and as filed with the regulatory authorities.
Issued by: Kurt Howard Effective: January5,2024+
General Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 15 of 17
PAGE 96
Florida City Gas
FPSC Natural Gas Tariff Second Revised Sheet No. 49
Volurne io. 46 Cancels First Revised Sheet No. 49
NATURAL GAS VEHICLE SERVICE-I (NGV-I)
(CLOSED SCHEDULE)
APPLICABILITY
For gas delivered to any Customer through a separate meter for the purpose of
compression and delivery into motor vehicle fuel tanks or other transportation containers. NGV-!
is only available to those Customers who are presently receiving this service as of August 13,
2013. Customers seeking such service after this date shall take service under the NGV-II terms
of this Tariff.
“MONTHLY RATE
Gas Supply fromPGA Gas Su fromTPS
Customer Charge $28-0031,00 $25.0031.00
Distribution Charge, per therm $0.23232 $0.23232
Commodity Charge Per Rider “A” Per TPS Agreement
“The charges set forth in this Rate Schedule will be adjusted for all other applicable Riders of
this Tariff and any additional taxes, assessments or similar charges that are lawfully imposed by
the Company. A Customer that receives gas supply from a TPS will be charged for commodity
according to any agreement between the Customer and the TPS.
MINIMUM BILL
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SPECIAL CONDITIONS APPLICABLE TO CUSTOMERS RECEIVING GAS SUPPLY FROM
THIRD PARTY SUPPLIERS (TPS)
1. See the Rules and Regulations for Transportation - Special Conditions for terms
related to Customers taking Gas Supply froma TPS.
2. Automatic Meter Reading (AMR) equipment is required for transportation
Customers served under this Rate Schedule using over 120,000 therms per year. See the Rules
and Regulations for Metering for terms and conditions related to AMR's.
Issued by: Garolyn-BermudezkKurt Howard Effective:-August44.2018
Vise-PresidentGeneral Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 16 of 17
PAGE 97
Florida City Gas
FPSC Natural Gas Tariff First Revised Sheet No.62
Volume No. 10 Cancels Original Sheet No. 62
THIRD PARTY SUPPLIER
(TPS)
(Continued)
CREDITWORTHINESS (Continued)
In the event TPS fails to meet the terms of this Creditworthiness section, Company
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MONTHLY RATE
Customer Charge $400.00
Charge for each Transportation
Customer served by the TPS $6.076.21
DETERMINATION OF THE AVERAGE DAILY DELIVERY QUANTITY (“ADDQ")
The ADDQ for each Customer without an AMR device will be calculated by the
Comnanv bv dividinag the Customer's usage for each of the most recent twelve (12)
Standard lime on the twentieth (2ZUth) of the month.
Issued by: Garolyn-BermudezKurt Howard Effective: August44,2018
Vice-PresidentGeneral Manager, Florida City Gas
ORDER NO. PSC-2023-0177-FOF-GU Attachment 6
DOCKET NO. 20220069-GU Page 17 of 17
PAGE 98
Florida City Gas
FPSC Natural Gas Tariff First Revised Sheet No. 74
Volume No. 10 Cancels Original Sheet No. 74
Economic Development Gas Service (EDGS)
(Continued)
If the volume of gas purchased or transported in a contract year is less than the volume
specified in the contract, the difference in the actual volume and the volume specified in the
apply if payment is received on or before the date as specified on the bill. Paymentsreceived
after that date shall be assessed late payment charges as defined inSection_7 on Sheet No. 13
of the Company's tariff.
BILLING ADJUSTMENTS
Bills for gas service hereunder shall be subject to adjustment for the applicable taxes, fees, and
the cost of purchased gas in accordance with Purchased Gas Adjustment (PGA), and shall be
subject to other adjustments, charges and/or credits as determined to be applicable to the
Issued by: Carolyn -BermudezKurt Howard Effective: August442048
Viee-PresidentGeneral Manager, Florida City GasSetzen Sie Ihre Recherche in ChatGPT oder Claude fort
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