Recommendation

State of Florida		Public Service Commission Capital Circle Office Center ● 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 -M-E-M-O-R-A-N-D-U-M-
DATE:	February 16, 2023
TO:	Office of Commission Clerk (Teitzman)
FROM:	Division of Engineering (Knoblauch, Ellis, King, Ramos, Thompson) Division of Accounting and Finance (Andrews, D. Buys, Cicchetti, Fletcher, Gatlin, Hinson, Norris, Snyder) Division of Economics (Barrett, Draper, Galloway, Hampson, Kunkler, Lang, McNulty, Smith II, Wu) Office of the General Counsel (Trierweiler, Jones)
RE:	Docket No. 20220069-GU – Petition for rate increase by Florida City Gas.
AGENDA:	02/28/23 – Special Agenda – Post-Hearing Decision – Participation is Limited to Commissioners and Staff
COMMISSIONERS ASSIGNED:			Fay, Passidomo, La Rosa
PREHEARING OFFICER:			Fay
CRITICAL DATES:			06/24/23 (12-Month Effective Date)
SPECIAL INSTRUCTIONS:			None

Table of Contents

Issue Description Page

Case Background. 5

Executive Summary. 7

Test Period and Forecasting. 9

1 Projected Test Year (Kunkler) 9

2 Customer and Therms Forecasts (Kunkler) 12

3 Estimated Gas Revenues (Kunkler) 15

Quality of Service. 18

4 Quality of Service (Knoblauch) 18

Depreciation Study. 21

5 Depreciation Parameters (Smith, Wu) 21

6 Reserve Surplus Amortization Mechanism Depreciation Parameters (Smith, Wu) 34

7 Resulting Imbalances (Smith, Wu) 38

8 Corrective Depreciation Measures (Smith, Wu) 41

9 Revised Depreciation Rates (Smith, Wu) 43

Rate Base. 45

10 Adjustment to Safety, Access, and Facility Enhancement Investments (Thompson) 45

11 Proposed Advanced Metering Infrastructure Pilot (Thompson) 46

12 Liquefied Natural Gas Plant in Service (Thompson) 50

13 Plant in Service for Projected Test Year (Gatlin, Thompson) 57

14 Remove all Non-Utility Activities from Plant in Service, Accumulated Depreciation and Working Capital (Gatlin) 61

15 Acquisition Adjustment (Snyder) 62

16 Construction Work in Progress (Hinson) 67

17 Accumulated Depreciation (Hinson) 68

18 Under Recoveries and Over Recoveries (Snyder, Barrett) 70

19 Unamortized Rate Case Expense (Hinton) 71

20 Deferred Pension Debit in Working Capital (Snyder) 75

21 Unbilled Revenues (Snyder) 76

22 Working Capital (Snyder) 77

23 Rate Base (Hinson) 80

Cost of Capital 82

24 Accumulated Deferred Taxes (D. Buys) 82

25 Short-Term Debt (D. Buys) 84

26 Long-Term Debt (D. Buys) 87

27 Customer Deposits (D. Buys) 90

28 Equity Ratio (D. Buys) 92

29 Return on Equity (D. Buys) 97

30 Equity Balance (D. Buys) 121

31 Weighted Average Cost of Capital (D. Buys) 122

Net Operating Income. 127

32 Purchased Gas Adjustment and Natural Gas Cost Recovery Revenues (Barrett, Snyder) 127

33 Net Operating Income Adjustment for SAFE Investments (Gatlin) 128

34 Proposal to Transfer Outside Service Costs (Gatlin) 129

35 Miscellaneous Revenues (Gatlin) 132

36 Total Operating Revenues (Kunkler) 134

37 Remove all Non-Utility Activities from Operation Expenses, Including Depreciation and Amortization Expense (Gatlin) 136

38 Salaries and Benefits (Snyder) 137

39 Affiliate Expense (Snyder) 143

40 Pensions and Post-Retirement Benefits Expense (Snyder) 145

41 Injuries and Damages Expense (Snyder) 147

42 Insurance Expense (Snyder) 150

43 Contractor Cost (Thompson) 153

44 Non-Labor Trend Factors (Barrett) 154

45 Storm Damage Reserve (Knoblauch, Snyder) 155

46 Parent Debt Adjustment (Cicchetti, D. Buys) 158

47 Rate Case Expense (Hinson) 160

48 Uncollectible Accounts (Gatlin) 163

49 O&M Expenses (Hinson) 164

50 Amortization Expense (Snyder) 166

51 Depreciation and Amortization Expense (Hinson) 168

52 Taxes Other than Income (Hinson) 170

53 Income Tax Expense (Gatlin) 172

54 Total Operating Expenses (Hinson) 174

55 Net Operating Income (Hinson) 176

Revenue Requirements. 178

56 Revenue Expansion Factor (Gatlin) 178

57 Annual Operating Revenue Increase (Gatlin) 179

Cost of Service and Rate Design. 181

58 Cost of Service Study (Hampson) 181

59 Revenue Increase Allocation to Rate Classes (Hampson) 185

60 Customer Charges (Hampson) 188

61 Distribution Charges (Hampson) 189

62 Demand Charges (Hampson) 190

63 Connect and Reconnection Charges (Hampson) 191

64 Transportation Customer Charge (Hampson) 192

65 Rates and Charges Effective Date (Hampson) 193

66 Administrative Authority to Approve Tariffs (Hampson) 194

Other Issues. 195

67 RSAM (Trierweiler, Fletcher, Smith) 195

68 Change in Tax Law (D. Buys) 205

69 Continue the SAFE Program (Thompson) 209

70 Expand the SAFE Program (Thompson) 210

71 Four-Year Rate Plan (Knoblauch, Kunkler) 211

72 Description of Adjustments to Reports (Hinson) 216

73 Close Docket (Trierweiler, Jones) 217

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. 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 Section 366.02, Florida Statutes (F.S.). As a subsidiary of Florida Power & Light Company, 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.

FCG requested an increase of $29.0 million in additional annual revenues, and updated its request in rebuttal testimony to $28.3 million. Of that amount, $5.7 million is associated with the reclassification of the Company’s Safety, Access, and Facility Enhancement (SAFE) program revenues from surcharge to base rates and $3.8 million is related to the revenue requirements for the previously approved Liquefied Natural Gas (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 reserve surplus amortization mechanism (RSAM). 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.

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 allowed FCG to generate an additional $11.5 million in revenues for the projected test year ended December 31, 2018. The settlement agreement also authorized a return on equity of 10.19 percent.

Order No. PSC-2022-0199-PCO-GU acknowledged intervention by the Office of Public Counsel (OPC). In Order No. PSC-2022-0262-PCO-GU, intervention was granted to the Federal Executive Agencies (FEA). Order No. PSC-2022-0377-PCO-GU granted intervention to the Florida Industrial Power Users Group (FIPUG). In Order No. PSC-2022-0285-PCO-GU, the Commission suspended the proposed permanent increase in rates and charges.

Three virtual customer service hearings were held on September 14 and 15, 2022. A total of 13 customers participated at the virtual service hearings and spoke positively of the Company’s quality of service, though one customer also voiced opposition to the rate increase. Two in-person service hearings were held, one in Pembroke Pines on September 20, 2022, and one in Melbourne on September 21, 2022. Four customers spoke at the in-person service hearings and spoke favorably of FCG’s quality of service, with one customer also expressing concerns regarding the size of the rate increase. An administrative hearing was held December 12-13, 2022. At the hearing, the Commission approved the following stipulated issues: 10, 14, 16, 18, 20, 21, 30, 32, 33, 37, 43, 44, 48, 21, 56, 63, 64, 69, 70, 72 and 73.

The Commission received letters from six customers that were placed in correspondence 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.

This recommendation addresses the requested permanent rate increase. The Commission has jurisdiction over this matter pursuant to Chapter 366, F.S., including Sections 366.06 and 366.071, F.S.

Executive Summary

The Company’s last rate case was filed on October 23, 2017, and was resolved by the Commission’s approval of the 2018 Settlement Agreement. Approximately five years later, on May 31, 2022, FCG filed the current petition requesting approval of a base rate increase and associated depreciation rates. In the petition, FCG requested an increase of $29.0 million in additional annual revenues. Of that amount, $5.7 million is associated with the reclassification of the Company’s SAFE program revenues from a surcharge to base rates. The reclassification of the SAFE revenues were stipulated in Issues 10, 69 and 70 prior to the hearing. The LNG Facility, which was previously approved as being needed in the 2018 Settlement Agreement, has a revenue requirement impact of $3.8 million. The controversy with this item is the delayed in-service date of the facility which is discussed in Issue 12. The remaining incremental base revenue increase is driven primarily by plant investment based on a requested mid-point of 10.75 percent return on equity (ROE). FCG’s current authorized ROE is 10.19 percent.

OPC, FEA, and FIPUG intervened in the docket, and OPC and FEA both sponsored witness testimony. In its post-hearing brief, OPC recommended an incremental revenue increase of $4.8 million based, in part, upon a 9.25 percent ROE. FEA recommended an ROE of 9.4 percent but did not provide a specific revenue requirement recommendation. FIPUG adopted the position of FEA regarding ROE and adopted the position of OPC for overall revenue requirement. Staff is recommending an incremental revenue increase of $16.6 million using a 10.00 percent ROE. Staff’s recommended adjustments to the Company’s request are mostly driven by a reduced ROE (Issue 29), removal of a prior acquisition adjustment (Issues 15 and 50), and a reduction in property taxes (Issue 52).

Also included in FCG’s petition was the request for approval of several regulatory provisions designed to manage earnings in order to mitigate the need for future rate relief. The primary components are: 1) a mechanism to account for future tax reform legislation; 2) continuation of the storm damage accrual and reserve amount; and, 3) the creation of a depreciation reserve surplus and the associated RSAM.

As discussed in Issue 68, staff is recommending that an additional mechanism to address future tax legislation is not needed as the current rules and practices suffice. As discussed in Issue 45, staff is recommending continued use of the existing storm damage accrual and reserve amounts as a means to address potential storm damage expenses without an incremental cost to customers. As discussed in Issue 5, staff is recommending the use of a depreciation study based on traditional utility practices and assumptions for service lives. The study was sponsored by FCG and results in a small, approximately $3.2 million, depreciation reserve deficit. Therefore, if the Commission approves staff’s recommendation in Issue 5, Issue 67 is moot as there would be no depreciation reserve surplus to support the use of an RSAM. However, FCG also proposed the approval of depreciation rates that are the same as those adopted in a settlement agreement with Peoples Gas System (PGS) in Docket No. 20200051-GU.[2] FCG’s proposal for setting aside its own depreciation study asks the Commission to ignore FCG specific depreciation rates, contrary to Section 366.06(1), F.S., as the basis of recording expenses in its books and records. If the PGS depreciation rates are utilized, depreciation expenses are slightly reduced and a significant depreciation reserve surplus, approximately $52.1 million, is created. FCG proposed these alternative depreciation rates in order to generate a reserve surplus solely to support the use of an RSAM. As discussed in Issue 67, neither staff nor any of the intervening parties support the creation and use of the proposed RSAM.

Historically, a depreciation reserve surplus has been returned to customers over the remaining life of the assets or through a refund. The concept behind an RSAM is allowing the utility to utilize depreciation-related funds already collected from customers in order to manage earnings within the Commission approved range. In theory, this benefits the customers and the utility by reducing the risk of volatility and potential frequency of rate cases. If the Commission is persuaded that an RSAM is needed, staff recommends that the reduced risk of volatility should be recognized with two modifications to FCG’s proposal. First, the RSAM should only be utilized in order to bring the Company to its authorized mid-point ROE. Any earnings from the mid-point up to the top of the authorized range should be accomplished through efficiency improvements, cost savings, or incremental sales above the test year values. Second, the approved mid-point and subsequent range of ROE should reflect the reduction in risk and be recognized with a 50 basis point reduction to 9.5 percent. These options are discussed in Issues 67 and 29.

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. The Commission held three virtual service hearings on September 14 and 15, 2022. Additionally, the Commission held two in-person service hearings within FCG’s service territory on September 20 and 21, 2022. The service hearings provide an opportunity for customers to raise concerns regarding the Company’s quality of service and its request for a rate increase. A total of 13 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, which were held in Pembroke Pines and Melbourne. All of the customers at the in-person service hearings spoke favorably of FCG’s quality of service, and one customer also expressed concerns regarding the size of the rate increase. FCG serves approximately 116,000 customers.

Staff witness Calhoun testified to the number of consumer complaints logged with the Commission against the Company from July 1, 2017, to June 30, 2022. During that time period, witness Calhoun testified that 584 complaints were logged with the Commission with 489 of those being transferred to FCG or Warm-Transfers. Of the complaints, approximately 52 percent concerned billing issues and approximately 48 percent involved quality of service issues. (TR 548) Additionally, witness Calhoun testified that four billing complaints and one service quality complaint appeared to demonstrate a violation of Commission Rules. (TR 549)

In his rebuttal testimony, 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 or Warm-Transfers. (TR 626-627; TR 624) Therefore, only 87 of the customer contacts were logged as complaints, with 4 being possible rule violations. (TR 624) Witness Howard testified that efforts had been made since 2018 to update the customer complaint resolution process. (TR 625) These included: (1) creation of 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) implementation of a management review process for Commission complaints, (5) instituting a one-call resolution target for Warm-Transfers, and (6) establishing internal goals to reduce Warm-Transfers and Commission complaints. (TR 625-626)

Pursuant to Rule 25-7.018, Florida Administrative Code (F.A.C.), each utility shall keep a complete record of all interruptions affecting the lesser of 10 percent or 500 or more of its division meters. Based on the FCG’s filing, there were no customer interruptions affecting either 10 percent or 500 meters during the historic test year. (EXH 9) Staff also examined the complaints presented in witness Calhoun’s testimony and observed that the number of service complaints has continually decreased since 2018. Based on a review of all witness and customer testimony and consideration of the information presented above, staff recommends that the Company’s quality of service is adequate.

CONCLUSION

Staff recommends that FCG’s quality of service is adequate.

Depreciation Study

Issue 5:

Based on FCG’s 2022 Depreciation Study, what are the appropriate depreciation parameters (e.g., service lives, remaining life, net salvage percentage, and reserve percentage) and resulting depreciation rates for each distribution and general plant account?

Recommendation:

The appropriate depreciation parameters are those that result from witness Allis’ FCG-specific depreciation study. These parameters are reflective of FCG’s assets life, mortality, and net salvage characteristics, and are consistent with past Commission practices. Staff’s recommended depreciation parameters and resulting depreciation rates for each distribution and general plant account are shown on Table 5-3. If the Commission approves staff’s recommended depreciation parameters and rates, Issues 6 and 67 are moot. (Smith, Wu)

Position of the Parties

FCG:

Based on FCG’s 2022 Depreciation Study, the most reasonable depreciation parameters and resulting depreciation rates for each distribution and general plant account are reflected on CEL Ex. 40. However, FCG’s proposed RSAM-adjusted depreciation rates represent a reasonable alternative to those contained in the 2022 Depreciation Study and are appropriate and necessary to support the tremendous customer value and savings under FCG’s proposed four-year rate plan. (Allis, Campbell, Fuentes)

OPC:

The depreciation parameters and resulting depreciation rates are shown in OPC Witness Garrett’s testimony and Exhibits 66-74. These parameters and rates are proposed for the legitimate establishment -- in the Commission’s litigated ratemaking process -- of depreciation expense to the lives of the assets and not for the purpose of creating an artificial earnings manipulation device.

FEA:

FEA took no position.

FIPUG:

FIPUG adopted the position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that there are three different proposals for depreciation parameters in this case: FCG’s 2022 Depreciation Study (2022 Study), OPC’s proposed parameters, and FCG’s RSAM-adjusted parameters. (FCG BR 11) FCG explained that each scenario proposes slightly different estimates for service lives for four distinct accounts. (FCG BR 11-12) FCG noted that even though all three scenarios propose longer lives than those currently approved for FCG, all are not materially different and are within a range of reasonableness. (FCG BR 12)

FCG witness Allis explained 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.” (FCG BR 12) FCG cited the National Association of Regulatory Utility Commissioners (NARUC) that the true depreciation parameters only become known “after the plant has lived its entire useful life.”^{^[6]} (FCG BR 12) FCG argued that, based on the preceding, informed judgement should be used to determine the appropriate depreciation parameters. (FCG BR 12)

FCG stated that its witness Allis determined his depreciation parameters, as presented in the 2022 Study, to be the most reasonable, but he suggested that all three sets of parameters are within a “range of reasonableness” when compared to the depreciation studies of other gas utilities. (FCG BR 12-13) FCG argued that, given the facts in this case, the issue to be decided is what are the appropriate depreciation parameters and rates. (FCG BR 13)

FCG argued that, if either the 2022 Study parameters or OPC’s proposed depreciation parameters were to be approved, FCG would not have the reserve necessary for the RSAM to function. (FCG BR 13) Thus, FCG argued that the Company would not be able to commit to its proposed four-year rate plan. (FCG BR 13) FCG argued that, as an alternative to the rates proposed in its 2022 Study, the RSAM-adjusted depreciation parameters are reasonable and appropriate. (FCG BR 13) The Company then stated that, if the Commission does not approve the RSAM in Issue 67, the most reasonable depreciation parameters are those proposed in the 2022 Study. (FCG BR 13)

Absent approval of the RSAM, and in support of the 2022 Study, FCG argued that the 2022 Study was performed by an outside expert (witness Allis) with years of experience who used industry-accepted methodologies, FCG’s historical books and records, along with his professional judgement to estimate the service lives and net salvage values for FCG’s assets. (FCG BR 13) FCG explained that witness Allis then calculated the composite remaining lives and annual depreciation accruals using those estimates. (FCG BR 13)

FCG explained that, in order to obtain an understanding of FCG’s operations, witness Allis met with Company personnel and visited portions of FCG’s plant. (FCG BR 14) FCG stated these visits also helped witness Allis gain an understanding of the reasons behind FCG’s past and future plant retirements. (FCG BR 14) FCG indicated that this information, along with discussions with FCG management, was used by witness Allis to form his proposed depreciation parameters. (FCG BR14)

FCG contended that the depreciation parameters that result from the 2022 Study are reasonable in the context of a single-year rate plan. (FCG BR 14) FCG stated that the depreciation parameters from the 2022 Study are reflected on CEL Exhibit 40 and result in a total increase to FCG’s depreciation expense of $0.9 million. (FCG BR 14-15)

FCG argued that the service lives proposed by OPC witness Garrett are less reasonable than those proposed in its 2022 Study. (FCG BR 15) The Company contended that witness Garrett relied entirely on FCG’s historical data for his proposed depreciation parameters. (FCG BR 15) FCG explained that since a depreciation study is attempting to forecast the future, relying on historical data alone does not lead to the most reasonable outcome. (FCG BR 15)

The Company contended that the amount of historical data it has is not sufficient to rely on alone for the service life indications of its assets. (FCG BR 15) FCG explained that service life estimates “should incorporate factors such as general knowledge of the property studied, information obtained from site visits and meetings with Company subject matter experts, and an understanding of estimates used for similar property for other utilities.” (FCG BR 15) FCG stated that these other considerations are even more essential when historical data is limited. (FCG BR 15) The Company also argued that witness Garrett did not take into account these other factors in his analysis. (FCG BR 15)

FCG argued that witness Garrett’s general criticisms and discussion of legal standards are both irrelevant and inaccurate. (FCG BR 15-16) They contended that witness Garrett did not take into account any other factors outside of the information used in his statistical analysis. (FCG BR 16) FCG further explained that witness Garrett’s reliance on the “mathematical fit” of his curves goes against what is recommended by NARUC. (FCG BR 16) FCG stated that NARUC advises that service life estimates must go beyond any objective measure and that “relying solely on mathematical solutions” is not appropriate. (FCG BR 16) FCG listed several factors suggested by NARUC that should be used in estimating service lives and FCG argued that witness Garrett did not discuss those factors nor give them any consideration in his analysis. (FCG BR 16) FCG contended that, given the reasons laid out above, OPC’s proposed depreciation parameters are less reasonable than those in FCG’s 2022 Study. (FCG BR 17)

OPC

OPC argued 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 BR 6) OPC witness Garrett used FCG’s aged property data to develop an “observed life table” (OLT) which was then compared to survivor curves. (OPC BR 6) OPC argued that witness Garrett used a mathematical technique that measures the distance between the survivor curve and the OLT curve in order to determine which survivor curve had the best fit. (OPC BR 7)

OPC argued that for each account in which witness Garrett proposed an adjustment, the average service life proposed by FCG in its 2022 Study was too short for the characteristics of that account’s assets. (OPC BR 7) OPC stated that witness Garrett’s proposed adjustments are objective due to the reliance on a mathematical fit of his proposed Iowa curves. (OPC BR 7) Witness Garrett also stated that he believed FCG witness Allis’ service lives recommendations rely too much on FCG employees’ expectations. (OPC BR 7)

OPC argued that witness Garrett’s proposed R3-70 curve (R3 Iowa curve with a 70-year ASL) for Accounts 376.1 and 376.2 (Steel and Plastic Mains) is more appropriate than witness Allis’ recommended R4-65 curve due to more significant data points indicating a flatter curve. (OPC BR 7) OPC argued that witness Garrett’s proposed S3-45 curve is more appropriate than witness Allis’ proposed S3-35 curve for Accounts 378 and 379 (Measuring and Regulating Station Equipment General and City Gate) because the S3-45 curve is a better fit both visually and mathematically. (OPC BR 7) For Accounts 380.10 and 380.20 (Steel and Plastic Services), OPC argued that witness Garrett’s proposed R2.5-55 curve is a better fit than witness Allis’ proposed R2.5-40 curve. (OPC BR 7-8) OPC stated that witness Garrett’s proposed R2-47 curve for Account 383 (House Regulators) is more appropriate because the R2.5-40 curve ignores important data points in the 30-45 year age range. (OPC BR 8)

OPC concluded that by utilizing all of witness Garrett’s proposed depreciation adjustments, 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 BR 8)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 5)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 5)

ANALYSIS

In this proceeding three proposals have been put forward to calculate depreciation rates for each distribution and general plant account: FCG’s 2022 Depreciation Study (2022 Study), OPC’s adjustments to FCG’s 2022 Study, and FCG’s RSAM-adjusted parameters. Based on staff’s review of these three proposals, staff concludes that the appropriate depreciation parameters to be used to establish FCG’s depreciation rates are those parameters that resulted from FCG’s 2022 Study sponsored by witness Allis. Staff would note that if FCG’s 2022 Study is approved, the reserve surplus necessary to enable FCG’s proposed RSAM to function would not exist.

In setting fair, just and reasonable rates pursuant to Section 366.06(1), F.S.:

. . . The commission shall investigate and determine the actual legitimate costs of the property of each utility company, actually used and useful in the public service, and shall keep a current record of the net investment of each public utility company in such property which value, as determined by the commission, shall be used for ratemaking purposes and shall be the money honestly and prudently invested by the public utility company in such property used and useful in serving the public, less accrued depreciation, and shall not include any goodwill or going-concern value or franchise value in excess of payment made therefor.

Based on its plain meaning, the statute requires a utility’s depreciation study to be based upon data specific to its property used and useful in serving customers.

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. Combining these parameters provides the account-specific depreciation rates on a going-forward basis, which is the remaining life rate. The remaining life rate is designed to recover the remaining unrecovered plant balance or investment (investment less net salvage less reserve) over the remaining life of the associated investment. The formula for the remaining life rate is the plant investment (represented as 100 percent) minus reserve percent minus net salvage percent which is then divided by the average remaining life in years.^{^[7]}

FCG’s 2022 Study versus OPC’s Adjustments

OPC Witness Garrett disagrees with FCG Witness Allis’ 2022 Study on the calculation of parameters associated with seven accounts combined into the following groups:

· Account 376.1 – Mains – Steel and Account 376.2 – Mains – Plastic

· Account 378 – M&R – General and Account 379 – M&R – City Gate

· Account 380.1 – Services – Steel and Account 380.2 – Services – Plastic

· Account 383 – House Regulators (TR 340; TR 738)

Average Service Life and Iowa Curves

In the development of depreciation rates, the first parameter reviewed is the ASL, which denotes the average number of years that the asset (within a particular account) 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 implementation.

Witness Garrett’s main argument in favor of his ASLs and curves relies on statistical analysis only. (TR 418) Witness Garrett utilized a statistical analysis technique referred to as the retirement rate method. (TR 417) This statistical analysis technique utilizes the Company’s property records in order to obtain all plant additions, retirements, and transfers. (TR 417) FCG’s property records cover the past sixteen years. This data is then organized by vintage and transaction year.[8] (TR 417) Next, witness Garrett used this data to form an Observed Life Table (OLT). (TR 417) Witness Garrett plotted the data points from the OLT on a graph to create an OLT curve. (TR 418)

With regard to the OLT curve, witness Garrett pointed out that it is rarely smooth and is almost never a complete curve.[9] (TR 418) However, in order to calculate the average remaining life for a particular account, there must be a complete curve as well as a proposed ASL. (TR 418) To attain a complete curve and ASL for calculating an account’s Average Remaining Life (ARL), depreciation professionals utilize a set of curves referred to as Iowa Curves. These are well-established depreciation tools. Each curve is denoted by a letter and number. The letter 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 number portion of the Iowa Curve designation indicates how steep or flat the curve’s shape is.

As witness Garrett testified, Iowa Curves are fitted to the OLT curve in order to try to find the best fit. (TR 418) This process can be done visually and mathematically. (TR 418) Witness Garrett’s analysis heavily depends on the mathematical fitting process referred to as the “sum-of-squared differences” or SSD. (TR 426) The SSD technique measures the distance between data points on the OLT curve and the Iowa Curve selected by the depreciation analyst. (TR 426) The lower the number resulting from the SSD analysis, the closer the Iowa Curve fit is to the OLT curve. (TR 426)

Witness Allis testified that witness Garrett relied entirely on a statistical analysis of FCG’s historical data. (TR 733-734) Witness Allis also argued that, because depreciation is attempting to forecast asset service lives and retirement patterns into the future, FCG’s historical information is insufficient to rely on completely. (TR 733) Witness Allis stated that relying on historical data alone would only be useful if you expect future retirement patterns to exactly match those in the past. (TR 733) He argued that this is true even when a company has extensive historical data. (TR 733) According to witness Allis, when the historical data is limited, as in FCG’s case, the analysis of other factors is imperative. (TR 733) Witness Allis stated that these other factors include “general knowledge of the property studied, information obtained from site visits and meetings with Company subject matter experts, and an understanding of estimates used for similar property for other utilities.” (TR 734) Witness Allis further testified that even though there have been another four years of data since the last depreciation study for FCG, the data only covers a 16-year period, which provides limited value for estimating service lives. (TR 735)

Gradualism, as it pertains to depreciation, is the concept of making smaller adjustments over time as opposed to less frequent, large adjustments. With the service lives that would result from only the use of limited historical data, witness Allis testified that “gradualism” is even more important. (TR 736) Witness Allis explained that gradualism is a vital regulatory and forecasting principle that requires the estimates from prior depreciation studies be considered, and in particular, to what extent those estimates have changed over time. (TR 736)

In his rebuttal testimony, witness Allis provided a table (Table 5-1 below) that compares FCG’s approved service life estimates from its 2014 and 2018 Depreciation Studies (2014 Study and 2018 Study) for the accounts that are in dispute in this case. (TR 738) The table also includes FCG’s and OPC’s proposed life estimates for the 2022 Study for the same accounts. (TR 738) As witness Allis stated, with the exception of two accounts, all of his proposed service life estimates are longer than the lives approved in FCG’s 2018 Study, and significantly longer than those from the 2014 Study.[10] (TR 738) In particular, witness Allis stated that his recommendation for Account 376.2 – Mains is 25 years (37.5 percent) longer than the approved service life from the 2014 Study. (TR 738) Witness Garrett’s proposal is to extend that account’s ASL to 30 years (42.8 percent) over the 2014 Study. (TR 738) Witness Allis further pointed to Account 380.1 – Services in which his proposal represents an increase of 15 years (30 percent) from the 2014 Study. (TR 738-739) Witness Garrett’s proposal represents an increase of 20 years (36 percent). (TR 738) Witness Allis argued that the ASLs recommended by witness Garrett are significant increases given that only eight years have passed since the 2014 Study. (TR 739)

Table 5-1

Comparison of Service Life Estimates

Account	2014 Study Approved	2018 Study Approved	2022 FCG Proposed (Allis)	2022 OPC Proposed (Garrett)
376.1/376.2 Mains	42/40	55	65	70
378/379 M&R	30	30/35	35	45
380.1/380.2 Services	35/34	45/54	50	55
383 House Regulators	25	30	40	47

Source: TR 738

Account 376.1 and 376.2 – Mains

The currently-approved ASL for these accounts is 55 years with a S3 curve. (EXH 40) In the 2022 Study, witness Allis proposed increasing the ASL for these accounts to 65 years with a R4 curve. (EXH 40) Witness Garrett proposed extending the ASL for these accounts to 70 years with a R3 curve. (EXH 67) Staff is persuaded by witness Allis’ multi-layered process and believes that a 65-year ASL with a R4 curve is reasonable for both accounts.

Account 378 and 379 – M&R Station Equipment

The currently-approved ASL for Account 378 is 30 years with a S3 curve. (EXH 40) The currently-approved ASL for Account 379 is 35 years with a S4 curve shape. (EXH 40) In the 2022 Study, witness Allis proposed a 35-year ASL with a S3 curve for both accounts. (EXH 40) Witness Garrett proposed extending the ASL for both accounts to 45 years with a S3 curve. (EXH 67) Staff believes that a 35-year ASL with a S3 curve is reasonable for both accounts because of witness Allis’ use of professional judgement and gradualism in his analysis.

Account 380.1 – Services – Steel& Account 380.2 – Services - Plastic

The currently-approved ASL for Account 380.1 is 45 years with a S6 curve. (EXH 40) The currently-approved ASL for Account 380.2 is 54 years with a R2.5 curve. (EXH 40) In the 2022 Study, witness Allis proposed a 50-year ASL with a R2.5 curve for both accounts. (EXH 40) Witness Garrett proposed extending the ASL to 55 years with a R2.5 curve for both accounts. (EXH 67) Witness Allis’ use of gradualism and professional judgement rather than a strict adherence to only statistical analysis and math is persuasive. Staff believes that a 50-year ASL with a R2.5 curve is reasonable for both accounts.

Account 383 – House Regulators

The currently-approved ASL for this account is 30 years with a S3 curve. (EXH 40) Witness Allis proposed a 40-year ASL with a R2.5 curve. (EXH 40) Witness Garrett proposed extending the ASL to 47 years with a R2 curve. (EXH 67) Similar to the above discussions, staff believes that a 40-year ASL with a R2.5 curve is reasonable because of witness Allis’ use of professional judgement and gradualism in his analysis.

Staff concludes that witness Allis’ analysis of the four disputed sets of parameters is more appropriate for establishing the ASLs and curves for FCG’s assets based on the foregoing. Given the fact that FCG’s historical data was insufficient, witness Allis’ additional efforts, including discussions with Company experts, site visits, and the use of gradualism, prove to be more persuasive than OPC’s reliance on statistical analysis of historical data alone. (EXH 42) Application of gradualism results in a balance between the recognition of new data on services lives or other components of the cost of service, with the impacts on rates through changes in depreciation expense. Staff concludes that witness Allis’ use of professional judgement and gradualism make his recommendations more suitable for estimating the depreciation parameters in this case.

Average Remaining Life

The next parameter is the average remaining life which is the average number of in-service years left for plant currently in service. Aside from the four sets of accounts in which OPC witness Garrett proposes different ASLs and curves than FCG, there are no disputed average remaining lives for any Distribution or General Plant accounts. (EXH 42; EXH 68) Using the industry-accepted methodology, staff was able to verify the average remaining life calculations of both witness Allis and Garrett based on their respective proposed parameters. Based on staff’s recommended ASLs and Iowa curves for each account, the appropriate average remaining lives are reflected in Table 5-3 below.

Net Salvage

The third parameter for determining depreciation rates, net salvage, is based on historical data but is also prospective in outlook. Net salvage is gross salvage minus cost of removal. FCG proposed changes to ten of its currently-approved net salvage percentages. (EXH 42) No intervenor disagreed with FCG’s proposed net salvage percentages. Staff has reviewed FCG’s proposed net salvage percentages and believes them all to be reasonable based on the evidence in the record. (EXH 42)

Reserve Percentage

After net salvage, 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 unless restated to another level.[11] The reserve percentage is calculated by dividing the book reserve by the original cost of plant. The reserve percentage or reserve position for FCG is reflected in Table 5-3. (EXH 40)

RSAM-Adjusted Depreciation Parameters

FCG proposes the Commission approve a set of depreciation parameters and rates taken from a recent settlement approved for PGS, along with allowance of an accounting mechanism known as the RSAM, in order to take advantage of the alleged customer value and savings associated with its four-year rate proposal. FCG proposes the Commission only fall back upon FCG’s 2022 depreciation study parameters and rates, which it admits are most reasonable, if the Commission rejects FCG’s four-year proposal and affirms a single year rate case. (FCG BR 11) In this section, staff reviews FCG’s argument that, while the depreciation rates resulting from its 2022 depreciation study are most reasonable, both the OPC’s proposed depreciation rates and FCG’s proposed depreciation rates are reasonable alternatives as well. Staff has identified five main concerns with FCG’s argument.

First, it is worth considering the relevance of the critical regulatory objectives the Commission has achieved only through well-constructed depreciation studies filed consistent with the Commission’s rules and carefully reviewed. The Commission achieves certain important regulatory objectives such as the matching of the incurrence of costs and benefits received (known as the matching principle) and the minimization of intergenerational inequities, through the implementation of the results of utility–specific depreciation studies. The matching principle is achieved when the costs to serve customers (as reflected in depreciation rates and, ultimately, customer rates) are matched in time with the benefits customers received from the assets included in the studies. The corollary to this is the minimization of intergenerational inequity, wherein today’s customers neither pay for costs which belong to an earlier generation of customers nor do the costs to serve today’s customers get deferred to a future generation. The Commission’s traditional basis of setting depreciation rates prevents customers from paying costs that are either too high or too low (via depreciation rates and cost of capital) compared to the benefits received.[12]

Second, staff is concerned that FCG proposes to substitute the traditional practice of relying upon utility-specific, rule-based depreciation studies to establish depreciation rates with its own approach that uses a different utility’s depreciation parameters. In this case, FCG proposes to determine the Company’s depreciation rates based solely on a different utility’s depreciation parameters that were approved as part of a comprehensive rate settlement, instead of parameters resulting from its own depreciation study. FCG supports its proposal by touting the benefits to its customers associated with its proposed four-year plan, i.e., the benefit of having the same rates for a four-year period. (TR 1064) However, no Florida Statute, Commission Rule, or Commission practice addresses consideration of benefits to customers as criteria for substituting another utility’s depreciation parameters for science-based depreciation parameters used to establish depreciation rates for a gas utility in the State of Florida. Also, this Commission has never approved the depreciation parameters of one utility as appropriate (in its entirety) for a different utility. Staff believes adopting the depreciation parameters of another utility is contrary to Chapter 366.06(1), F.S., which requires the Company to use the property of the Company, and its associated value, for ratemaking purposes. For the first time, the Commission is being asked to approve in totality those depreciation parameters approved in the PGS Settlement, as appropriate for FCG. The balance of whether the benefits argued by FCG are of sufficient magnitude to reverse the traditional application of a utility-specific depreciation study is the subject of Issue 67.

Third, FCG’s proposal sets aside its own depreciation study and, instead asks the Commission to ignore the purpose of the depreciation rule, which is to use the study to establish utility-specific depreciation rates as the basis of customer rates and the basis of recording expenses in its books and records. In response to staff’s interrogatory as to how the development of the RSAM-adjusted depreciation rates is consistent with Rule 25-7.045(4) and (5), F.A.C. (the Depreciation Rule), FCG stated that its 2022 Study meets the full requirements of the Depreciation Rule without addressing whether or not the RSAM-adjusted parameters do so. (EXH 134) However, staff believes the purpose of the rule is clear. Consider Rule 25-7.045(4)(c), F.A.C.:

A utility proposing an effective date coinciding with the expected date of additional revenues initiated through a rate case proceeding shall submit its depreciation study no later than the filing date of its Minimum Filing requirements.

The language of the rule provides the clear link between the depreciation study and ratesetting. The need to establish those depreciation rates resulting from a review of the study are evident in the following paragraph of the depreciation rule, Rule 25-7.045(4)(d), F.A.C.:

The plant balances may include estimates. Submitted data including plant and reserve balances or company planning involving estimates shall be brought to the effective date of the proposed rates.

This paragraph of the rule pertains to the utility’s depreciation study. Under the rule, the proposed effective date of the rates of the study match the end date of the Company’s submitted study. The rule does not contemplate effective dates for depreciation rates other than those generated from the study itself. The Commission’s depreciation rule does not offer any optional method for establishing a utility’s depreciation rates. FCG argued that the RSAM-adjusted depreciation parameters are a reasonable alternative to the 2022 Study but did not address how the RSAM-adjusted parameters satisfy the Depreciation Rule. (EXH 134)

Fourth, FCG’s own argument against OPC’s proposed parameters is counter to its argument in favor of the proposed RSAM-adjusted parameters. FCG argued in its brief that the service lives proposed by OPC witness Garrett are less reasonable than those proposed in its 2022 Study because witness Garrett failed to “incorporate factors such as general knowledge of the property studied, informed judgement, and information obtained from site visits and meetings with Company subject matter experts.” (FCG BR 15) Yet none of these factors, as they pertain to FCG specifically, were used in developing the RSAM-adjusted parameters.

Regarding the ASLs proposed by witness Garrett, witness Allis testified that:

For the largest of these accounts (gas mains and gas services) as well as house regulators, my recommendations are for significantly longer lives than those adopted in the depreciation study that preceded the 2018 Depreciation Study (i.e., the “2014 Depreciation Study” included in Docket No. 20140051-GU). For each of these accounts, OPC witness Garrett proposes to increase the service lives even further than what I have recommended. However, he does so with little support.

(TR 732)

Staff agrees with witness Allis regarding his assessment of witness Garrett’s proposed ASLs having little support. Witness Allis’ argument above demonstrates that the RSAM-adjusted parameters are subject to the same lack of support. For each of the three accounts in which witness Allis argued that witness Garrett’s ASLs were too long, the RSAM-adjusted ASLs are five years longer than witness Garrett’s. (EXH 22; EXH 67)

Beyond the three accounts mentioned earlier, there are three additional accounts in which the adoption of the RSAM-adjusted ASLs trouble staff. The proposed ASLs for those accounts in each scenario are reflected in Table 5-2 below.

Table 5-2

Comparison of RSAM-adjusted and the 2022 Study Average Service Lives

Account	RSAM-Adjusted	2022 Study	Percent Difference
379 - M & R Equip. - City Gate	50	35	42.9%
382.1 - Meter Installations - ERT	44	20	120.0%
387 - Other Equipment	24	35	31.4%

Source: EXH 40; EXH 22

As reflected in the table above, the percentage differences in the ASLs proposed by witness Allis in the 2022 Study compared to the RSAM-adjusted ASLs represent changes of approximately 42.9 percent, 120 percent, and 31.4 percent. The size of these differences clearly does not take into account the concept of gradualism that witness Allis himself testified was so important. (TR 736-738) Witness Allis specifically took issue with witness Garrett’s proposal of a 55-year ASL for Account 380.1 – Services due to its lack of gradualism. (TR 750) That ASL proposal represents an increase of 20 years (36 percent) from the 2014 Study. (TR 738) Staff notes that this change represents eight years between studies. The changes represented in Table 5-1 are over just a four-year period. Therefore, staff concludes the RSAM-adjusted ASLs for the accounts in Table 5-1, and the three accounts listed earlier in this issue about which witness Allis argued against witness Garrett, are wholly unreasonable and inappropriate in this case. The mere fact that FCG proposes certain depreciation parameters as appropriate for the sole purpose of creating a theoretical reserve surplus on one hand, while rejecting those parameters and proffering witness Allis’ 2022 Study parameters if the RSAM is not approved, demonstrates that their simultaneous arguments for the appropriateness of each plan (a one-year scenario and a four-year scenario) are contradictory. (FCG BR 13-17)

The fifth concern staff has regarding the reasonableness of FCG’s proposed RSAM-adjusted depreciation rates is the impact such rates impose on the calculation of FCG’s theoretical reserve, thereby creating a need to address a very large surplus that would not otherwise exist. Despite FCG’s assertion that the RSAM-adjusted parameters are reasonable, staff believes the magnitude of the change in the theoretical reserve that results from the 2022 Study parameters compared to the RSAM-adjusted parameters, suggests otherwise. As discussed in Issue 7, the theoretical imbalance that results from the 2022 Study is a deficit of $3.2 million. (EXH 40) The theoretical reserve imbalance that results from the RSAM-adjusted parameters is a $52.1 million surplus. (EXH 22)

The magnitude of this imbalance difference should be analyzed in relation to FCG’s December 31, 2022 depreciable plant reserve balance of $198,147,854. (EXH 22) This shifting of the imbalance of $55.3 million is approximately 28 percent of the December 31, 2022 depreciable plant reserve balance. (EXH 22) Staff believes such a drastic change in the theoretical reserve imbalance undercuts FCG’s argument that the RSAM-adjusted depreciation parameters are appropriate. (FCG BR 11)

A further indication that the parameters resulting from the 2022 Study are the most appropriate parameters in this case is the size of the imbalances mentioned above. The relatively small reserve deficit of $3.2 million that results from the 2022 Study demonstrates that the reserve is on target and, as discussed in Issue 7, does not require any adjustments. (EXH 40) In contrast, the significant surplus that results from FCG’s proposed RSAM-adjusted depreciation parameters calls into question whether such parameters are appropriate. (EXH 22)

Thus, a summary of staff’s concerns regarding the application of any depreciation study in this case rather than the 2022 FCG Depreciation Study include:

· Traditional regulatory objectives, such as the matching principle and minimization of intergenerational inequities, are best achieved when depreciation rates are based on a utility-specific depreciation study.

· The Commission has consistently relied upon depreciation rates resulting from utility-specific depreciation studies, as required by Section 366.06(1), F.S., rather than depreciation rates based solely on another utility’s settlement agreement.

· The Commission’s depreciation rule (Rule 25-7.045, F.A.C.) provides for the application of depreciation rates, resulting from a review of the utility’s own plant per its depreciation study, for purposes of setting customer rates and reflecting the depreciation study’s rates in its recorded expenses. Any alternate methods must be approved by the Commission.

· FCG’s own witness testimony variously concludes that OPC’s service lives are too long, not supported, are inappropriate, and not reflective of gradualism or professional judgement; yet many of FCG’s proposed RSAM-adjusted service lives are as long as, or longer than, OPC’s proposed service lives.

· The manufactured reserve imbalance resulting from FCG’s proposed RSAM-adjusted depreciation parameters produces a $52.1 million surplus, whereas the Company’s own utility-specific 2022 Study produces a $3.2 million deficit.

These concerns pertain to whether it is reasonable to set aside the results of the review of FCG’s 2022 depreciation study and instead approve the rates that are included in an another company’s rate settlement. Staff’s concerns raised herein point to the several serious consequences resulting from setting aside the Company’s own depreciation study and instead relying on rates not based on company-specific data. Staff believes FCG’s proposed RSAM-adjusted depreciation rates, based entirely on depreciation data external to the Company, would have impacts on customer rates, recorded expenses, and future reserve levels without regard to achieving traditional regulatory objectives. The ultimate decision of whether it may be reasonable to approve the proposed RSAM-adjusted depreciation rates to achieve the purported customer benefits and value argued by FCG is the subject of Issue 67.

CONCLUSION

The depreciation parameters recommended by staff are those that resulted from witness Allis’ FCG-specific depreciation study. These parameters are reflective of FCG’s assets life, mortality, and net salvage characteristics, and are consistent with the intent of the depreciation rule. Staff’s recommended depreciation parameters and resulting depreciation rates for each distribution and general plant account are shown on Table 5-3. If the Commission approves staff’s recommended depreciation parameters and rates, Issues 6 and 67 are moot.

Table 5-3

Staff’s Recommended Depreciation Parameters

Source: EXH 40

Issue 6:

If the Commission approves FCG’s proposed RSAM (Issue 67), what are the appropriate depreciation parameters (e.g., service lives, remaining lives, net salvage percentages, and reserve percentages) and depreciation rates?

Recommendation:

If the Commission approves FCG’s proposed RSAM in Issue 67, staff recommends that the appropriate depreciation parameters and resulting depreciation rates for each distribution and general plant account are those shown on Table 6-1 below. If the Commission does not approve FCG’s proposed RSAM, staff’s recommended depreciation parameters are discussed in Issue 5. (Smith, Wu)

Position of the Parties

FCG:

The appropriate depreciation parameters and resulting depreciation rates to be used in conjunction with the RSAM are reflected in Exhibit 22. The RSAM-adjusted depreciation parameters are a critical and essential component of FCG’s proposed four-year rate plan, and are necessary to provide rate stability for FCG’s customers and avoid the potential for approximately $27.0 million in additional cumulative net cash paid by customers through at least the end of 2026 if FCG’s proposed four-year rate plan with RSAM is denied. (Fuentes, Campbell)

OPC:

The Commission does not have the authority to, and should not, approve FCG’s proposed RSAM. The Commission may not establish depreciation rates in a general rate case for the express purpose of creating a depreciation imbalance (surplus) based on parameters which are not factually based on a depreciation study. Such a practice would be a departure from generally accepted accounting principles. It would also eliminate any incentive for FCG to generate efficiencies, and it would be grossly unfair to FCG’s current and future customers.

FEA:

FEA took no position.

FIPUG:

FIPUG adopted the position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued that the rates reflected on Exhibit 22 are the appropriate rates to use in conjunction with FCG’s proposed RSAM. (FCG BR 17) FCG stated these rates are reasonable and are the same rates, with the exception of FCG’s LNG Facility, approved through a settlement agreement in People’s Gas System’s most recent base rate case. (FCG BR 17)

FCG explained that its witness Allis considered the RSAM-adjusted rates to be within the overall range of reasonableness. (FCG BR 18) FCG argued that these parameters are very similar to the ones OPC witness Garrett proposed in the Florida Public Utilities rate case in Docket No. 20200067 and only slightly longer than the parameters he proposed in this case. (FCG BR 18)

FCG also argued that, since depreciation parameters are estimates of what may occur in the future, it is inevitable that those estimates will create surpluses and deficits. (FCG BR 18) FCG explained that this is the reason for the Commission’s rule requiring gas utilities to file a depreciation study every five years. (FCG BR 18) For these reasons, FCG argued that the RSAM-adjusted depreciation parameters do not create intergenerational inequities. (FCG BR 18)

FCG concluded that, given the arguments above, the RSAM-adjusted depreciation parameters are a reasonable alternative to the parameters proposed in its 2022 Study by witness Allis, and should be adopted. (FCG BR 19)

OPC

OPC argued that “the Commission lacks the authority to establish depreciation rates that ignore the remaining life technique methodology and that neither the company’s expert, nor the intervenor experts, nor the Commission’s rules, practices, and policies support, for the sole purpose of artificially creating a surplus to be used for an amortizable Reserve Amount capable of effectively setting rates at the top of the range.” (OPC BR 8-9)

OPC argued that FCG, through the testimony it presented, is attempting to artificially create a reserve surplus (referred to as a “Reserve Amount”) instead of the reserve deficit that resulted from the Company’s depreciation study. (OPC BR 9) OPC stated that the size of this Reserve Amount can be increased or decreased by factors that have no relation to depreciation rates and parameters. OPC argued that the RSAM itself is worthless to FCG and its parent FPL if no reserve amount exists, which OPC states, the Commission cannot lawfully create if agency rules and policies are followed. (OPC BR 9)

OPC argued that the wording of this issue has “the FCG thumb on the scale” by presuming whether or not a RSAM is to be authorized is the threshold decision. (OPC BR 9) OPC stated that FCG is attempting to get the Commission to deviate from its rules, policies, and practice in order to “reverse-engineer parameters and rates for the benefit of shareholders.” (OPC BR 9)

OPC stated in its brief, “The first decision here should be whether, in a contested rate case, the Commission possesses the authority to independently establish depreciation rates and a depreciation surplus for reasons wholly unrelated to determining the cost of consumption of capital that is enshrined in Rule 25-7.045, Florida Administrative Code (“F.A.C.”) (the Depreciation Rule).” (OPC BR 9) OPC argued that the answer to that question is no because it is prohibited by Commission rules and Section 120.68(7)(e)3, F.S. (OPC BR 9-10)

OPC explained that this rate case is being conducted under Section 366.061(1), F.S., and that this statute lays out two principles for gas utility ratemaking in Florida. (OPC BR 10) OPC stated that the first principle is that “the rate case petition must be filed by the company pursuant to the prescribed rules and regulations” which must be followed unless a waiver is granted under Section 120.542, F.S. (OPC BR 11) OPC explained that the second established principle is that in a petition for a change in rates, the Commission must set those rates based on costs that are accounted for in a systematic way, which includes net investment (investment minus accrued depreciation). (OPC BR 11)

OPC argued that, through the Commission’s own rules, it has adopted the Federal Energy Regulatory Commission (FERC) Uniform System of Accounts (USOA), which has strict rules as to what can be charged to certain accounts. (OPC BR 11-12) OPC also argued that, as it pertains to Account 108 Accumulated Provision for Depreciation of Gas Utility, only the cost of removal and the original cost of the plant retired may be debited to this account. OPC stated that the Depreciation Rule does not allow the Commission to alter what can be debited to this account outside of a negotiated settlement agreement. (OPC BR 11-13)

OPC explained that it is Commission practice to use the remaining life technique to correct any reserve imbalance unless that imbalance is material enough to cause intergenerational inequities and violate the matching principle. (OPC BR 13) OPC further explained that the matching principle plays a part in how to correct a reserve imbalance, and that the Commission has stated that intergenerational inequities exist whenever a reserve imbalance exists. (OPC BR 13-14)

OPC explained that in the 2010 Florida Power & Light (FPL) rate case, the Commission ordered FPL to include an amortization of the reserve surplus in the test year income statement which goes to the benefit of the customers. (OPC BR 14) OPC stated that this is consistent with the Depreciation Rule because it corrects the imbalance. (OPC BR 14) OPC argued that the Depreciation Rule does not have a provision for creating an imbalance. (OPC BR 14)

OPC concluded its argument by stating that the adjustments to witness Allis’ depreciation parameters as offered by witness Garrett should be adopted in this case. (OPC BR 14) OPC concluded by stating the remaining life technique should be used to address any resulting reserve imbalance. (OPC BR 14-15)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 5)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 5)

ANALYSIS

This issue addresses the appropriate depreciation parameters and resulting depreciation rates for distribution and general accounts if the Commission approves FCG’s RSAM in Issue 67. Staff’s recommended depreciation parameters include the ASL, curve shape, the remaining life (in years), net salvage percent, and reserve percent.

FCG witness Campbell stated that the RSAM is a key component of FCG’s proposed 4-year rate plan. (TR 1045) Witness Campbell explained that FCG would use the RSAM in order to manage the daily fluctuations in revenues and expenses. FCG would accomplish this by amortizing a reserve surplus. (TR 1095)

Based on FCG’s 2022 Study conducted by FCG witness Allis, and staff’s recommended depreciation parameters in Issue 5, the resulting theoretical reserve imbalance would be a reserve deficit. (EXH 40) Therefore, FCG is proposing that the Commission approve the alternate depreciation parameters in order to create a depreciation reserve surplus. (EXH 22) These alternate depreciation parameters were the result of a settlement agreement in Peoples Gas Systems’ prior petition for rate increase and were approved by the Commission as a result of a settlement in Docket No. 20200051-GU.[13] These alternate depreciation parameters are reflected on Table 6-1 below. The resulting reserve position is discussed more fully in Issue 7.

CONCLUSION

If the Commission approves FCG’s proposed RSAM in Issue 67, staff recommends that the appropriate depreciation parameters and resulting depreciation rates for each distribution and general plant account are those shown on Table 6-1 below. (EXH 22) If the Commission does not approve FCG’s proposed RSAM, staff’s recommended depreciation parameters are discussed in Issue 5.

Table 6-1

Staff’s Recommended Depreciation Parameters – RSAM Scenario

Issue 7:

Based on the application of the depreciation parameters that the Commission has deemed appropriate to FCG’s data, and a comparison of the theoretical reserves to the book reserves, what, if any, are the resulting imbalances?

Recommendation:

If the Commission approves staff’s recommended life and salvage parameters in Issue 5, staff recommends a resulting reserve deficit of $3.2 million, based on FCG’s 2022 Depreciation Study. If the Commission approves staff’s recommended life and salvage parameters in Issue 6, as proposed by FCG as part of its RSAM request, staff recommends a resulting reserve surplus of $52.1 million. (Smith, Wu)

Position of the Parties

FCG:

If the Commission adopts the RSAM contained in the Company’s four-year rate proposal, then the appropriate theoretical reserve imbalance is a surplus of approximately $52.1 million as reflected in CEL Ex. 22, of which FCG has requested $25 million to be available under an RSAM. The $25 million of RSAM is only sufficient to allow FCG to earn at the proposed midpoint ROE over the term of the rate plan. If the Commission does not approve the RSAM, the theoretical reserve imbalances from FCG’s 2022 Depreciation Study are reflected on CEL Ex. 40, which totals a net deficit of $3.2 million (total system). (Allis, Campbell, Fuentes)

OPC:

The depreciation parameters and resulting depreciation rates are shown in OPC Witness Garrett’s testimony and Exhibits 66 and 68. The resulting imbalance, if any, with these adjustments is a fallout number.

FEA:

FEA took no position. (FEA & FIPUG BR 5)

FIPUG:

FIPUG adopted the position of OPC. (FEA & FIPUG BR 5)

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued that the appropriate reserve imbalance that would result if the Commission approves the RSAM-adjusted depreciation rates in Issue 6 would be $52.1 million. (FCG BR 19) FCG explained that, under its RSAM scenario, $25 million would be available for the Company to amortize during the 2023-2026 timeframe. (FCG BR 19) FCG contended that, even with the $25 million Reserve Amount, FCG would still have to find cost savings to reach the proposed midpoint ROE. (FCG BR 19)

FCG argued that the appropriate reserve imbalance that would result if the Commission approves FCG’s 2022 Depreciation Study in Issue 5 would be a deficit of $3.2 million. (FCG BR 20)

OPC

OPC explained that OPC witness Garrett testified when the book accumulated depreciation does not equal the calculated accumulated depreciation, a reserve imbalance exists. (OPC BR 15) OPC continued by stating that when the remaining life technique is used, accumulated depreciation is adjusted over the remaining life of the assets. (OPC BR 15)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 5)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 5)

ANALYSIS

FCG witness Allis calculated a $3.9 million theoretical reserve deficit for FCG’s distribution accounts and a $0.8 million reserve surplus related to its general plant accounts, based on the proposed life and salvage parameters in FCG’s 2022 Depreciation Study. (EXH 40) Neither OPC nor any other intervenor provided a calculation for a reserve imbalance based on their proposed parameters.

FCG witness Allis also calculated a $50.8 million theoretical reserve surplus for FCG’s distribution accounts and a $1.3 million reserve surplus related to its general plant accounts, based on FCG witness Fuentes’ proposed RSAM life and salvage parameters discussed in Issue 6. (EXH 22) OPC and the other parties did not provide a calculation for a reserve imbalance based on these parameters.

The formula for the prospective theoretical reserve is provided in Rule 25-7.045(4)(k), F.A.C.[14] Using this formula and the life and salvage components that staff recommends in Issue 5 (no RSAM), staff calculates a reserve imbalance of $3.2 million, as shown in Table 7-1 below. Further, using this formula and the life and salvage components that staff recommends in Issue 6 (with RSAM), staff calculates a reserve imbalance of $52.1 million, as shown in Table 7-2 below.

Table 7-1

Reserve Imbalances

Account Type	Reserve Imbalance ($000)
Distribution	($3,936.0)
General	$800.0
Total Reserve Imbalance	($3,166.2)

Source: EXH 40 (Numbers do not add due to rounding)

Table 7-2

Reserve Imbalances (RSAM)

Account Type	Reserve Imbalance ($000)
Distribution	$50,813.2
General	$1,313.3
Total Reserve Imbalance	$52,126.5

Source: EXH 22 (Numbers do not add due to rounding)

CONCLUSION

If the Commission approves staff’s recommended life and salvage parameters in Issue 5, staff recommends a resulting reserve deficit of $3.2 million. If the Commission approves staff’s recommended life and salvage parameters in Issue 6, staff recommends a resulting reserve surplus of $52.1 million.

Issue 8:

What, if any, corrective depreciation reserve measures should be taken with respect to any imbalances identified in Issue 7?

Recommendation:

If the Commission approves staff’s recommended life and salvage parameters in Issue 5, staff recommends using the remaining life technique for the Distribution and General Plant accounts. If the Commission approves FCG’s proposed RSAM in Issue 67 and staff’s recommended life and salvage parameters in Issue 6, the method for addressing the imbalance is discussed in Issue 67. (Smith, Wu)

Position of the Parties

FCG:

If the Commission adopts the RSAM as part of FCG’s four-year rate proposal, then the corrective reserve measures outlined in CEL Ex. 16 should be taken. Any remaining reserve imbalance should be addressed in FCG’s next depreciation study. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, then the remaining life technique should be used, and no other corrective reserve measures should be taken. (Allis, Campbell, Fuentes)

OPC:

Imbalances identified by adoption of the parameters and resulting depreciation rates in Garrett’s testimony and exhibits should, consistent with Commission practice, be allocated over the service life of the assets using the parameters included in his testimony and exhibits. The Commission lacks authority to establish depreciation rates in a general rate case for the express purpose of creating a depreciation imbalance (surplus) based on parameters which are not factually based on a depreciation study. Such a practice would be a departure from Generally Accepted Accounting Principles (“GAAP”) and would be grossly unfair to FCG’s current and future customers.

FEA:

FEA took no position.

FIPUG:

FIPUG adopted the position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued that the corrective measures outlined in CEL Exhibit 16 are the appropriate measures to take if the Commission approves FCG’s proposed RSAM in Issue 67. (FCG BR 20) FCG contended that the remaining life technique should be used if the Commission does not approve the proposed RSAM. (FCG BR 20-21)

OPC

OPC did not provide an argument. (OPC BR 15)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 5)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 5)

ANALYSIS

This issue addresses whether any corrective measures should be taken with regard to the reserve imbalances discussed in Issue 7. Traditionally, the Commission has utilized three techniques for addressing reserve imbalances. The first two methods are appropriate for addressing reserve imbalances that are relatively small when compared to the utility’s overall reserve balance. The first and most common technique is the use of remaining life depreciation rates. This method self-corrects these imbalances over the remaining life of the assets. The second method of addressing these relatively small reserve imbalances is to transfer a portion of the reserve from one account to another. This method is useful especially when, even though the overall reserve imbalance is small, one account may have a large surplus while another has a large deficit, and those imbalances can be used to offset one another.

The third method of addressing a reserve imbalance includes amortizing the imbalance over a certain period of time. When the reserve imbalance rises to a level that the Commission deems more immediate action should be taken, amortizing the imbalance over a certain period of time may be more appropriate. In this scenario, the imbalance is generally amortized over a four-year period and that amortized amount is included in the calculation of the revenue requirement. This way, if a surplus exists, the customers are guaranteed to receive a dollar-for-dollar refund of the money they overpaid. This method of addressing reserve imbalances was ordered by the Commission in the 2009 FPL base rate case.^{^[15]}

If the Commission approves FCG’s Reserve Surplus Amortization Mechanism (RSAM) in Issue 67, FCG proposes having a Reserve amount of $25 million available to use for managing daily fluctuations in revenues and expenses. (TR 1065; TR 1066) FCG did not propose any treatment for the remaining reserve surplus of $27.1 million. Therefore, that amount would remain on FCG’s books and records until the Company files its next depreciation study.

CONCLUSION

Based on the record, if the Commission approves staff’s recommended life and salvage parameters in Issue 5, staff recommends using the remaining life technique for the Distribution and General Plant accounts. If the Commission approves FCG’s proposed RSAM in Issue 67 and staff’s recommended life and salvage parameters in Issue 6, the method for addressing the imbalance is discussed in Issue 67.

Issue 9:

What should be the implementation date for revised depreciation rates and amortization schedules?

Recommendation:

Staff recommends January 1, 2023, for implementing the revised depreciation rates and amortization schedules approved in either Issue 5 or Issue 6 of this recommendation. (Smith, Wu)

Position of the Parties

FCG:

The implementation date for revised depreciation rates should be the effective date of new base rates. (Fuentes)

OPC:

The depreciation parameters and resulting depreciation rates are as shown in OPC Witness Garrett’s testimony and exhibits and should be implemented upon approval by the Commission, effective January 1. 2023. The implementation date should be consistent with the Rule 25-7.045, F.A.C.

FEA:

FEA took no position.

FIPUG:

FIPUG adopted the position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that the company filed its 2022 Study, along with the alternative RSAM-adjusted depreciation rates, direct testimony, and MFRs all in compliance with Rule 25-7.045(4)(c), F.A.C. (FCG BR 21) During cross-examination by Commission staff, FCG witness Fuentes stated “the implementation date for new depreciation rates should appropriately coincide with the effective date of new base rates that reflect those depreciation rates.” (FCG BR 21) FCG argued that this will be a matching of the new base rates with the new depreciation rates.[16] (FCG BR 21) 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. (FCG BR 21)

OPC

OPC did not provide an argument. (OPC BR 15)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 5)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 5)

ANALYSIS

Rule 25-7.045(4)(d), F.A.C. (the Depreciation Rule), 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.” Staff confirmed that the plant and reserve balances were as of December 31, 2022, thus matching an implementation date of January 1, 2023. Staff would note that the Projected Test Year MFRs in this case were based on the period January 1, 2023 through December 31, 2023. (EXH 2-9)

FCG has taken the position that the implementation date for the proposed depreciation rates should be the same as the effective date for new base rates. When asked how an implementation date of February 1, 2023 comports with the Depreciation Rule, FCG witness Fuentes testified that the rates from the depreciation study were based on forecasted data through the end of 2022. (TR 966) Witness Fuentes continued, “The resulting rates under the Company’s alternate rate scenario were used to calculate depreciation expense as a company adjustment, as I have in my testimony.” (TR 966)

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 the Depreciation Rule, the implementation date of the new depreciation rates and amortization schedules should be January 1, 2023, not February 1, 2023.

CONCLUSION

Staff recommends January 1, 2023, for implementing the revised depreciation rates and amortization schedules approved in either Issue 5 or Issue 6 of this recommendation.

Rate Base

Issue 10:

Has FCG made the appropriate adjustment to Rate Base to transfer the SAFE investments as of December 31, 2022 from clause recovery to base rates?

Approved Type II Stipulation:

Yes. Per Order No. PSC-15-0390-TRF-GU in Docket No. 150116-GU, investments in the SAFE program are required to be folded into any newly approved rate base and the SAFE surcharge is to begin anew. As reflected on Exhibit LF-3, $5.7 million of SAFE revenue requirements were transferred from clause recovery to base rates in the 2023 Test Year.

Issue 11:

Should FCG’s proposed Advanced Metering Infrastructure (AMI) Pilot be approved? If so, what adjustments, if any, should be made?

Recommendation:

Yes. Staff recommends that the AMI Pilot should be approved. As shown in Attachment 3, a staff adjustment of ($3,104) is recommended to the originally projected operation and maintenance (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, staff recommends that FCG provide a final report with a summary of the findings to the Commission within 90 days of completion of the AMI Pilot. (Thompson)

Position of the Parties

FCG:

Yes. The AMI Pilot will enable FCG to test and evaluate whether it would be appropriate in the future to deploy AMI technology across its entire system, as well as allow FCG to test and gather data on the corrosion resistance and life of new smart meters. FCG took a measured approach to its AMI Pilot, limiting the implementation of the pilot to only 5,000 meters that currently experience accelerated corrosion and retirement. No adjustments should be made. (Howard)

OPC:

No, the cost for this experimental program should be borne by shareholders, not customers, since it is not known whether there will be a benefit. The adjustments shown on Exhibit 46, Schedule B-3, of a plant in service adjustment of $837,500 and related accumulated depreciation adjustment of $23,456 and should be made. In addition, the related O&M expense of $20,000 and depreciation expense of $46,913 should be reduced as shown in Issue 49 and Exhibit 46, Schedules C and C-7.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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, FCG will be gathering information on the benefits of automated remote readings, and the corrosion resistance and life of the 5,000 new smart meters to be installed in Brevard County under the pilot, which is an appropriate sample size to determine benefits for the whole system while potentially reducing the costs. (FCG BR 22-23)

FCG asserted that the intervenors do not oppose the AMI Pilot, only its cost recovery, with OPC contending that the costs should be borne by shareholders because of the newness of the technology, which they suggest is intended to benefit shareholders as opposed to customers. FCG maintained that the smart meters and AMI to be deployed under the AMI Pilot 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. (FCG BR 23)

FCG contended that OPC ignored the expected benefits identified in the direct testimony of FCG witness Howard associated with the AMI Pilot, which accrue to customers and the system, not shareholders, through improved functionality and potential cost reductions. In addition, FCG argued 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. FCG averred that if OPC’s arguments are accepted, this 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. (FCG BR 24)

FCG asserted that OPC’s argument that the costs for the AMI Pilot should be borne by shareholders overlooks the numerous pilot projects that the Commission has previously approved. For example, FCG identified FPL’s Green Hydrogen Pilot approved under FPL’s most recent settlement agreement.^{^[17]} As such, FCG recommended that OPC’s arguments opposing the AMI Pilot be rejected, and the AMI Pilot be approved to enable FCG to evaluate whether future system-wide deployment is appropriate. (FCG BR 25)

OPC

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 should deny the AMI Pilot because FCG has not demonstrated the prudence of this program. (OPC BR 16)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 6)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 6)

ANALYSIS

FCG is requesting a research and development pilot to evaluate AMI infrastructure with two-way communication capability. 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. (TR 591-592) 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 devices with related back-office technology support installed in the Brevard County area where accelerated corrosion has been documented. (TR 592-593) After the conclusion of the pilot, FCG anticipates being able to report a summary of the findings, and provide sample reports with relevant information to the Commission. (EXH 139) The estimated total cost of the AMI Pilot is $3.4 million in capital expenditures, with annual O&M estimated at $16,896, as corrected by FCG witness Howard, for the pilot period. (TR 594-595) As shown in Attachment 3, a staff adjustment of ($3,104) was made to the originally projected O&M expense for the AMI Pilot to reflect the corrected O&M expense identified in witness Howard’s testimony.

OPC witness Schultz raised concerns that the AMI Pilot was both (i) a risk due to the newness of the technology to the gas industry with uncertainty of benefits, and (ii) to the extent that benefits are proposed by FCG, it did not include them 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. (TR 298) Staff notes that pilot programs are typically vehicles through which utilities explore new technologies or processes, and assess the benefits using a sample prior to system-wide implementation.^{^[18]} As previously discussed, 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. (TR 593)

Regarding witness Schultz’s first concern, in discovery, FCG agreed 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, due to differences in the technologies. (TR 592; EXH 135) Staff believes 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.

Regarding witness Schultz’s second concern, staff agrees that FCG has not attempted to quantify benefits; however, as part of the AMI Pilot, 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 truck-rolls and related expenses. (TR 592-593) 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, as well as provide sample reports including information such as customer daily usage, remote meter communication performance, and billing accuracy impacts. FCG intends to use this information, as well as potential cost savings, to determine the feasibility of AMI technology on its system, as well as the appropriateness of system-wide deployment of this technology in the future. (EXH 135) Witness Howard also testified that the Commission has previously accepted pilots as a means of determining benefits, and if the Commission accepted witness Schultz’s reasoning, the Commission would deter utilities from pursuing pilot programs that might lead to future benefits, such as the proposed AMI Pilot. (TR 611-612)

Staff has reviewed FCG’s requested AMI Pilot, and agrees with FCG witness Howard that customers and the Utility could potentially benefit from implementation of AMI technology due to the potential for reduced costs for the Utility, and, as a result, the customers. While staff agrees with witness Schultz that FCG has not quantified the benefits associated with the AMI Pilot, staff notes that FCG has identified several benefits, as discussed above, that it expects following implementation of the pilot, and explained that these benefits, including potential cost savings, will be further assessed under the pilot. (TR 592-593; EXH 135, 139) As FCG would be the first gas utility to implement AMI technology in Florida, staff agrees with witness Howard that the benefits of such implementation need to first be assessed prior to system-wide deployment, and that a pilot program provides the means to do so. As such, staff recommends that FCG’s proposed AMI Pilot be approved.

CONCLUSION

Staff recommends that the AMI Pilot should be approved. As shown in Attachment 3, a staff adjustment of ($3,104) is recommended 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, staff recommends that FCG provide a final report with a summary of the findings to the Commission within 90 days of completion of the AMI Pilot.

Issue 12:

What is the appropriate amount of plant in service for FCG’s delayed LNG facility that was approved in its last rate case?

Recommendation:

Staff recommends that the appropriate amount of plant in service for FCG’s delayed LNG facility, once it is placed in service, is $68 million. (Thompson)

Position of the Parties

FCG:

The need and construction of the LNG Facility were previously approved by the Commission in Docket No. 20170179-GU. FCG currently projects the total cost necessary to complete the LNG Facility is $68 million with an in-service date of March 2023. As reflected on page 27 of MFR G-1, the appropriate amount of plant in service for the LNG Facility when it is placed in service in March 2023 is $68 million. (Campbell, Howard)

OPC:

OPC Witness Schultz’s testimony and exhibits address the appropriate amount of plant-in-service. The plant in service for the delayed LNG facility should be reduced by at least $7,692,308 and the associated accumulated depreciation of $56,253. Further adjustments may be warranted based on the actual in-service date of the facility.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG contended that the LNG facility was approved by the Commission in Order No. PSC-2018-0190-FOF-GU, when the 2018 Settlement Agreement, to which OPC was a signatory, approved both the need for and construction of the facility with a then estimated $58 million in-service cost. (FCG BR 25) FCG asserted that based on actual project costs, 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 that OPC agreed to the need of 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 as it did when its need was approved in the 2018 Settlement Agreement. (FCG BR 26)

FCG contended that OPC’s argument that the incremental $10 million should be disallowed is inconsistent with Commission practice and the 2018 Settlement Agreement. FCG averred that standard practice for any project is to update estimates with the actual estimated costs, be it higher or lower than the estimated value. (FCG BR 27) FCG asserted that parties were aware that both the in-service date and costs were estimates, and that the 2018 Settlement Agreement terms specifically envisioned some of this uncertainty, with rates not going into effect until the in-service date of the unit. (FCG BR 27-28)

FCG argued it is inappropriate for OPC to contend that the incremental $10 million be disallowed because of either (a) uncertainty in the in-service date or (b) that FCG was imprudent in acquiring the original site prior to a zoning change. FCG maintained that the record in this case demonstrates that the LNG facility is fully permitted and on schedule to begin LNG deliveries in January 2023, and meet its projected March 2023 in-service date. (FCG BR 28) FCG further argued that regardless of the property selected, the siting and construction of an LNG facility requires many permits and approvals, and that there are limited site options that can accommodate the proposed LNG facility at a reasonable and fair price. (FCG BR 31)

Regarding costs related to the LNG facility that are currently included in base rates, FCG argued that OPC, as a party to the 2018 Settlement Agreement, was aware that $2.5 million of revenue requirements associated with the LNG facility were included in the annual revenue requirement increase under the 2018 Settlement Agreement, and that no party disputes this. (FCG BR 32) FCG further argued that OPC’s recommendation that amounts collected from customers associated with the LNG facility when it goes into service should be set aside in a regulatory liability and amortized back to ratepayers over the next five years should be rejected because it is in direct violation of the following statement agreed to by the parties to the 2018 Settlement Agreement:

Parties further agree that they believe the 2018 Agreement is in the public interest, that they will support this 2018 Agreement and will not request or support any order, relief, outcome, or result in conflict with the terms of this 2018 Agreement in any administrative or judicial proceeding relating to, reviewing, or challenging the establishment, approval, adoption, or implementation of this 2018 Agreement or the subject matter hereof.^{^[19]} (FCG BR 32-34)

FCG asserted that allowing parties to violate terms agreed upon in a prior Commission-approved settlement would cause parties to become more hesitant to enter settlement agreements. FCG argued that the Commission should honor the 2018 Settlement Agreement with regard to amounts collected from customers for the LNG facility. (FCG BR 34)

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. (FCG BR 34)

OPC

Although OPC acknowledged that some recovery of expenses associated with the LNG facility were allowed under the 2018 Settlement Agreement, OPC expressed concerns with the timeframe over which ratepayers have been paying for the LNG facility. (OPC BR 18) OPC argued that it is unjust that customers have been paying for a facility that is not yet in-service. (OPC BR 18-19) An additional concern OPC noted is a possible double recovery specifically as it relates to the $11.6 million that has already been received from customers associated with the original $58 million cost for the LNG facility contemplated by the 2018 Settlement Agreement. OPC expressed concerns that since FCG is seeking recovery of $68 million in costs associated with the LNG facility in this proceeding (which consists of the original $58 million cost plus an additional $10 million in costs), funds already received from customers will potentially result in customers overpaying for the LNG facility. As such, OPC proposed that the Commission create a mechanism to ensure that customers only pay for the LNG facility once. (OPC BR 19) Specifically, OPC recommended that any funds that have been collected from ratepayers related to the LNG facility be accounted for in a regulatory liability and returned to ratepayers over five years. (OPC BR 22)

Regarding recovery of the $68 million LNG facility cost, OPC recommended that no costs be recovered until the facility is in-service due to the delayed in-service date. (OPC BR 22-23) Additionally, OPC recommended that any additional depreciation associated with the LNG facility that is currently included in rates 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 annual clause dockets at a weighted average cost of capital (WACC) that recognizes the cost carried in rates. (OPC BR 23)

Regarding the additional $10 million cost associated with acquiring a new site for the LNG facility, OPC recommended that this cost be disallowed. OPC argued that FCG failed to properly and prudently plan the project by acquiring land and incurring costs prior to receiving the zoning exemption for the site. (OPC BR 23) OPC further argued that the informal communications between FCG and the County Planning staff should not have been used as the basis for obtaining the site since no official approval was granted. (OPC BR 24-25) In addition, OPC asserted that the land for which FCG failed to receive zoning approval ultimately benefitted FPL as it appears to now be owned by FPL. (OPC BR 27)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 6)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 6)

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. (TR 583) 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.^{^[20]} The 2018 Settlement Agreement determined that the LNG facility was needed to address the peak capacity concerns on FCG’s system for 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. (TR 586) The primary cause of this is due to the loss of the originally proposed site as a viable location for the LNG facility, and the resulting in-service date delay. (TR 587) 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. (TR 584-585) As part of this record, staff 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.

Need for the LNG Facility

While the Commission previously approved the need for the LNG facility under the 2018 Settlement Agreement and no party has disputed the continued need for the facility, the Commission noted in a prior proceeding that prudent utility managers continually reassess the need for a project or facility as circumstances change.[21] As such, staff reviewed whether or not the LNG facility is still needed to serve customers on the southern-most portion of FCG’s system in the projected test year.

To 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. (TR 585; EXH 139) FCG further indicated that the FGT pipeline is the sole source of FCG capacity in Miami-Dade County, but the FGT pipeline has no additional incremental capacity available. (EXH 139, 142) Witness Howard argued that to date, FCG has been unable to acquire any additional interstate capacity at terms and pricing that are acceptable and reasonable, including additional capacity to serve customers in the Miami-Dade County area. (TR 585; EXH 139) 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. (EXH 142)

In response to staff’s discovery, FCG indicated that it has been able to continue to meet the capacity needs in the Miami-Dade County area with the FGT pipeline during the delay period only because the system has not experienced any extraordinary circumstances that have stressed the system such that the flow of gas had to be curtailed or interrupted. (EXH 142) In addition, witness Howard argued that FCG has seen significant gas demand growth on the southern-most portion of its system since the 2018 Settlement Agreement. (TR 585) As such, FCG indicated that reliably serving customers at this portion of its system is becoming increasingly constrained due to customer growth in that area, and provided supporting documentation demonstrating the consumption increase in this area since 2018. (TR 585; EXH 142) In addition, FCG identified specific capacity shortages on its system, by region, for 2023, some of which the LNG facility will help supply. FCG argued that although it has been fortunate to not encounter any degree days or upstream interruptions that have stressed the system to the point where the flow of gas had to be curtailed or interrupted, it would not be prudent to assume that this will continue to be the case rather than adding resiliency to ensure FCG can continue to provide safe and reliable service to customers located at the southern-most portion of its system. (EXH 142) As 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, staff recommends that the LNG facility is still needed for FCG to reliably serve its customers.

LNG Facility Cost and OPC Proposal

As part of the 2018 Settlement Agreement, the Commission has already approved the inclusion of $58 million in rate base for the LNG facility which no party disputes. However, 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. (TR 586-587) These increased project costs have been offset by $2.2 million in benefits from the sale of the original site. (TR 587)

Following approval of the LNG facility as part of the 2018 Settlement Agreement, FCG began the effort to secure an appropriate site for the LNG facility, which resulted in selection of the original site. The LNG facility was originally proposed to be located along and connected to FCG’s Jet Fuel Line to reinforce FCG’s system south of the Miami International Airport by providing extra capacity to serve customers at this portion of FCG’s system during times of high demand. (TR 582-583) However, the original site was located outside of the County’s urban development boundary and thus, only agricultural and agricultural accessory uses were permitted without first obtaining a special or unusual use zoning exemption. Therefore, FCG requested a formal opinion from the Miami-Dade County Planning Director to determine whether the development of an LNG facility would be suitable at the initial proposed site, and received a formal consistency determination from the County Planning Director on August 17, 2018. (EXH 156) Following this determination, FCG acquired the original site for the LNG facility, and began pursuing the permits and approvals needed for the site, including the special or unusual use zoning exemption from the County. Although FCG received support and recommendations of approval from County staff, the Community Council ultimately denied FCG’s special or unusual use zoning exemption request for the original site on June 5, 2019. (TR 606; EXH 155, 156)

As such, FCG determined that it would be most appropriate to sell the original site, and locate a new site. After reviewing over 100 potential parcels, FCG located a suitable site within the City of Homestead. (TR 607; EXH 139) After receiving positive feedback from the City of Homestead’s Planning Director, FCG proceeded with the submittal of a new zoning application in October 2020, and received approval from the Homestead City Council in July 2021. (TR 608) Staff notes that no party disputes the selection of the alternative site as an appropriate site to construct the LNG facility.

Although OPC witness Schultz acknowledged that the difficulties FCG experienced associated with obtaining the permits and approvals for the original site, the loss of the original site as a viable location, the need to sell the original site, and the need to secure a new site all contributed to the delay in constructing the LNG facility, witness Schultz recommended that the Commission disallow the additional cost of $10 million for the LNG facility because FCG failed to properly and prudently plan the project. (TR 295-296) Witness Schultz argued that it is not prudent to buy property zoned residential and plan industrial construction in the hopes that a zoning change will be allowed. (TR 296)

FCG witness Howard rebutted witness Schultz’s testimony by arguing that the original site for the LNG facility was not zoned as residential, but was zoned for agricultural and agricultural accessory uses. Witness Howard further argued that FCG did not acquire the original site in the hopes that the zoning for the site would be changed, but FCG undertook due diligence with the County Planning Director, as discussed above, regarding the consistency of the LNG facility within the established zoning requirements. (TR 607) Based on FCG’s description of and response to the obstacles encountered that led to the delay of the LNG facility and OPC’s acknowledgement of said obstacles, staff agrees with witness Howard that FCG has acted prudently. Staff is of the opinion that the Community Council’s decision to deny FCG’s zoning exemption request for the original site, as well as the amount of time this process, locating a new site, and acquiring the necessary approvals for the new site took to reach completion, was beyond FCG’s control. As such, staff recommends that the additional cost of $10 million for the LNG facility was prudently incurred.

In-Service Date Concerns

FCG projects an in-service date of March 2023 for the LNG facility. (TR 586) 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. (TR 293-296) 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 WACC that recognizes the cost carried in rates. (TR 296-297)

In response to discovery, FCG indicated that construction of the LNG facility began in June 2022. (EXH 139) In addition, FCG witness Howard testified that construction of the LNG facility is essentially complete, with LNG deliveries scheduled to commence in January 2023. (TR 655) 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.

Staff notes that 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.[22] 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, staff believes that it is reasonable to conclude that the LNG facility will be completed on or near the March 2023 in-service date. As such, staff recommends no adjustments to projected depreciation for the LNG facility.

LNG Facility Costs in Current Base Rates and OPC Refund Proposal

OPC witness Schultz testified that his understanding of FCG witness Howard’s testimony is that customers would not be paying for the LNG facility until it was in service. However, in response to discovery, witness Schultz asserted that FCG identified $29 million in current base rates associated with the LNG facility. (TR 293; EXH 161) Due to this and to avoid double recovery, witness Schultz recommended that any funds that have been collected from ratepayers related to the LNG facility be set aside in a regulatory liability and amortized back to ratepayers over five years. (TR 294)

FCG witness Fuentes rebutted witness Schultz’s testimony regarding this issue by asserting that OPC agreed to this ratemaking treatment as part of FCG’s 2018 Settlement Agreement. (TR 823) Due to this, 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 as this recommendation is in direct violation of the 2018 Settlement Agreement. (TR 824)

Staff notes that OPC admitted in its brief that some recovery for the LNG facility was allowed under the 2018 Settlement Agreement. (OPC BR 18) 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.[23] FCG’s updated total project cost estimate is $68 million. (TR 586) 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, staff agrees 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.

CONCLUSION

Staff recommends that the appropriate amount of plant in service for FCG’s delayed LNG facility, once it is placed in service, is $68 million.

Issue 13:

What is the appropriate level of plant in service for the projected test year?

Recommendation:

The appropriate level of plant in service for the projected test year is $643,079,704. (Gatlin, Thompson)

Position of the Parties

FCG:

As reflected in page 1 of MFR A-3 (with RSAM), the appropriate amount of plant in-service, including the gross amount of the acquisition adjustment, is $664,736,539 (adjusted) for the 2023 projected Test Year. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount of plant in service for the 2023 projected test year is also $664,736,539 (adjusted). (Campbell, Fuentes, Howard)

OPC:

OPC Witness Schultz’s testimony and exhibits demonstrate that the appropriate amount of plant-in-service to include in the projected test year should be no greater than $624,911,908. This includes an adjustment to remove $9,637,988 of overstated projected plant in service plus $460,884 of accumulated depreciation.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that the appropriate amount of plant in service for the projected test year of 2023 is $664,736,539 and that includes the gross amount of the acquisition adjustment. (FCG BR 35; EXH 2) FCG has projections to invest more than $290 million in infrastructure and other capital to support customer growth, enhance customer service, and enhance safety and reliability of its system. (FCG BR 35; TR 577-578; TR 1059-1060) FCG stated that it practices the same rigorous and long-standing processes used by Florida Power & Light Company for the development and approval of capital expenditure budgets, financial forecasts, and MFRs. (FCG BR 35; TR 1047-1048) FCG noted that none of the interveners disproved of the forecasting methodologies done by FCG. (FCG BR 35) FCG argued that by following its procedures it is able to secure the capital expenditures at the lowest reasonable cost including: competitive bidding, contractor quality assurance, and cost tracking. (FCG BR 35; TR 576) FCG explained that even with procedures in place to ensure low cost for capital expenditures cost of construction has 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. (FCG BR 36; TR 575-576) FCG recognized OPC’s recommendation of a reduction of nearly $9.6 million of plant in service, but argued that the reduction is exclusively based off of a three-year historical average from capital expenditures, plant additions, and plant in service. (FCG BR 36; TR 299-302) FCG acknowledged that the historical average is helpful to evaluate the reasonableness of a forecast, but argued it should not take precedent over a forecasted test year for a growing business in which the Company’s plant additions for the 2023 test year are considered prudent. (FCG BR 36-37; TR 1089)

OPC

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 BR 27; TR 299) 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 BR 28; TR 300) OPC noted that the 2022 budget-to-actual spending shows an overstatement averaging $36,954,004. (OPC BR 28; EXH 46) OPC acknowledged that un-reflected 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 BR 28; TR 301) 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, OPC recommends an adjustment. (OPC BR 28-29; TR 668-669) OPC recommended an adjustment to 2022 plant additions, by a reduction of $9,637,988. (OPC BR 28-29; TR 300-301; EXH 46) This reduction is based by subtracting the actual three-year average of plant additions from the estimated 2022 plant additions. (OPC BR 29; TR 300-301; EXH 46) 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 half of depreciation. (OPC BR 29; TR 300-301; EXH 46)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 6)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 6)

ANALYSIS

Although this issue is identified as a fallout issue, OPC’s concerns regarding FCG’s projected capital additions will also be addressed. OPC witness Schultz testified that FCG’s plant additions are overstated. (TR 299) 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. (TR 299) Witness Schultz continued that FCG having an approximate 67 percent increase in projected capital expenditures over the actual average is cause for concern. (TR 299-300) 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. (TR 300) OPC witness Schultz made a comparison between MFR Schedule G-1, Page 9 and the response provided by the Company in Interrogatory No. 5-164 and 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 the response provided in discovery. (TR 300; EXH 46) 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. (TR 301)

OPC requested a comparable summary with actuals by month for January to June 2022, and, according to OPC, the discovery response should have included SAFE plant in order for it to be comparable. (TR 301) FCG did not provide any more information to OPC in order to determine the cause of the overstatement. (TR 301) Witness Schultz argues that because the information provided does not allow for a complete analysis he recommends an adjustment for the 2022 plant additions by a reduction of $9,637,988. (TR 301-302) Witness Schultz explained the calculation for the reduction is by subtracting the actual three-year average of plant additions from the estimated 2022 plant additions. (TR 302). OPC reflected a corresponding reduction of $307,256 in depreciation expense and a $460,884 reduction to accumulated depreciation. (TR 302)

FCG argued that historical data is useful to evaluate the reasonableness of a forecast, but should not replace a forecast for a growing business. (TR 1089) In FCG witness Campbell’s rebuttal testimony, he responded that OPC witness Schultz should not have used historical averages because it is not representative of a prudent forecast for the projected test year and upon review it seems he used incomparable data for the historical periods. (TR 1106) Witness Campbell continued that witness Schultz used data from FEA’s first set of interrogatories No. 4 for capital expenditures and OPC’s first set of interrogatories Supplemental No. 87 for plant additions. In both of these responses, the data only provided retail base and does not include data for all clause investments. (TR 1106) OPC witness Schultz then utilized this data to compare the historical retail base capital expenditures and plant additions to the projected period amounts included in the MFR Schedule G-1. (TR 1106) However, the projected MFR Schedule G-1 are presented as company per book and include both base rate and clause investments, while the historical periods witness Schultz utilized only included base rate investments. (TR 1106) Witness Campbell recalculated the historical averages with the Company’s corrected adjustments as shown in the table below.

Table 13-1

FCG’s Corrections to Exhibit HWS-1 Schedule B4

Category	As Represented in HWS-2	Company’s Corrections	Total Amount Per Company
3-Yr Avg.—Capital Expenditures	$30,951,611	$12,479,341	$43,430,952
3-Yr Avg.—Plant Additions	$30,261,012	$11,773,794	$42,034,806
Difference—Actual & Projected Plant In Service[24]	($36,954,004)	$36,580,270	($373,733)

Source: TR 1107-1109

Witness Campbell applied witness Schultz’s methodology and determined that with the adjustments provided, there would be a $2,134,806 increase to plant-in-service, instead of the $9,637,988 decrease that witness Schultz recommended. (TR 1109-1110)

Staff does not believe any adjustments to the Company’s projected plant in service are necessary. Based on staff’s recommendations in previous issues, the appropriate level of plant in service for the projected test year is $643,079,704.

CONCLUSION

Based on staff’s recommendations in previous issues, the appropriate level of plant in service for the projected test year is $643,079,704.

Issue 14:

Has FCG made the appropriate adjustments to remove all non-utility activities from Plant in Service, Accumulated Depreciation, and Working Capital?

Approved Type II Stipulation:

FCG does not have any non-utility investments; no adjustments are necessary.

Issue 15:

Should any adjustments be made to the amounts included in the projected test year for acquisition adjustment and accumulated amortization of acquisition adjustment?

Recommendation:

Yes. In agreement with Generally Accepted Accounting Principles (GAAP), which directs an acquiring entity to write off any goodwill existing on the prior owner’s balance sheet at the time of acquisition, the entire acquisition adjustment should be removed as well as any amortization related to the acquisition adjustment. The acquisition adjustment should be decreased by $21,656,835 and the accumulated amortization of the adjustment should be decreased by $13,475,365. (Snyder, Harper)

Position of the Parties

FCG:

No. FCG has not requested approval or recovery of an acquisition adjustment related to the acquisition from Southern Company Gas in July 2018. Rather, FCG carried over FCG’s existing positive acquisition adjustment related to AGLR’s acquisition of FCG in 2004, which was approved by Commission Order No. PSC-07-0913-PAA-GU (“AGLR Order”). This acquisition adjustment survived a subsequent acquisition by Southern Company Gas and was addressed and resolved in FCG’s most recent base rate case. As a result, there is no need to make an adjustment to remove the approved AGLR acquisition adjustment from FCG’s 2023 Test Year. (Fuentes)

OPC:

Yes. The net unrecovered acquisition adjustment of $8,181,470 resulting from the original acquisition adjustment of $21,656,835 less the accumulated amortization of acquisition adjustment in the amount of $13,475,365 should be disallowed pursuant to existing Commission policy. Acquisition adjustments do not survive subsequent purchases of a utility’s assets. Amortization expense in the amount of $721,894 should also be removed from the test year net income.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that it carried over the amounts reflected in the balance sheet at the time of the acquisition from Southern Gas Company (Southern) in July 2018, as opposed to recording an acquisition adjustment from the transaction. (FCG BR 37-38) FCG noted that these amounts on the balance sheets already reflected an existing positive acquisition adjustment from FCG’s acquisition by AGL Resources (AGLR) in 2004. (FCG BR 38) The acquisition adjustment was approved by the Commission in Order No. PSC-07-0913-PAA-GU (AGLR Order).[25] (TR 817) In 2016, AGLR was acquired by Southern and, as a result, FCG became a subsidiary of Southern. (TR 817) FCG continued the amortization of the existing AGLR acquisition adjustment after the acquisition by Southern. (TR 818) FCG claimed that the permanence and continuation of the acquisition adjustment and related amortization were addressed in Docket No. 20170179-GU (2018 Rate Case), which was resolved through a settlement agreement (2018 Settlement Agreement).[26] (TR 817-818)

FCG argued against OPC’s claim that the previously approved AGLR acquisition adjustment and related accumulated amortization should be disallowed by stating that OPC ignored the evidence of what actually occurred. (FCG BR 38) FCG also showed that OPC did not propose any rate base or net operating income adjustments to remove the AGLR acquisition adjustment or its related accumulated amortization in the 2018 Rate Case. (FCG BR 39; TR 818; EXH 109) The Company stated that FCG’s AGLR acquisition adjustment already survived a subsequent acquisition by Southern in 2016. (TR 818) FCG stated that the continuation of the acquisition adjustment was addressed in the 2018 Rate Case, where it was not disallowed in the 2018 Settlement Agreement. (FCG BR 41)

Witness Fuentes stated that while the settlement contained no reference to the acquisition adjustment in question, FCG responded to Staff’s First Data Request on Stipulation and Settlement No. 2 in Docket No. 20170179-GU (“Staff’s 2018 Settlement Data Request”) regarding FCG’s intent for the continued recovery of the AGLR acquisition adjustment in base rates. (TR 819) The data request in question asked, “does FCG believe that this Stipulation and Settlement Agreement fulfills its obligation to demonstrate to the Commission the prudence of the Acquisition Adjustment?” (TR 819; EXH 108). FCG responded:

While the Stipulation and Settlement does not specifically address the Acquisition Adjustment, the Company provided the testimonies of Witnesses Kim and Bermudez in support of the continued prudence of the Acquisition Adjustment. To the extent that no intervenor party provided testimony recommending an adjustment to the unamortized amount associated with the Acquisition Adjustment, and the Settlement and Stipulation does not contain a specific adjustment to the remaining unamortized amount associated.

On cross-examination during the hearing, witness Fuentes cited Order No. PSC-03-0038-FOF-GU, as an example of an acquisition adjustment that survived a subsequent acquisition.[27] (TR 936-937) In the Order, an acquisition adjustment related to Peoples Gas System’s (PGS) acquisition of Southern, as approved in Order No. 23858, was continued after Tampa Electric Company’s acquisition of Southern.[28]

FCG noted that OPC referred to two water and wastewater utility orders to suggest that the Commission has a policy of acquisition adjustments not surviving subsequent purchases of a utility’s assets. (FCG BR 40; TR 290-291) FCG claimed that OPC’s reliance on the orders is misplaced and show no Commission policy regarding acquisition adjustments. (FCG BR 40) FCG included the $21.7 million AGLR acquisition adjustment and related accumulated amortization of $13.5 million in rate base, and $0.7 million of amortization expense in net operating income in the 2023 Test Year. (EXH 8) FCG claimed this treatment is consistent with the AGLR Order and the 2018 Settlement Agreement. (TR 820)

OPC

OPC stated that the Commission has an established policy that acquisition adjustments resulting from previous transactions do not survive subsequent purchases of a utility’s assets. (OPC BR 29). OPC also claimed that FCG failed to provide proof of why it should be allowed to recover the acquisition premium against the Commission policy. (OPC BR 30) 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. (TR 934) Order No. PSC-00-1165-PAA-WS stated that “acquisition adjustments do not survive subsequent purchases of the utility’s assets.”[29] Order No. PSC-05-1242-PAA-WS stated that “consistent with prior Commission decisions, acquisitions adjustments do not survive subsequent transfers.”[30]

OPC stated that FCG’s entire argument seems to rest on a perceived oversight by OPC when it failed to challenge the expired ALGR acquisition adjustment in the 2018 Rate Case. (OPC BR 30; TR 818) OPC further stated that FCG asked the Commission to heavily consider a submission of a discovery response provided by Southern Company at a time the company knew—but did not disclose to parties or the Commission—that Southern Company and NextEra Energy (NEE) were engaged in negotiations for FCG to be sold to NEE. (OPC BR 31; TR 918; EXH 108,192) OPC noted that NEE appears to have absorbed a very large acquisition premium associated with the 2018 acquisition that has not been recorded on the books of FCG. (OPC BR 33)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 6)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 6)

ANALYSIS

The acquisition adjustment at issue in this proceeding relates to the acquisition of FCG by AGLR in 2004, which was approved by the Commission in Order No. PSC-07-0913-PAA-GU, in Docket No. 20060657-GU AGLR Order.[31] (TR 817) The Commission approved the acquisition adjustment and required the review of the savings that supported the acquisition adjustment in the next rate proceeding. (TR 817-818) 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.[32] 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.[33]

Since the Commission approved the acquisition adjustment, the utility has changed ownership twice. In 2016, AGLR was acquired by Southern Gas Company (Southern). (TR 817-818) The Company was later acquired by NEE, the parent company of Florida Power & Light Company (FPL) in 2018. FCG continues to amortize the AGLR acquisition adjustment approved in 2007. (TR 817-18)

The permanence of the acquisition adjustment has never been a litigated issue in any proceeding since it was approved in 2007. FPL witness Fuentes acknowledged that the 2018 Settlement Agreement did not address the acquisition adjustment and argued the acquisition adjustment should be permanent because OPC did not propose an adjustment in the 2018 Rate Case. (TR 818-819; EXH 108, 109)

Witness Schultz testified that the achievement of the five factors is not relevant in the instant case because the Company has since been acquired by NEE and transferred to FPL. Staff agrees with OPC witness Schultz that the five factors for reviewing an acquisition adjustment should not be at issue in this proceeding. (TR 289) Instead, the Commission should rely on its past decisions where the Commission refused to allow acquisition adjustments to survive subsequent purchases by new owners.[34]

Staff agrees with OPC’s position, as stated when the Commission reviewed the Florida Water transfer to Aqua Utilities:

There are many items which belong to a particular system being sold that do not transfer to the new owner. One particular example is the prior owner’s equity in the assets. The level of equity and debt financing to be reflected on the ongoing utility’s books will be based on the buyer’s management decisions. Other examples of assets that do not transfer include an acquisition adjustment from the prior owner’s purchase of the assets or deferred income taxes relative to the held assets (for example Financial Accounting Standard Board (FASB) 142, Goodwill.)

Order No. PSC-05-1242-PAA-WS, at page 8.

In the PGS Orders cited by witness Fuentes, the issue of whether an acquisition adjustment survived an acquisition was not discussed or addressed. (TR 936-937) In Order No. PSC-2018-0566-FOF-EU, the Commission stated that “a positive acquisition adjustment is considered goodwill or going–concern value for accounting purposes.”[35] Under GAAP (e.g., Accounting Standards Codification (ASC) 350, entitled Intangibles – Goodwill and Other) any goodwill existing on the prior owner’s balance sheet at the time of acquisition is written off by the acquiring entity. (EXH 152 BSP 627) After FPL acquired FCG, FCG’s debt and equity accounts were affected by the acquisition but the acquisition adjustment remained. (EXH 186-187) As discussed in Issue 28, FCG has proposed to use the 59.6 percent equity ratio of its current parent, FPL, in the instant case. (TR 1069) Staff has recommended the 59.6 percent equity ratio of FPL, not the 44 percent equity ratio maintained by FCG’s prior owner, be recognized for ratemaking purposes going forward. As such, staff recommends the entire acquisition adjustment be removed as well as any amortization expense related to the acquisition adjustment. The acquisition adjustment should be decreased by $21,656,835 and the accumulated amortization of the acquisition adjustment should be decreased by $9,264,312.

CONCLUSION

In agreement with GAAP, which directs an acquiring entity to write off any goodwill existing on the prior owner’s balance sheet at the time of acquisition, the entire acquisition adjustment should be removed as well as any amortization related to the acquisition adjustment. The acquisition adjustment should be decreased by $21,656,835 and the accumulated amortization of the adjustment should be decreased by $13,475,365.

Issue 16:

What is the appropriate level of CWIP to include in the projected test year?

Approved Type II Stipulation:

The appropriate amount of CWIP is $28,192,440 for the 2023 projected test year.

Issue 17:

What is the appropriate level of Gas Plant Accumulated Depreciation and Amortization for the projected test year?

Recommendation:

The appropriate level of Gas Plant Accumulated Depreciation and Amortization is $209,484,638. (Hinson)

Position of the Parties

FCG:

As reflected on page 1 of MFR A-3 (with RSAM), the appropriate amount of Accumulated Depreciation with RSAM, including accumulated amortization associated with the acquisition adjustment, is $221,380,711 (adjusted) for the 2023 Test Year. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount of Accumulated Depreciation without RSAM, including accumulated amortization associated with the acquisition adjustment, is $222,960,003 (adjusted) for the 2023 Test Year as reflected on page 1 of MFR A-3. (Campbell, Fuentes)

OPC:

OPC Witness Schultz addresses this in his testimony and exhibits including, but not limited to, EX 46, Schedule B. The appropriate level of Accumulated Depreciation and Amortization for the projected test year should be at least $208,172,408.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that the appropriate amount of Accumulated Depreciation, including accumulated amortization associated with the acquisition adjustment, for the projected test year is $221,380,711, with RSAM, and $222,960,003, without RSAM. (FCG BR 42; EXH 7, P 1-2) FCG argued that OPC’s recommended $13.2 million adjustment to Accumulated Depreciation is unsupported, inappropriate, and should be rejected. (FCG BR 42; EXH 2)

OPC

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. (OPC BR 34; EXH 46, P 4).

FEA

FEA did not provide an argument. (FEA & FIPUG BR 7)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 7)

ANALYSIS

This is a fallout issue. Based on staff’s recommendation in Issue 5 regarding the Company’s Depreciation Study and Issue 15 regarding the Company’s acquisition adjustment, the appropriate level of Gas Plant Accumulated Depreciation and Amortization is $209,484,638.

CONCLUSION

The appropriate level of Gas Plant Accumulated Depreciation and Amortization is $209,484,638.

Issue 18:

Have under recoveries and over recoveries related to the Purchased Gas Adjustment, Energy Conservation Cost Recovery, and Area Expansion Plan been appropriately reflected in the Working Capital Allowance?

Approved Type II Stipulation:

Yes.

Issue 19:

Should the unamortized balance of Rate Case Expense be included in Working Capital and, if so, what is the appropriate amount to include?

Recommendation:

No, staff recommends removing the unamortized balance of Rate Case Expense included in Working Capital. As such, Working Capital should be decreased by $1,742,227. (Hinson)

Position of the Parties

FCG:

Yes. The inclusion of the unamortized balance of rate case expenses of $1,645,732 (as reflected on Exhibit LF-7) for the 2023 projected test year in Working Capital is appropriate in order to avoid an implicit disallowance of reasonable and necessary costs. Full recovery of necessary rate case expenses is appropriate but will not occur unless FCG is afforded the opportunity to earn a return on the unamortized balance of those expenses. (Fuentes)

OPC:

No, unamortized rate case expense should not be included in working capital for a gas company pursuant to Commission policy. OPC’s adjustments to rate case expense are explained in Issue 47.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

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 BR 43; EXH 107) Full recovery of necessary Rate Case Expense is appropriate but will not occur unless FCG is afforded the opportunity to earn a return on the unamortized balance of those expenses. (FCG BR 42)

In rebuttal, FCG updated its estimated rate case expense to $1.9 million reflecting a reduction of $0.1 million from the original estimate. The unamortized 13-month average balance to be included in Working Capital is $1.6 million resulting in a reduction of $96,000 from FCG’s original estimate. (TR 816; EXH 107; FCG BR 43)

Additionally, FCG stated that no parties introduced any testimony or evidence that raised concern with FCG’s proposal to include the unamortized Rate Case Expense in rate base. (TR 815; FCG BR 43). FCG opines that OPC asserted in its Prehearing statement that unamortized Rate Case Expense should not be included in Working Capital pursuant to Commission policy. (FCG BR 43). In response to OPC's assertion, FCG stated that OPC’s witness disagreed. (FCG BR 43) 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; therefore, OPC witness Schultz agreed that the recovery of the unamortized Rate Case Expense should be in Working Capital. (TR 319; EXH 46; FCG BR 43) FCG stated requesting a four-year rate plan in this proceeding reduces the amount of Rate Case Expense FCG would otherwise incur for multiple, back-to-back rate cases. (TR 794-795; FCG BR 43). FCG asked that it be remembered that FCG is a regulated entity and must seek rate relief through the rate case process, which is laborious and expensive. (FCG BR 43) FCG asserted that the rate case process does not only address return for shareholders, but all components of ratemaking, which include the recovery of prudent investments and expenses incurred for the benefit of FCG’s customers. (FCG BR 43) FCG submitted that it is appropriate to include the unamortized Rate Case Expense in Working Capital. (FCG BR 43-44)

OPC

OPC stated that unamortized Rate Case Expense should not be included in Working Capital for a gas company pursuant to Commission policy. (OPC BR 34) OPC’s adjustments to Rate Case Expense are explained in Issue 47. (OPC BR 34)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 7)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 7)

ANALYSIS

FCG requested that the 13-month average of unamortized Rate Case Expense be allowed in Working Capital. (TR 794; EXH 7) 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.” (TR 794) 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. (TR 795) As noted by FCG witness Fuentes, neither OPC nor FEA took issue with allowing unamortized Rate Case Expense in Working Capital in the direct testimony filed by each party. (TR 815)

However, OPC did take issue with the amount of unamortized Rate Case Expense included in Working Capital. (TR 319) Alternatively, OPC contended in its brief that FCG should not be able to include unamortized Rate Case Expense in Working Capital pursuant to Commission policy and that the adjustment was explained in its analysis of Issue 47. (OPC BR 34) OPC witness Schultz calculated deferred Rate Case Expense in rate base for Working Capital and the deferred rate case amount proposed by witness Schulz remained in Issue 47 of OPC’S brief. (TR 319; OPC BR 55)

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.[36] 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.[37] The Commission further noted that the difference in water and wastewater cases, which at the time included unamortized rate case expense in working capital, stemmed from a statutory requirement that water and wastewater utilities reduce rates after the amortization period of rate case expense, which is not done in electric and gas cases. The Order also cited other electric and gas rate cases where the Commission denied unamortized Rate Case Expense in Working Capital.[38]

However, there are also electric and gas rate cases which reflect the Commission’s allowance of one-half of Rate Case Expense in Working Capital.[39] In Florida Public Utilities Company’s 1993 Rate Case, the Commission recognized and concluded that if Rate Case Expense is prudent and reasonable, the Company should be allowed to earn a return on investment on the unamortized balance, as it is a cost of doing business in the regulated arena.[40] The Company did not cite any Commission Orders that reflect the allowance of the full amortized balance of Rate Case Expense in Working Capital. Based on staff’s review, there are no Commission Orders reflecting the full allowance.

In light of the multiple Commission decisions reflecting both exclusion and inclusions of half, staff recognizes the complicated nature and history of this issue. FCG’s request to include the full unamortized amount departs from both Commission practices. Yet the Company provided very little justification for doing so beyond asserting its position that disallowance prevents the Company from fully recovering all necessary and reasonable costs. Staff believes FCG has not met the burden to support the inclusion of any unamortized Rate Case Expense in Working Capital and recommends the full disallowance. As such, Working Capital should be decreased by $1,742,227.

OPC

OPC did not proffer a specific argument in its post-hearing brief. OPC witness Garrett asserted that the appropriate ratio of short-term debt in the projected test year capital structure is 4.13 percent. (TR 335) 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. (EXH 46, Schedule D) OPC did not object to FCG’s cost rate of 1.78 percent for short-term debt. (OPC BR 36; TR 335)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 8)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 8)

ANALYSIS

Both FCG and OPC agree the appropriate cost rate for short-term debt is 1.78 percent. (FCG BR 47; OPC BR 36) Staff reviewed FCG’s estimate for the short-term debt cost rate based on LIBOR as provided in FCG’s response to staff’s request for production of documents No. 10 and believes it to be reasonable. (EXH 151) The recommended amount of short-term debt in the projected test year capital structure, without RSAM, differs slightly between FCG’s and OPC’s recommendations. (EXH 112, Page 3; EXH 46, Schedule D) FPL provides all the investor-provided capital to FCG at the capital structure ratios of FPL. (TR 1068-1069) 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. (EXH 7, Schedule G-3) After reconciliation with all capital structure components, the ratio of short-term debt in the projected test year capital structure is 4.13 percent. (EXH 7, MFR Schedule G-3, Page 2 of 11) This ratio equates to a short-term debt balance of $20,141,146 without RSAM. (EXH 7, MFR Schedule G-3, Page 2 of 11) FCG subsequently recalculated its revenue requirement which included a reduction to its requested rate base for the projected test year. (TR 782-786; EXH 112, Page 3) As a result, the rate base was reduced by $96,495, which resulted in a corresponding reduction to short-term debt of $3,987. (EXH 112, Page 3) FCG’s final amount of short-term debt included in its projected test year capital structure was $20,137,159 without RSAM. (EXH 112, Page 3) OPC witness Garrett recommends a ratio of 4.13 percent for short-term debt in the projected test year capital structure. (TR 335; EXH 65) 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. (EXH 46, Schedule D) In Issue 23, staff is recommending a total rate base amount of $477,497,041. When this amount is reconciled pro rata over all capital sources to staff’s recommended capital structure, the corresponding amount of short-term debt based on a ratio of 4.13 percent is $19,730,996.

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 staff believes it to be a reasonable rate. Based on the aforementioned, staff recommends the appropriate amount and cost rate for short-term debt to include in the projected test year capital structure ending December 31, 2023, is $19,730,996, at a cost rate of 1.78 percent.

Issue 26:

What is the appropriate amount and cost rate for long-term debt to include in the projected test year capital structure?

Recommendation:

The appropriate amount of long-term debt to include in the projected test year capital structure ending December 31, 2023, is $150,425,423, at a cost rate of 4.28 percent. (D. Buys)

Position of the Parties

FCG:

As reflected in Exhibit LF-11, the appropriate amount and cost rate for long-term debt with RSAM for the 2023 projected test year is $154,025,674 (adjusted) and 4.28%, respectively. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount and cost rate for long-term debt without RSAM for the 2023 projected test year is $153,521,933 (adjusted) and 4.28%, respectively, as reflected in Exhibit LF-12. (Fuentes, Campbell)

OPC:

The appropriate amount of long term debt is $194,277,560 and the cost rate is 4.28%. EXH 46, Schedule D; EXH 65.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued the appropriate amount and cost rate for long-term debt with RSAM for the projected test year is $154,025,674 (adjusted) and 4.28 percent, respectively. (FCG BR 48; EXH 111) FCG asserted that it utilized FPL’s long-term debt cost because, pursuant to Commission-approved financing orders, FCG obtains 100 percent of its debt and equity financing from FPL and the interest rate on any long-term borrowings by FCG from FPL is a pass-through of FPL’s weighted cost for borrowing these funds. (FCG BR 48) FCG argued it does not issue its own debt or equity and, pursuant to Commission-approved financing orders,[42] 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 BR 48; TR 1068-1069.) 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. (TR 1114) 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. (FCG BR 48; EXH 46, Schedule D)

OPC

OPC did not proffer a specific argument in its post-hearing brief. OPC recommended an increase of $54.6 million in long-term debt to reflect OPC’s proposed capital structure. (FCG BR 48; EXH 46, Schedule D) OPC also recommended an additional decrease of $13.8 million in long-term debt based on OPC witness Schultz’s recommended rate base adjustments. (FCG BR 48; EXH 46, Schedule D) OPC witness Garrett asserted 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. (TR 411) Witness Garrett opined an insufficiently low debt ratio causes the weighted average cost of capital to be unreasonably high. (TR 411) Based on his findings, witness Garrett recommended the Commission impute a capital structure for ratemaking purposes consisting of long-term debt of 51.3 percent. (TR 411-412)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 8)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 8)

ANALYSIS

Both FCG and OPC agree the appropriate cost rate for long-term debt is 4.28 percent. (FCG BR 48; TR 1069; EXH 112; TR 335; EXH 65) 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. (TR 1068-1069) 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. (EXH 7, MFR Schedule G-3; EXH 112) After reconciliation with all capital structure components, the ratio of long-term debt in the projected test year capital structure is 31.50 percent. (EXH 7, MFR Schedule G-3, Page 2 of 11) This ratio equates to a long-term debt balance of $153,552,232 without RSAM. (EXH 7, MFR Schedule G-3, Page 2 of 11) FCG subsequently recalculated its revenue requirement which included a reduction to its requested rate base for the projected test year. (TR 782-786; EXH 112, Page 3) As a result, the rate base was reduced by $96,495, which resulted in a corresponding reduction to long-term debt of $30,399. (EXH 112, Page 3) FCG’s adjusted amount of long-term debt included in its projected test year capital structure was $153,521,933 without RSAM. (EXH 112, Page 3)

OPC recommends the Commission reject FCG’s requested long-term debt ratio of 31.50 percent (40.4 percent from investor sources only) and impute a debt ratio equal to that based on the average debt ratio of the proxy group of companies used to determine an appropriate ROE. (TR 335) OPC witness Garrett opined that his analysis strongly indicates that FCG’s proposed long-term debt ratio of 40.4 percent based on investor sources is too low to be considered fair for ratemaking. (TR 408, 411) Witness Garrett asserted 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. (TR 411-412) 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 in his Exhibit HWS-2 attached to his direct testimony. (EXH 46, Schedule D) When OPC’s recommended capital structure is reconciled 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 is $194,277,560. (EXH 46, Schedule D)

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. (TR 411; EXH 46, Schedule D) In rebuttal, FCG witness Nelson contended that increasing the Company’s financial leverage by reference to the 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. (TR 148)

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 to FCG. (TR 1069) 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 BR 48; TR 1069) FCG’s cost projections for FCG’s long-term borrowings from FPL are shown in MFR G-3, Page 3. (TR 1069; EXH 7, MFR Schedule 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. (TR 1069; EXH 7, MFR Schedule G-3, Page 3) Staff reviewed the aforementioned MFR Schedules and believe the projected long-term debt cost rate of 4.28 percent is reasonable. In Issue 23, staff is recommending a total rate base amount of $477,497,041. When this amount is reconciled pro rata over all capital sources to staff’s recommended capital structure, the corresponding amount of long-term debt based on a ratio of 31.50 percent is $150,425,423.

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 staff believes 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 $150,425,423 at a cost rate of 4.28 percent.

Issue 27:

What is the appropriate amount and cost rate for customer deposits to include in the capital structure?

Recommendation:

The appropriate amount and cost rate for customer deposits to include in the projected test year capital structure is $3,710,465 at a cost rate of 2.64 percent. (D. Buys)

Position of the Parties

FCG:

As reflected in Exhibit LF-11, the appropriate amount and cost rate for customer deposits with RSAM for the 2023 test year is $3,799,283 (adjusted) and 2.64%, respectively. If the Commission does not adopt the RSAM as part of FCG’s four year rate proposal, the appropriate amount and cost rate for customer deposits without RSAM for the 2023 test year is $3,786,845 (adjusted) and 2.64%, respectively, as reflected in Exhibit LF-12. (Fuentes, Campbell)

OPC:

The appropriate amount of customer deposits is $3,535,924 and the cost rate is 2.64%.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued the appropriate amount and cost rate for customer deposits with RSAM for the 2023 Test Year is $3,799,283 (adjusted) and 2.64 percent, respectively. (FCG BR 49; EXH 111, P 3) 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. (FCG BR 49)

OPC

OPC did not proffer an argument 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. (TR 335) 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. (EXH 46, Schedule D) OPC recommended a customer deposit balance of $3,535,924 at a cost rate of 2.64 percent. (OPC BR 36; EXH 46, Schedule D)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 32)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 32)

ANALYSIS

Both FCG and OPC agree the appropriate cost rate for customer deposits is 2.64 percent. (FCG BR 48; OPC BR 36) Both FCG and OPC agree on the ratio of 0.78 percent for customer deposits to include in the projected test year capital structure. (EXH 112, Page 3; TR 335; EXH 46, Schedule D) FCG did not provide testimony specific to the amount of customer deposits to include in the test year capital structure. FCG witness Campbell testified the components are found in MFR Schedule G-3, page 2. (TR 1070; EXH 7, Schedule G-3) FCG calculated the customer deposit balance and effective cost rate in MFR Schedule G-3, page 7 of 11. (EXH 7) Staff reviewed FCG’s calculations and believe they are reasonable. FCG recalculated its base revenue requirement which resulted in a corresponding adjustment to the original customer deposit balance filed in MFR Schedule G-3. (TR 828; EXH 111, 112) FCG’s adjustment resulted in an adjusted balance for customer deposits of $3,799,283 with the RSAM. (TR 828; EXH 111)

If the Commission does not adopt the RSAM as part of FCG’s four year rate proposal, the appropriate amount and cost rate for customer deposits without RSAM for the projected test year is $3,786,845. OPC recommended a customer deposit balance of $3,535,924 be included in the projected test year capital structure. (EXH 46, Schedule D) The difference in the parties’ recommended customer deposit amounts arises from OPC’s recommendation to make adjustments to reduce rate base and reconcile the lower rate base amount pro rata over all capital sources, which by function of math, lowers the customer deposit balance proportionately. In Issue 67, staff is recommending the Commission deny FCG’s RSAM proposal. In Issue 23, staff is recommending a total rate base amount of $477,497,041. When this amount is reconciled pro rata over all capital sources to staff’s recommended capital structure, the corresponding amount of customer deposits based on a ratio of 0.78 percent is $3,710,465.

CONCLUSION

No parties objected to the ratio for customer deposits of 0.78 percent to use in the projected capital structure nor the cost rate of 2.64 percent. Based on the aforementioned, the appropriate amount and cost rate for customer deposits to include in the projected test year capital structure is $3,710,465 at a cost rate of 2.64 percent.

Issue 28:

What is the appropriate equity ratio to use in the capital structure for ratemaking purposes?

Recommendation:

The appropriate equity ratio is 59.6 percent as a percentage of investor-supplied capital. (D. Buys)

Position of the Parties

FCG:

FCG’s equity ratio should be 59.6% based on investor sources. This is appropriate due to the fact that FCG does not issue its own debt or equity and obtains all short- and long-term financing through its parent, FPL pursuant to Commission-approved Financing Applications. (Campbell, Nelson)

OPC:

The Commission should authorize an equity ratio of no more than 46.9%.

FEA:

Mr. Walters’ testimony states that a common equity ratio of no higher than 50% is fair, reasonable, and more consistent with the capital structures of the proxy group used to estimate FCG’s cost of equity.

FIPUG:

Join position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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. (FCG BR 49; TR 1069) FCG asserted it does not issue its own debt or equity and obtains all of its debt and equity financing from FPL. (FCG BR 49; TR 1068-1069) FCG argued that because it receives all of its debt and equity financing directly from FPL, mirroring FPL’s approved equity ratio is appropriate. (FCG BR 49) FCG opined that its proposal to use the capital structure of its parent is fully consistent with FCG’s proposal in FCG’s 2018 rate case in Docket No. 20170179-GU. (FCG BR 49-50; TR 1068) FCG also argued the Commission has previously approved the use of a parent company’s capital structure where the regulated utility operates as a division and/or does not issue its own debt. (FCG BR 50; TR 114) FCG argued 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 is consistent with industry practice. (FCG BR 50; TR 114) FCG argued that although FCG’s proposed equity ratio is slightly higher than the mean and median three-year average equity ratio of the gas utilities in the proxy group, it is still within the proxy group range and appropriately accounts for the business risks that are unique to FCG. (FCG BR 50; TR 154, 158) FCG argued that OPC’s recommended equity ratio of 48.70 percent (excluding short-term debt) is flawed and should be rejected for several reasons. (FCG BR 51; EXH 46, Schedule D) FCG argued OPC witness Garrett relied on the result of his analysis of the equity ratios of companies in other industries and did not include the natural gas utility sector in the industries he analyzed. (FCG BR 51; TR 405-406) FCG argued witness Garrett improperly used the debt ratio data at the publicly traded holding company level to evaluate the reasonableness of FCG’s requested capital structure, as it itself is not publicly traded. (FCG BR 51; TR 155) FCG argued OPC witness Garrett’s theory that low-risk industries should have higher debt ratios was refuted by FCG witness Nelson who determined that industries of higher risk correspond to higher debt ratios, not lower as OPC witness Garrett suggested. (FCG BR 51; TR 156-157; EXH 125) FCG argued FEA witness Walters reviewed recent authorized equity ratios and the capital structures at the publicly traded holding company level and recommended an equity ratio no higher than 50 percent based on the presumption that FCG should be financed with the same proportions of equity and debt as the “average” natural gas utility in 2021. (FCG BR 52; TR 436) FCG argued that setting the authorized capital structure based on annual averages implies all utilities should be financed as an average utility and assumes that all utilities have the same risks and underlying assets and should be financed with the same proportions of equity and debt, which is clearly not the case. (FCG BR 52; TR 154-155) For these reasons FCG argued, the Intervenors’ recommendations should be rejected, and FCG’s requested capital structure including an equity ratio of 59.6 percent should be approved. (FCG BR 52)

OPC

OPC argued that witness Garrett’s recommended 53.1 percent 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 BR 38; TR 328, 412; EXH 65) 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 BR 36; TR 402) OPC argued 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 BR 36; TR 402) OPC argued that there is no merit to FCG’s assertion that an equity ratio of 59.6 percent is appropriate since it is the same as its parent, FPL. (OPC BR 37) OPC opined that regulators generally establish capital structures for utilities based on the operational and market risk factors that apply to the individual utility, that is, electric utility companies like FPL face different market risks and pressures than do gas utility companies, such as FCG. (OPC BR 37; TR 410) OPC asserted that while FPL has maintained its equity ratio between 59-60 percent for over two decades, FCG’s equity ratio for the last twenty years averages to be less than 44 percent. (OPC BR 37; TR 410-411) OPC asserted rather than explaining why the Intervenors’ recommend use of the average equity ratio of the gas utility proxy group is flawed and illogical, witness Nelson merely claimed that “utility capital structures vary wildly,” which in fact is precisely why the Intervenors’ recommendations based on an average equity ratio are logical. (OPC BR 38; TR 149)

FEA

FEA argued FCG’s requested common equity ratio of 59.6 percent is not appropriate and should be rejected. (FEA & FIPUG BR 9) FEA argued FCG’s proposed common equity ratio 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 & FIPUG BR 9; TR 440, 456) 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 of 38.6 percent. (FEA & FIPUG BR 9; TR 457) 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. (FEA & FIPUG BR 9)

FIPUG

FIPUG joined the arguments of FEA. (FEA & FIPUG BR 9)

ANALYSIS

FCG

In its filing, FCG requested a projected test year capital structure consisting of an equity ratio of 59.6 percent based on investor-supplied capital for rate setting purposes. (EXH 7; Schedule G-3) 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. (TR 1068) The revenue requirement associated with increasing the equity ratio from 48 percent to 59.6 percent is approximately $4.1 million. (TR 1060) FCG 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. (FCG BR 52; TR 158-159) FCG argued its requested equity ratio is reasonable compared to the range of equity ratios for the regulated natural gas operating companies held by the publicly traded gas companies in the proxy group as well as to authorized equity ratios for natural gas utilities in other jurisdictions. (FCG BR 52) 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. (TR 115; EXH 39) 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. (TR 115) Therefore, FCG concluded its requested equity ratio of 59.60 percent is within the proxy group range and consistent with industry practice. (FCG BR 52; TR 115) FCG further asserted 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. (FCG BR 52; TR 158-159)

OPC

OPC witness Garrett used the same gas utility proxy group as that of FCG witness Nelson for his cost of capital analysis. (TR 404) Witness Garrett opined that the capital structures of the proxy group can be used to assess a fair rate making equity ratio for FCG. (TR 403) Witness Garrett 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. (TR 404-405; EXH 62) 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). (TR 405-406) From his comparison of other non-regulated industries, witness Garrett concluded the debt ratios of other industries are higher than that of the gas utility proxy group (53.1 percent) and FCG’s proposed debt ratio of 40.4 percent. (TR 407) 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. (TR 410) OPC argued that regulators generally establish capital structures for utilities based on the operational and market risk factors that apply to the individual utility. (OPC BR 37; TR 410) 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 59-60 percent for over two decades. (TR 410) OPC argued that unlike FPL, FCG has maintained an equity ratio of just over 43 percent for the past twenty years, and has been 48 percent since only mid-2018 when FCG was a subsidiary of Southern Company Gas. (OPC BR 37; TR 410) 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. (TR 411) Based on witness Garrett’s testimony, OPC recommended an equity ratio of 46.9 percent from investor-supplied capital with is consistent with the gas utility proxy group average. (OPC BR 38)

FCG argued OPC witness Garrett’s analysis of the average equity ratio for the gas utility proxy group was flawed. (FCG BR 51; TR 148) FCG witness Nelson disagreed with witness Garrett’s approach to calculate the average equity ratio of the gas utility proxy group and testified that 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. (TR 148) 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. (FCG BR 50; TR 148) Witness Nelson asserted the Intervenor witnesses recommended increasing FCG’s financial leverage by reference to the publicly traded holding companies and other industry capital structures, which would increase FCG’s financial risk and, in turn, its cost of capital to the detriment of customers. (FCG BR 50-51; TR 148)

FEA

FEA argued FCG’s proposed equity ratio significantly exceeds the equity ratio for the gas utility proxy group. (TR 456) FEA witness Walters used the same gas utility proxy group as FCG witness Nelson and OPC witness Garrett. (TR 456) Witness Walters testified that the gas utility proxy group has an average equity ratio of 38.6 percent (including short-term debt), based on data from S&P Global Market Intelligence and 44.6 percent (excluding short-term debt) based on data from Value Line Investment Survey. (TR 456-457; EXH 81) Based on that analysis, witness Walters recommends an equity ratio of no higher than 50.0 percent. (TR 457) 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. (TR 502-503; TR 114-115) Witness Walters asserted that in a in a recent CenterPoint Energy gas rate case (Docket G-008/GR 15-424), the Minnesota Public Utilities Commission authorized a stated capital structure of 50.0 percent common equity, compared to CenterPoint’s requested 53.43 percent common equity ratio. Witness Walters testified that in its Order dated June 3, 2016, adopting a 50.0 percent common equity ratio, the Minnesota Public Utilities Commission stated that:

The Company argued that simply being within the range of the equity ratios in the proxy groups was adequate evidence of reasonableness, but the Commission does not agree. Proxy-group averages have much higher probative value than proxy-group ranges; the purpose of a proxy group is to provide a representative average or composite to stand in for the company being studied.[43]

(TR 503; EXH 180)

FCG witness Nelson disagreed with the Minnesota Public Utilities Commission’s finding cited by witness Walters and testified that, “The mere fact that a utility’s capital structure deviates from the average does not automatically demonstrate that it is unreasonable.” (TR 155) Witness Nelson opined that setting utility capital structures to the average assumes that all utilities have the same risks and underlying assets and should be financed with the same proportions of equity and debt, which is clearly not the case. (FCG BR 52; TR 155) Witness Nelson also disagreed with the Intervenor witnesses’ reliance on the average capital structure of the gas utility proxy group only during calendar year 2021. (TR 152-153) Witness Nelson pointed out that it is preferable to use data over several periods to avoid misleading conclusions from anomalies in the data. (TR 115, 153) For example, in 2021 two of the six gas utilities in the proxy group, Atmos Energy and ONE Gas, Inc., each reported more than $2 billion in additional natural gas commodity costs attributed to Winter Storm Uri which impacted their Texas service territories in February 2021. (TR 151-152) As a result, both companies’ capital structures included more debt than usual due to the unforeseen winter weather event which increased their debt ratios and skewed the capital structure data used by witness Walters. (TR 152-153) Witness Nelson asserted that adverse 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. (TR 152)

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. Further, the equity ratio and allowed return on equity are inextricably related. Based on the risk-return paradigm which is discussed in more detail in Issue 29, a company with a higher equity ratio in its capital structure, all else being equal, will have less financial risk and should have a comparatively lower return on equity. The higher the proportion of equity, the lower the financial risk which must be factored into the allowed return on equity as addressed by staff in Issue 29. Accordingly, staff recommends the appropriate equity ratio is 59.6 percent as a percentage of investor-supplied capital.

Issue 29:

What is the appropriate authorized return on equity (ROE) to use in establishing FCG’s projected test year revenue requirement?

Recommendation:

The appropriate authorized ROE midpoint is 10.00 percent with a range of plus or minus 100 basis points. (D. Buys)

Position of the Parties

FCG:

The Commission should authorize 10.75% as the return on common equity. Granting FCG’s requested return on equity will appropriately take into account FCG’s unique risk profile and the Company’s commitment to a strong financial position. The requested rate also addresses the risk of the Company’s proposed multi-year stay-out. Granting FCG’s requested return on common equity is critical to maintaining FCG’s financial strength and flexibility and will help FCG attract capital necessary to serve its customers on reasonable terms. (Nelson, Campbell)

OPC:

OPC Witness Garrett’s testimony and exhibits address the appropriate authorized ROE of 9.25% to include in the projected test year capital structure shown on Exhibit HWS-2, Schedule D, page 1 of 2.

FEA:

Christopher Walters’ testimony provides that the appropriate return on common equity to use in establishing FCG’s test year revenue requirement is in the range of 9.00% to 9.80% with a midpoint of 9.40%.

FIPUG:

Join position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG witness Campbell asserted an ROE of 10.75 percent, as recommended by witness Nelson, with a range from 9.75 percent to 11.75 percent, would fairly compensate equity investors for the use of their capital over the 2023-2026 period of FCG’s proposed four-year rate plan. (TR 1070) FCG argued that the U.S. Supreme Court has recognized that the 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.[44] (FCG BR 53; TR 51-52) FCG argued that both the U.S. Supreme Court and the Florida Supreme Court have held that setting the ROE is a utility-specific, factual determination.[45] (FCG BR 53) FCG held that witness Nelson calculated FCG’s cost of equity using three widely used market based financial models which focused on different aspects of investors’ return requirements. (FCG BR 53) Additionally, FCG argued, witness Nelson considered FCG’s risk profile relative to a proxy group of companies that are comparable, but not necessarily identical in risk to FCG. (FCG BR 54; TR 47) FCG argued that in reaching her ROE recommendation, witness Nelson considered: (1) the results from three commonly used analytical approaches; (2) the Company’s higher risk profile associated with its significantly smaller size; (3) the regulatory environment in which it operates, including the incremental risk associated with its proposed multi-year rate plan; (4) the costs associated with issuing stock; and (5) the current volatile and uncertain economic and capital market environment. (FCG BR 54) Based on these factors, FCG argued witness Nelson concluded that a midpoint ROE of 10.75 percent is just and reasonable. (FCG BR 54; TR 116-17) FCG argued that both OPC’s and FEA’s recommended ROEs of 9.25 percent and 9.40 percent, respectively, do not properly reflect the undisputed facts that inflation, interest rates, capital costs, and overall market risk are all substantially higher than the levels experienced since FCG’s last base rate case and should be rejected. (FCG BR 53; TR 124) FCG further argued the Intervenors’ recommended ROEs are biased downward due to their reliance on inputs that are flawed and contradictory to sound financial theory. (FCG BR 55) FCG argued that the Intervenors’ ROE recommendations are below any reasonable measure of FCG’s cost of equity and do not satisfy the Hope and Bluefield standards. (FCG BR 55; TR 124) FCG argued the Intervenors’ ROE recommendations, if adopted, would be viewed as a departure from the Commission’s practices, increasing the Company’s regulatory and financial risk, and thus, diminishing FCG’s ability to compete for capital. (FCG BR 56)

OPC

OPC argued pursuant to the standards set forth in the Hope and Bluefield decisions, the financial integrity of a company should be sufficient to attract capital on reasonable terms under a variety of market and economic conditions. (OPC BR 38-39; TR 51-52) OPC argued under Hope and Bluefield, the awarded ROE should be commensurate with returns on investments of corresponding risk, and be sufficient to assure financial soundness and integrity under efficient management. (OPC BR 39-40; TR 349) OPC argued since utility stocks are low risk, the return required by equity investors should be relatively low. (OPC BR 39; TR 349) OPC argued that the low cost of equity results witness Garrett derived from his cost of equity analysis using the DCF model (7.1 percent) and CAPM (7.9 percent) confirm that the industry experiences relatively low levels of risk. (OPC BR 39; TR 349) OPC argued the other guiding legal principle to be followed in Hope established that the allowed return should be based on the actual cost of capital. (OPC BR 39-40; TR 342) OPC argued if the Commission sets the awarded return based on witness Garrett’s lower and more reasonable proposed ROE of 9.25 percent, the Commission will better comply with the U.S. Supreme Court’s standards, allow the Company to maintain its financial integrity, and allow the Company to achieve reasonable returns for its investors. (OPC BR 40; TR 343) However, OPC opined, if the Commission sets the awarded ROE much higher than the true cost of capital, as requested by FCG, it will run contrary to the U.S. Supreme Court’s mandates and result in an inappropriate transfer of wealth from customers to shareholders. (OPC BR 40; TR 343) OPC argued that witness Garrett accounted for the effects of recent inflation by using the yields on 30-year Treasury bonds as a proxy for the risk-free rate in the CAPM. (OPC BR 39; TR 338) OPC argued FCG witness Nelson used non-sustainable and unreasonably high growth rates in her DCF model, which led to the extremely high cost of equity result of 11.2 percent. (OPC BR 40; TR 376) OPC argued FCG witness Nelson’s CAPM result of 12.9 percent is similarly flawed due to her use of an extremely inflated equity risk premium (ERP) of 12.27 percent. (OPC BR 41) OPC also disagreed with witness Nelson’s size adjustment and inclusion of flotation costs in support FCG’s request for a higher awarded ROE. (OPC BR 41; TR 394-399) OPC opined, as pointed out by witness Garrett, the size premium theory has been debunked since 1983, and therefore, the Commission should ignore FCG’s size risk adjustment. (OPC BR 41-42; TR 395) OPC argued the Commission should also ignore witness Nelson’s inclusion of flotation costs in her ROE recommendation. (OPC BR 42) OPC argued since FCG does not issue securities it does not incur underwriters’ costs or experience any other out-of-pocket flotation costs, and additionally, investors already have access to the information they need about underwriters’ costs when investors make their decision to purchase shares at a certain price. (OPC BR 42; TR 397-398) OPC argued witness Garrett’s analyses demonstrated that FCG’s cost of equity is approximately 8.0 percent. (OPC BR 42; TR 399) OPC argued given the legal standards by which the Commission is bound, the Commission should award FCG an ROE of no more than 9.25 percent. (OPC BR 42; TR 338) OPC argued an ROE of 9.25 percent would result in fair, just, and reasonable rates, and would benefit both FCG’s consumers as well FCG’s shareholders. (OPC BR 42)

FEA

FEA asserted the purpose of the rate of return testimony provided in this proceeding is to estimate the expected return that investors require on an investment in FCG. (FEA & FIPUG BR 11) FEA argued the determination of a fair market-required return is governed in part by the standards set forth in the Hope and Bluefield U.S. Supreme Court decisions.[46] (FEA & FIPUG BR 11) FEA opined that in accordance with these decisions, a utility should be allowed a return on equity sufficient to maintain its financial integrity and to attract capital on reasonable terms, and the return should be commensurate with returns investors could earn by investing in other companies of comparable risk. (FEA & FIPUG BR 11-12) FEA argued witness Walters’ estimated current market cost of equity range of 9.0 percent to 9.8 percent, with a mid-point estimate of 9.4 percent, is consistent with the standards set forth in these decisions for determining a utility’s fair cost of common equity. (FEA & FIPUG BR 12) FEA argued 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. (FEA & FIPUG BR 10) FEA further argued that observed gas utility authorized ROEs have been below 10 percent for approximately the past nine years. (FEA & FIPUG BR 10) FEA asserted witness Walters developed his ROE recommendation of 9.4 percent by applying the Discounted Cash Flow (DCF) model, the Risk Premium model, and the Capital Asset Pricing Model (CAPM) to the same proxy group of gas utility companies used by FCG witness Nelson and accurately reflects the current market cost of equity for FCG. (FEA & FIPUG BR 12-13) FEA argued the Commission should reject FCG witness Nelson’s recommended ROE of 10.75 because it is significantly overstated. (FEA & FIPUG BR 17) As explained by witness Walters, to reach her recommendation, witness Nelson relied on inflated inputs and flawed applications of the DCF model, CAPM, and Empirical CAPM. (FEA & FIPUG BR 17) FCG argued the deficiencies in witness Nelson’s ROE analyses identified by witness Walters in his direct testimony all led to her results being higher than they should have been. (FEA & FIPUG BR 17; TR 468-503) FEA argued after witness Walters made prudent and reasonable adjustments to witness Nelson’s ROE estimates, her analyses would support witness Walters’ recommended ROE range of 9.0 to 9.8 percent. (FEA & FIPUG BR 17)

FIPUG

FIPUG joined the arguments of FEA. (FEA & FIPUG BR 9)

ANALYSIS

The ROE is the allowed cost of common equity included in a utility’s regulatory capital structure used to determine the overall rate of return used to establish a revenue requirement. 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 return on equity (ROE). (TR 401; TR 784) OPC witness Garrett and FEA witness Walters used the same proxy group as that of FCG witness Nelson. (TR 784-785) 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, witnesses Nelson and Walters employed a risk premium analysis to estimate the cost of equity. (TR 399) Witness Garrett also applied the Hamada Formula to his CAPM. (TR 409) In general, FCG witness Nelson used inputs and assumptions that produced a higher ROE estimate, while the Intervenor witnesses used inputs and assumptions that produced a lower ROE estimate. (TR 403; TR 839) As a result of their respective assumptions used in the cost of equity models, the staff 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 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 29-1.

Table 29-1

Summary of Cost of Equity Model Results

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%

Source: (TR 66, 68, 76, 79, 82, 399, 470, 475, 509)

Legal Standard

The landmark Hope and Bluefield U.S. Supreme Court cases established standards for setting a fair rate of return for equity investment for utilities providing monopoly service to the public. (TR 401) Simply stated, a fair rate of return is commensurate with returns available on investments having comparable risks. (TR 401, 775) The rate of return should also be sufficient to assure financial soundness and integrity, support reasonable credit quality, and allow a company to raise capital on reasonable terms. (TR 401, 775) Witness Garrett opined that the Hope standard ultimately requires that the end result should be just and reasonable and based upon a utility’s actual cost of equity. (TR 769) Witness Garrett further opined that an allowed ROE that is far above the cost of equity runs the risk of being at odds with the Hope and Bluefield standards and results in an excess transfer of wealth from the customers to the utility. (TR 343)

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. (TR 56) The gas proxy group includes Atmos Energy Corp., New Jersey Resources Corp., NiSource, Inc., Northwest Natural Holding Co., ONE Gas, Inc., and Spire, Inc. (TR 57) Witness Nelson asserted the proxy group companies all have investment grade credit ratings and are in sound financial condition. (TR 57) Witness Nelson contended that the gas proxy group is comparable, but not identical, to the financial and operational characteristics of FCG. (TR 57) Witness Nelson asserted that because the proxy group is not identical in risk to FCG, a relative risk assessment between FCG and the proxy group must be performed to arrive at an appropriate ROE for FCG. (TR 60) The Intervenor witnesses took no issue with FCG witness Nelson’s selection of gas utilities for her gas proxy group and used the same proxy group for their respective cost of equity analyses. (TR 351, 458)

Cost of Equity Models

DCF

The DCF 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. (TR 61, 359-360) In its basic form, the DCF model is expressed as the dividend yield of a stock plus the expected long-term growth rate. Expressed mathematically as ROE = (dividend ÷ stock price) + growth rate. (TR 61, 459) The differences between witness Nelson’s and the Intervenor witnesses’ DCF model results are primarily driven by differences in growth rates and 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. (TR 488; EXH 31, 32) FEA witness Walters used three different growth rates of 5.95, 5.67, and 4.35 percent in three variations of the DCF model. (EXH 83, 86, 88) 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. (EXH 54)

FCG

FCG witness Nelson relied on the constant growth and quarterly growth forms of the DCF model. (TR 60) Witness Nelson asserted that the models she used are commonly used by the financial community, as well as in regulatory proceedings. (TR 60) Witness Nelson calculated her constant growth DCF result for each of the proxy companies using three different averaging periods of daily stock closing prices for the 30, 90, and 180-trading days ended March 31, 2022. (TR 62) She used the current quarterly dividend as of March 31, 2022, (multiplied by 4) for the term dividend. (TR 62) For the growth rate, witness Nelson relied on the long-term earnings per share (EPS) growth rate projections as of March 31, 2022, reported by three well recognized financial resources; Zacks, Yahoo! Finance, and Value Line. (TR 62) Witness Nelson contended because utility companies tend to increase their quarterly dividends at different times throughout the year, it is reasonable to assume that dividend increases will be evenly distributed over calendar quarters. (TR 62) Given that assumption, witness Nelson calculated the expected dividend yield by applying one-half of the long-term growth rate to the current dividend yield. (TR 62) Witness Nelson asserted that adjustment ensures that the expected dividend yield is, on average, representative of the coming 12-month period. (TR 62-63)

For each proxy company, witness Nelson calculated the low, mean, and high DCF model result. (TR 65-66) In developing her ROE recommendation, witness Nelson relied on the average of the mean and median proxy group Constant Growth DCF results. (TR 66; EXH 31). Witness Nelson asserted that relying on the average of the mean and median results prevents giving undue weight to the highest or lowest estimates. (TR 66) The results of her three iterations of the constant growth DCF model ranged from 8.05 percent to 10.69 percent, with a simple average of the mean results of her three iterations of 9.72 percent (9.54% + 9.76% + 9.85% = 29.15% ÷ 3 = 9.72%). (TR 66; EXH 31)

Witness Nelson contended that most companies pay dividends on a quarterly basis. (TR 66) Witness Nelson asserted although the dividend yield adjustment used in the constant growth DCF model is meant to address that assumption (by increasing the observed dividend yield by one-half of the expected growth rate), it does not fully account for the quarterly receipt and reinvestment of dividends. (TR 66) As a consequence, she opined that the constant growth DCF model likely understates the cost of equity. (TR 66) The quarterly growth DCF model specifically incorporates the quarterly payment of dividends, and the associated quarterly compounding of those dividends as they are reinvested at the required ROE. (TR 66-67) Because the required ROE is a variable in the dividend calculation, the quarterly growth DCF model is solved by iterative calculations. (TR 67) The results of witness Nelson’s three iterations of the quarterly growth DCF model ranged from 8.14 percent to 10.87 percent, with a simple average of the mean results of her three iterations of 9.86 percent (9.68% + 9.91% + 10.00% = 29.59% ÷ 3 = 9.86%). (TR 68; EXH 32)

FEA disagreed with FCG’s constant growth DCF results and asserted they are based on unsustainably high growth rates. (TR 486) FEA witness Walters contended witness Nelson’s average proxy group growth rate of 6.07 percent is based on consensus analysts’ projected growth rates which is significantly above the long-term sustainable growth rate of 4.35 percent. (TR 488) FEA witness Walters also contended witness Nelson’s quarterly DCF model results are overstated because using quarterly compounding dividends in her dividend yield can overstate a fair ROE for setting rates. (TR 488) Witness Walters asserted reinvesting dividends is not a cost to the Company and should not be reflected as a cost of capital for setting rates. (TR 488-489) FEA witness Walters opined by including the quarterly compounding adjustment in the authorized returns used to set rates, investors are provided an opportunity to earn that quarterly compounding return twice: first, by setting rates to increase the allowed ROE to include a dividend reinvestment return despite the absence of actual reinvestment of the dividend in the Company; and second, investors are able to earn the reinvestment dividend return again when they receive dividends from the companies and actually reinvest in alternative investments. (TR 489)

OPC argued FCG witness Nelson’s DCF model produced overstated results because of her use of unsustainable and unreasonably high growth rates. (OPC BR 40; TR 376) OPC witness Garrett contended witness Nelson’s growth rates are greater than the projected annual long-term nominal U.S. GDP growth rate of 3.8 percent which violates the basic principle that no company can grow at a rate greater than the economy in which it operates over the long-term. (TR 377) Witness Garrett contended a short-term, quantitative growth estimates published by analysts as relied upon by witness Nelson is not appropriate for a sustainable growth estimate. (TR 377)

OPC

Witness Garrett asserted a fundamental concept of finance in that no firm can grow forever at a rate higher than the growth of the economy, or the Gross Domestic Product (GDP). (TR 367) Witness Garrett testified that the Congressional Budget Office’s 2021 long-term budget outlook forecast for the U.S. GDP is 3.80 percent. (TR 368) Witness Garrett used the nominal GDP in his DCF analysis. (TR 375) Witness Garrett opined that the stable growth DCF model considers only sustainable growth rates, which are appropriate for estimating the growth for utility companies because they are in the sustainable growth stage of the industry life cycle. (TR 365-367). Witness Garrett opined it is reasonable to assume that a regulated utility would grow at a rate that is less than GDP. (TR 367) To derive his DCF result, witness Garrett calculated an average dividend yield for the gas proxy group of 3.2 percent based on a 30-day average stock price from June-July 2022 and the most recent quarterly dividend paid by each company and annualized the dividends. (TR 360; EXH 52, 54) Witness Garrett calculated a DCF result of 7.1 percent using his estimated sustainable growth rate of 3.80 percent. (TR 375; EXH 54) Witness Garrett derived a second DCF estimate using analyst growth forecasts of 8.0 percent. (TR 376; EXH 54) Witness Garrett did not recommend his analyst growth rate should be considered, but nonetheless, used it to illustrate the sensitivity of using an analyst growth rate in the DCF model. (TR 376)

FCG witness Nelson disagreed with the use of GDP as a measure of long-term growth in the DCF Model. (TR 166) Given that current inflation is at 8.60 percent, OPC witness Garrett’s measure of sustainable growth using nominal GDP growth of 3.80 percent implies negative growth in real terms. (TR 165) Witness Nelson opined it is unlikely an investor would be willing to assume the risks of equity ownership in exchange for negative real growth or even only modestly greater growth than OPC witness Garrett’s estimate of expected long-term inflation. (TR 165) Further, witness Nelson contended witness Garrett’s 3.80 growth rate is based on a generic estimate of the economy as a whole and doesn’t reflect any measure of company-specific growth or growth in the natural gas utility industry. (TR 166) As cited by witness Nelson, the Commission previously determined that GDP growth is not an appropriate measure of growth in the DCF model because it is not based on any measure of growth in the utility industry.[47] (TR 168) Staff agrees with FCG witness Nelson that the GDP should not be the sole measure of growth in the DCF model because it is not based on any measure of growth in the gas utility industry or the companies in the proxy group.

FEA

FEA witness Walters used three different variations of the DCF model in his analysis. (TR 470) Witness Walters used two constant growth DCF models; one with analysts’ growth estimates and a second with a sustainable growth estimate. (TR 470) In addition, witness Walters employed a multi-stage DCF Model. (TR 470) The results of witness Walters DCF model analysis ranged from 7.99 percent to 9.31 percent. (TR 470)

In his constant growth DCF Model with analysts’ growth rates, witness Walters used the proxy group average stock price over a 13-week period ended July 8, 2022. (TR 459) Witness Walters used the same dividend valuation as witness Nelson’s constant growth DCF model by annualizing the dividend (multiplied by 4) and adjusted for next year’s growth by multiplying the annualized dividend by 1 plus the growth rate to obtain a dividend yield of 3.36 percent. (TR 460; EXH 83) For his growth rate estimate of 5.95 percent, witness Walters relied on an average of analysts’ growth rate estimates from three sources: Zacks, S&P Global Market Intelligence, and Yahoo! Finance. (TR 461) The average result from witness Walters constant growth DCF model was 9.31 percent (3.36% + 5.95% = 9.31%). (TR 461; EXH 83) Witness Walters asserted that his constant growth DCF model with analyst’s growth rates is based on an average long-term growth rate of 5.95 percent using three to five year analysts’ growth rate projections is nearly 40 percent higher than the projected long-term GDP growth rate of 4.35 percent which indicates 5.95 percent is not a sustainable level of growth. (TR 461-462) Witness Walters asserted Blue Chip Economic Indicators projects that over the next 5 and 10 years, the U.S. nominal GDP will grow at an annual rate of approximately 4.35 percent which he believes is a reasonable proxy for long-term growth. (TR 462) Witness Walters contended the long-term sustainable growth rate for a utility stock cannot exceed the growth rate of the economy in which it sells its goods and services. (TR 462) Witness Walters asserted the long-term maximum sustainable growth rate for a utility investment is, accordingly, best proxied by the projected long-term GDP growth rate as that reflects the projected long-term growth rate of the economy as a whole. (TR 462)

Witness Walters also used a sustainable growth rate DCF model based on the percentage of the proxy group utilities’ earnings that is retained and reinvested in utility plant and equipment. (TR 463) The data witness Walters used to estimate the long-term sustainable growth rate is based on each of the proxy group company’s current market-to-book ratio and on Value Line’s three to five year projections of earnings, dividends, earned returns on book equity, and stock issuances. (TR 463; EXH 85) The average sustainable growth rate for the proxy group using this internal growth rate method is 5.67 percent. (EXH 85) Using the same dividend yield of 3.36 percent, witness Walters’ sustainable growth rate DCF model result was 9.02 percent. (EXH 86)

Witness Walters multi-stage DCF model reflects the possibility of non-constant growth for a company over time. (TR 465) The multi-stage DCF model reflects three growth periods: (1) a short-term growth period consisting of the first five years; (2) a transition period, consisting of the next five years (year 6 through 10); and (3) a long-term growth period starting in year 11 and extending into perpetuity. (TR 465) Witness Walters relied on the same dividend yield of 3.36 percent that he used in his other two DCF models. (TR 469) For the first stage of five-years, witness Walters used the same analysts’ growth rate projections of 5.95 percent that he used in his constant growth DCF model. (TR 469; EXH 88) For the second stage consisting of five years, the growth rate transitions from the first stage to the third stage using a straight linear trend from 5.95 percent to 4.35 percent. (TR 469; EXH 88) For the third stage, or long-term sustainable growth stage, starting in year 11, witness Walters used a 4.35 percent long-term sustainable growth rate based on the consensus of economists’ long-term projected nominal GDP growth rate as published in Blue Chip Economics Forecast. (TR 469; EXH 88) Witness Walters’ results from his multi-state DCF model averaged 7.99 percent. (EXH 88)

FCG witness Nelson argued there is evidence that utility equity growth rates can exceed GDP growth over the long term. (TR 168) The long-term growth component in the DCF model reflects the return expected from capital appreciation. (TR 168) Witness Nelson asserted according to data in Kroll 2022 SBBI Yearbook, the long-term average historical rate of capital appreciation for the S&P 500 between 1926 and 2021 has been 8.20 percent, well above long-term historical GDP growth and the Intervenor witnesses’ GDP growth estimates of 3.8 and 4.35 percent. (TR 168) Thus, she argued, it would seem long-term equity growth has not been limited by GDP growth. (TR 168) Additionally, witness Nelson opined, the projected earnings growth rates assumed by FEA witness Walters and her are below the long-term average capital appreciation growth rate of 8.20 percent, demonstrating their reasonableness. (TR 168) As such, witness Nelson contended, the Intervenor witnesses’ ROE estimates using the GDP growth rates should be rejected. (TR 168)

CAPM

The CAPM method of analysis 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. (TR 475) The CAPM assumes that all non-market or unsystematic risk, can be eliminated through diversification. (TR 69) The risk that cannot be eliminated through diversification is called market, or systematic risk. (TR 69) Therefore, the CAPM assumes that investors require compensation only for systematic, or market, risk. (TR 69-70) Non-diversifiable (or systematic) risk is measured by the beta coefficient. (TR 70) The beta is expressed as the volatility of an individual security compared against the stock market as a whole. (TR 357) A beta value of 1.0 indicates the individual security has the same volatility as the stock market. (TR 357) 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. (TR 357) 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). (TR 378-379)

FCG

Witness Nelson used two forms of the CAPM in her analysis, the traditional CAPM and an empirical CAPM. (TR 75-76) The empirical CAPM reduces the effect of the beta coefficient by 25 percent to compensate for what she explained is a tendency of the CAPM to underestimate the cost of equity for companies with low beta coefficients. (TR 76-77) The results from the empirical CAPM are greater than results from the traditional CAPM. (EXH 34) Witness Nelson calculated four separate derivations of the traditional CAPM and four separate derivations of the empirical CAPM. (EXH 34) Witness Nelson’s spectrum of average results for the proxy group from the traditional CAPM ranged from 10.12 to 12.94 percent; the average results using the empirical form ranged from 10.67 to 13.37 percent. (TR 76, 79; EXH 34) Witness Nelson did not select a specific ROE result from her CAPM analysis as an appropriate ROE for setting rates for FCG. Instead, witness Nelson graphically presented the results of her CAPM analysis in her testimony and opined that she considered the results from three commonly used analytical approaches which included her CAPM analysis. (TR 76, 79, 116)

Beta: Witness Nelson used two estimates of the beta coefficient for each proxy company. (TR 71) The first estimate is the current beta coefficient reported by Value Line as of March 31, 2022. (TR 71) The proxy group average beta coefficient from Value Line was 0.85. (TR 71) The second estimate is the adjusted beta coefficient calculated from Bloomberg over the ten years ended March 31, 2022, rather than the five-year period used by Value Line. (TR 71) The average beta for the proxy group from Bloomberg was 0.78. (TR 71)

Risk-Free Rate: Witness Nelson applied two estimates of the risk-free rate: the current 30-day average yield (2.37 percent) and a projected yield (3.32 percent) on 30-year U.S. Treasury Bonds. (TR 70) Witness Nelson opined natural gas utilities are typically long-duration investments and, as such, the 30-year Treasury yield is more suitable for the purpose of calculating the cost of equity. (TR 71)

Equity Risk Premium: Witness Nelson derived two estimates of the expected market return. (TR 72; EXH 34) She calculated the market capitalization-weighted ROE of the S&P 500 Index by applying the Constant Growth DCF model described earlier to each of the companies in the S&P 500 Index. (TR 73; EXH 33) Witness Nelson calculated two separate DCF forward-looking estimates, one using Value Line data and the other using data from Bloomberg. (TR 73) Witness Nelson’s DCF forward-looking market return estimate results were 14.64 percent using the Bloomberg data and 16.14 percent using Value Line data. (TR 73) Witness Nelson relied more on the Bloomberg generated market return of 14.64 percent. (TR 73) The second estimate considered the long-term, historical arithmetic average market return of 12.33 percent between 1926 and 2021 reported by Duff & Phelps. (TR 72-73).

Witness Nelson opined the long-term arithmetic average historical return on the market of 12.33 percent is an appropriate alternate estimate of the expected market return. (TR 74) As explained by witness Nelson:

My objective is to develop a reasonable estimate of the expected market return during the time rates will be in effect to apply in the CAPM. Because the Cost of Equity is forward looking, any estimate – whether based on historical or projected data – assumes the estimate reflects investors’ expectations into the future. Although the 14.64 percent expected market return is highly consistent with historically observed market returns (as shown in Figure 9 above), it is above the long-term arithmetic annual average market return. Therefore, it may be reasonable to expect that over time, the market return will revert to its long run historical arithmetic average. From that perspective, the application of the long-run historical arithmetic average market return as an alternate estimate of the expected market return is prospective in nature.

(TR 74-75)

In this case, staff agrees with witness Nelson that the historical market return estimate of 12.33 percent more likely reflects the prospective market return based on the current economic and market conditions discussed later. Accordingly, staff believes the more reasonable CAPM estimate from witness Nelson is her average proxy group result of 10.33 percent using the risk-free rate of 3.32 percent from the projected 30-year yield on U.S. Treasury Bonds, the long-term average historical market return of 12.33 percent, and the 10-year Bloomberg Beta coefficient, which averages 0.775 for the proxy group. (EXH 34) Witness Nelson’s empirical CAPM result for the same data group was 10.83 percent. (EXH 34)

OPC witness Garrett asserted there were specific problems with witness Nelson’s CAPM analysis. (TR 389) First, staff agrees with OPC that witness Nelson’s CAPM results are unreasonably high due to her overestimation of the projected market return and ERP. (OPC BR 41; TR 389; EXH 34) Witness Nelson’s ERP using an estimated market return of 14.64 percent is 11.32 percent using a risk-free rate of 3.32 percent. (EXH 34) Witness Garrett compared witness Nelson’s ERP estimate to his and other independent sources for the ERP and concluded her estimate is not within the range of reasonableness. (TR 390) Witness Garrett also took issue with witness Nelson’s use of the empirical CAPM. (TR 391) Witness Garrett contended:

The premise of Ms. Nelson’s E-CAPM is that the real CAPM underestimates the return required from low-beta securities, such as those of the proxy group. There are several problems with this concept, however. First, the betas that both Ms. Nelson and I used in the real CAPM already account for the theory that low-beta stocks might tend to be underestimated. In other words, the raw betas for each of the utility stocks in the proxy groups have already been adjusted by Value Line to be higher. Second, there is empirical evidence suggesting that the type of beta-adjustment method used by Value Line actually overstates betas from consistently low-beta industries like utilities. According to this research, it is better to employ an adjustment method that adjusts raw betas toward an industry average, rather than the market average, which ultimately would result in betas that are lower than those published in Value Line. Finally, Ms. Nelson’s ECAPM still suffers from the same overestimated risk-free rate and ERP inputs discussed above. Thus, regardless of the differing theories regarding the mean reversion tendencies of low-beta securities, Ms. Nelson’s ECAPM should be disregarded for its ERP input alone.

(TR 391-392)

FEA witness Walters also took issue with witness Nelson’s DCF-derived ERP estimates in her application of the CAPM. (TR 490) Witness Nelson’s DCF-based market return used to calculate her ERP includes 70 companies with growth rates that exceed 20%, of which four are greater than 135 percent. (TR 491) Further, witness Walters asserted 305 of the growth rates (for companies in the S&P 500) relied on by witness Nelson are 8.7 percent or higher, which is two times the projected growth of the U.S. economy. (TR 492) Witness Walters contended it is simply not reasonable to believe individual companies, and as a result the overall market, can sustain growth rates as high as witness Nelson has assumed. (TR 492)

FCG witness Nelson disagreed with witness Walters suggestion that her expected market return is inflated because expected individual growth rates of certain companies exceed his measure of long term sustainable growth. (TR 212) Witness Nelson opined witness Walters’ criticism focused on individual company growth rates he deemed as too high and he failed to acknowledge that the expected market return estimates also include growth rates that could be considered unsustainably low. (TR 212) Witness Nelson asserted by not attempting to evaluate the sustainability of each of the 500 individual companies’ growth rate in the S&P 500 as FEA witness Walters does, she did not introduce bias into the expected market return analysis. (TR 212) Witness Nelson further opined a proper market return estimate must include all companies in the analysis to avoid internal inconsistencies. (TR 212)

FEA witness Walters also took issue with Ms. Nelson’s ECAPM analysis. (TR 494) Witness Walters asserted the impact of witness Nelson’s ECAPM increased the Value Line adjusted beta estimate of 0.85 to 0.90 and is mathematically the same as adjusting the beta since the beta inputs are all multiplicative. (TR 494) The ECAPM with adjusted betas has the effect of increasing CAPM return estimates for companies with betas less than 1, and decreasing the CAPM return estimates for companies with betas greater than 1. (TR 495) Witness Walters contended there is simply no legitimate basis to use an adjusted beta within an ECAPM because it unjustifiably alters the security market line and materially inflates a CAPM return for a company with a beta less than 1. (TR 495-496)

OPC

OPC witness Garrett’s CAPM yielded an ROE estimate of 7.9 percent based on a risk-free rate of 3.21 percent, an average beta for the proxy group of 0.83 and an ERP estimate of 5.6 percent. (TR 387-388; EXH 59)

Beta: For his beta value, witness Garrett used betas published by Value Line Investment Survey on May 27, 2022, and determined the average for the proxy group was 0.83. (TR 381, 387; EXH 56)

Risk-Free Rate: Witness Garrett used the average of 30 daily Treasury yield curve rates on 30-year Treasury bonds during the period from June 1, 2022, through July 14, 2022, to estimate his risk-free rate of 3.21 percent. (TR 379-380; EXH 59)

Equity Risk Premium: Witness Garrett developed his ERP using the average of four estimates from expert surveys of expected market risk premiums. (TR 384) The first ERP of 5.60 percent was obtained from a 2022 survey published by the IESE Business School. (TR 384) Witness Garrett explained the survey involves conducting a survey of experts including professors, analysts, chief financial officers and other executives around the country about what they believe the ERP is. (TR 384) A second ERP estimate published by Kroll, formerly Duff & Phelps, was 5.5 percent. (TR 387) A third estimate using an implied ERP from Aswath Damodaran published in the Implied Equity Risk Premium Update indicated an ERP of 5.6 percent. (TR 386) For the fourth estimate, witness Garrett employed the DCF Model to calculate the return on the S&P 500 Index data over the past six years. (TR 384) He calculated the S&P 500 dividend yield, buyback yield, and gross cash yield for each year, and calculated the compound annual growth rate from earnings. (TR 386) He used these inputs, along with a risk-free rate of 3.21 percent and current value of the S&P 500 Index (3,882) to calculate a current expected return on the entire market of 9.0 percent. (TR 386; EXH 57) He then subtracted the risk-free rate to arrive at the implied equity risk premium of 5.80 percent. (TR 386; EXH 57) The average of all four estimates used by witness Garrett was 5.60 percent. (TR 387)

FCG witness Nelson disagreed with witness Garrett’s use of current as opposed to projected 30-year U.S. Treasury yields for the risk-free rate and reliance on surveys in his CAPM analysis. (TR 170) Witness Nelson opined it is appropriate to reflect forward-looking expectations of the risk-free rate to match the forward-looking cost of equity estimate. (TR 170) Witness Nelson took issue with using surveys to estimate the ERP because it is not clear how the survey respondents derived the ERP in their response or the risk-free rate on which they relied. (TR 173) Further, witness Nelson took specific issue with the use of Kroll’s ERP of 5.5 percent because it is not clear if Kroll’s develops its ERP in relation to its risk-free rate. (TR 171) Witness Nelson opined:

The Market Risk Premium is calculated as the difference between the expected market return and risk-free rate; therefore, it is a function of the expected market return and risk-free rate at a point in time. Consequently, the Market Risk Premium and risk-free rate are not independent of each other, they are interrelated. In fact, academic studies have shown that the two are inversely related. As the risk-free rate decreases, the Market Risk Premium increases and vice versa.

(TR 171)

Witness Nelson conducted a statistical analysis of Kroll’s ERP and the risk-free rate and found that there is no clear inverse relationship between the two variables. (TR 171-172) Witness Nelson opined that her analysis did not suggest that the usefulness of Kroll’s ERP estimate is not a valid or credible source of data, but rather, it suggested that the usefulness of Kroll’s ERP is questionable given it doesn’t comport with academic and financial theory. (TR 173)

FEA

FEA witness Walters calculated nine different applications of the CAPM using a combination of three different beta estimates and three different ERP estimates. (TR 483; EXH 95) The first three CAPM results were based on the proxy group’s current average Value Line beta of 0.83. (TR 483) The results of the CAPM based on the Value Line beta ranged from 8.08 percent to 10.97 percent. (TR 483) The second set of three CAPM results were based on the proxy group’s historical Value Line beta of 0.74, and ranged from 7.56 percent to 10.15 percent. (TR 483) The last set of three results were based on the proxy group’s current S&P Global Market Intelligence beta of 0.70 and ranged from 7.34 percent to 9.8 percent. (TR 483, 509) The average of witness Walter’s CAPM results is approximately 9.3 percent with a median of 9.78 percent (TR 484, 509) Based on his results, witness Walters recommended a CAPM return estimate of 9.4 percent. (TR 484)

Beta: FEA witness Walters contended the current proxy group average Value Line beta estimate of 0.83 is abnormally high and unlikely to be sustained over the long-term. (TR 477) Therefore, witness Walters also used the historical average of the proxy group’s Value Line betas since 2014 of 0.74. (TR 483; EXH 94) Third, witness Walters used adjusted beta estimates using S&P Global Market Intelligence’s beta generator model of 0.70 (MI beta). (TR 477, 509; EXH 94) Witness Walters explained since he relied on the S&P 500 to estimate the market return used to calculate his ERP estimate it makes sense to rely on beta estimates that are based on the S&P 500 as the benchmark for the market. (TR 478)

Risk-Free Rate: Witness Walters used the projected 30-year U.S. Treasury Bond yield of 3.8 percent. (TR 476) Witness Walters opined that U.S. Treasury bond yields do include risk premiums related to future inflation and liquidity, and as such are not entirely risk-free. (TR 477) Witness Walters asserted equity risk premiums related to unanticipated inflation and interest rates reflect systematic market risks, and consequently, for a company with a beta less than 1.0, using the U.S. Treasury bond yield as a proxy for the risk-free rate in the CAPM analysis can produce an overstated estimate of the CAPM return. (TR 477)

Equity Risk Premium: Witness Walters used three different ERPs in his nine iterations of the CAPM. (EXH 95) He used ERPs of 5.5 percent, 8.1 percent and 8.6 percent. (EXH 95) Witness Walters calculated two equity risk premium estimates using two different methods; a risk premium model approach and a DCF model approach. (TR 478) He also employed a normalized market risk premium of 5.5 percent with the normalized risk-free rate of 3.5 percent as published by Kroll, formerly known as Duff & Phelps. (TR 478)

Witness Walters’ risk premium method to calculate the risk premium was derived by estimating the expected S&P 500 return on the market and subtracting the risk-free rate from the market return. (TR 478-479) Witness Walters used the Kroll 2022 SBBI Yearbook estimate for the historical arithmetic average real market return over the period 1926 to 2021 of 9.2 percent. (TR 479) He then added the current consensus for projected inflation as measured by the Consumer Price Index (CPI) of 2.5 percent to obtain an expected market return of 11.93 percent. (TR 479) The market risk premium is the difference between the 11.93 percent expected market return and the projected risk-free rate of 3.8 percent, or 8.13 percent. (TR 479)

For his market risk premium derived using the DCF model, witness Walters employed two versions of the constant growth DCF model. (TR 479) Witness Walters used the Federal Energy Regulatory Commission’s (FERC) prescribed method for determining the market risk premium. Starting with the market return of 12.29 percent, he subtracted the projected risk-free rate of 3.8 percent, resulting in an ERP of 8.5 percent. (TR 480) Witness Walters’ second DCF-based market risk premium estimate was derived by performing the same FERC prescribed DCF models, except he used all companies in the S&P 500 index rather than just the dividend paying companies. (TR 480) The FERC DCF-derived expected return on the market was 12.48 percent. (TR 480) The market risk premium is the expected market return of 12.48 percent less the projected risk-free rate of 3.8 percent, or 8.7 percent. (TR 480) The average ERP from his two DCF model calculations was 8.6 percent. (TR 480)

FCG witness Nelson disagreed with witness Walter’s ERP estimates, his use of the MI beta coefficients, and his criticisms of the ECAPM analysis. (TR 208) Witness Nelson explained because S&P’s beta Generator model allows the analyst to select the sample group, the size and makeup of the chosen sample group is highly subjective and could substantially affect the MI beta results. (TR 217) Witness Nelson opined S&P’s Beta Generator model, and the Vasicek adjustment used to calculate the beta value, generally is susceptible to debate over the proper size and selection of the comparable group used in the adjustment. (TR 217) Adjusted beta coefficients from Value Line and Bloomberg, however, are simpler, independently reported, and easily verifiable; therefore, they are not exposed to potential bias. (TR 217) Regarding witness Walters use of Kroll’s 5.5 percent ERP and normalized risk-free rate of 3.50 percent, witness Nelson asserted Kroll’s estimates contradict financial theory, resulting in CAPM ROE estimates that are far removed from any reasonable estimate of FCG’s cost of equity and should be rejected. (TR 209) Notably, it does not appear FEA witness Walters gave the three CAPM estimates using Kroll’s ERP of 5.5 percent (ranging from 6.71 percent to 8.08 percent) any weight in determining his 9.40 percent CAPM-based ROE estimate. (TR 209) Witness Nelson also disagreed with witness Walters’ DCF model approach to calculate the market return used in his ERP derivation. She argued this method is internally inconsistent and does not fully reflect the expected market return as a whole. (TR 210) Witness Nelson opined that the purpose of the expected market return analysis is to estimate the return investors expect for the market as a whole, including high and low-growth companies, not to estimate the aggregate return for companies that pay dividends or those that FEA witness Walters believes have proper growth rates. (TR 210) Witness Nelson asserted that at any point in time, the market as a whole includes companies that are both dividend and non-dividend paying, as well as those with negative and positive growth, even companies with very high or very low growth. (TR 210) Witness Nelson opined:

A fundamental assumption of the CAPM is that the required return is proportional to the risk of the investment. Under the CAPM, the Beta coefficient is the measure of risk, and is calculated by comparing the subject security’s returns to the overall market returns. Because the Beta coefficient is calculated relative to the overall market (e.g., the S&P 500 Index or the New York Stock Exchange), it is important that the expected market return also reflect the overall market. Therefore, it is inconsistent to combine Beta coefficients calculated relative to the entire market with a Market Risk Premium estimate calculated using only a subset of the market. Consequently, any credible estimate of the expected return on the market as a whole must include all companies.

(TR 210-211)

Risk Premium Model

The Bond Yield Plus Risk Premium approach is based on the basic financial principle of risk and return, which states that equity investors require a premium over the return required as a bondholder to account for the incremental residual risk associated with equity ownership. (TR 79-80) Risk premium approaches, therefore, estimate the cost of equity as the sum of an equity risk premium and the yield on a particular class of bonds. (TR 80)

FCG

FCG witness Nelson calculated a risk premium ROE based on the difference between the authorized ROE and the then-prevailing 30-year U.S. Treasury Bond yield for 1,226 natural gas utility rate proceedings during the period January 1, 1980, and March 31, 2022. (TR 80) Witness Nelson applied a semi-log regression analysis to the data, in which the equity risk premium is expressed as a function of the natural log of the 30-year U.S. Treasury Bond yield. (TR 81) For the risk-free rate, witness Nelson used both the current 30-year U.S. Treasury Bond yield of 2.37 percent, and the projected 30-year U.S. Treasury Bond yield of 3.32 percent. (TR 82; EXH 35) The results of witness Nelson’s risk premium approach was an estimated ROE of 9.73 percent using a risk-free of 2.37 percent, and 9.8 percent using a risk-free rate of 3.32 percent. (TR 82; EXH 35)

FEA witness Walters disagreed with the application of a regression analysis to estimate the cost of equity in the risk premium model. (TR 497) However, witness Walters agreed witness Nelson’s results are consistent with his own and does not take issue with them at this time. (TR 497) Witness Walters opined that given witness Nelson’s recommended ROE of 10.75 percent is between 95 and 102 basis points higher than the results of her risk premium approach, she does not seem to give much weight to the risk premium results based on her current and near-term interest rate levels. (TR 497)

OPC witness Garrett disagreed with the results and the entire premise of witness Nelson’s risk premium analysis. (TR 392) Witness Garrett contended witness Nelson’s risk premium model considers ROEs allowed by regulatory commissions for electric utilities dating back more than 40 years which contradicts her acknowledgement that cost of equity estimation is a forward-looking process. (TR 392) Witness Garrett also contended the risk premium analysis offered by witness Nelson is completely unnecessary because the CAPM is a risk premium model. (TR 393) Witness Garrett asserted the CAPM has been utilized by companies around the world for decades to estimate cost of equity. (TR 393) In stark contrast to the Nobel-prize-winning CAPM, the risk premium models relied upon by utility witnesses are not market-based, and therefore have no value in estimating the market-based cost of equity. (TR 393) Witness Garrett contended that unlike the CAPM, the risk premium models used by utility witnesses are almost exclusively found in the texts and testimonies of utility witnesses. (TR 393) Finally, witness Garrett asserted witness Nelson’s risk premium model attempts to create an inappropriate link between market-based factors, such as interest rates, with awarded returns on equity, and inevitably, this type of model is used to justify an ROE is much higher than the return that would be dictated by market forces. (TR 393)

FEA

FEA witness Walters risk premium ROE is based on two estimates of an equity risk premium. First, similar to FCG witness Nelson, witness Walter’s calculated the difference between regulatory commission-authorized ROEs and the 30-year U.S. Treasury bond yield. (TR 470) Witness Walters estimated the risk premium on an annual basis for each year since January 1986. (TR 470) Witness Walters asserted commission-authorized returns are typically based on expert witnesses’ estimates of the investor-required return at the time of the proceeding. (TR 470) The risk premium using this method was 5.66 percent. (TR 471; EXH 90) Considering the current economic environment, current levels of interest rates as well as interest rate projections, witness Walters opined a move toward a more normalized equity risk premium is warranted and asserted a risk premium in the range of 5.68 percent to 6.44 percent is appropriate given the current economic environment and risk-free interest rate projection of 3.8 percent. (TR 474) Adding these risk premiums to the projected Treasury yield of 3.8 percent produced an ROE in the range of 9.48 percent to 10.24 percent. (TR 474)

Witness Walters’ second equity risk premium estimate is based on the difference between regulatory commission-authorized ROEs and the average “A” rated utility bond yields published by Moody’s during the period 1986 through 2021. (TR 471) Witness Walters contended over this period, an analyst can infer that authorized ROEs were sufficient to support market prices that at least exceeded book value and demonstrates that utilities were able to access equity markets without a detrimental impact on current shareholders. (TR 471). The risk premium using this method was 4.3 percent. (TR 472; EXH 91) Witness Walters also increased his risk premium result of 4.3 percent to a range of 4.24 percent to 5.33 percent to account for the current economic conditions. (TR 474) However, witness Walters determined the A-rated utility bond yield has averaged 4.74 percent over the 13-week period ending July 8, 2022, while the Baa-rated utility bond yield has averaged 5.09 percent over the same period. (TR 474) Witness Walters added the adjusted risk premiums of 4.24 percent to 5.33 percent to the 13-week A-rated utility bond yield of 4.74 percent which resulted in an ROE range of 9.27 percent to 10.07 percent. (TR 474) Witness Walters also added the adjusted risk premiums to the 13-week Baa-rated utility bond yield of 5.09 percent for an ROE range of 9.62 percent to 10.42 percent. Based on his risk premium analysis, witness Walters concluded a reasonable ROE is 9.8 percent. (TR 474)

FCG witness Nelson had two issues with witness Walters’ risk premium method. First, witness Nelson asserted witness Walters analysis understated the required risk premium in the current market because it failed to adequately reflect the inverse relationship between the equity risk premium and bond yields. (TR 203) Second, witness Nelson contended witness Walters did not apply projected utility bond yields even though he applied a projected 30-year Treasury bond yield. (TR 203-204) Witness Nelson opined that because the cost of equity is forward-looking, witness Walters should have considered projected utility bond yields in his risk premium analysis. (TR 204) FCG witness Nelson opined that although witness Walters’ risk premium-based ROE recommendation is consistent with her bond yield plus risk premium ROE estimate, the low end of his risk premium ROE results reflect assumptions that bias his results downward. (TR 206) Therefore, witness Nelson recommend several adjustments to FEA witness Walters’ risk premium analyses to correct certain deficiencies. (TR 206) Witness Nelson asserted that after her adjustments, witness Walters’ revised results are 10.19 percent and 10.24 percent, respectively. (TR 207)

Flotation Costs

FCG

Witness Nelson estimated the effect of flotation costs on the cost of equity at nine basis points (0.09 percent) by calculating the weighted average issuance costs for the two most recent equity issuances for each company in the proxy group. (TR 97; EXH 38) Witness Nelson did not make an explicit adjustment for flotation costs, but nevertheless considered them in determining her recommended ROE for FCG. (TR 97) Witness Nelson also asserted the Commission allowed recovery of flotation costs in a prior rate case in its Order for Florida Public Utilities Company in Docket No. 20070304-EI.[48] Witness Nelson asserted the Commission stated, “we have traditionally recognized a reasonable adjustment for flotation costs in the determination of the required return on equity.” (TR 97)

OPC

OPC witness Garrett disagreed with witness Nelson’s position regarding flotation costs. (TR 397) Witness Garrett confirmed that witness Nelson’s did not propose a specific adjustment for flotation costs, but merely suggested flotation costs would have an increasing effect on FCG’s awarded ROE. (TR 399) OPC witness Garrett disagreed with the inclusion of flotation costs in the cost of equity for FCG. Witness Garrett contended that FCG has not experienced any out-of-pocket costs for flotation, and if it did, those costs should be included as an expense. (TR 397) Also, underwriters are not compensated through out-of-pocket costs, but are compensated through an underwriting spread which is the difference between the price at which the underwriter purchases the shares from the firm, and the price at which the underwriter sells the shares to investors. (TR 397) Furthermore, FCG is not a publicly traded company, which means it does not issue securities to the public and thus would have no need to retain an underwriter. (TR 397) Witness Garrett also opined that when an underwriter markets a firm’s securities to investors, the investors are well aware of the underwriter’s fees and have already considered and accounted for flotation costs when making their decision to purchase shares at the quoted price. (TR 398) As a result, OPC argued, it is inappropriate to add any additional basis points to an awarded ROE that is already far above FCG’s cost of equity, and therefore, flotation costs should be disallowed. (TR 398)

FEA

FEA witness Walters did not specifically address flotation costs in his testimony.

Risk Analysis

FCG

FCG witness Nelson asserted because the gas proxy group is not identical in risk to FCG, an assessment of the differences in risk between FCG and the proxy group must be undertaken in order to develop an appropriate estimate of the Company’s cost of equity. (TR 82-83) Therefore, witness Nelson considered FCG’s significantly smaller size, the regulatory environment in which it operates, its proposed multi-year rate plan, and the effect of flotation costs in determining where the Company’s cost of equity falls within the range of analytical results. (TR 82-83) In Issue 71, staff is recommending that FCG’s four-year rate proposal is unenforceable and would not result in any benefits to customers.

Witness Nelson contended smaller utility companies are less able to withstand adverse events that affect their revenues and expenses. (TR 84) Witness Nelson asserted capital expenditures for system maintenance and replacements put proportionately greater pressure on customer costs, potentially leading to customer attrition or demand reduction which affect the return required by investors for smaller companies. (TR 84) Witness Nelson contended it is appropriate to consider the risk associated with FCG’s small size even though its ultimate parent is NextEra Energy. (TR 85) Witness Nelson asserted the widely accepted standalone principle in the regulatory and financial communities treats each utility subsidiary as its own company. (TR 85) Witness Nelson asserted the cost of equity is a function of the risk of the equity investment, not on the source of equity funding (the parent company). (TR 85) When funding is provided by a parent entity, the return still must be sufficient to provide an incentive to allocate equity capital to the subsidiary or business unit rather than other internal or external investment opportunities. (TR 85-86)

To quantify the affect of FCG’s smaller size on the cost of equity, witness Nelson compared the market capitalization of FCG to the median size of the gas proxy group. (TR 87) The implied market capitalization based on witness Nelson’s calculation was $548.53 million for FCG. The proxy group median market capitalization is approximately $4.36 billion, which is approximately 7.94 times FCG’s implied market capitalization. (EXH 37; TR 87) Based on Duff & Phelps’s market capitalization data in its Cost of Capital Navigator, FCG’s implied market capitalization of $548.53 million falls within the 9th decile of all publicly traded companies and corresponds to a size premium of 210 basis points. (TR 87) The proxy group market capitalization of $4.36 billion falls within the fifth decile which corresponds to a size premium of 89 basis points. (TR 87; EXH 36) The difference between those size premiums is 121 basis points. Although witness Nelson quantified the small size effect, she did not make an adjustment to increase her recommended ROE, but alternatively, she considered FCG’s smaller size to determine where FCG’s ROE should fall within the range of her analytical results. (TR 87)

Witness Nelson also contended the regulatory environment is one of the most important issues considered by both debt and equity investors in assessing the risks and prospects of utility companies. (TR 94) Witness Nelson asserted the operating companies within the proxy group have similar cost recovery and ratemaking mechanisms as FCG, although the Company’s multi-year rate plan introduces some incremental risk. (TR 94-95) Witness Nelson contended because utilities are capital intensive enterprises, it is essential that the ROE and capital structure authorized in this proceeding 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. (TR 95)

OPC

OPC witness Garrett disagreed with witness Nelson’s assertion that FCG’s smaller size as compared to the proxy group should have an increasing effect on FCG’s awarded ROE. (TR 394) Witness Garrett contended that the small size adjustment phenomenon arose from a study in 1981 by Rolf W. Banz which indicated that the common stock of small firms had on average higher risk-adjusted returns that larger firms.[49] (TR 394) Witness Garrett contended that there were subsequent studies that found the size effect phenomenon disappeared within a few years after it was discovered and the authors of the study concluded it is inappropriate to automatically expect there to be a small-cap premium on every stock.[50] (TR 395) Witness Garrett cited two additional publications that discredited the small size risk premium theory and concluded the Commission should reject witness Nelson’s testimony that size should automatically have an increasing effect on its cost of equity as estimated through the DCF model and CAPM. (TR 396) Further, OPC witness Garrett contended that public utilities are characterized as defensive firms that have low beta coefficients, low market risk, and are relatively insulated from overall market conditions which should be reflected in FCG’s authorized ROE (TR 357-359)

FEA

FEA witness Walters asserted the market’s assessment of FCG’s investment risk is described by credit rating analysts’ reports. (TR 454) FCG is not an independently rated entity and therefore does not have any reports detailing its overall risk from a ratings analysts, and for that reason, witness Walters reviewed the overall risk of its parent, FPL. (TR 454) FPL’s current credit ratings from S&P and Moody’s are “A” and “A1”, respectively. (TR 454) FPL currently has a “Stable” outlook from both ratings agencies. (TR 454) Specifically, in its most recent report covering FPL, S&P stated in pertinent part:

Business Risk: Excellent

Supporting FPL's business risk profile are: its largely residential customer base, which accounts for about 58% of its operating revenue; its effective management of regulatory risk; and its above-average economic and customer growth, demonstrated by Florida outperforming the national GDP growth rate in the past seven consecutive years and, consequently, strong energy demand. At the same time, Florida's economy continues to recover from the impacts of the ongoing COVID-19 pandemic, demonstrated by improvements in the unemployment rate and consumer confidence. The FPSC regulates FPL. We view the regulatory environment in Florida as constructive and supportive of credit quality.

Financial Risk: Intermediate

We assess FPL's stand-alone financial measures using our medial volatility financial benchmarks to reflect its lower-risk regulated electric utility operations and its effective management of regulatory risk. Our base case scenario assumes that the company will maintain its regulatory capital structure, reflecting an equity ratio of about 60%, a robust capital spending program, and timely recovery of costs through the use of constructive regulatory mechanisms. Overall, we expect the company's stand-alone FFO to debt to reflect 30%-33%, over the next three years, which is consistent with the middle of the range for the company's financial risk profile category.

(TR 454-455)

FEA witness Walters contended the major business risks identified by FEA witness Nelson are already reflected in the financial metrics of the companies in the proxy group and the use of a proxy group fully captures the investment risk of FCG. (TR 498) Witness Walters further contended financial theory generally, and the CAPM specifically, is predicated on the idea that investors should only be compensated for taking on market risk, whereas specific business risk can and will be diversified away. (TR 498) Witness Walters asserted witness Nelson’s attempt to compensate investors for specific business risks is contrary to financial theory, and violates the underpinnings of the CAPM, a model which witness Nelson relied on heavily to support her recommendation. (TR 498) For these reasons, FEA argued witness Nelson’s additional risk factors should be disregarded as a justification to support a higher ROE. (TR 498) FEA witness Walters opined witness Nelson provided evidence to support the assertion that FCG is of similar, if not lower, risk relative to the proxy group. (TR 498-499) Therefore, any conclusion drawn by witness Nelson suggesting that FCG is of higher risk relative to the proxy group used to estimate its cost of equity capital should be explicitly rejected. (TR 498-499)

Witness Walters disagreed with witness Nelson’s small size adjustment presumption. (TR 499) Witness Walters contended witness Nelson applied a size adjustment without even considering that FCG is a wholly-owned subsidiary of FPL, which is a wholly-owned subsidiary of NextEra Energy. (TR 499) NextEra Energy has a market capitalization of approximately $174.7 billion and FPL’s hypothetical market capitalization is $63.2 billion, easily placing it in the top decile. (TR 499-500) Witness Walters contended a size adjustment is not justified in the way performed by witness Nelson because she has not accurately measured the corporate structure which owns FCG and the size-specific risk is already incorporated in the Company’s credit rating and should be rejected. (TR 500)

Capital Market Environment

FCG witness Nelson opined over the last two years, the economic and financial market environment has operated under heightened market uncertainty. (TR 111) Witness Nelson asserted investors are increasingly faced with inflationary pressures, and long-term interest rates have increased substantially since the historic lows of 2020 and are expected to continue to increase. (TR 111)

Witness Nelson also contended that market volatility has remained elevated relative to historical levels. (TR 100) A widely reported measure of expected market volatility is the Chicago Board Options Exchange Volatility Index (VIX). (TR 98-101) Witness Nelson opined that since November 2022, the VIX has been increasing as a result of inflation concerns and the conflict in Ukraine and is significantly higher than in previous years. (TR 100) Witness Nelson asserted although volatility declined somewhat from its March 2020 highs as the Federal government and central bank implemented fiscal and monetary policies to stabilize the U.S. economy, market volatility remains, and is expected to remain, above historical levels. (TR 103) Witness Nelson opined that according to a study by Morning Star during volatile markets there often is little distinction in returns across assets, and when that happens, utility stocks lose their defensive quality. (TR 105)

Witness Nelson asserted her ROE recommendation also considered the current interest rate environment. (TR 106) The 30-year U.S. Treasury Bond yield has increased nearly 100 basis points (from 1.99 percent to 2.95 percent) since the Federal Reserve signaled on November 3, 2021, that it would begin tightening monetary policy by tapering its asset purchases. (TR 106) Further, witness Nelson opined that according to Blue Chip Financial Forecasts, the 30-year U.S. Treasury Yield is expected to be 3.4 percent on average over the next five years. (TR 107)

Witness Nelson asserted that higher inflation has several implications for utilities and their cost of capital. (TR 109) Witness Nelson opined that if investors expect increased levels of inflation, they will require higher yields to compensate for the increased inflation risk which means interest rates and debt costs will increase. (TR 109) Inflation also increases utility operating expenses. (TR 109) As expenses and costs rise, revenues and cash flow decline, putting downward pressure on credit metrics. (TR 109)

FEA witness Walters disagreed with witness Nelson that the VIX supports her assertion that the investment risk of FCG is increasing. (TR 501) Witness Walters opined the VIX is a broader-based index of stock volatility and not applicable to the utility subsector nor does it indicate a similar change in investment risk for regulated utility companies. (TR 501) The VIX is a measure of 30-day expected volatility, which is a relatively short-term estimate, and does not represent the volatility level effective during the period rates will be determined in this regulatory proceeding. (TR 501) Witness Walters disagreed with witness Nelsons’ presumption that market sentiments support her findings that FCG’s market cost of equity is currently 10.75 percent. (TR 501) Witness Walters opined a fair analysis of utility securities shows the market generally regards utility securities as low-risk investment instruments and supports the finding that utilities’ cost of capital is low in today’s marketplace. (TR 501) Witness Walters graphically demonstrated the S&P 500 Gas Utilities index has outperformed the S&P 500 by 27.54 percentage points from June 30, 2021 through June 30, 2022. (TR 501-502)

ROE With RSAM

In the event the Commission approves the RSAM, staff recommends the Commission lower the allowed ROE by up to 50 basis points to recognize the decrease in the variability of earnings, and therefore risk, associated with the RSAM. As stated by FCG witness Nelson, “…equity investors have a claim on cash flows only after debt holders are paid, and the uncertainty (or risk) associated with those residual cash flows determines the cost of equity.” TR (50) Additionally, FCG witness Campbell stated, “Simply put, the RSAM will allow FCG to absorb changes primarily in cash revenues and expenses while maintaining a pre-established ROE within its authorized range without an increase in customer rates.” (TR 1065) In staff’s opinion, the evidence clearly indicates the RSAM reduces earnings variability and consequently the uncertainty (or risk) of FCG’s earnings and cash flows. An allowed return on equity of 9.50 to 10.00 percent will still be above the average authorized ROE for gas utilities in 2022 (approximately 9.38 percent) and FCG would have an RSAM and a 59.6 percent equity ratio as a percent of investor capital as well. (TR 438)

Summary

Staff believes 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. As such, the Commission should place greater weight on the results from the traditional forms of the DCF Model and the CAPM. OPC witness Garrett’s DCF results were 7.1 percent and 8.0 percent. Staff agrees with FCG witness Nelson 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 should 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. (TR 376) An objective review of FCG witness Nelson’s DCF results established the average of her constant growth DCF model at 9.72 percent and the average of her quarterly growth DCF model at 9.86 percent. (EXH 31, 32) 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. (EXH 83) The average of FCG and FEA witnesses’ DCF Model results is 9.2 percent. 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 percent to 10.97 percent for FEA. Staff agrees with witness Nelson that witness Garrett’s CAPM result of 7.9 percent is unreasonable low and should be given little weight because he used a current risk-free rate, which is now stale, and an unreasonably low ERP estimates based on various publications of ERP surveys. Staff agrees with FEA witness Walters that witness Nelson’s projected market required return of 14.64 percent in the CAPM is overstated and unreasonable. Therefore, staff believes witness Nelson’s highest results of 12.80 and 12.94 percent from her traditional CAPM should be given less weight. Staff believes the record provides stronger support for her results of 10.12 percent and 10.33 percent based on an estimated market return of 12.33 percent. (EXH 34) The average of those results is 10.23 percent. Staff agrees with FCG witness Nelson that FEA witness Walter’s use of the MI beta coefficient of 0.70 in his CAPM is questionable and subject to analyst bias in selecting the inputs to the model. (TR 214-217) Staff also agrees with FCG witness Nelson’s criticism of witness Walters’ use of Kroll’s ERP of 5.5 percent and the results of the CAPM using that data should be given little weight. (TR 171-173) The average results from FEA witness Walter’s CAPM results, excluding five estimates using the MI beta and/or Kroll’s ERP estimate is 10.36 percent. The average of the results from FCG and FEA witnesses’ CAPM analyses is 10.3 percent.

After eliminating some of the witnesses’ results produced by questionable assumptions and inputs used in the DCF and CAPM models, 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. Witness Nelson’s FCG’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. Staff believes the witnesses’ risk premium results confirm that staff’s composite ROE of 9.75 is within the range of reasonableness. This result is also greater than the national average authorized ROE for gas utilities in 2022 of approximately 9.38 percent. (TR 438)

Record evidence supports the risk-return concept that utilities with lower financial risk should be allowed lower returns. Hence, the allowed return on equity and the equity ratio are inextricably related. The record evidence demonstrates FCG has a much higher equity ratio (59.6 percent) than the average of the gas proxy group (47 percent), and as such, FCG has less financial risk than the proxy group average. Therefore, FCG’s required return on equity should be lower than the average return on equity of the gas proxy group. However, FCG witness Nelson provided a persuasive argument that FCG’s small size based on market capitalization as compared to the gas utilities in the proxy group suggests a small size adjustment is appropriate. (TR 84-87) Accordingly, staff agrees with witness Nelson that consideration of where the investor-required return exists on the range of returns is appropriate. However, staff believes FCG’s higher equity ratio and financial strength balance out any risk associated with its smaller size and a numerical adjustment is not necessary or reasonable.

Further, record evidence confirms that the financial information and data used by the witnesses to formulate their cost of equity models and analysis was based on information available in the first half of 2022. Since that time market conditions have changed, including rising interest rates, historic rising inflation, in addition to increased volatility in the stock market, which puts upward pressure on the cost of equity going forward. (TR 111) Therefore, staff believes the record evidence supports an ROE of 10.00 percent for FCG which is above the current national average of awarded ROEs of 9.38 percent and would 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.

In the event the Commission approves the RSAM, staff recommends the Commission lower the allowed ROE by up to 50 basis points to recognize the decrease in the variability of earnings, and therefore risk, associated with the RSAM. As stated by FCG witness Nelson, “… equity investors have a claim on cash flows only after debt holders are paid, and the uncertainty (or risk) associated with those residual cash flows determines the cost of equity.” TR (50) Additionally, FCG witness Campbell stated, “Simply put, the RSAM will allow FCG to absorb changes primarily in cash revenues and expenses while maintaining a pre-established ROE within its authorized range without an increase in customer rates.” TR (1065) In staff’s opinion, the evidence clearly indicates the RSAM reduces earnings variability and consequently the uncertainty (or risk) of FCG’s earnings and cash flows. An allowed return on equity of 9.50 to 10.00 percent will still be above the average authorized ROE for gas utilities in 2022 (approximately 9.38 percent) and FCG would have an RSAM and a 59.6 percent equity ratio as a percent of investor capital as well. (TR 438)

CONCLUSION

Based on the analysis of the record evidence discussed above, the appropriate authorized ROE midpoint is 10.00 percent with a range of plus or minus 100 basis points. If the Commission approves an RSAM in Issue 67, the appropriate authorized ROE midpoint is 9.50 percent with a range of plus or minus 100 basis points.

Issue 30:

Has FCG made the appropriate adjustments to remove all non-utility investments from the common equity balance?

Approved Type II Stipulation:

FCG does not have any non-utility investments and therefore, adjustments were not required.

Issue 31:

What is the appropriate weighted average cost of capital to use in establishing FCG’s projected test year revenue requirement?

Recommendation:

The appropriate capital structure consists of 59.6 percent common equity, 39.39 percent long-term debt, and 5.51 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 in Issues 24 through 29, the appropriate weighted average cost of capital for FCG for purposes of setting rates in this proceeding is 6.70 percent. (D. Buys)

Position of the Parties

FCG:

The associated components, amounts, and cost rates with RSAM are reflected on Exhibit LF-11 for the 2023 projected test year. Based on those amounts, the appropriate after-tax weighted average cost of capital (“WACC”) for the 2023 projected test year is 7.09%. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate after-tax WACC without RSAM for the 2023 projected test year is also 7.09% as reflected on Exhibit LF-12. (Fuentes)

OPC:

OPC Witnesses Garrett and Schultz testimony, including errata, and exhibits show the appropriate weighted average cost of capital of 5.75% to use in establishing the projected test year revenue requirement.

FEA:

FEA did not specify an appropriate weighted average cost of capital to use in establishing FCG’s projected test year revenue requirement. Notwithstanding the above, adopting the cost of capital parameters proposed by Christopher Walters, including a return on common equity of 9.40% and a common equity ratio of 50.0%, would produce a weighted average cost of capital of approximately 5.95%.

FIPUG:

Adopt position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued the appropriate after-tax WACC with RSAM for the 2023 Test Year is 7.09 percent as presented in FCG witness Fuentes recalculated revenue requirement. (FCG BR 57; EXH 112.) 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. (TR 1070) 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. (TR 1070) FCG argued the Intervenors’ recommended WACCs are based on their proposed capital structure and midpoint ROE, which should be rejected for the reasons explained in Issue Nos. 28 and 29. (FCG BR 57) FCG argued for the same reasons, the Intervenors’ proposed WACCs should be rejected. (FCG BR 57)

OPC

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 BR 43; TR 336) 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 BR 43; TR 336) 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. (OPC BR 43) OPC witness Garrett recommended that the Commission impute a capital structure for ratemaking purposes consisting of long-term 53.1 percent debt, and a 9.25 percent return on equity. (OPC BR 43; TR 328,411-412) This would result in a WACC of 5.75 percent. (OPC BR 43; TR 328, 411-412)

FEA

FEA did not specify an appropriate weighted average cost of capital to use in establishing FCG’s projected test year revenue requirement. (FEA & FIPUG BR 20) However, FEA recommended the Commission 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. (FEA & FIPUG BR 20)

FIPUG

FIPUG did not provide an argument. (FEA & FIPUG BR 19)

ANALYSIS

The WACC is a fall-out issue that incorporates the amounts and cost rates of the capital sources into a final WACC. The amounts and cost rates of the capital components are recommended in Issues 24 through 29. 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. (TR 1070; EXH 7) In her rebuttal testimony, FCG witness Fuentes included revised projected 2023 test year cost of capital schedules, but the WACC did not change. (TR 828; EXH 112) 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. (TR 1070; EXH 111, 112) 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. (EXH 112) FCG’s requested capital structure is summarized in Table 31-1

ANALYSIS

This is a fallout issue based on the resolution of other issues. Per staff’s recommendation on Issues 2 and 3, 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 in Issue 35, staff agrees with the Company that miscellaneous revenues at current rates for the projected test year should 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. (TR 265) This adjustment results in projected Total Operating Revenues in the amount of $64,724,868 for the projected test year.

Table 36-1

Calculation of Company Total Operating Revenue for the Projected Test Year

Total Revenue from Sales of Gas at Current Rates	Miscellaneous Revenues (including Company adjustments)	Total Operating Revenue
$62,828,352	$1,896,516	$64,724,868

Source: EXH 6; EXH 25; TR 265

In its brief, OPC referenced FCG witness Campbell’s cross examination in which he was questioned by staff counsel regarding additional revenues resulting from customer growth in 2024 and 2025. OPC cites witness Campbell’s admission of exclusion of this additional revenue for 2024 and 2025, as well as his admission of the reduced reliability of customer and therm forecasts the further they project into the future, as reasons to doubt the accuracy of FCG’s projected Total Operating Revenue (OPC BR 44) However, as was the case with Issues 2 and 3, staff believes that OPC’s argument in the instant issue appears to be unrelated to the issue itself. The Intervenors did not present testimony or evidence to disprove FCG’s projected Total Operating Revenues for the projected test year.

Therefore, staff recommends that $64,724,868 is the appropriate level of total operating revenues for the 2023 projected test year.

CONCLUSION

Staff recommends that FCG’s projected Total Operating Revenue in the amount of $64,724,868 for the projected test year is appropriate.

Issue 37:

Has FCG made the appropriate adjustments to remove all non-utility activities from operation expenses, including depreciation and amortization expense?

Approved Type II Stipulation:

Yes.

Issue 38:

What is the appropriate amount of salaries and benefits to include in the projected test year?

Recommendation:

The appropriate amount of salaries and benefits to include in the projected test year is $14,803,183. Employee pension & benefits expense should be decreased by $505,222. (Snyder)

Position of the Parties

FCG:

As adjusted on Exhibit LF-11 (with RSAM) and LF-12 (without RSAM), the appropriate amount of salaries and benefits, including incentive compensation amounts allocated from FPL, to include in the Test Year is $14,803,183. One hundred percent of the 2023 Test Year level of Salaries and Employee Benefits expense is appropriate, and reflects that portions of executive and non-executive incentive compensation allocated from FPL have been excluded consistent with Order No. PSC-2010-0153-FOF-EI. The reasonableness of salary and benefit expense is demonstrated by comparison of FCG’s salaries, annual pay increase program, and non-executive variable incentive pay to the relevant comparative market. (Howard, Slattery)

OPC:

Base payroll should be reduced by $793,501. Excessive incentive compensation should be reduced by $524,119. Incentive compensation should be reduced by $398,746. Long term incentive compensation should be reduced by $163,461. Benefits should be reduced to match actual employee complement in the amount of $49,533. Payroll taxes should be reduced by $122,767 as reflected in Issue 52. Affiliate payroll related expenses should be reduced by the amount of $405,440, and affiliate SERP expense should be reduced by $29,576.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that the appropriate amount of salaries and benefits for the 2023 Test Year is $14,803,183. FCG also stated that FCG’s expense request for 2023 does not include any type of compensation or benefits expense that the Commission has not previously approved for recovery. (FCG BR 58)

FCG claimed that OPC’s recommended adjustment is based on OPC witness Schultz’s recommendation to set FCG projected headcount for the 2023 Test Year at 173 employees (a reduction of 14 employees) to reflect the actual number of employees as of June 30, 2022. FCG argued that this number fails to account for FCG’s staffing forecast or requirements in the 2023 test year. (FCG BR 58-59) FCG claimed that the number of employees on June 30, 2022 was lower because of certain hiring difficulties, such as COVID, and that there have been significant efforts to fill all of the positions needed to run efficiently. (FCG BR 59)

FCG recalled that, in its original filing, it did not remove any incentive compensation costs from the 2023 Test Year because there is no specific order requiring FCG to make such an adjustment to its incentive compensation expense. (FCG BR 60; TR 994) OPC witness Schultz recommended a disallowance of 100 percent of the $163,461 in long-term non-executive cash incentive compensation expense. FCG stated that OPC failed to offer any explanation or justification why 100 percent of FCG’s long-term non-executive cash incentive compensation expense should be excluded. OPC witness Schultz also recommended a disallowance of $922,865 of the 2023 Test Year short-term non-executive cash incentive compensation expense. (FCG BR 61) FCG claimed its 2023 Test Year payroll expenses are reasonable based on the annual benchmarking of the total compensation package compared to relevant market data, using a variety of nationally recognized third-party compensation survey sources. (FCG BR 63; TR 998-999)

OPC

OPC stated that since FCG is using the same incentive plan as FPL, FCG should treat the costs of the incentive compensation for setting rates the same as FPL. (OPC BR 45; TR 306-12) OPC argued that FCG failed to take a vacancy factor into account when determining the number of employees. (OPC BR 45) OPC also stated that in 2021, the actual payroll was $11,232,775, which was $1,893,794 under the Company budget of $13,126,569. Based on the most known and measurable employee count of 173 FTEs, as of June 2022, OPC recommended the payroll expense request of $10,598,909 should be reduced by $793,501 to $9,805,408. (OPC BR 46; TR 306)

OPC also argued that long term incentive compensation should be reduced by $163,461. (TR 312) Benefits should be reduced to match actual employee complement in the amount of $49,533. (TR 312) Payroll taxes should be reduced by $122,767 as reflected in Issue 52. (TR 321) Affiliate payroll related expenses should be reduced by the amount of $405,440, and affiliate SERP (Supplemental Executive Retirement Plan) expense should be reduced by $29,576. (OPC BR 46-47; TR 312, 320-321, 524).

FEA

FEA did not provide an argument. (FEA & FIPUG BR 21)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 21)

ANALYSIS

In its brief, FCG stated that the appropriate amount of salaries and benefits for the 2023 Test Year is $14,803,183 (EXH 112) OPC witness Schultz’s testimony reflected adjustments to several components of the Company’s total compensation package. The proposed adjustments to the Company’s amount of salaries and benefits in the projected test year are further discussed below.

Salaries and Full Time Employees (FTEs)

Witness Schultz testified that the employee complement of 187 FTEs is inappropriate and does not consider a vacancy factor. (TR 304) As of June 30, 2022, FCG had filled 12 positions, and the employee count should be 175. (TR 304) The employee count was at 173 indicating that while employees were added, others left. (TR 304) Witness Schultz added that the projected employee complement for 2021 was 175 FTEs and FCG had a year-end complement of 163 and an average complement of 159 FTEs. (TR 304) Further, he stated in his testimony that FCG did not provide specifics on what positions were required and why they were needed. In response to discovery, FCG referred to FCG witness Howard’s testimony which stated that the request was reasonable and appropriate but did not provide justification. (TR 305) Witness Schultz is recommending a head count of 173 FTEs. Further, he states that in 2021, actual payroll, excluding recovery clause costs for 2021, was $1,893,794 under budget over the actual of $13,126,569. He states the FCG forecast employee complement and budget costs are over optimistic compared to historical data. (TR 305) Witness Schultz also recommended a $49,533 reduction to employee benefits. This recommendation is based on OPC’s adjustment for the number of FTEs. (TR 312)

In its brief, FCG countered OPC’s adjustment, and stated that OPC failed to account for FCG’s staffing forecast or requirements in the 2023 test year. (TR 991) Witness Slattery testified that in 2019 and 2020, actual head count exceeded the budgeted headcount to support the replacement of services and functions provided by Southern Company and growth in the business. (TR 991) In 2021, FCG faced difficulties to fill forecasted positions. (TR 991) Witness Slattery stated these difficulties included “limited availability of a technical and engineering related labor force, 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.” (TR 991) She also stated that there was a skilled labor shortage due in part to the COVID-19 pandemic, “the Great Resignation,” and the rise in remote work. (TR 992) She asserted, that despite these factors, FCG put significant efforts in 2022 to fill the open positions. As of September 22, 2022, eight positions have been filled which increased the employee headcount to 180 FTEs.

With regards to the vacancy factor asserted by OPC witness Schultz, FCG witness Slattery testified that hiring costs and saving associated with vacancies were offset by the cost of overtime by staff handling vacant positions’ workload and the costs associated with recruiting, onboarding and training new staff. (TR 992)

In his rebuttal testimony, witness Howard stated that FCG provided justification for the increased headcount and explained why each position was required. (TR 617) He further elaborated on the need for the positions as follows:

The insourcing of specific functions, such as leak surveying; (ii) the transition of functions post-acquisition from Southern Company; (iii) positions to support growing customer demands, including account management and engineering needs; (iv) positions supporting the expansion of physical gas infrastructure; (v) support for enhancements to FCG’s customer information system (“CIS”) and helping to implement other technology and initiatives to drive efficiency gains; and (vi) replacement positions.

(TR 617)

In broader terms, he asserted the new positions were created due the physical expansion of FCG’s system and the increase in customer count. (TR 618)

Incentive Compensation

OPC recommended 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. (TR 312; EXH 46) Witness Schultz testified that in Docket No. 20210015-EI, FPL’s portions of executive compensation and non-executive compensation were excluded by Order No. PSC-10-0153-FOF-EI in the 2010 FPL Rate Case.[52] FCG’s incentive compensation costs are based on the plans that FPL excluded from cost recovery in Docket No. 20210015-EI. (TR 307) He stated that, in the Progress Energy Florida (PEF) rate case, the Commission disallowed all of PEF’s requested incentive compensation. (TR 307) The order stated, “PEF should pay the entire cost of incentive compensation, as its customers do not receive a significant benefit from it.”[53]

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. (TR 307) Second, the total projected amount for 2023 is not known because performance and results of operation are not known and there are no goals set. (TR 307) Third, since 2018, almost every employee received incentive compensation. The 2021 historic test year had the lowest percent of employees that received incentive compensation at 85.2 percent. Between 2018 through 2020, 94.7 percent of employees received incentive compensation. (TR 308) The primary reasons for employees not receiving incentive compensation were either late hires, being inactive, or on leave of absence. Witness Schultz stated all employees received incentive compensation in 2018, and, in each of the years 2019 through 2021, only one employee was denied incentive compensation due to poor performance. (TR 308-309) He stated given these facts, FCG’s incentive pay is “really nothing more than supplemental pay.” (TR 309) 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. (TR 311) He stated the financial goals provide benefits to shareholders. (TR 310) He further stated that FCG’s incentive compensation plan is discretionary and that is not what is customarily considered a short-term incentive plan. (TR 311) OPC recommended that $163,461 of the long-term plan costs be excluded and that $922,865 of short-term plan costs be excluded. (EXH 46; TR 312)

Witness Slattery addressed incentive compensation in her rebuttal testimony and proposed a reduction of $505,222 associated with executive incentive compensation. She stated that despite there being no Commission order requiring FCG to do so, FCG removed parts of incentive compensation as the Commission ruled in the 2010 FPL Rate Case Order. (TR 994) She asserted 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.” (TR 995) She stated that OPC’s adjustment to short-term cash incentive compensation would result in a 70-percent decrease not 50-percent. (TR 996) She cited Order No. PSC-12-0179-FOF-EI in which the Commission rejected OPC’s recommendation to disallow all incentive compensation and allowed recovery of all of Gulf Power Company’s employee cash compensation.[54] The Order also stated: “[w]e recognize that the financial incentives that Gulf employs as part of its incentive compensation plans may benefit ratepayers if they result in Gulf having a healthy financial position that allows the Company to raise funds at a lower cost than it otherwise could.” She testified that 85 percent of U.S. based companies have performance-based variable pay and FCG could not compete in the labor market without a market-based cash incentive compensation program. (TR 997)

Addressing FCG’s incentive compensation compared to the market, witness Slattery stated that FCG’s plan is at or below market. (EXH 131; TR 997) If performance-based cash incentive compensation were eliminated, FCG employees would be compensated roughly 9.6-percent below the market median. (TR 998) She stated that FCG would not be able to compete in the labor market if cash-based incentive compensation were to be removed and that “FCG would not be able to attract and retain the number and caliber of employees that are required to deliver on its commitments to its customers.” (TR 998) She elaborated further that, if incentive compensation were to be removed, it would lead to a reduction in performance-based variable cash incentive compensation and increase in base salary and other fixed-cost programs. (TR 1000)

Witness Slattery testified that the reasons a high percentage of FCG employees receive incentive compensation is due to company culture. (TR 1001) Specifically, she cited the performance-based cash incentives help develop a culture of employees committed to performance. (TR 1001) Few employees who stay with FCG fail to meet expectations by the end of the performance period. (TR 1001) With regard to company goals, she stated that they are reassessed annually and are soft goals. (TR 1002) She asserted that, while FCG failed to meet some goals in 2020 and 2021, 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. (TR 1002) Witness Slattery contended that the growth in performance-based cash incentive compensation cost correlates to the growth in headcount and the growth in salaries. (TR 1003)

Staff believes 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.[55] As such, staff recommends decreasing employee pension & benefits expense by $505,222 to recognize the Company’s adjustment to remove executive incentive compensation. Based on this adjustment, the appropriate amount of salaries and benefits to include in the projected test year is $14,803,183.

CONCLUSION

The appropriate amount of salaries and benefits to include in the projected test year is $14,803,183. Employee pension & benefits expense should be decreased by $505,222.

Issue 39:

What is the appropriate amount of the affiliate expense to be included in the projected test year?

Recommendation:

Based on staff’s recommendations in other issues, affiliate expense for the projected test year should be $2,477,003. (Snyder)

Position of the Parties

FCG:

As adjusted in Exhibit LF-11, the appropriate amount of affiliate expense to be included in the 2023 Test Year is $2.5 million. This amount is included in the total amount of operation and maintenance expenses in the calculation of revenue requirements and does not reflect any affiliate costs related to rate case expenses or costs that were transferred from base to clause. (Fuentes)

OPC:

Yes, AMI O&M expense should be removed from the projected test year since the Commission should not grant FCG’s request to burden customers with the cost of this experimental program. OPC Witness Schultz addresses this in his testimony and exhibits including, but not limited to, Schedule C-7.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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 BR 63-64) FCG stated that OPC recommended that $405,400 of costs allocated as part of FPL’s CSC should be excluded. (TR 320-321) FCG argued that these costs relate to executive incentive compensation, which have already been removed by FCG in its rebuttal adjustments explained in Issue 38. (FCG BR 64)

OPC

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. (TR 320) OPC argued that the Company has $405,440 of costs that the Commission disallowed in prior dockets. (EXH 167; TR 320) OPC also claimed that $29,576 of SERP costs were included in Corporate Service Charges. These costs are considered excessive compensation, therefore OPC recommended they be disallowed. (EXH 46; OPC BR 47)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 21)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 21)

ANALYSIS

The Company’s projected test year reflects affiliate expense of $2,982,225. (EXH 160) 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). (TR 798) 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 Corporate Service Charges (CSC). (TR 798) Of the total affiliate expense in the projected test year, $1,257,227 are direct charges and $1,724,997 are billed through CSC.

OPC witness Schultz testified that there were several concerns with affiliate expense in the projected test year. (TR 320) 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. (TR 320) Second, OPC contended that FCG included $405,400 of costs related to incentive compensation that the Commission has disallowed all or part of in prior dockets. (EXH 167; TR 320) Third, supplemental executive retirement plan (SERP) costs in the amount of $29,576 were included in CSC. (EXH 162). 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 latter three concerns are addressed in Issues 38 and 40, respectively. Staff believes no further adjustments are warranted. Based on staff’s recommendations in other issues, affiliate expense for the projected test year should be $2,477,003.

CONCLUSION

Based on staff’s recommendations in other issues, affiliate expense for the projected test year should be $2,477,003.

Issue 40:

What is the appropriate amount of pensions and post-retirement benefits expense to include in the projected test year?

Recommendation:

The appropriate amount of pensions and post-retirement benefits expense to include in the projected test year is $661,618. (Snyder)

Position of the Parties

FCG:

The appropriate amount of Other Post Employment Benefit expense for the 2023 Test Year is $29,845 (adjusted). The appropriate amount of Pension income for the 2023 Test Year is $1,357,212 (adjusted). (Fuentes, Slattery, Campbell)

OPC:

Affiliate SERP costs in the amount of $29,576 should be removed as shown in Issue 39.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued that no adjustments should be made to remove SERP benefit expenses from the corporate service charges. (TR 995) This treatment is consistent with the adjustments made by FPL pursuant to the FPL 2010 Order. (FCG BR 64-65; TR 995)

OPC

As OPC stated in Issue 39, affiliate SERP costs in the amount of $29,576 should be removed. (OPC BR 47)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 21)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 21)

ANALYSIS

FCG requested employee pensions and post-retirement benefits expense of $661,618. (EXH 8) 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. (EXH 46, 48; TR 321). 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).[56] (TR 995) In the FPL 2010 rate case order, the Commission declined to adjust FPL’s forecast for affiliate expense.

Based of the lack of record evidence, staff has no basis to make an adjustment to SERP expense.

CONCLUSION

The appropriate amount of pensions and post-retirement benefits expense to include in the projected test year is $661,618.

Issue 41:

Is the injuries and damages expense in the test year reasonable?

Recommendation:

Yes, injuries and damages expense in the amount of $515,304 in the projected test year is reasonable. (Snyder)

Position of the Parties

FCG:

Yes. As reflected on page 4 of MFR E-6, the reasonable Test Year expense for Account 925 (Injuries & Damages) is $515,304. The record evidence demonstrates FCG’s commitment to safety and minimizing its OSHA-recordable incidents. The record evidence also demonstrates that the increase in the expense for Account 925 (Injuries and Damages) is largely attributable to an increase in the cost of insurance premiums across the business. (Howard)

OPC:

No. OPC Witness Schultz addresses this issue in his testimony and Exhibits including but not limited to, Schedule C-5. The Commission should adjust the injuries and damages expense by $212,790.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that its core values emphasize a commitment to safety. (TR 563; FCG BR 65) 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 BR 65, EXH. 6.)

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. (TR 314-315; FCG BR 65) FCG stated that OPC’s claims are without merit and should be rejected. (FCG BR 65) FCG asserted that OPC’s reliance on OSHA-recordable events is misplaced and that while it is a useful metric, it does not necessarily demonstrate overall workplace safety. (FCG BR 64) 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 BR 64) 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 the strains and sprains variety. FCG additionally stated that since 2019, the Company has never had more than three OSHA recordable incidents within a year. (TR 619; FCG BR 65-66) FCG then explained that the increase in the cost is the result of increases in insurance premiums across the industry and the reclassification of expenses. (TR 620; FCG BR 66) FCG then reiterated that the amount requested for injuries and damages expense is reasonable and should be approved. (TR 620; FCG BR 66)

OPC

OPC argued the storm reserve at present was adequately funded since 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 BR 49) OPC also argued that the Company’s Reserve Study estimated the annual storm cost to be $190,000; however, this was not consistent with the historical record. When questioned on the reserve amount being much higher than historical costs, FCG asserted that it had instead relied on the findings of an independent expert. OPC argued that the annual accrual of $57,500 should be discontinued as of January 1, 2023. (OPC BR 50)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 22)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 22)

ANALYSIS

Rule 25-7.0143, F.A.C., addresses 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. 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. (TR 1071) 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 the Commission’s storm rule applicable to electric utilities. (TR 1071-1072) The Commission has since adopted Rule 25-7.0143, F.A.C., which became effective June 28, 2021 and is specific to gas utilities. Therefore, 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., rather than Rule 25-6.0143, F.A.C., as was specified in the 2018 Settlement Agreement. However, FCG is not requesting any changes to the annual accrual or target reserve amounts. (TR 1072)

OPC witness Schultz testified that the Company’s storm reserve balance was $162,290 as of March 31, 2022. Witness Schultz 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 to $1,264 a month or $15,164 annually. (TR 313) Therefore, FCG could charge $15,164 to the storm reserve every year for more than 10 years before the storm reserve was fully depleted. (TR 313-314)

Witness Schultz testified that he also reviewed the Company’s Reserve Study, which estimated the annual cost to FCG based on simulated hurricanes. Witness Schultz stated that while the Reserve Study observed that the annual cost due to hurricanes will vary from year to year, it concluded that there would be a few years where large costs would be incurred. The largest cost recorded by the Company since FCG was acquired by FPL was $48,626 in 2020. Given this, witness Schultz testified that the storm reserve is currently sufficient .for the next 10 plus years. (TR 313)

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. (TR 621) Witness Howard stated 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. (TR 621-622) 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.” (TR 622) 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. (TR 622) 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. (TR 622-623)

Based on the conclusions of the Reserve Study, staff believes the storm reserve mechanism should 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 does not seem to be 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. Staff does not believe any persuasive information was presented that warrants discontinuing FCG’s previously approved storm reserve mechanism or modifying 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.

CONCLUSION

Staff recommends continuation of FCG’s Storm Damage Reserve provision as included in the 2018 Settlement Agreement and consistent with Commission Rule 25-7.0143, F.A.C., with no change to the annual storm damage accrual of $57,500 and target reserve amount of $800,000.

Issue 46:

Is a Parent Debt Adjustment pursuant to Rule 25-14.004, Florida Administrative Code, appropriate, and if so, what is the appropriate amount?

Recommendation:

No, a parent debt adjustment pursuant to Rule 25-14.004, Florida Administrative Code, is not appropriate. (Cicchetti, D. Buys)

Position of the Parties

FCG:

No. Upon FCG’s 2018 acquisition by FPL, there was no significant change in FCG’s total per book capital structure value and the initial investment and resulting goodwill to acquire FCG is maintained at FPL as non-utility investment. Further, FCG receives all of its debt and equity from FPL pursuant to Commission-approved Financing Applications. FCG has proposed a 2023 Test Year financing capital structure equal to FPL’s, which consists of 59.6% common equity and 40.4% debt over investor sources. As such, no additional interest expense tax benefit exists at the parent level and no parent debt adjustment is appropriate. (Campbell)

OPC:

Yes, a Parent Debt Adjustment is appropriate and is required by Rule 25-14.004, F.A.C. in this case. OPC Witness Schultz addresses this issue in his testimony and exhibits including, but not limited to, Schedules C and C-12. The Commission should approve a Parent Debt Adjustment of $382,452.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG witness Campbell testified that FCG has received 100 percent of its debt and equity financing from FPL’s pool of funds and that pool of funds was available based on FPL’s capital structure. Given this fact, 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 therefore 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, FPL, which consists of 59.6 percent common equity and 40.4 percent debt as a percentage of investor sources of funds. (TR 1112-1113)

OPC

OPC argued the issue is simple. The Commission has an effective, valid rule 25-14.004, F.A.C. (PDA Rule) that is not subject to waiver (requested or granted 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 BR 50) 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. (EXH 46, Schedule C-12; OPC BR 54)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 22)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 22)

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. The premise that debt issued by the parent is invested in the equity of the subsidiary presumes double leverage exists. Leverage exists when debt is used, at least in part, to finance assets. As long as the firm overall earns more than the after-tax cost of debt, shareholder returns are increased, i.e., levered. Double leverage is presumed to exist when a parent company issues debt and some or all of that debt is assumed to be invested in a subsidiary that also issues its own debt, i.e., the leverage is doubled.

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. (TR 1111) FCG has proposed a 2023 test year capital structure equal to the capital structure of FCG’s parent, FPL, which consists of investor sources of funds of 59.6 percent common equity and 40.4 percent debt. (TR 1112-1113)

FCG does not issue its own debt or equity in the marketplace. (TR 1113) Because FCG does not issue its own debt, there is no double leverage. In the instant case, FCG has petitioned, and staff is recommending, that 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. 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 a parent debt adjustment is neither necessary nor appropriate under the PDA Rule.

CONCLUSION

Issue 47:

What is the appropriate annual amount and amortization period for Rate Case Expense?

Recommendation:

The appropriate annual amount of Rate Case Expense should be reduced by $27,570 to result in a total Rate Case Expense of $470,209. The appropriate amortization period is four years. (Hinson)

Position of the Parties

FCG:

As shown in Exhibit LF-7, the appropriate annual amount of FCG’s rate case expense is $470,209. The appropriate amortization period is four years. (Fuentes)

OPC:

OPC Witness Schultz addresses this issue in his testimony and exhibits including, but not limited to, Schedule C-8. Rate case expense should be amortized over four years. The appropriate annual amount of rate case expense should be reduced by $142,785.

FEA:

Brian Collins’ testimony provides that the appropriate amount for rate case expense should be the amount approved in the prior rate case adjusted for inflation, or approximately $1.427 million. This would lower FCG’s amortization expense by $141,000 and lower the deferred rate case expenses in rate base in 2023 by approximately $494,000.

FIPUG:

Join position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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 filing estimate $1.9 million. (FCG BR 72; EXH 102). 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. (TR 794; FCG BR 73) FCG pointed out that no parties opposed the four-year amortization period. (TR 815; FCG BR 73)

FCG opined that the primary driver of Rate Case Expense is the amount of work involved to litigate the case. (TR 809; FCG BR 73). FCG stated that it took a bottom-up approach to estimate the work involved to prepare, file, and litigate this rate case. (FCG BR 73). The Company then explained this estimate was benchmarked against work and time involved in Docket No. 20210015-EI, as well as in Docket No. 20170179-GU and Docket No. 20200051-GU. (FCG BR 73). The Company explained that it is important to remember the amount of work involved with a rate case is due to factors largely out of the control of the Company. (TR 815; FCG BR 73).

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. (TR 815; FCG BR 75)

OPC

OPC stated that the test year costs have increased by $769,350 or 62.97 percent over the costs from Docket No. 20170179-GU. (TR 317; OPC BR 54) OPC then stated that while the scope of the study has increased, the requested amount is still excessive. (TR 318; OPC BR 55). OPC asserted that the $1,564,981 FPL replacement cost is unwarranted. (TR 318; OPC BR 55). OPC pointed out that these costs are higher than the benchmark Rate Case Expense of $1,476,260 applicable to Docket No. 20170179-GU. (OPC BR 55; EXH 46). OPC stated an additional concern over the fact that the Company failed to take advantage of the Proposed Agency Action method and asserted FCG’s choice to do so burdened customers and benefited shareholders. (TR 318-319; OPC BR 55).

FEA

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. (TR 520, TR 537; FEA & FIPUG BR 23) 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 and why this level of support was not needed in earlier rate cases. (TR 538; FEA & FIPUG BR 23) FEA witness Collins argued that the Commission should limit FCG’s rate case 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. (TR 520, TR 537; FEA & FIPUG BR 23)

FIPUG

FIPUG joined the argument of FEA. (FEA & FIPUG BR 22-23)

ANALYSIS

FCG’s initial filing of Rate Case Expense was $1,991,116. (EXH 107) OPC argued that the amount of rate case expense was excessive and unnecessary, being that FCG’s requested costs were higher than its eliminated costs. (TR 318; OPC BR 55) OPC witness Schultz stated that FCG’s decision to ignore a streamlined regulatory approach, the Proposed Agency Action method, designed by the Legislature to benefit customers was an attempt by FCG to benefit its shareholders and a failure to assist FCG customers. (TR 319) FEA suggested that the Rate Case Expense be the same amount for FCG’s last rate case, adjusted for inflation, resulting in an approximate total of $1.427 million. FEA asserted that FCG did not demonstrate which services were provided by FPL’s affiliate support, causing the 63 percent increase in Rate Case Expense. (TR 520, TR 537; FEA & FIPUG BR 23) Because of this, FEA stated that the amount is unjustified. (TR 537-538)

FCG stated that arguments made by OPC and FEA are without merit and unreasonable due to the nature of the costs associated with a fully litigated rate case. (TR 815; FCG BR 75) 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. The components of the Company’s estimated Rate Case Expense are reflected in the table below.

Table 47-1

Rate Case Expense

Category	Initial Filing	Revised
Depreciation Study/Witness	$157,862	$107,000
ROE Witness	$60,000	$60,000
Legal	$150,000	$67,040
FPL	$1,564,981	$1,530,518
NEER		$1,274
Traveling/Hearing Expenses	$18,200	$53,387
Temporary Services		$7,862
Other	$40,073	$53,755
Total	$1,991,116	$1,880,836

Source: EXH 107

Staff has examined the requested actual and estimated expenses, along with supporting documentation, and believes 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 staff believes it is reasonable.

CONCLUSION

The appropriate annual amount of Rate Case Expense is $470,209. The appropriate amortization period is four years.

Issue 48:

Should an adjustment be made to Uncollectible Accounts and for Bad Debt in the Revenue Expansion Factor?

Approved Type II Stipulation:

No.

Issue 49:

What is the appropriate amount of projected test year O&M expenses?

Recommendation:

The appropriate amount of projected test year O&M expense is $25,497,650. (Hinson)

Position of the Parties

FCG:

As reflected in Exhibit LF-11, the appropriate amount of O&M Expense is $25,445,071 (adjusted) for the 2023 projected test year. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount of O&M Expense for the 2023 projected test year is also $25,445,071 (adjusted) as reflected on Exhibit LF-12. (Howard, Campbell)

OPC:

OPC Witness Schultz addresses this issue in his testimony and exhibits including, but not limited to, Schedule C. The total amount of O&M expense, including removal of AMI O&M in the amount of $20,000, should be reduced to no more than $23,174,085. AMI O&M expense should be removed from the projected test year since the Commission should not grant FCG’s request to burden customers with the cost of this experimental program. OPC Witness Schultz addresses this in his testimony and exhibits including, but not limited to, Schedule C-7.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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. (TR 579; TR 1061) 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. (FCG BR 76)

OPC

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 will benefit from the program. (OPC BR 56) OPC also noted that even though FCG claimed there would be costs savings, FCG was unable to support this claim. (OPC BR 57)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 24)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 24)

ANALYSIS

This is a fallout issue. Based on staff’s recommendations in previous issues, the appropriate amount of projected test year O&M expense is $25,497,650.

CONCLUSION

The appropriate amount of projected test year O&M expense is $25,497,650.

Issue 50:

Should any adjustments be made to the amounts included in the projected test year for amortization expense associated with the acquisition adjustment?

Recommendation:

Consistent with staff’s recommendation to disallow the acquisition adjustment, amortization expense should be decreased by $721,894. (Snyder)

Position of the Parties

FCG:

No. The permanence of the AGLR acquisition adjustment has already been resolved in Docket No. 20170179-GU. Inclusion of the AGLR acquisition adjustment in base rates is consistent with the treatment of other assets that FCG had on its books when it became a subsidiary of FPL. Therefore, there is no need to adjust the AGLR acquisition adjustment and amortization. FCG included the $21.7 million AGLR acquisition adjustment and related accumulated amortization of $13.5 million in rate base, and $0.7 million of amortization expense in FCG’s test year net operating income. This treatment is consistent with the 2018 Settlement Agreement. (Fuentes)

OPC:

Yes, amortization expense associated with the acquisition adjustment in the amount of $721,894 should be removed.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that OPC recommended that the amortization expense associated with the previously approved AGLR acquisition adjustment should be disallowed on the basis that the AGLR acquisition adjustment did not survive FCG’s acquisition by FPL. (FCG BR 76) For reasons explained in Issue No. 15, FCG contends that OPC’s recommended adjustment should be rejected. (FCG BR 76; TR 288)

OPC

OPC stated that, as demonstrated in Issue 15, Commission policy does not allow for an acquisition adjustment resulting from a prior transaction to survive a subsequent purchase. Accordingly, no amortization of the acquisition adjustment can be included in test year expenses. See argument on Issue 15. (OPC BR 57)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 24)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 24)

ANALYSIS

As addressed in Issue 15, staff recommended the disallowance of the acquisition adjustment associated with AGLR’s acquisition of FCG. Therefore, the corresponding amortization expense should be disallowed. Amortization expense should be decreased by $721,894 in the projected test year.

CONCLUSION

Consistent with staff’s recommendation to disallow the acquisition adjustment, amortization expense should be decreased by $721,894 in the projected test year.

Issue 51:

What is the appropriate amount of Depreciation and Amortization Expense for the projected test year?

Recommendation:

The appropriate amount of Depreciation and Amortization Expense for the projected test year is $19,779,288. (Hinson)

Position of the Parties

FCG:

As reflected on MFR A-4 (with RSAM), the appropriate amount of Depreciation and Amortization expense with RSAM is $17,316,572 (adjusted) for the 2023 Test Year. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount of Depreciation and Amortization expense without RSAM is $20,501,181 (adjusted) for the 2023 Test tear as reflected on MFR A-4. (Fuentes)

OPC:

The total amount of Depreciation and Amortization Expense should be reduced to no more than $18,189,244, after making the adjustments identified in lines 18-22 of Exhibit 46, Schedule C, page 2 of 2.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued that OPC’s depreciation parameters as explained in previous issues should be rejected. (TR 322; FCG BR 77) Thus, FCG stated that OPC’s associated Depreciation and Amortization Expense should also rejected. (FCG BR 77).

OPC

OPC stated the total amount of Depreciation and Amortization Expense should be reduced to no more than $18,189,244 based on OPC’s recommended adjustments. (OPC BR 33; EXH 46)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 24)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 24)

ANALYSIS

This is a fallout issue. Based on staff’s recommendation in Issue 5 regarding the Company’s Depreciation Study and Issue 50 regarding the requested acquisition adjustment amortization expense, the appropriate amount of Depreciation and Amortization Expense for the projected test year is $19,779,288.

CONCLUSION

The appropriate amount of Depreciation and Amortization Expense for the projected test year is $19,779,288.

Issue 52:

What is the appropriate amount of projected test year Taxes Other than Income?

Recommendation:

Staff recommends that Taxes Other than Income (TOTI) be reduced by a total of $543,184. As such, the appropriate amount of TOTI for the projected test year is $5,843,427. (Hinson)

Position of the Parties

FCG:

As reflected on MFR A-4 (with RSAM), the appropriate amount of Taxes Other Than Income Taxes is $6,386,610 (adjusted) for the 2023 projected test year. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount of Taxes Other Than Income Taxes is also $6,386,610 (adjusted) as reflected on Exhibit LF-12. (Campbell, Fuentes)

OPC:

OPC Witness Schultz addresses this issue in his testimony and exhibits including, but not limited to, Schedule C. 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. See also Issue 39.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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. (FCG BR 77)

OPC

OPC witness Schultz addressed this issue in his testimony and exhibits. (OPC BR 57). 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. (OPC BR 57)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 24)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 24)

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. (EXH 7) Through discovery, FCG provided a more detailed calculation of the methodology used to estimate property taxes. (EXH 145) 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. (EXH 146) Staff believes 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, staff 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.

Based on staff’s recommendation in previous issues, additional corresponding adjustments to TOTI are necessary. An adjustment to LES revenue in Issue 3 results in an increase of $777 for corresponding regulatory assessment fees (RAFs). A reduction to forecasted miscellaneous revenue in Issue 35 results in a decrease of $80 for corresponding RAFs. A reduction to incentive compensation in Issue 35, results in a corresponding reduction of $32,995 to payroll taxes. Therefore, staff recommends that TOTI be reduced by a total of $543,184. As such, the appropriate amount of TOTI for the projected test year is $5,843,427.

CONCLUSION

Staff recommends that TOTI be reduced by a total of $543,184. As such, the appropriate amount of TOTI for the projected test year is $5,843,427.

Issue 53:

What is the appropriate amount of projected test year Income Tax Expense?

Recommendation:

The appropriate amount of projected test year Income Tax Expense, including current and deferred income taxes and interest synchronization is $1,176,567. (Gatlin)

Position of the Parties

FCG:

As reflected on Exhibit LF-11, the appropriate amount of Income Taxes Expense with RSAM is $1,804,203 (adjusted) for the 2023 Test Year. If the Commission does not adopt the RSAM as part of FCG’s four-year rate proposal, the appropriate amount of Income Taxes Expense without RSAM is $964,255 (adjusted) for the 2023 Test Year as reflected on Exhibit LF-12. (Fuentes)

OPC:

OPC Witness Schultz addresses this issue in his testimony and exhibits including, but not limited to, Exhibit 46, Schedule C. The appropriate amount of income tax expense is no more than $241,372.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG stated that the appropriate amount of Income Tax Expense for the projected test year is $1,804,203 with the RSAM, and $964,255 without RSAM. (FCG BR 77-78; EXH 112) FCG noted that OPC’s recommended adjustment to increase Income Tax Expense for the projected test year by $1.4 million, as reflected in OPC witness Schultz’s testimony. (FCG BR 78; TR 322) 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. (FCG BR 78)

OPC

OPC stated that the appropriate amount of Income Tax Expense is no more than $241,372, as addressed by OPC witness Schultz. (OPC BR 58; EXH 46, P12) 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. (EXH 46, P12)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 24)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 24)

ANALYSIS

This is a fallout issue. Based on staff’s recommendations in previous issues, the appropriate amount of Net Operating Income for the projected test year is $12,427,937.

CONCLUSION

The appropriate amount of Net Operating Income for the projected test year is $12,427,937.

Revenue Requirements

Issue 56:

What are the appropriate revenue expansion factor and the appropriate net operating income multiplier, including the appropriate elements and rates for FCG?

Approved Type II Stipulation:

As reflected in MFR G-4, the revenue expansion factor and net operating income multiplier for the 2023 projected test year is 73.9255 and 1.3527, respectively.

Issue 57:

What is the appropriate annual operating revenue increase for the projected test year?

Recommendation:

The appropriate annual operating revenue increase for the projected test year is $26,454,304. This amount includes an incremental base rate increase of $16,635,469 and revenue associated with the transfer of SAFE investments and the LNG facility. (Gatlin)

Position of the Parties

FCG:

As reflected in Exhibit LF-11, the appropriate test year annual operating revenue increase with RSAM is $28.3 million, which includes an incremental increase of $18.8 million, the previously approved increase of $3.8 million for the LNG Facility, and $5.7 million to transfer the SAFE investments from clause to base. As reflected in LF-12, if the Commission does not adopt the RSAM, the appropriate test year annual operating revenue increase without RSAM is $31.3 million, which includes an incremental increase of $21.5 million, the increase of $3.8 million for the LNG Facility, and $6.0 million to transfer the SAFE investments. .(Fuentes)

OPC:

The Commission should authorize a base rate revenue increase of no more than $4,805,981. This increase should be reduced to reflect the impact of revenue projections being understated and to reflect the impact of the Company having already recovered over $11,596,631 from ratepayers for the LNG facility not yet used and useful by means of a credit to prevent a double recovery of the plant cost once it is put into service.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG requested a four-year rate plan that included an RSAM with a total base rate revenue increase of $28.3 million based on the projected 2023 test year, which 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 BR 79; TR 828; EXH 111) FCG recognized that the Commission may decline the four-year rate plan with an RSAM and if that is the case then the total base revenue increase for the projected 2023 test year is $31.3 million with an incremental revenue increase of $21.5 million based on the depreciation rates determined by the 2022 depreciation study prepared by FCG. (FCG BR 80; TR 828; EXH 112) FCG argued that the proposed four-year rate plan with RSAM and incremental increase of $18.8 million will provide rate stability and certainty to customers, as such providing customers with savings and benefits lasting all four years, as explained in more detail in Issue No. 67. (FCG BR 80; TR 1064-1065; TR 1091)

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. (FCG BR 80; TR 787-788; TR 1088) 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 BR 80; TR 787-788) 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. (FCG BR 80; TR 140-142)

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 in Issue Nos. 1-56. (FCG BR 80; TR 277) 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. (FCG BR 81; TR 787-788; TR 1088)

OPC

OPC stated that the base rate revenue increase should be no more than $4,805,981. (OPC BR 58; EXH 46) 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. (OPC BR 58; EXH 46)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 25)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 25)

ANALYSIS

This is a fallout issue. Based on staff’s recommendations in previous issues, the appropriate total annual operating revenue increase for the projected test year is $26,454,304, as reflected in the table below.

Table 57-1

Staff’s Recommended Annual Operating Revenue Increase

Operating Revenue Increase	$26,454,304
LNG Revenue	(3,828,493)
Transfer of SAFE Investments	(5,990,342)
Incremental Revenue Increase	$16,635,469

Source: EXH 112

CONCLUSION

The appropriate annual operating revenue increase for the projected test year is $26,454,304. This amount includes an incremental increase of $16,635,469 and revenue associated with the transfer of SAFE investments and the LNG facility.

Cost of Service and Rate Design

Issue 58:

Is FCG’s proposed cost of service study appropriate and, if so, should it be approved for all regulatory purposes until base rates are reset in FCG’s next general base rate proceeding?

Recommendation:

Yes, FCG’s proposed cost of service study is appropriate and should be approved for all regulatory purposes until base rates are reset in FCG’s next general base rate proceeding. Within seven business days of today’s vote, the Company should be required to file a revised cost of service and tariffs to reflect the Commission-approved revenue increase. (Hampson)

Position of the Parties

FCG:

Yes, FCG’s cost of service study is appropriate and consistent with the methodologies utilized by the Company in prior rate cases. The Company’s study also follows the presentation format contained in the H Schedules of the prescribed MFR forms. (DuBose)

OPC:

No position.

FEA:

No. Brian Collins’ testimony provides that FCG’s class cost of service study (“CCOSS”) is not appropriate. Furthermore, the CCOSS does not accurately reflect class cost causation because it uses the P&A method to allocate the cost of mains to customer classes and also fails to classify and allocate any distribution mains costs on a customer basis.

FIPUG:

Join position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued in its brief that the Company’s cost of service study (COSS) utilizes the same cost classification methodology used in its previous three rate cases (2000, 2003, and 2018) and that the Peak and Average (P&A) cost allocation methodology is consistent with and required by MFR Schedule H. (FCG BR 81) FCG stated in its brief that FEA and FIPUG, which represent a handful of commercial and industrial (C&I) customers, oppose FCG’s COSS and recommend that the Commission accept the COSS proposed by FEA witness Collins. (FCG BR 82) FCG further argued that FEA witness Collins’ proposed COSS would significantly shift costs from C&I classes to the residential customer classes if adopted. (FCG BR 82)

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 BR 82) FCG further asserted that witness Collins’ proposal is essentially a minimum distribution system allocation. (FCG BR 82) 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 BR 83). 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. (FCG BR 83).

Additionally, FCG stated that although residential customers make up to 93 percent of its customers, residential customers flow 14 percent of the gas while C&I customers flow 86 percent of the gas on FCG’s system on an annual basis. (FCG BR 83). 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 BR 83) FCG argued FEA’s proposal does not account for the actual utilization of the mains by different classes of customers. (FCG BR 83) The Company stated that:

Despite the fact that the C&I customers’ use of the FCG system is over six times that of the residential customers, FEA witness Collins’ cost of service 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 BR 83)

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 BR 83) 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. (FCG BR 83-84) 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. (FCG BR 84)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

FEA argued in its brief 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 & FIPUG BR 26) FEA contended that in order to correct these flaws, the Company should classify mains on both a demand and customer basis. (FEA & FIPUG BR 26) Specifically, FEA explained in its brief that the demand component should be allocated to classes based on the design day demand and the customer component should be allocated to the classes based on the number of customers in each class. (FEA & FIPUG BR 26)

FEA emphasized in its brief that a fundamental question when selecting a COSS is whether the methodology reflects cost causation. (FEA & FIPUG BR 26). 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. (FEA & FIPUG BR 26-27) Thus, FEA concluded, the costs the utility incurs to provide service are driven by peak day demand and the number of customers. (FEA & FIPUG BR 27) 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 & FIPUG BR 27)

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. (FEA & FIPUG BR 28; TR 529) 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. (TR 529) 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. (TR 529)

In sum, 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 & FIPUG BR 29)

FIPUG

FIPUG joined the arguments of FEA. (FEA & FIPUG BR 25)

ANALYSIS

FCG witness DuBose addressed FCG’s COSS in direct and rebuttal testimony. Witness DuBose explained that the purpose of the COSS is to allocate the Company’s costs among the different rate schedules based on cost causation principles. (TR 236) Witness DuBose testified that the Company followed the presentation format contained in the H schedules of the MFRs to develop its COSS. (TR 237) 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. (TR 237)

As shown in MFR Schedule H, capacity costs include mains, regulator stations, and LNG storage. (EXH 8) Customer costs include meters, house regulators, and services. (EXH 9) Capacity- and customer-related costs represent the majority of the total cost of service.

The next step in a COSS is the allocation of costs to the various rate classes based upon allocation factors. Witness DuBose testified that capacity costs were allocated based upon the standard P&A method applied in previous base rate cases. (TR 238) Under the P&A method, the highest monthly therm usage for each rate class (the non-coincident peak demand) and the average of the 12 months’ usage of each rate class are added. Each rate classes’ P&A sales volume as a percent of the total system sales yields the allocation factor used to allocate capacity costs. Customer costs were allocated based on the number of customers served in each class, as they are incurred to connect customers to the distribution system, meter and read their usage, and maintain their accounts. (TR 238)

FEA witness Collins takes issue with FCG’s allocation of capacity-related costs. Witness Collins testified that FCG allocates capacity-related costs essentially based on annual usage, instead of class design day demands, which does not reflect cost causation and is not based on sound cost of service principles. (TR 529) Witness Collins asserted that by using 12 monthly usages plus the maximum monthly volumes for the class P&A allocators, FCG is allocating capacity-related costs on annual usage and not on the traditional P&A method. (TR 529) Witness Collins testified that when a gas distribution utility is considering whether to expand capacity, the key consideration is the expected demands of the customer classes on the peak day, or the design day demands. (TR 529) Witness Collins contended that it is unreasonable to allocate distribution main costs on the basis of annual usage. (TR 532)

Staff reviewed the MFRs of 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 the Commission approved the P&A method, consistent with the allocation of capacity-related costs in the instant case. Staff therefore agrees 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. (TR 526) However, witness DuBose argued that while design day may be a factor in system design, the 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. (FCG BR 82; TR 259) 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. (FCG BR 83; TR 260) While staff acknowledges that there are different methodologies to allocate costs, staff believes 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 C&I customers flow 86 percent of the gas. (TR 260) FCG’s COSS methodology assigns 37 percent of the cost to residential customers and 62 percent to the C&I customers. (TR 261) Witness Collins allocated 70 percent of the total revenue requirement to residential customers and only 29 percent to C&I customers. (TR 260-261) Staff believes 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.

CONCLUSION

Based on the record, FCG’s proposed cost of service study is appropriate and should be approved for all regulatory purposes until base rates are reset in FCG’s next general base rate proceeding. Within seven business days of today’s vote, the Company should be required to file a revised cost of service and tariffs to reflect the Commission-approved revenue increase.

Issue 59:

If the Commission grants a revenue increase to FCG, how should the increase be allocated to the rate classes?

Recommendation:

If the Commission grants a revenue increase to FCG, the revenue increase approved in Issue 57 should be allocated to the rate classes as shown by FCG witness DuBose in Exhibit TBD-3. 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 the Commission’s guidelines on gradualism and improves parity among the rate classes. (Hampson)

Position of the Parties

FCG:

The increase should be allocated as shown in Exhibit TBD-3. FCG has set the proposed revenues by rate class to improve parity among the rate classes to the greatest extent possible, while following the Commission practice of gradualism and considering the competitive nature of the natural gas industry. (DuBose)

OPC:

No position.

FEA:

Brian Collins’ testimony provided that as depicted in Exhibit BCC-1 FCG’s class revenue allocation be distributed to classes using the results of his CCOS study, with no class receiving an increase greater than 1.5 times the system average increase, and with no class receiving a rate decrease.

FIPUG:

Join position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

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 the Commission’s practice of gradualism and considering the competitive nature of the natural gas industry. (FCG BR 84) 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. (FCG BR 84-85)

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 BR 85) 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 BR 85) 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. (FCG BR 85)

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 in Issue 58, which is inconsistent with Commission practice and not reflective of how FCG operates and provides service to its customers. (FCG BR 86)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

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 & FIPUG BR 29) 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. (FEA & FIPUG BR 29)

FIPUG

FIPUG joined the arguments of FEA. (FEA & FIPUG BR 29)

ANALYSIS

This issue addresses the allocation of the revenue increase to the various rate classes. 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. (TR 246) 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. (TR 248) 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. The Commission has typically applied in previous electric and natural gas rate cases 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. (TR 246) Witness DuBose testified that FCG is requesting a 44 percent increase in total revenues for the 2023 test year. (TR 247) Under the Commission’s 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. (TR 247) 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. (TR 247; EXH 26)

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. (EXH 8) 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. (TR 246)

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. (TR 247) Therefore, to address the potential for fuel switching and bypass, FCG slightly reduced the proposed increases to rate classes GS-120K and GS-1250K. (TR 248) 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. Staff agrees 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, because as discussed in Issue 58, FEA 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. (TR 525) Witness Collins did not testify that FCG proposed an increase greater than 1.5 times to any rate classes; FEA only objected to FCG’s COSS methodology.

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 Exhibit TBD-9, witness DuBose summarized the difference between FCG and FEA’s proposed revenue increase allocations, based in their respective COSS. (EXH 117) 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. (EXH 117) Staff does not believe that FEA’s proposed increases provide a balanced approach.

CONCLUSION

Based on the foregoing and considering prior Commission practice of using gradualism to allocate an approved increase to the rate classes, if approved, staff is persuaded by FCG’s proposed allocation of the rate increase as shown by witness DuBose in Exhibit TBD-3. (EXH 26) If the Commission grants a revenue increase to FCG, the revenue increase approved in Issue 57 should be allocated to the rate classes as shown by FCG witness DuBose in Exhibit TBD-3. 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 the Commission’s guidelines on gradualism and improves parity among the rate classes.

Issue 60:

Are FCG’s proposed Customer Charges appropriate?

Recommendation:

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference. (Hampson)

Position of the Parties

FCG:

Yes. The appropriate customer charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). (DuBose)

OPC:

No position.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG did not provide an argument. (FCG BR 87)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 29)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 29)

ANALYSIS

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

CONCLUSION

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

Issue 61:

Are FCG’s proposed per therm Distribution Charges appropriate?

Recommendation:

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference. (Hampson)

Position of the Parties

FCG:

Yes. The appropriate per therm Distribution Charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). (DuBose)

OPC:

No position.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG did not provide an argument. (FCG BR 87)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 29-30)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 29-30)

ANALYSIS

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

CONCLUSION

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

Issue 62:

Are FCG’s proposed Demand Charges appropriate?

Recommendation:

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference. (Hampson)

Position of the Parties

FCG:

Yes. The appropriate Demand Charges are those shown in 2023 Test Year MFRs E-2 and H-1 (1 of 2). (DuBose)

OPC:

No position.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG did not provide an argument. (FCG BR 87)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 30)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 30)

ANALYSIS

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

CONCLUSION

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

Issue 63:

Are FCG’s proposed connect and reconnection charges appropriate?

Approved Type II Stipulation:

Yes. The appropriate service, connect, and reconnection charges are those shown in 2023 Test Year MFR H-1 (2 of 2).

Issue 64:

Is FCG’s proposed per transportation customer charge applicable to Third Party Suppliers appropriate?

Approved Type II Stipulation:

Yes. 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).

Issue 65:

What is the appropriate effective date for FCG’s revised rates and charges?

Recommendation:

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference. (Hampson)

Position of the Parties

FCG:

Pursuant to the statutory eight-month suspension period in Section 366.06(3), F.S., FCG’s filing requested a February 1, 2023 effective date for new base rates. (DuBose)

OPC:

The effective date of FCG’s revised rates and charges should allow for time for implementation promptly after the Commission’s final order in this matter.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG did not provide an argument. (FCG BR 87)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 30)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 30)

ANALYSIS

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

CONCLUSION

This is a fall-out issue and will be decided at the March 28, 2023 Commission Conference.

Issue 66:

Should the Commission give staff administrative authority to approve tariffs reflecting Commission approved rates and charges?

Recommendation:

This issue will be decided at the March 28, 2023 Commission Conference. (Hampson)

Position of the Parties

FCG:

Yes. The Commission should approve tariffs reflecting the Commission’s approved rates and charges. The Commission should direct staff to verify that the revised tariffs are consistent with the Commission’s decision. (DuBose)

OPC:

No position.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG did not provide an argument. (FCG BR 87)

OPC

OPC did not provide an argument. (OPC BR 59)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 30)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 30)

ANALYSIS

This issue will be decided at the March 28, 2023 Commission Conference.

CONCLUSION

This issue will be decided at the March 28, 2023 Commission Conference.

Other Issues

Issue 67:

Should the Commission approve FCG’s requested Reserve Surplus Amortization Mechanism (RSAM)?

Recommendation:

No. The proposed RSAM contradicts well-established Commission practice and ratemaking principles, could potentially result in double recovery by the Company from its customers in the future, and could allow a depreciation surplus paid by customers to be transferred unfairly to shareholders. (Trierweiler, Fletcher, Smith)

Position of the Parties

FCG:

Yes. The RSAM is essential to FCG’s proposed four-year rate plan and should be approved as set forth in Exhibit MC-6. FCG’s proposed RSAM utilizes a framework previously approved by the Commission and would allow FCG to maintain an ROE within its authorized range. FCG projects it will need to use the entire $25 million Reserve Amount to earn at its midpoint ROE for 2024-2026. If FCG’s four-year rate plan and RSAM are not approved, FCG would need to file another base rate case in 2024, which would cost customers approximately $27.0 million more than FCG’s proposed rate plan. (Campbell, Fuentes)

OPC:

FCG’s case is built around the RSAM. Absent the agreement of the parties, the Commission lacks the authority to approve the request as filed and cannot and should not approve the RSAM. Witness Schultz thoroughly demonstrates why the Commission should deny this request. Additionally, the Commission may not establish depreciation rates in a litigated rate case for the express purpose of creating a depreciation reserve surplus. Such a practice would be a departure from GAAP and Commission Rules. A RSAM would eliminate any incentive for FCG to generate efficiencies, and would be grossly unfair to FCG’s current and future customers.

FEA:

No. Brian Collins’ testimony provides that FCG’s proposed RSAM should be denied because it does not incent FCG to manage its costs efficiently to the benefit of its customers if it is automatically guaranteed its approved rate of return. Furthermore, the proposed RSAM shifts revenue recovery risk to FCG’s customers.

FIPUG:

Join position of FEA.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG asserted that the RSAM is a critical and essential component of FCG’s proposed four-year rate plan. FCG argued that 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: lower annual revenue requirements by $2.7 million due to the implementation of RSAM-adjusted depreciation rates; reducing customer bills; overall savings to customers of approximately $27 million over the four-year term; providing customers with rate stability and certainty; avoiding repetitive and costly rate proceedings; and enabling FCG to focus on providing safe, reliable, and affordable service to their customers. (FCG BR 87-89)

Without the RSAM, FCG asserted that it cannot commit to the four-year plan. Additionally FCG asserted that without the RSAM, it will fall below its authorized ROE range and would need to file an additional rate case in 2024 for a base rate increase in 2025. (TR 1058, 1062, 1064-1065, 1091-1092, 1166)

FCG also asserted that the Intervenors’ arguments that the RSAM can only be approved in the context of a settlement and that the Commission is without jurisdiction and authority to approve an RSAM in a litigated proceeding are nonsensical. (FCG BR 88, 91-94) FCG noted that its proposed RSAM follows the same framework approved by the Commission in prior proceedings and is modeled after the RSAM recently agreed to by OPC, FEA, and FIPUG and approved by this Commission for FPL in Docket No. 20210015-EI. (TR 1065, 1108) (FCG BR 93-94)

FCG also argued that the Commission’s jurisdiction and authority to fix fair, just, and reasonable rates is not conditioned upon whether the case is litigated as opposed to being settled. The standard of review does not change the Commission’s statutory authority and jurisdiction; rather, it governs the evidentiary standard by which the Commission will review those proposals that are properly within its jurisdiction and authority to hear and decide. To hold that the Commission can only approve an RSAM in a settlement but not in a litigated proceeding, as suggested by the Intervenors, would mean that the parties to a settlement can somehow expand the Commission’s legal jurisdiction and authority beyond what is granted by Chapter 366, F.S. (FCG BR 91-94)

FCG asserted that the RSAM is a non-cash mechanism that will provide rate stability for FCG’s customers and will save customers approximately $27 million over the period 2023-2026. FCG argued that the Intervenors’ claims that the RSAM is only a mechanism that guarantees FCG will earn at the top of its ROE range are unsubstantiated. (FCG BR 94; TR 284-285, 539-541, 1065) Moreover, FCG asserted that the Intervenors’ comparisons of this case to FPL’s prior settlement case are irrelevant to the evidentiary basis FCG put forward to support the RSAM. (FCG BR 94) FCG stated that the evidence of record in this proceeding is that, with the RSAM, FCG will still need to identify and generate cost savings and productivity improvements just to get to the midpoint ROE. (FCG BR 95; TR 1095; EXH 103) The RSAM will instead allow FCG to appropriately manage risks and costs such as higher inflation and interest rates over the term of the four-year rate plan. (FCG BR 95; TR 1095) FCG witness Campbell further explained that it is inappropriate to compare the projected impact of FCG’s proposed RSAM to FPL’s prior RSAMs, due to FPL’s demonstrated ability to successfully identify and implement significant long-term cost savings and productivity improvements for customers. Not only were FPL’s RSAMs a component of complex settlement agreements, but there are vast differences between the makeup and performance of the two utilities. (FCG BR 94-95; TR 1123-1124, 1170, 1200)

FCG’s 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, according to FCG, they represent a reasonable alternative to those contained in FCG’s 2022 Depreciation Study. (FCG BR 96; TR 1100-1101) FCG argued that these RSAM-adjusted depreciation parameters are within the range of reasonableness, are in line with those approved for other similar natural gas utilities in Florida, and will enable a multi-year rate agreement that will keep customer rates low and stable, will avoid multiple rate increases, and will allow FCG to focus on continuing and improving its ability to provide safe and reliable service. (FCG BR 96; TR 1101-1102)

FCG asserted that the evidence supports a finding that FCG’s proposed RSAM is fair, just, and reasonable and should therefore, be approved. (FCG BR 96)

OPC

OPC argued that the Commission, absent a settlement, is bound by the Depreciation Rule, and thus cannot independently establish a depreciation reserve component without the use of the rule. (OPC BR 62-64) OPC asserted that absent a stipulation of the parties, the Commission lacks the authority to approve an RSAM, because the proposed RSAM establishes depreciation rates for the express purpose of creating a depreciation imbalance (surplus) and is based on parameters that are not factually based on a depreciation study made pursuant to the rule. (OPC BR 60-61) OPC contended that the Commission lacks the authority to establish an RSAM mechanism that can be utilized in conjunction with the artificially created surplus or Reserve Amount. (OPC BR 61-64)

OPC also asserted that other than when an RSAM is approved as part of a settlement agreement under the “public interest” standard, the Commission is not exempt from following its policy, and that the RSAM mechanisms were previously approved in rate case settlement orders have no precedential value. (OPC BR 65-69) OPC then distinguished the underlying facts in those cases from the present docket and concluded that nothing approaching the circumstances in those cases exists within this FCG RSAM. (OPC BR 65-72)

OPC made substantive arguments concerning FCG’s proposed RSAM by comparing it to FPL’s RSAMs, which resulted from rate case settlement agreements. OPC asserted that FCG’s proposed RSAM is designed to achieve top of the range earnings especially if future revenues are understated or if other un-forecasted efficiencies materialize. (OPC BR 74-75) According to OPC, witness Campbell tacitly acknowledged that the existence of the RSAM would not prevent the Company from achieving top of range earnings even if no efficiencies were achieved. (TR 1258-1259) OPC stated that this is consistent with OPC witness Schultz’ testimony that the RSAM would remove the incentive for FCG to be more efficient. (TR 283) OPC concluded that customers could in fact be saddled with higher rate base costs after shareholders benefited from earnings at the top of the range. (TR 282)

OPC also asserted that the proposed RSAM could be used to enhance shareholder earnings and to support a future rate case by increasing rate base by $25 million. (OPC BR 74-75) This future rate base increase would not be the product of any expert’s opinion on depreciation, and this approach is not consistent with the requirement to set just and reasonable depreciation rates. OPC stated that approving this RSAM mechanism would allow FCG to manage its earnings within the range without a termination point contained in a negotiated settlement, which would limit the Commission’s and other parties’ ability to review FCG’s rates in the future by creating a self-regulating mechanism. OPC recommended that the Commission reject any mechanism that could diminish its regulatory responsibilities to conduct an adequate level of economic oversight over traditional rate case proceedings. (OPC BR 75) OPC argued that the proposed RSAM creates no additional value in exchange for agreeing to a departure from the Depreciation Rule and policies that are cost based.

FEA

FEA asserted that FCG’s proposed RSAM will be used to respond to changes in underlying revenues and expenses during the four-year rate plan in order to maintain a Commission adjusted ROE within an authorized ROE range.^{^[59]} (FEA & FIPUG BR 31) FEA noted that FCG witness Campbell stated that Commission approval of the RSAM adjusted depreciation parameters and depreciation rates would support a Reserve Amount up to $52 million.^{^[60]} However, FEA witness Collins observed that FCG requested an RSAM Reserve Amount of only $25 million be available during the four-year rate plan.^{^[61]} (FEA & FIPUG BR 31) FEA argued that the FCG’s proposed RSAM should be rejected as it improperly shifts the risk of revenue recovery to customers so that the Company can more readily earn its guaranteed approved rate of return.^{^[62]} (FEA & FIPUG BR 31-32) FEA also stated that the RSAM does not provide FCG with an incentive to manage its costs efficiently to the benefits of its customers.^{^[63]} Instead, as explained by FEA witness Collins, the RSAM allows FCG to adjust its depreciation expense, leading to an artificially inflated rate base by distorting the accurate measurement of the undepreciated or net plant value of assets included in rate base over rate cycles.^{^[64]} (FEA & FIPUG BR 31-32)

Witness Collins also opined that FCG’s proposed RSAM will lead to potential future costs to FCG customers as reduced depreciation expense will be used to increase the Company’s earnings and its return.^{^[65]} FEA argued that this will lead to customers paying more of a return over a longer period of time at a higher rate.^{^[66]} (FEA & FIPUG BR 32) FEA also argued that despite FCG’s four-year stay-out period, which is contingent upon the approval of the RSAM, nothing in the RSAM proposal prohibits the Company from filing a rate case during that time. (FEA & FIPUG BR 32) FEA highlighted witness Collins’ statement that “paying excessive rates can be far greater detriment to customer than rate case expense.”^{^[67]} FEA opposes approval of the RSAM as unnecessary by pointing out that the Company admitted it continues to see growth with customers on its system and that customer growth should generate revenue growth for the Company.^{^[68]} (FEA & FIPUG BR 32) For these reasons, FEA concluded that the RSAM is an imbalanced regulatory mechanism that should by rejected by the Commission. (FEA & FIPUG BR 32)

FIPUG

FIPUG joined the arguments of FEA. (FEA & FIPUG BR 31)

ANALYSIS

A major component of this rate case centers on FCG’s proposed Reserve Surplus Amortization Mechanism (RSAM). (TR 1063) FCG’s proposed RSAM is an accounting mechanism created by FCG in an effort to manage its earnings. (TR 1065) FCG’s proposed RSAM would take advantage of a portion of any depreciation reserve surplus and use that reserve surplus to increase or decrease depreciation expense, with the intent of bringing about a favorable earnings position. (TR 1066)

In order for FCG’s proposed RSAM to function, a depreciation reserve surplus must exist. (TR 792; TR 1067) FCG proposes to create a reserve surplus by adopting the depreciation parameters included as part of the recent Peoples Gas System settlement agreement (PGS Settlement) in lieu of FCG’s own 2022 Depreciation Study (2022 Study) parameters. (TR 791-792) Because the 2022 Study resulted in a reserve deficit rather than FCG’s proposed reserve surplus, FCG needed alternate parameters to achieve a surplus. (EXH 40; TR 791-792)

For FCG’s proposed RSAM, the assumed surplus was attained by subtracting the calculated theoretical reserve, based on the PGS Settlement parameters, from FCG’s book reserve amounts, resulting in a $52.1 million surplus. FCG proposed using $25 million of its thusly created $52.1 million surplus for its proposed RSAM. (TR 723; TR 1066) FCG would then be able to amortize the $25 million portion of the proposed reserve surplus to reduce or increase depreciation expense, an expense that is embedded in customer rates, thereby increasing or decreasing the Company’s net income. (TR 1066) The net effect of FCG’s proposed RSAM would be to reduce FCG’s depreciation reserve in order for FCG to maintain its ROE within the authorized range. (TR 1066)

Statutory Authority and Jurisdiction

Chapter 366, F.S., sets forth the Commission’s jurisdiction and authority to fix fair, just, and reasonable rates. Staff disagrees with OPC that the Commission lacks authority to approve accounting mechanisms like the proposed RSAM unless it does so in a settlement agreement. The Commission’s jurisdiction and authority to fix fair, just, and reasonable rates pursuant to Chapter 366, F.S., is 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 and 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 expand the Commission’s legal jurisdiction and authority beyond what is granted by Chapter 366, F.S.

For these reasons, the Commission has the authority to approve an RSAM as a means of addressing a depreciation surplus. The question before the Commission in Issue 67 is whether the proposed RSAM should be approved in this particular case. Staff addresses its substantive concerns regarding the proposed RSAM below.

Ratemaking Principles of Depreciation

In setting fair, just and reasonable rates pursuant to Section 366.061(1), F.S.:

. . . . The commission shall investigate and determine the actual legitimate costs of the property of each utility company, actually used and useful in the public service, and shall keep a current record of the net investment of each public utility company in such property which value, as determined by the commission, shall be used for ratemaking purposes and shall be the money honestly and prudently invested by the public utility company in such property used and useful in serving the public, less accrued depreciation, and shall not include any goodwill or going-concern value or franchise value in excess of payment made therefor.

(Emphasis added) Based on its plain meaning, the statute requires a utility’s depreciation study to be based upon data specific to its property used and useful in serving customers.

Rule 25-7.014(1), F.A.C., states “. . . . each natural gas utility shall maintain its accounts and records in conformity with the Uniform System of Accounts for Natural Gas Companies (USOA) as found in the Code of Federal Regulations, Title 18, Subchapter F, Part 201, for Major Utilities (2013).” The USOA for gas companies defines depreciation as: “. . . . the loss in service value not restored by current maintenance, incurred in connection with the consumption or prospective retirement of gas plant in the course of service from causes which are known to be in current operation and against which the utility is not protected by insurance . . . .” In Section A.(1) of USOA Account 108, Accumulated provision for depreciation of gas utility plant, it states: “[t]his account shall be credited with the following: (1) [a]mounts charged to account 403, [d]epreciation [e]xpense, or to clearing accounts for current depreciation expense for gas plant in service.”

Under the ratemaking principles of depreciation, the Intervenors have raised concerns that the proposed RSAM manufactures a reserve surplus from a deficit posture (e.g. FCG’s 2022 Depreciation Study indicated a reserve deficit) that deviates from Commission practice and creates a future burden on customers. (OPC BR 61, 64; FEA and FIPUG BR 31) Staff shares these concerns by the Intervenors. In addition, staff believes the proposed RSAM does not follow the long-standing matching principle and could potentially result in double recovery by the Company from its customers in the future, if the RSAM is approved and any amount of it is amortized.

Manufactured Reserve Surplus

The Company’s 2022 Depreciation Study produces a $3.2 million reserve deficit. (EXH 40) The use of PGS Settlement service lives as proposed in the RSAM adjustments produces a depreciation reserve surplus of $52.1 million. Under normal circumstances, the manufactured surplus that results from the use of PGS Settlement depreciation parameters could trigger regulatory action. (EXH 22) Further, there is no historical precedent for supplanting the depreciation rates resulting from a utility-specific depreciation study in its entirety with rates not based on the utility’s plant.

OPC argued that the proposed RSAM in a litigated rate case is prohibited pursuant to Section 120.68(7)(e)3., F.S. (OPC BR 61) Section 120.68(7)(e)3., F.S., states that when agencies change their established policies, practices and procedures, they must give an explanation for the deviation. Approval of the RSAM depreciation parameters would deviate from past Commission practice in rate cases by not using depreciation rates from a utility-specific depreciation study based on that utility’s plant. Because past settlements that approved RSAM-like mechanisms carry no precedential value, an explanation for the deviation from Commission practice is required. The record in this case shows that resulting fallout effects from the proposed RSAM do not warrant such a deviation from the Commission’s established practices regarding depreciation.

Future Burden of Customers

FEA witness Collins asserted that the approval of the RSAM would lead to potential future costs to the Company’s customers. (TR 540) When the RSAM is amortized, the Company would credit depreciation expense and debit accumulated depreciation. (EXH 138) The result of debiting accumulated depreciation will increase rate base. Thus, if the RSAM were approved, the amount amortized by FCG from 2023 through 2026 by operation of math would have the corresponding effect of increasing rate base by the same amount in the Company’s next rate case. Staff agrees with FEA witness Collins that the increase to rate base places a burden on FCG’s customers in the future.

FCG estimated that the Company’s total incremental revenue requirement from 2024 to 2026 over the 2023 requested revenue requirement is approximately $24.9 million. (EXH 137) FCG witness Campbell testified that his high-level earnings analysis demonstrated that the RSAM will only allow the Company the opportunity to earn at its proposed midpoint ROE of 10.75 percent and does not compensate for additional inflationary and interest rate costs. (TR 1096). Further, in response to discovery, the Company stated that, under the RSAM construct, FCG can only use the amount of the RSAM approved by the Commission such that the reserve amount does not go below $0. (EXH 137) As such, barring any downward pressure on the revenue requirement from cost savings or deferment of plant investments from 2024 to 2026, it is possible that FCG could utilize 100 percent of the proposed RSAM-reserve amount, if approved. Using 100 percent of the $25 million RSAM-reserve amount, as well as the recommended overall cost of capital, the estimated future long-term burden of the RSAM on customers is approximately $26.7 million without any application of an NOI multiplier,[69] as reflected in the table below.

Table 67-1

Line No.	Description	Amounts
1	Reserve Surplus Amount Proposed	$25,000,000
2	100 Percent Amortization of Reserve Amount	$25,000,000
3	Staff's Recommended Overall Cost of Capital	6.70%
4	Additional Depreciation Expense to be Recovered (Line 2)	$25,000,000
5	Return on RSAM Resulting Increase to Rate Base (Line 2 * Line 3)	1,675,000
6	Estimated Future Customer Burden (Line 4 + Line 5)	$26,675,000

Source: Staff Calculations

If the proposed RSAM is approved, any amortized amount of the RSAM is essentially deferring depreciation expense incurred and already paid by customers and the return on the associated increase to rate base to a different set of customers at the time of FCG’s next rate case.

Matching Principle

With regard to depreciation, the Commission has found: “[i]n our view, the purpose of depreciation is to match depreciation expenses as closely as possible to the time period that the equipment is serving the public.”^{^[70]} (Emphasis added) Witness Fuentes sponsored FCG’s response to a request for admission and agreed that “[t]he matching principle can be defined as matching revenues with expenses for services rendered by a utility.” However, Ms. Fuentes conditioned her agreement as follows:

FCG generally agrees that the matching principle “can” be defined in this manner but does not agree that the language used in this request is the only definition of the matching principle. For example, the phrase “services rendered by a utility” is vague and subject to varying interpretations. Further, to the extent that this request for admission is intended to imply a global policy that applies in all circumstances, FCG does not agree.

(EXH 159)

As stated previously by witness Fuentes, when the RSAM is amortized, the Company would credit depreciation expense and debit accumulated depreciation. (EXH 138) By crediting depreciation expense and debiting accumulated depreciation in the manner proposed, staff concludes such action would be contrary to the matching principle.

Double Recovery

When the RSAM is amortized, the Company credits depreciation expense and debits accumulated depreciation. (EXH 138) The result of crediting depreciation expense will increase net operating income and correspondingly increase retained earnings. The result of debiting accumulated depreciation will increase rate base.

FCG witness Campbell explained that depreciation expense is a non-cash expense. (TR 1254) While staff agrees that depreciation expense is a non-cash expense, as reflected in the MFRs and discussed below, depreciation expense will be included as operating expense that will be embedded in both the revenue requirement and rates. As such, a portion of the revenue received by FCG from its customers is attributable to depreciation expense.

If the RASM were to be approved, any amortized amount would represent the total reduction amount of depreciation expense previously recovered from customers through rates. To illustrate this point by operation of math, if the Company has a $1,000 asset for which customers have paid $100 in depreciation expense and FCG amortizes $25 through its proposed RSAM, depreciation expense and accumulated depreciation will be reduced by $25 which will have to be collected again from customers before this asset can be fully depreciated. If no other RSAM amortization occurs, staff submits the result in this example would be that customers will pay $1,025 through depreciation expense before the $1,000 asset is fully depreciated. As reflected in Table 67-1 above, staff estimated that the future double recovery from FCG customers is approximately $26.7 million, if the RSAM is approved.

Value Proposition

FCG witness Campbell testified that the RSAM and four-year rate plan provides its customers with rate stability. (TR 1084) Staff agrees with FCG that rate stability is beneficial to customers. However, staff disagrees with the Company’s purported customer benefits of its RSAM and four-year rate plan proposal, such as its commitment to stay out and customer savings.

Stay-Out Commitment

Without the RSAM, FCG asserted that it cannot commit to the four-year plan and it will fall below its authorized ROE range and would need to file an additional rate case in 2024, for a base rate increase in 2025. (TR 1058, 1062, 1064-65, 1091-1092, 1166) However, on cross-examination by OPC, FCG witness Campbell acknowledged that the Company’s stay-out commitment is not a guarantee. (TR 1203) As addressed in Issue 71, staff submits that the Company’s commitment is not enforceable, and thus is not a true customer benefit.

Customer Savings

The record does not support FCG’s assertion of $10.8 million savings to customers under the RSAM depreciation parameters. (TR 1090) If the RSAM depreciation parameters that FCG contended are in a reasonable range actually come to fruition, it just means those RSAM deprecation rates reflected the accurate cost of service to the customers. If the RSAM depreciation parameters are approved and FCG witness Allis’ deprecation parameters in the 2022 Depreciation Study are realized, the result would be an approximate $10.8 million incremental deficit. Any deficit produced by the difference between the approved depreciation expense and actual experience would apply upward pressure on revenue requirement and rates for FCG’s customers in the future. Similarly, rate case expense is not eliminated but merely deferred. FCG’s RSAM and four-year rate plan will not eliminate rate increases but only delays a portion of the increase and puts upward pressure on the magnitude of the rate increase in the Company’s next rate case.

Non-Cash Expense and Dividend Payments to Shareholders

OPC witness Schultz asserted that non-cash earnings through an RSAM would increase current period dividend payments to shareholders. (TR 282) FCG witness Campbell testified that the RSAM is a non-cash mechanism and thus cannot result in dividend payments to shareholders from its use. (TR 1099-1100) While staff agrees that depreciation expense is a non-cash expense, depreciation expense will be included as operating expense that will be embedded in both the revenue requirement and rates. As such, a portion of the revenue received by FCG from its customers is attributable to depreciation expense and represents cash available to the Company.

In FCG’s 2021 Annual Report filed with the Commission, depreciation expense is part of the Company’s operating expenses deducted from operating revenues to derive net operating income. (EXH 186) Once other income and deductions are applied to net operating income, the result is FCG’s net income for 2021. (EXH 186) As shown in its Statement of Retained Earnings, the net income is later transferred to retaining earnings, thereby increasing the balance, while dividends declared reduces the retained earnings balance. (EXH 186) As shown on its Statement of Cash Flows, the non-cash depreciation expense increased FCG’s net cash provided by operating activities, and the dividends declared reduced FCG’s net cash provided by financing activities. (EXH 186) Further, on cross-examination, FCG witness Campbell acknowledged that: 1) depreciation expense affects earnings; 2) debits and credits to the RSAM affect earnings; 3) a company’s retained earnings can either be reinvested in the business or paid out to shareholders as dividends; and 4) all company revenues come from its customers. (TR 1254-1255) Because funds are fungible, staff believes that the RSAM and non-cash depreciation expense are a source of funds to pay dividends to shareholders. Increased earnings derived from the RSAM directly benefit shareholders either through cash dividends or increased retained earnings which increases the value of the Company. (TR 1256-1257)

CONCLUSION

The proposed RSAM contradicts well-established Commission practice and ratemaking principles. The proposed RSAM could potentially result in double recovery by the Company from its customers in the future, and could allow a depreciation surplus paid by customers to be unfairly transferred to shareholders.

In the event the Commission approves the RSAM, staff recommends the Commission limit any annual reserve surplus amortization to an amount that would not exceed the midpoint of FCG’s authorized ROE range. In other words, the Company can use the reserve amortization to reach the authorized ROE midpoint, but it cannot use any of the reserve amortization in any earnings period in which it reports an earned return on equity above its authorized midpoint. In his rebuttal testimony, FCG witness Campbell testified that the RSAM would be used to achieve the midpoint of the authorized ROE range. (TR 1095)

As further testified to by witness Campbell, under FCG’s RSAM proposal, the possibility exists that FCG can increase its earnings from the bottom of the authorized ROE range to the top of the authorized ROE range by drawing down the reserve surplus. (TR 1256) Consequently, earnings can be increased to the top of the authorized ROE range at the expense of customers and to the benefit of shareholders even if there are no efficiencies achieved or innovations attained. By limiting any reserve surplus amortization to the midpoint of the authorized ROE range, it increases the likelihood that any drawdown of the surplus would be used to offset unanticipated expenses while reducing the amount and likelihood that any drawdown of the surplus would be used to increase earnings and benefit shareholders at the expense of customers. Finally, as discussed in Issue 29, if the Commission approves an RSAM, the appropriate authorized ROE midpoint should be 9.50 percent, with a range plus or minus 100 basis points.

Issue 68:

Should the Commission approve FCG’s proposal for addressing a change in tax law, if any, that occurs during or after the pendency of this proceeding?

Recommendation:

No. If there is a change in State or Federal tax laws, FCG or OPC has the opportunity to file a petition for a limited proceeding pursuant to Section 366.076, Florida Statutes, requesting that the Commission consider the issues and expenses affected by a potential corporate tax law change. (D. Buys)

Position of the Parties

FCG:

Yes. FCG’s proposed mechanism will allow FCG to adjust base rates in the event tax laws change during or after the conclusion of this proceeding. Following enactment of a change in tax law, FCG would calculate the impact of the change by comparing revenue requirements with and without the change, and submit the calculation of the rate adjustment needed to ensure FCG is not subject to tax expenses that are not reflected in the MFRs submitted with its base rate request. (Campbell)

OPC:

No. Furthermore, this issue should be stricken from the case and FCG’s request should be summarily dismissed based on Commission precedent.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued its projected test year forecast was based on the 2017 Tax Cuts and Jobs Act (TCJA), which was in effect at the time FCG filed this case in May 2022. (FCG BR 97) FCG argued 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 BR 97) FCG would not be able to quantify the impacts until such time as a final bill is passed and signed into law. (FCG BR 97; TR 1073) 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 BR 97) 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 BR 97) However, and importantly, the amount to be recovered from or credited to customers would be subject to Commission review and approval in a subsequent expedited filing. (FCG BR 97) FCG argued the Commission has previously approved nearly identical tax adjustment mechanisms in Docket Nos. 20200051-GU, 20210016-EI, and 20210015-EI. (BR 98; TR 1075.)

OPC

OPC argued that in Order No. PSC-2017-0099-PCO-EI (2017 Gulf Tax Decision), the Commission established a policy in a final order 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 BR 75) OPC argued in the 2017 Gulf Tax Order, the Commission ruled a tax law change provision to be premature and that a separate, subsequent proceeding is the only appropriate way to address the matter when and if a change in the tax law occurs. (OPC BR 75-76) In addition, OPC argued that FCG, through its parent FPL and FPL employee witnesses, in this case are acting contrary to the 2021 Settlement agreement terms adopted by Order No. PSC-2021-0446-S-EI in Docket No. 20210015-EI. (OPC BR 76) OPC argued that FCG seeks to have the Commission rely on the negotiated provision in that settlement agreement as precedent which is prohibited by an express term of the 2021 Settlement Agreement. (OPC BR 76) OPC also argued that as a matter of policy, the Commission should further 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. (OPC BR 76) OPC opined that negotiated provisions in other company situations may well be accompanied by bargained for revenue requirement concessions that would indicate fairness and balance in the negotiated prescriptive adjustment to rates and revenue requirements in the future. (OPC BR 76) OPC asserted that no such bargained for consideration is present in this fully litigated case. (OPC BR 76) OPC argued that during the period leading up to the sale of Gulf Power to FPL in 2017, Gulf Power argued against the OPC and intervenors even raising the issue about whether a mechanism should be adopted. (OPC BR 76) OPC asserted that the prehearing officer ruled that “the issue is premature and not ripe for consideration at this time. Should federal tax changes occur in the future, the issue may be addressed at the appropriate time in a separate proceeding.” (OPC BR 77)

OPC argued the 2017 Gulf Tax Decision became final and controlling for the case. (OPC BR 77) OPC asserted the parties ultimately settled the case and in the shadow of the decision, negotiated a tax rate adjustment provision that became the first such mechanism in Florida. (OPC BR 75) OPC argued that together, both orders established the predicate that if the parties wanted certainty in the resolution of tax changes that the method for accomplishing it was in a rate case settlement since the remedy was not available in a conventional litigated rate case. (OPC BR 77) OPC argued that for FCG to just show up and demand to receive a Commission-ordered tax adjustment mechanism on top of a fully litigated revenue requirement award violates the policy enunciated in the 2017 Gulf Tax Decision. (OPC BR 77) 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. (OPC BR 77; TR 1231).

FEA

FEA did not provide an argument. (FEA & FIPUG BR 32)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 32)

ANALYSIS

FCG witness Campbell testified 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 course of the rate case or after the conclusion of the rate case. (TR 1073-1074) FCG proposed that the impact of any permanent change in tax law would be handled through an adjustment to base rates and any change would be calculated and submitted to the Commission for review within 90 days of the enactment of the new tax law. (TR 1074) Witness Campbell explained FCG’s process to quantify and apply any adjustments if the tax law changed for the projected 2023 test year by comparing the difference in revenue requirements between two forecasted earnings surveillance reports (FSER), one with the tax changes and one without. (TR 1075)

For 2024-2026, FCG proposes no adjustment to base rates consistent with its four-year rate plan. (TR 1075) If a new tax law is not enacted until after 2023, FCG would utilize the forecasted earnings surveillance report (FESR) for the calendar year that includes the period in which the new tax law is effective, to determine the amount of the one-time base rate adjustment needed to ensure that FCG is not subject to unplanned changes in revenue requirements as a result of changes in tax law. (TR 1075) For the time period between enactment of the new tax law and implementation of new tax-adjusted base rates, FCG would defer the impact of a new tax law to the balance sheet for collection or refund through the Natural Gas Conservation Cost Recovery Clause in the subsequent year. (TR 1075) FCG also proposed that, depending on the nature of the tax law, any changes in the treatment of deferred taxes as a result of a new tax law change would be handled similar to the method of treatment outlined by the TCJA. (TR 1076) FCG’s tax rate change proposal for any future tax law change affecting deferred income tax treatment is based upon the parameters established for the TCJA in prior dockets. (TR 1076) Witness Campbell testified that FCG would account for the impact of deferred income taxes as part of the calculation that would be completed within 90 days of enactment of the new tax law. (TR 1076)

FCG has not accounted for or included any potential tax law changes in its current filing. (TR 1073) On cross-examination, witness Campbell agreed that in May 2022 there was discussion of a potential change in the tax law by the U.S. Administration. (TR 1222) Witness Campbell also agreed that in August 2022, a change in tax law was passed under the Inflation Reduction Act (IRA), and that the IRA did not have any immediate impact on FCG. (TR 1222) Witness Campbell testified that FCG is still assessing the IRA, but doesn’t foresee anything affecting FCG. (TR 1223) 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 during the four years 2023 through 2026. (TR 1232)

In its brief, OPC argued that by the Commission’s decision in the Prehearing Order in Docket No. 20160186-EI,[71] whereby the Commission denied inclusion of a tax law change provision issue in a litigated rate case, but then subsequently approved a settlement agreement that included a tax law change provision in the same rate case, the Commission set a policy that a tax law change provision can only be approved in the context of a settlement agreement and is inappropriate for inclusion in a litigated rate case. (OPC BR 76)

In its post-hearing brief, FCG provided a rebuttal to OPC’s precedent argument in a footnote stating the following:

During cross-examination of FCG witness Campbell, OPC cited to a prehearing order from a Gulf Power Company 2016 base rate case in Docket No. 20160186-EI where the prehearing officer found that it was premature to include an issue in that case that addressed potential future federal tax changes. (CEL Ex. 205.) OPC’s reliance on this prehearing order is misplaced as it is not precedential and limited to the facts of that case. Moreover, OPC overlooks that FCG’s proposed tax adjustment mechanism only sets up the framework for the parties and Commission to expeditiously review the impacts of potential tax legislation. Any necessary changes to base rates will still be subject to review and approval once the impacts are known and measurable. Finally, OPC overlooks that the Commission has approved similar tax reform adjustment mechanisms for multiple utilities. (Tr. vol. 6, p. 1075.)

(FCG BR 97)

Staff agrees with FCG that a Prehearing Order is not precedential. The purpose of a Prehearing Order is to determine the relevant issues to be addressed at hearing. A Prehearing Order is not intended to establish or declare substantive Commission policy. Further, in Docket No. 20220067-GU, the Commission voted to deny a very similar tax law change provision for Florida Public Utilities Company. To be consistent, the Commission should deny FCG’s request for a tax law change provision in this Docket.

CONCLUSION

In Issue 71, staff is recommending that FCG’s four-year rate proposal is unenforceable and would not result in any benefits to customers. Accordingly, the tax law change provision is unnecessary. 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 allow the Commission and interested parties an opportunity to consider all the issues that may arise from State or Federal tax law changes and establish the appropriate rates at that time. Therefore, if there is a change in State or Federal tax laws, FCG or OPC has the opportunity to file a petition for a limited proceeding pursuant to Section 366.076, F.S., requesting that the Commission consider the issues and expenses affected by a potential corporate tax law change.

Issue 69:

Should the Commission approve FCG’s proposal to continue the SAFE program to include additional mains and services to be relocated from rear property easements to the street front? If so, what adjustments, if any, should be made?

Approved Type II Stipulation:

Yes. The 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 the Commission has 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. If approved in this proceeding, FCG will propose a new investment/construction schedule and term for the SAFE program in its next applicable annual SAFE filing.

Issue 70:

Should the Commission approve FCG’s proposal to expand the SAFE program to include replacement of “orange pipe”? If so, what adjustments, if any, should be made?

Approved Type II Stipulation:

Yes. 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. If approved in this proceeding, FCG will propose a new investment/construction schedule and term for the SAFE program in its next applicable annual SAFE filing.

Issue 71:

Should the Commission approve FCG’s requested four-year rate plan?

Recommendation:

No. Even if approved by the Commission without modification, FCG’s requested four-year rate plan would not result in an enforceable stay out provision, and would not result in any additional benefits to customers. (Knoblauch, Kunkler)

Position of the Parties

FCG:

Yes. Utilities in the state have operated under multi-year rate plans over the past two decades. Multi-year plans offer rate stability for customers and, importantly, allow the Company to continue improving the value delivered to customers. FCG’s proposed four-year rate plan provides tremendous value and savings to customers while avoiding the need for any additional base rate increase through at least the end of 2026. If FCG’s four-year rate plan and RSAM are not approved, FCG would need to file another base rate case in 2024, which would cost customers approximately $27.0 million more than FCG’s proposed rate plan. (Howard, Campbell)

OPC:

No. The so-called four-year rate plan cannot be lawfully implemented because the Commission lacks the authority to deny the company rate-relief if it demonstrates that it is earning outside of its established range. This type of plan is an illusion and is cannot be defined. FCG’s commitment is unenforceable against the current owners and any future owners of the company. Regarding portions of FCG’s requested rate increase, including FCG’s request to maintain the acquisition adjustment, the Commission does not have the authority, absent an agreement of the parties, to approve the request as filed.

FEA:

No position.

FIPUG:

Adopt position of OPC.

Staff Analysis:

PARTIES’ ARGUMENTS

FCG

FCG argued that its requested four-year rate plan would provide rate stability and benefits to customers which would not be available with a single-year rate plan. (FCG BR 98) The Company’s requested four-year rate plan includes eight core elements, which are 1) a single incremental base revenue increase based on a projected 2023 Test Year, 2) a 10.75 percent mid-point ROE and an equity ratio of 59.6 percent, 3) allocate the revenues based on a class cost of service study, 4) adopt an RSAM, 5) continue and expand its existing SAFE program, 6) implement a new limited AMI Pilot, 7) create a mechanism to account for future potential tax law changes, and 8) continue its existing Storm Damage Reserve provision. (FCG BR 98-99) FCG argued that disapproval of the Company’s proposed four-year rate plan with RSAM would cost customers more. (FCG BR 99) Additionally, FCG argued that if the Commission approved the four-year plan, the Commission’s final order would be both binding and enforceable against all parties to this docket, thus FCG would be obligated to comply with the requirements and limitations of the four-year plan. (FCG BR 100)

OPC

OPC argued that absent a settlement agreement, the Commission does not have authority or precedent for approving a “stay out” provision; therefore, it should not approve FCG’s requested four-year rate plan. (OPC BR 79) OPC argued that the Statutes and Rules regulating gas utilities do not give the Commission authority to limit a utility’s ability to request a rate increase, and time-period restrictions exist only as a result of negotiated settlement agreements. Thus, the Commission would be acting against Florida law and Commission precedent if a time-period restriction was ordered. (OPC BR 80) Absent a settlement agreement, the Commission must review each request and determine whether it will result in fair, just, and reasonable rates. Instead, OPC argued that the Company’s plan as presented in this proceeding would cause harm to customers. Further, OPC argued that the Commission would have no enforceable way to prevent FCG from requesting a new rate case before the stay out period ended. (OPC BR 81) OPC cited to 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 the Commission on the propriety of the stay out provision was never made. (OPC BR 82) 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. (OPC BR 83-84)

FEA

FEA did not provide an argument. (FEA & FIPUG BR 33)

FIPUG

FIPUG adopted the position of OPC; but did not provide an argument. (FEA & FIPUG BR 33)

ANALYSIS

FCG witness Howard testified that the Company was requesting the following as part of its four-year rate plan:

· An incremental base revenue increase of $18.8 million based on a projected 2023 Test Year[72]

· A 10.75 percent mid-point ROE and an equity ratio of 59.6 percent

· Allocation of revenues based on a class cost of service study and application of the Commission’s guideline on gradualism

· Adoption of a reserve surplus amortization mechanism or RSAM

· Continuation and expansion of the existing SAFE program

· Implementation of a new limited AMI Pilot

· A mechanism to account for future potential tax reform legislation

· Continuation of the existing Storm Damage Reserve provision

(TR 569-570)

In support of its proposed four-year plan, FCG witness Campbell states in his direct and rebuttal testimony that if the Commission were to deny the use of the RSAM, the Company is “projected to fall below its proposed authorized ROE range and would need to file a rate case in 2024 to support a base rate increase in 2025.” (TR 1064-1065; TR 1085) FCG’s projected revenue shortfall is $0.5 million in 2024.[73] (EXH 105) However, this figure does not consider incremental revenues for the years 2024 and 2025 due to customer growth. While witness Campbell confirmed that the Company did not conduct a revenue analysis for 2024 and 2025, he estimated at the hearing that the incremental revenue associated with growth considerations for each of those years would be approximately $0.2 million. (TR 1263)

Staff reviewed the incremental increase in customers (slightly over 1,000 customers in both 2024 and 2025) and therms (essentially zero growth, unlike the increasing trend evident from actual sales in 2010 through 2021 and projected sales in 2022 and 2023), and believes that witness Campbell’s estimated revenue impact of $0.2 million is quite conservative. (EXH 149) Therefore, staff believes FCG’s failure to conduct a revenue analysis for 2024 and 2025 that accounts for customer growth calls into question the accuracy of its earnings projections for those years. As such, staff believes FCG’s argument for projected under-earnings in such years is unsubstantiated.

FCG witness Campbell testified that the four-year plan included a commitment to not request another general base rate increase effective prior to January 1, 2027. (TR 1062) Witness Campbell also testified that if the four-year rate plan was approved, the Commission would have full regulatory oversight of rates and charges and the Company would continue to provide earnings surveillance reports as required. (TR 1064) OPC witness Schultz testified the Company did not provide an absolute assurance that it would not seek a base rate increase before 2026. (TR 279) When questioned on this by OPC at the hearing, witness Campbell stated that “ . . . the four-year plan is not a guarantee. It is a commitment by the Company to operate within the four-year plan to utilize the RSAM to stay out for the benefit of our customers.” (TR 1203) OPC also argued in its brief that the Commission lacked the authority to approve FCG’s four-year plan. (OPC BR 1-2)

In witness Campbell’s rebuttal testimony, he testified that over the past two decades, the Commission had granted multi-year rate plans or stay-outs, which had been beneficial to customers. (TR 1090) Witness Campbell cited two dockets, Docket Nos. 20210015-EI and 20160021-EI, involving multi-year rate plans with stay outs, both of which resulted in settlement agreements. (TR 1094) However, if the proposed RSAM is not approved by the Commission, witness Campbell testified that FCG would not be able to commit to its four-year rate plan. (TR 1091) In other words, witness Campbell stated the outright rejection of the RSAM “equates to a rejection of the four-year plan.” (TR 1090)

Subsection 366.06(2), F.S., states that if rates are insufficient to yield reasonable compensation, a utility may request a proceeding in order for the Commission to determine just and reasonable rates. Alternatively, if rates yield excessive compensation for services rendered, the Commission can initiate a proceeding upon a request from an affected person or on its own motion to determine just and reasonable rates. Given the language in Section 366.06(2), F.S., staff agrees with OPC that the Commission would not have the authority to prevent the Company from seeking a base rate increase if its rates were insufficient to yield reasonable compensation. Similarly, the Commission would not have the authority to prevent an affected person or entity, such as OPC, from requesting an overearnings proceeding. Thus, even if the Commission approved FCG’s four-year rate plan without modification, it is unenforceable and it would not preclude the Company from requesting a base rate increase within the four-year period.

This was affirmed by witness Campbell that the four-year plan was a commitment by FCG but not a guarantee. (TR 1203) Witness Campbell indicated that portions of its four-year rate plan, specifically the RSAM, would allow it to stay within its authorized ROE range, and thus it would not need to seek another rate increase through at least 2026. (TR 1064-1065) However, witness Campbell testified that during the four-year period of the Company’s 2018 Settlement Agreement, it had been confronted with rising inflation, increased operating costs, and capital investments which all impacted FCG’s ability to achieve a reasonable return. (TR 1044-1045) As indicated by these factors contributing to the Company’s current rate request, unforeseen circumstances (e.g., inflation or increased operating costs) outside of FCG’s control could arise in the next four years requiring a base rate adjustment before the end of 2026.

The four-year rate plan was presented as beneficial to customers given the stay out provision concept that would provide rate stability, and witness Campbell pointed to prior precedent of multi-year rate plans. (TR 1090) However, no Commission orders were cited beyond those approving a settlement. (TR 1094) OPC pointed to this in its brief, stating “the Commission has never ordered a ‘stay out’ provision absent a settlement agreement.” (OPC BR 82) In consideration of Section 366.06, F.S., and absent any Commission precedent, staff does not believe the Company’s four-year plan could require FCG to stay out for the four-year period. Additionally, without the guarantee of the stay out provision, the benefits of the four-year plan as laid out by the Company are called into question.

[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.

[2] Order No. PSC-2020-0485-FOF-GU in Docket Nos. 20200051-GU In re: Petition for rate increase by Peoples Gas System; 20200166-GU In re: Petition for approval of 2020 depreciation study by Peoples Gas System; and 20200178-GU; In re: Petition for approval to track, record as a regulatory asset, and defer incremental costs resulting from the COVID-19 pandemic, by Peoples Gas System.

[3] Docket No. 20170179-GU, In re: Petition for rate increase by Florida City Gas.

[4] 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.

[5] The Company’s forecasted revenue from sales of gas in the amount of $62,828,352, as detailed in MFR E-1, page 2 of 3, includes a positive adjustment in the amount of $155,495 to reflect revenues associated with the LES rate class.

[6] National Association of Regulatory Commissioners Public Utility Depreciation Practices, p. 189

[7] See Rule 25-7.045(1)(e), F.A.C.; (100% - Reserve % - Average Future Net Salvage %) ÷ Average Remaining Life in Years

[8] Vintage refers to the year in which assets were purchased. Transaction year is the year in which the asset was retired.

[9] An OLT curve is only ever complete when all assets within the data set being analyzed are retired.

[10] For Account 379 – M&R Station Equipment witness Allis recommends retaining the currently-approved ASL and Account 380.2 – Services – Plastic witness Allis proposed decreasing the ASL to 50 years.

[13] Order No. PSC-2020-0485-FOF-GU in Docket Nos. 20200051-GU In re: Petition for rate increase by Peoples Gas System; 20200166-GU In re: Petition for approval of 2020 depreciation study by Peoples Gas System; and 20200178-GU; In re: Petition for approval to track, record as a regulatory asset, and defer incremental costs resulting from the COVID-19 pandemic, by Peoples Gas System.

[14] Theoretical Reserve = Book Investment – Future Accruals – Future Net Salvage

[15] Order No. PSC-10-0153-FOF-EI in Docket Nos. 20080677-EI In re: Petition for increase in rates by Florida Power & Light Company and Docket No. 20090130-EI In re: 2009 depreciation and dismantlement study by Florida Power & Light Company.

[16] Pursuant to the statutory eight-month suspension period in Subsection 366.06(3), F.S., FCG’s filing requested a February 1, 2023 effective date for new base rates.

[17] Staff notes that the 2021 FPL Settlement Agreement, approved by Order No. PSC-2021-0446A-S-EI, includes Section 30, which states in part: “No party will assert in any proceeding before the Commission or any court that this Agreement or any of the terms in the Agreement shall have any precedential value, except to enforce the provisions of this Agreement.”

[18] Order No. PSC-2021-0237-PAA-EI, issued June 30, 2021, in Docket No. 20200234-EI, In re: Petition for approval of direct current microgrid pilot program and for variance from or waiver of Rule 25-6.065, F.A.C., by Tampa Electric Company.

[19] 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.

[20] 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.

[21] 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.

[22] 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.

[23] 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.

[24] December 2021 through June 2022 (6-Month Average)

[25] 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.

[26] 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.

[27] 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.

[28] Order No. 23858, issued December 11, 1990, in Docket No. 891353, In re: Application of PEOPLES GAS SYSTEMS, INC. for a rate increase.

[29] Order No. PSC-00-1165-PAA-WS, issued June 27, 2000, in Docket No. 20040951-WS, In re: Application for limited proceeding increase and restructuring of water rates by Sun Communities Finance Limited Partnership in Lake County, and overearnings investigation.

[30] Order No. PSC-05-1242-PAA-WS, issued December 20, 2005, in Docket No. 20040952-WS, In re: Joint application for approval of sale of Florida Water Services Corporation’s land, facilities, and certificates in Brevard, Highlands, Lake, Orange, Pasco, Polk, Putnam, a portion of Seminole, Volusia, and Washington counties to Aqua Utilities Florida, Inc.

[34] Order No. PSC-00-1165-PAA-WS and Order No. PSC-05-1242-PAA-WS.

[35] Order No. PSC-2018-0566-FOF-EU, issued November 30, 2018, in Docket No. 20170235, In re: Petition by Florida Power & Light Company (FPL) for authority to charge FPL rates to former City of Vero Beach customers and for approval of FPL's accounting treatment for City of Vero Beach transaction.

[36] 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.

[38] 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.

[39] 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.

[41] 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.

[42]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.

[43]In the Matter of the Application of CenterPoint Energy Resources Corp. for Authority to increase Natural Gas Rates in Minnesota, Docket G-008/GR 15-424, FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDER at 35 (June 3, 2016).

[44] Bluefield Water Works and Improvement Co. v. Public Service Commission, 262 U.S. 679, 692 (1923) (Bluefield) and Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944) (Hope).

[45] Bluefield, at 692; United Tel. Co. v. Mayo, 345 So. 2d 648 (Fla. 1977).

[46] Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm., 262 U.S. 679 (1923) and F.P.C. v. Hope Natural Gas Co., 320 U.S. 591 (1944).

[47] Order No. PSC-2021-0206-FOF-WS, Issued June, 2021, in Docket No. 20200139-WS, In re: Application for increase in water and wastewater rates in Charlotte, Highlands, Lake, Lee, Marion, Orange, Pasco, Pinellas, Polk, and Seminole Counties, by Utilities, Inc. of Florida.

[48] Order No. PSC-08-0327-FOF-EI, Issued May 19, 2008, in Docket No. 070304-EI, In re: Petition for rate increase by Florida Public Utilities Company, at 37.

[49] Rolf W. Banz, The Relationship Between Return and Market Value of Common Stocks, P. 3-18 (Journal of Financial Economics 9 (1981))

[50]Elroy Dimson, Paul Marsh & Mike Staunton, Triumph of the Optimists: 101 Years of Global Investment Returns, P. 131 (Princeton University Press 2002).

[51] 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.

[52] 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.

[53] Order No. PSC-10-0131-FOF-EI, issued March 5, 2010, in Docket No. 090079-EI, In re: Petition for increase in rates by Progress Energy Florida, Inc.

[54] 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.

[55] 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.

[56] 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.

[57] 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.

[58] 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.

[59] See FEA Direct Testimony of Brian C. Collins (August 26, 2022) at 21-22.

[60] See FCG Direct Testimony of Mark Campbell (May 31, 2022) at 27; EX MC-6.

[61] See FEA Direct Testimony of Brian C. Collins (August 26, 2022) at 22.

[69] If an NOI multiplier were applied to the $26,675,000 amount, the estimated future customer burden would be considerably greater.

[70] Order No. PSC-92-0604-FOF-TL, issued July 6, 1992, in Docket No. 19910725-TL, In re: 1992 Depreciation Study for UNITED TELEPHONE COMPANY OF FLORIDA.

[71] Order No. PSC-17-0099-PHO-EI, Issued March 14, 2017, in Docket No. 20160186-EI, In re: Petition for rate increase by Gulf Power Company.

[72] FCG witness Howard’s direct testimony listed the incremental base revenue increase as $19.4 million; however, this was updated in FCG’s brief to $18.8 million. (TR 569, FCG BR 2)

[73] Based on FCG’s estimate of a $4 million revenue shortfall below its ROE midpoint in 2024 (as projected by witness Campbell), and FCG’s estimate that $3.5 million equates to 100 basis points, staff concludes that the Company expects to earn $0.5 million below the bottom of its ROE range in 2024.

Capital Component	Amount (adjusted)	Ratio	Cost Rate	Weighted Cost
Common Equity	$256,187,447	52.56%	10.75%	5.65%
Long-Term Debt	$153,552,333	31.50%	4.28%	1.35%
Short-Term Debt	$20,141,146	4.13%	1.78%	0.07%
Customer Deposits	$3,787,595	0.78%	2.64%	0.02%
Deferred Taxes	$53,745,303	11.03%	0.00%	0.00%
Total	$487,422,824	100.00%		7.09%

MFR Amount Requested	$792,742
Staff Adjustments:
Interest Synchronization Adjustment	$36,286
Fall-Out Adj Federal Income Taxes	273,843
Fall-Out Adj State Income Taxes	73,695
Total Staff Adjustments	$383,825

Staff Adjusted Amount	$1,176,567

Capital Component	Amount	Ratio	Cost Rate	Weighted Cost
Common Equity	$188,217,673	41.36%	9.25%	3.83%
Long-Term Debt	$194,277,560	42.70%	4.28%	1.83%
Short-Term Debt	$18,821,767	4.14%	1.78%	0.07%
Customer Deposits	$3,535,924	0.78%	2.64%	0.02%
Deferred Taxes	$50,182,583	11.03%	0.00%	0.00%
Total	$455,035,463	100.00%		5.75%