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DATE: |
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TO: |
Office of Commission Clerk (Cole) |
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FROM: |
Division of Economic Regulation (Prestwood, Bulecza-Banks, Draper, Hadder, Hewitt, Kummer, Kyle, P. Lee, Lester, Livingston, Maurey, Piper, A. Roberts, Slemkewicz, Springer) Office of the General Counsel (Brubaker, Jaeger) Division of Service, Safety & Consumer Assistance (Hicks, Mills) |
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RE: |
Docket No. 080366-GU – Petition for rate increase by Florida Public Utilities Company. |
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AGENDA: |
05/05/09 – Regular Agenda – Proposed Agency Action – Interested Persons May Participate |
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COMMISSIONERS ASSIGNED: |
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PREHEARING OFFICER: |
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05/18/09 (5-Month Effective Date (PAA Rate Case)) |
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SPECIAL INSTRUCTIONS: |
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FILE NAME AND LOCATION: |
S:\PSC\ECR\WP\080366.RCM.DOC |
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Issue Description Page
1 Projected test period (Prestwood)
2 Bills and therms (Hadder, Piper, A. Roberts, Hewitt)
3 Quality of service (Hicks, Prestwood)
4 Updated allocations for non-regulated business and common plant. (Prestwood)
5 Electronic Data Processing Equipment (Prestwood)
6 Bare steel replacement program (Daniel, Prestwood, P. Lee, Mills)
7 Area Expansion Program (Prestwood)
8 Account 252 - Customer Advances (Prestwood)
9 Working Capital Allowance (Prestwood)
10 Level of rate base (Prestwood)
11 Accumulated Deferred Income Taxes (Livingston, Kyle)
12 Unamortized investment tax credits (Livingston)
13 Cost rate for short-term debt (Livingston)
14 Cost rate for long-term debt (Livingston)
15 Return on common equity (Livingston)
16 Capital structure (Springer)
17 Weighted average cost of capital (Livingston)
18 Non-regulated business expense (Prestwood)
20 Gross Receipts Tax (Prestwood)
22 Account 903 – Account 903 - Customer Records and Collections (Prestwood)
23 Account 904 - Uncollectible Accounts expense (Prestwood)
24 Account 911 - Misclassified travel expenses (Prestwood)
25 Account 913 - Promotional Advertising Expense (Prestwood)
26 Account 920 - Administrative and General Salaries (Prestwood)
27 Account 921 - Corporate Office Flooring expenses (Prestwood)
28 Account 924 - Storm damage accrual (Prestwood)
29 Account 926.5 - Employee Benefits Medical (Prestwood)
30 Account 928 - Rate case expense (Prestwood)
31 Effects of new depreciation study (Prestwood, P. Lee)
32 Vacant Positions (Prestwood)
33 Taxes for South Florida Operations Facility (Prestwood)
34 Taxes Other Than Income Taxes for Common Plant Allocations (Prestwood)
35 Income Tax Expense (Kyle, Livingston)
36 Net Operating Income (Prestwood)
37 Test year revenue expansion factor (Prestwood)
38 Revenue Requirement (Prestwood)
COST OF SERVICE AND RATE DESIGN
39 Estimated revenues from sales of gas by rate class (A. Roberts, Hewitt)
40 Cost of service methodology (Draper)
41 Customer charges (Draper, A. Roberts)
42 Non-fuel energy charges (Draper)
43 Miscellaneous service charges (A. Roberts)
44 Temporary disconnection charges (A. Roberts)
45 General service rate schedules GS-2 and GSTS-2 (Piper)
46 Residential Standby Generator Service (A. Roberts, Draper)
47 Commercial Standby Generator Service (CS-GS) rate schedule (Draper)
48 Gas Lighting Service Transportation Service (GLSTS) rate schedule (Piper)
49 Area Expansion Surcharge (Hadder)
50 Unrecovered excess construction cost balances (Hadder)
51 Revised rates and charges (Hadder)
52 Interim increase (Slemkewicz)
53 Entries or adjustments to various reports, books and records (Slemkewicz)
54 Step increase for new South Florida Operations Center (Prestwood)
This proceeding commenced on December 17, 2008, with the filing of a petition for a permanent rate increase by Florida Public Utilities Company (FPUC, Company, or Utility). The Company is engaged in business as a public utility providing distribution and transportation of gas as defined in Section 366.02, Florida Statutes (F.S.), and is subject to the Commission’s jurisdiction. FPUC serves gas customers through two divisions: the Central Florida Division consisting of portions of Seminole, Marion and Volusia Counties, and the South Florida Division consisting of portions of Palm Beach, Broward and Martin Counties. Together, FPUC provides service to over 51,000 residential and commercial customers.
FPUC requested an increase in its retail rates and charges to generate $9,917,690 in additional gross annual revenues. This increase would allow the Company to earn an overall rate of return of 8.74 percent or an 11.75 percent return on equity (range 10.75 percent to 12.75 percent). The Company based its request on a projected test year ending December 31, 2009. In its petition, FPUC stated that this test year is the appropriate period to be utilized because it best represents expected future operations for use in analyzing the request for rate relief. FPUC has elected to have its petition for rate relief processed under the Proposed Agency Action (PAA) procedure authorized by Section 366.06(4), F.S.
The Commission last granted FPUC a $5,865,903 rate increase by Order No. PSC-04-1110-PAA -GU.[1] In that order, the Commission found the Company’s jurisdictional rate base to be $59,171,674 for the projected test year ended December 31, 2005. The allowed rate of return was found to be 7.62 percent for the test year using an 11.25 percent return on equity.
FPUC also requested an interim rate increase in its retail rates and charges to generate $984,054 in additional gross annual revenues. Based on FPUC’s calculations, the increase would allow the Company to earn an overall rate of return of 7.66 percent or a 10.25 percent return on equity, which is the minimum of the currently authorized return on equity range of 10.25 percent to 12.25 percent. The Company based its interim request on a historical test year ended December 31, 2007. The Commission granted the interim rate increase in Order No. PSC-09-0123-PCO -GU, issued March 3, 2009. The interim rates became effective for all meter readings made on or after 30 days from the date of the vote approving the interim increase. In the same order, the Commission suspended the final rates and associated tariff revisions proposed by the Company pending a final decision in this docket.
The Office of Public Counsel (OPC) intervened in this proceeding.[2]
Customer Meetings were held in West Palm Beach on March 26, 2009, and in Ocala and Deltona on April 2, 2009. A total of four customers spoke at the three meetings.
This recommendation addresses FPUC’s requested permanent rate increase. The Commission has jurisdiction pursuant to Sections 366.06(2) and (4), and 366.071, F.S.
Is FPUC’s projected test period of the 12 months ending December 31, 2009, appropriate?
Recommendation:
Yes. With the adjustments recommended by staff in the following issues, the projected test year of 2009 is appropriate. (Prestwood)
Staff Analysis:
The Company used actual data for the 2007 historical base test year. This data served as a basis for developing its 2009 projected test year request. The 2008 projected test year was based on actual data through April 2008 plus projected data for the remainder of 2008. The projected 2009 test year was based on the projected level of customers, related revenues, expenses updated for cost changes and trending, capital expenditures, and the projected cost of capital. The projections through 2009 were reviewed by Commission auditors and analyzed by staff.
The purpose of the test year is to represent the financial operations of a company during the period in which the new rates will be in effect. Staff believes that the projected test period of the 12 months ending December 31, 2009, as adjusted for staff’s recommendations, is representative of the period in which the new rates will be in effect and is appropriate.
Are the projected bills and therms for the test year ending December 31, 2009, appropriate for use in this case?
Recommendation:
Yes. The projected bills and therms for the test year ending December 31, 2009, are appropriate for use in this case (Hadder, Piper, A. Roberts, Hewitt)
Staff Analysis:
FPUC projected usage per customer for the 2009 test year separately for South Florida and Central Florida by rate class. The Company used monthly data from December 2004 through July 2008 to estimate the historical relationship between gas use per customer, normal weather conditions, natural gas prices (for certain rate classes), and time. Staff evaluated these forecast assumptions and found them appropriate. Staff also evaluated the econometric equations used to produce the projected usage per customer and believe they are appropriate for use in this case.
FPUC projected customer growth separately for South Florida and Central Florida by rate class. In Mr. Schneidermann’s direct testimony (p.130), he states that most customer classes have experienced an increase in the number of customers since the previous rate case, but the rate of increase has declined in recent years. He says the Company also considered the recent troubles in the housing market and general economy, and that the Company is using a conservative estimate to assume that the number of customers will not decrease between 2008 and 2009. Staff, FPUC’s South Florida and Central Florida General Managers, as well as, the Company’s Director of Marketing and Sales, reviewed the 2009 projections and found them to be reasonable extensions of historical growth patterns.
After evaluating the Company’s historical data and its projections for 2009, and taking the current economic climate into consideration, staff believes the projected bills and therms are appropriate.
Is the quality of service provided by FPUC adequate?
Recommendation:
Yes. FPUC’s quality of service is satisfactory. (Hicks, Prestwood)
Staff Analysis:
Customer Meetings were held in West Palm Beach on March 26, 2009, and in Ocala and Deltona on April 2, 2009. The purpose of the meetings was to gather information from customers regarding the Company’s quality of service and its request for a permanent rate increase. Two customers spoke at the West Palm Beach meeting, two customers spoke at the Deltona meeting, and no customers attended the Ocala meeting. There were no quality of service complaints expressed at the meetings. All of the residential customers who spoke at the meetings expressed concern over the rate increase. A customer at the Deltona meeting complained that the Company would not allow him to enter into a payment plan for the balance on his account.
Quality of service was reviewed by analyzing all complaints taken by the Commission’s Division of Service, Safety, and Consumer Assistance for the calendar year 2008. There were a total of 40 complaints, 30 involving billing complaints, and 10 involving service. All but three were resolved in a timely manner. The number of complaints per customer compares favorably with other large Florida natural gas utilities.
FPUC has not experienced an outage that falls under the reporting requirements of the Commission’s Bureau of Safety since its last rate case, in 2004.
Considering all of the above, staff recommends that the Commission find that FPUC’s quality of service is satisfactory.
Should an adjustment be made to update the allocations attributable to non-regulated business and common plant?
Recommendation:
Yes. Staff recommends adjustments to increase plant in service and the accumulated depreciation reserve by $81,565 and $79,623, respectively, to reflect the 2009 allocation factors. Staff also recommends an adjustment to increase depreciation expense by $17,740. (Prestwood)
Staff Analysis:
The Company reviews its individual plant accounts each year to determine the appropriate allocations for non-regulated business and common plant. The Company’s projected 2009 test year Minimum Filing Requirements (MFR) data for plant in service, accumulated depreciation reserve, and depreciation expense were prepared using the 2008 allocation factors for non-regulated business and common plant. The 2009 allocation factors were not available at the time of filing.
The Company provided the 2009 allocation factors in response to a staff data request. Staff recommends adjustments to increase plant in service and accumulated depreciation reserve by $81,565 and $79,623, respectively, to reflect the 2009 allocation factors. Also, staff recommends an adjustment to increase depreciation expense by $17,740.
Should an adjustment be made for the allocation of common Electronic Data Processing Equipment (EDP)?
Recommendation:
Yes. Staff recommends adjustments to increase plant in service and the accumulated depreciation reserve by $90,819 and $52,067, respectively, for the test year. Staff also recommends an adjustment to increase depreciation expense by $9,616. (Prestwood)
Staff Analysis:
In Audit Finding No. 12, staff auditors found that there was an error in the allocation of common Electronic Data Processing (EDP) equipment. As a result, the allocation to the electric and natural gas divisions were understated and the allocation to the propane division was over stated. The corrections required for the test year are increases to plant in service and the accumulated depreciation reserve of $90,819 and $52,067, respectively. Also, staff recommends an adjustment to increase depreciation expense by $9,616 to correct this error. The Company concurs with this adjustment.
Should FPUC’s proposed adjustments to Rate Base and Depreciation Expense & Amortization expense due to the expansion and modification of its bare steel replacement program be approved?
Recommendation:
No. The Company’s modified bare steel replacement program should be approved, with the exception that the replacement period should be shortened to 50 years to reflect the average useful life of the equipment. Staff recommends an adjustment to decrease the Company’s plant in service and depreciation reserve by $67,503 and $716, respectively. Staff also recommends an adjustment to increase amortization expense by $124,621 and decrease depreciation expense by $1,841.
Further, the Company should be required to file a report with the Commission’s Division of Economic Regulation, within 90 days of the final order in this rate case, showing the dollar amount and feet of plastic mains and services installed in 2005, 2006, 2007, and 2008 to replace the bare steel pipe retired in those same years. Thereafter, the Company should be required to file an annual status report by March 31 of each year showing the dollar amount and feet of plastic mains, services and tubing installed during the previous calendar year to replace bare steel pipe and tubing retired that year. (Daniel, Prestwood, P. Lee, Mills)
Staff Analysis:
The Company’s bare steel replacement program was approved by the Commission in the Company’s last rate case in Docket No. 040216-GU.[3] The Commission’s Order in Docket No. 040216-GU stated:
The utility’s proposed program would replace all existing mains over a 75-year period beginning in 2005, at a total cost of $28,315,380, amortized at $377,538 per year. We find that the replacement period shall be shortened to 50 years to reflect the average useful life of the equipment. This change results in a yearly increase in amortization expense of $188,770 for a total of $566,308. Accumulated amortization for the projected test year is also increased by $94,385.3
According to the Company, the Department of Transportation, Pipeline and Hazardous Materials Safety Administration, and the Commission’s Bureau of Safety are both in the process of developing rulemaking to address distribution integrity management. This emphasizes the need not only to continue the bare steel replacement program, but to enhance this program to include steel tubing replacements, recognizing the possible increased hazard from steel tubing.
The Company estimates that the total cost of the program is $37,386,365, from $28,315,380, as approved in the last rate case, an increase of $9,070,985. This increase is mainly due to greater material and installation costs associated with the replacement of steel pipe with plastic. Adding steel tubing to the replacement program, accounts for only $642,660 of the program’s total increased cost.
In the current rate case, the Company included an annual amortization of $623,106, for the bare steel mains, services, and steel tubing replacement program. The annual expense reflects the revised total cost of the replacement program and the Company’s requested 60-year amortization period. These changes increase the annual amortization expense from $566,308, as approved in the last rate case, to $623,106, or an increase of $56,798.
In the last rate case, the Company proposed a 75-year amortization period for the bare steel replacement program. In Order No. PSC-04-1110-PAA-GU granting FPUC a permanent rate increase, the Commission stated:
The utility’s proposed program would replace all existing mains over a 75-year period beginning in 2005, at a total cost of $28,315,380, amortized at $377,538, per year. We find that the replacement period shall be shortened to 50 years to reflect the average useful life of the equipment.
Staff recommends that the Company’s revised bare steel replacement program should be approved with the exception that the amortization period should remain at 50 years to reflect the average useful life of the equipment. This change results in a yearly increase in amortization expense of $181,419 over the program approved in the last rate case. It requires an adjustment to decrease the Company’s plant in service and depreciation reserve by $67,503 and $716, respectively. It also requires an adjustment to increase amortization expense by $124,621 and decrease depreciation expense by $1,841.
Staff further recommends that the Company should be required to file a report with the Commission’s Division of Economic Regulation, within 90 days of the Commission’s final order in this rate case, showing the dollar amount and feet of plastic mains and services installed in 2005, 2006, 2007, and 2008 to replace the bare steel pipe retired in those same years. Thereafter, the Company should be required to file an annual status report by March 31 of each year showing the dollar amount and feet of plastic mains, services and tubing installed during the previous calendar year to replace bare steel pipe and tubing retired that year.
Should FPUC’s Area Expansion Program (AEP) deficiency be allowed in rate base?
Recommendation:
Yes. Staff recommends that the Company’s AEP deficiency be allowed in rate base, as corrected. This requires an adjustment to increase plant in service by $17,419 to correct an error in the Company’s filing. (Prestwood)
Staff Analysis:
FPUC extends its facilities to provide service in accordance with the provisions of Rule 25-7.054, Florida Administrative Code (F.A.C.). The rule requires extensions to be made at no cost to the customer when the capital investment necessary to extend the Company’s facilities is less than the allowable construction cost. The allowable construction cost is equal to four times the estimated gas revenues from the facilities less the cost of gas. In the event the cost exceeds the allowable construction cost, the Company requires the customer(s) to make an advance in aid of construction, which has to be made up-front.
The AEP is an alternate method of recovering capital construction costs that are in excess of estimated four-year base revenues that are to be derived from a defined main extension project. While Rule 25-7.054, F.A.C. is designed to address individual customers, the AEP is designed to address a group of customers that are part of an expansion project. The AEP allows the Company to add a surcharge that is billed to each participating customer until the excess construction cost is paid in full or a maximum period of 10 years, whichever comes first.
FPUC’s existing AEP was originally approved in Docket No. 941291-GU.[4] The current program does not provide for a true-up mechanism at any point during the 10-year allowable collection period. Additionally, the program does not allow the AEP per therm surcharge rate to be changed once the in-service date has been established.
FPUC currently has 44 active AEP projects of which 38 are projected to have excess construction cost balances as of December 31, 2008. Due to the current economic conditions that have affected the new construction housing market, the Company does not anticipate the excess construction cost balances of these projects to be recovered prior to the end of the 10-year allowable collection period. The Company has conducted an analysis of all 44 active AEP projects. The analysis showed that without an adjustment to the per therm surcharge, the unrecovered excess construction costs at the end of the 10-year collection period of each project, in total, will exceed $4,000,000.
The Company proposes to deal with this shortfall in two ways. First it proposes to increase the allowable surcharge rate, which is discussed in Issue 50. If the Company’s proposed increase is approved, the unrecovered excess construction cost balances will be reduced to $2,461,202 based on its original filing. However, the Company corrected the original filing in response to Staff Data Request No. 70, increasing the unrecovered excess construction cost, after the proposed increase in the surcharge, from $2,461,202 to $2,478,621, or an increase of $17,419. The Company proposes to transfer the remaining balance of $2,478,621 to plant in service, increasing rate base as filed in the current rate proceeding. In the Company’s last rate proceeding the Commission did not address the unrecovered excess construction cost balances associated with the AEP
FPUC is also proposing a new AEP, based on its experience in managing the existing AEP projects over the last 14 years. The Company’s proposal for the new AEP, which is designed in part to reduce the under recovery of cost in the future, is discussed in Issue 49.
Staff believes that the AEP allows customers access to natural gas that they otherwise would not have been able to receive. Adding additional customers to the system helps spread common costs over a larger base, helping all customers.
Staff recommends that the unrecovered cost associated with the existing AEPs be allowed in rate base and recovered over the life of the property. Therefore, staff recommends accepting the Company’s adjustment to increase plant in service and accumulated depreciation reserve by $2,478,621 and $31,998 respectively. This requires an adjustment to increase plant in service by $17,419, to correct the error in the Company’s filing.
Should an adjustment be made to Account 252 - Customer Advances for the projected test year?
Recommendation:
Yes. Account 252 - Customer Advances for Construction should be increased by $87,449 for the projected 2009 test year. (Prestwood)
Staff Analysis:
Audit Finding No. 1 noted that FPUC made an error in the Account 252 - Customer Advances for Construction forecast for 2009. The 2009 forecast was calculated by taking the 2007 historical average amount and applying the combined customer growth and inflation factor of 1.0274. The Company should have used the 2008 forecast average amount and the 2009 customer growth and inflation factor of 1.0274.
Account 252 - Customer Advances for Construction should be increased by $87,449 for the projected 2009 test year. The Company concurs with this adjustment.
Is FPUC’s requested level of Working Capital Allowance for the projected test year appropriate?
Recommendation:
No. Staff recommends that working capital be reduced by $26,028, to correct errors in the Company’s calculation of workman’s compensation insurance and non-utility plant for the 2009 test year. (Prestwood)
Staff Analysis:
In response to Staff Data Request No. 49, the Company noted that the projected amounts shown in the MFRs represent the incorrect years for workman’s compensation insurance. Staff corrected the calculation of the 13 month average for workman’s compensation insurance for the 2009 test year. The correct amount of $88,748, compared to the Company’s original filing of $106,340, requires an adjustment to decrease working capital by $17,592, for the 2009 test year.
Also, in response to Staff Data Request No. 90, the Company noted that it had erroneously included $8,436 of Account 1210 Non-utility Property in working capital for the 2009 test year. Staff recommends an adjustment to decrease working capital by $8,436.
The total of these two adjustments is a decrease to working capital of $26,028.
Is FPUC’s requested level of Rate Base for the projected test year appropriate?
Recommendation:
No. The appropriate amount of rate base for the 2009 projected test year is $73,262,885, as shown on Schedule 1. (Prestwood)
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the appropriate 13-month average rate base for the 2009 projected test year should be reduced from $73,747,220 to $73,262,885, as shown on Schedule 1.
What is the appropriate amount of accumulated deferred income taxes (ADITs) to include in the capital structure?
Recommendation:
The appropriate amount of ADITs to include in the capital structure for the projected test year is $2,773,818. (Livingston, Kyle)
Staff Analysis:
Staff agrees with the methodology used by FPUC to calculate the appropriate amount of ADITs to include in the Company’s 2009 projected test year. Therefore, staff recommends the appropriate amount of ADITs to include in the capital structure is $2,773,818.
What is the appropriate amount and cost rate of the unamortized investment tax credits (ITCs) to include in the capital structure?
Recommendation:
The appropriate amount and cost rate of unamortized ITCs to include in the capital structure are $115,553 and 8.79 percent, respectively. (Livingston)
Staff Analysis:
FPUC included ITCs of $115,553 in its projected 2009 test year capital structure at a 9.38 percent cost rate. FPUC stated that ITCs arise from the normalization procedures of accrual accounting. The Company stated that its proposed treatment of ITCs capitalizes the tax benefit and amortizes the balance to income in equal installments over the life of capital. The unamortized balance of ITCs is carried as a deferred liability. The Company also noted that it is common to include the liability in the capital structure for purposes of determining regulated prices. The Company stated that this treatment has been recognized by the Commission in the past, and it is the approach taken by FPUC in this filing.
Staff agrees with the methodology used by FPUC to calculate the appropriate amount of ITCs to include in the Company’s 2009 projected test year. Staff determined the appropriate cost rate for ITCs based on staff’s recommended capital structure, which is discussed in Issue 16, and staff’s recommended ROE, discussed in Issue 15. Therefore, staff recommends the appropriate amount of ITCs to include in the capital structure is $115,553 at a cost rate of 8.79 percent.
What is the appropriate cost rate for short-term debt for the projected test year?
Recommendation:
The appropriate cost rate for short-term debt is 2.73 percent. (Livingston)
Staff Analysis:
FPUC proposed a short-term debt cost rate of 4.71 percent based on the London Interbank Offer Rate (LIBOR) plus 156 basis points. The Company used a U.S. Federal Funds (Fed Funds) interest rate of 2.98 percent to estimate LIBOR. The Company noted that LIBOR has traded at an average of 17 basis points above the Fed Funds rate since January 2001. Therefore, the Company added 17 basis points to the Fed Funds rate to estimate a LIBOR rate of 3.15 percent. Next, the effective interest rate spread on outstanding daily balances, 80 basis points, was added to the 3.15 percent LIBOR rate to produce a cost rate of 3.95 percent. The Company then added 76 basis points to account for fees associated with the unused credit line, direct charges, and charges for outstanding balances. The use of this Fed Funds rate and methodology produced the Company’s recommended short-term debt cost rate of 4.71 percent.
Staff disagrees with FPUC’s proposed cost rate for short-term debt of 4.71 percent. The Company acknowledged that the Fed Funds rate was one percent at the time of the filing, and it is expected to hold steady over the near term due to the current slowdown in economic activity. Based on this Fed Funds rate, the appropriate estimate of the cost rate for short-term debt is 2.73 percent, using FPUC’s proposed methodology.
What is the appropriate cost rate for long-term debt for the projected test year?
Recommendation:
The appropriate cost rate for long-term debt for the projected test year is 7.90 percent. (Livingston)
Staff Analysis:
FPUC proposed a cost rate for long-term debt of 7.90 percent. This cost rate is based on FPUC’s five outstanding first mortgage series bonds that were issued over the 1988-2001 period. These issues have maturity dates ranging from 2018 to 2031 and carry coupon interest rates ranging from 4.90 percent to 10.03 percent. The Company’s embedded cost rate is determined according to contemporary accounting conventions and accounts for the 2009 amortization schedule of issuance costs. The average net outstanding balance of long-term debt for 2009 also reflects unamortized issuance costs and sinking fund schedules. FPUC stated that the Company does not expect to issue additional long-term debt prior to 2010.
After review of FPUC’s MFRs and supporting documentation, staff recommends that FPUC’s proposed cost rate of 7.90 percent accurately reflects the Company’s long-term debt cost rate.
What is the appropriate return on common equity for the projected test year?
Recommendation:
The appropriate return on common equity for the projected test year is 11.00 percent with a range of plus or minus 100 basis points. (Livingston)
Staff Analysis:
FPUC requested a return on common equity (ROE) of 11.75 percent. The Company’s currently-allowed ROE of 11.25 percent was authorized in Order No. PSC-04-1110-PAA-GU.
This docket is being handled as a proposed agency action (PAA). The Commission has not held a hearing in this matter. To support its proposed ROE, FPUC proffered a witness that provided the results of four capital valuation methods applied to two groups of companies identified as comparable in risk to FPUC. These methods include the Capital Asset Pricing Model (CAPM), Discounted Cash Flow (DCF) analysis, Risk Premium (RP) model, and an assessment of realized market returns. No other parties filed testimony in this docket regarding ROE.
ROE Models
Based on the statutory principles for determining the appropriate rate of return for a regulated utility set forth by the U.S. Supreme Court in its Hope and Bluefield decisions, the Company developed two groups of comparable risk utilities to determine the ROE for FPUC.[5] The first group, “Sample 1,” consisted of eight mid-sized natural gas distribution companies (LDCs). These companies were selected based on business line and financial performance. FPUC also analyzed each company based on the following criteria: equity participation in total capital, coefficient of variation in earnings per share over five and ten year periods, CAPM beta, and variation in market returns. This criteria was also applied to the second group, “Sample 2,” which is comprised of 11 mid-sized electric utilities (IOUs). FPUC identified the companies in each group using data from Value Line Investment Survey (Value Line), Ibbotson Associates (Morningstar), and web-based services such as Yahoo Finance, UBS Financial Services, and Zacks Financial Services.
FPUC’ witness used a single-stage DCF model in its analysis of each group. The DCF model defines the cost of capital as the sum of the adjusted dividend yield and expectations of future growth in cash flows to investors, including dividends and future appreciation in share prices. The results of this analysis ranged from 13.13 percent to 14.97 percent for the LDCs and from 9.57 percent to 13.17 percent for the IOUs. These results included an adjustment for flotation costs of 6 percent or approximately 25 to 33 basis points. Based on this analysis, FPUC concluded a DCF-based ROE of 12.84 percent.
FPUC’ witness also employed the CAPM in its analysis. The CAPM is a risk premium model that uses as inputs a risk-free rate, an overall return for the market, and beta. Beta is a measure of systematic risk, which is risk that cannot be diversified away. FPUC applied the CAPM to both groups of comparable companies. The results of this model ranged from 9.56 percent to 13.26 percent for the LDCs and from 9.57 percent to 13.39 percent for the IOUs. These results included an adjustment for flotation costs of 6 percent or approximately 25 to 33 basis points. Based on this analysis, FPUC concluded a CAPM-based ROE of 11.42 percent.
The next approach FPUC’ witness employed was a RP analysis. The underlying concept of the RP approach is that differences in perceptions of risks among financial assets such as equities and debt are revealed in differences between historical market returns. Thus, the Company stated that these differences can serve as a surrogate for the compensation of risk over future timeframes. The results of this approach ranged from 11.20 percent to 13.40 percent for both groups. These results included an adjustment for flotation costs of 6 percent or approximately 25 to 33 basis points. These results also included a small-size premia adjustment of 200 basis points. Based on this analysis, FPUC concluded a RP-based ROE of 12.30 percent.
Finally, FPUC’ witness employed an assessment of realized market returns, or historical earned returns, over 5 and 10 year periods for both groups as well as for broader indices of companies in the natural gas and electric industries. The approach based on realized market returns assumes that if historical earned returns guide expectations of future returns, historical returns provide a useful benchmark and, within reasonable bounds, reflect the opportunity cost of capital. The results of this assessment ranged from 9.81 percent for the natural gas industry to 10.40 percent for the electric industry. These results included an adjustment for flotation costs of 6 percent or approximately 25 for the natural gas companies and 33 basis points for the electric companies. FPUC concluded an ROE of 10.11 percent for this approach.
Based on the results of its analyses, FPUC determined a range of equity returns of 10.11 percent to 12.84 percent for the four approaches. The average of these indicated returns is 11.67 percent. The Company argued that its models were applied to mid-sized companies that, while not large, have much larger market capitalization than FPUC. It is the Company’s view that the cost of equity is higher for small firms, other factors held constant. For these reasons, FPUC recommended the ROE be set at a level of 11.75 percent or higher.
Analysis
The Company’s ROE analysis relied heavily on dated information for estimates of the necessary inputs. The CAPM analysis relied on betas from 2007 and market returns based on historical, earned returns from 1970 through 2007. The timeframe relied on to determine the risk-free rate was not specified. There is considerable academic research documenting that risk premiums based on historical, earned returns are poor predictors of current market expectations. This deficiency also extends to the results of the RP model as it too relied on historical, earned returns.
The growth rate assumed in the DCF analysis for the LDCs was 10.14 percent. It is important to keep in mind that the ROE recognized for purposes of setting rates in this proceeding should be in line with the risk associated with the provision of regulated services. In the current economic environment, staff does not believe an annual rate of growth in earnings this high is a reasonable approximation of the growth in earnings investors expect from regulated operations.
It is generally accepted that earned or realized returns can and do differ significantly from investor required returns. Investors’ required returns are a function of investors’ expectations of risk and return going forward. Just because a particular investment earned a 5 percent or 15 percent return last year does not mean investors expect the same investment to earn a return of 5 percent or 15 percent the following year.
There is little doubt the recent disruption in the capital markets has exerted some degree of upward pressure on the current expectations of the market risk premium. However, staff believes this incremental increase in required return, whatever the appropriate amount may be, should be applied to a contemporary estimate of the investor-required return. FPUC’ witness identified a group of LDCs that he believes are comparable in risk to FPUC. Excluding the three LDCs with ROEs set in the mid 1990’s, these utilities have authorized ROEs ranging from a low of 9.95 percent to a high of 10.70 percent. The average ROE for this group is 10.24 percent. Staff does not believe the investor-required return for FPUC is 150 basis points greater than the average authorized return for the group of companies the Company identified as comparable in risk to FPUC.
Conclusion
Staff recommends an authorized ROE of 11.00 percent. This return is above the relevant average ROE for the group of LDCs the Company identified as comparable in risk to FPUC to compensate for the recent disruption in the capital markets. Staff believes this level of return also compensates for the financial risk associated with FPUC’s capital structure. Finally, 11.00 percent was the ROE the Commission recently authorized for FPUC’s electric division.[6] For the reasons discussed above, staff recommends the Commission set an authorized ROE of 11.00 percent, with a range of plus or minus 100 basis points, for FPUC.
What is the appropriate capital structure for the projected test year?
Recommendation:
The appropriate capital structure is detailed on Schedule 2. Staff recommends the implementation of a 13-month average capital structure consistent with prior Commission practice. (Springer)
Staff Analysis:
In its MFR’s, FPUC filed a projected capital structure on both a 13-month average and year-end basis. Although the Company used a 13-month average capital structure for purposes of its request for a rate increase, the Company made an argument to support consideration of a year-end capital structure for purposes of this proceeding. FPUC’s stated reason for requesting the year-end capital structure is to reflect the issuance of new shares of common equity in mid-year 2009. Use of a year-end capital structure produces an overall cost of capital that is 20 basis points greater than the rate of return indicated by a 13-month average capital structure. This incremental difference represents approximately $240,000 in annual revenue requirements. The equity ratio using FPUC’s alternatively proposed year-end capital structure is 52.75 percent which is 4.62 percentage points higher than the 13-month average capital structure equity ratio of 48.13 percent.
The Company acknowledged that use of a year-end capital structure is a departure from the long-standing Commission policy of using a 13-month average capital structure. By using a projected test year, staff believes the Company’s projected equity issuance is being partially recognized in the rate setting process. Staff believes that the Company should use a 13-month average capital structure corresponding with its 13-month average rate base, so that all the components are consistent. Furthermore, staff does not believe that FPUC has demonstrated sufficient extenuating circumstances, such as extraordinary growth or inflation, to merit a divergence from the standard practice of using a 13-month average capital structure. For these reasons, staff recommends that FPUC should use a 13-month average capital structure to be consistent with its use of a 13-month average rate base and past Commission practice as approved in Order No. 10449.[7]
Additionally, the Company used a capital structure excluding the unregulated subsidiary Flo-Gas balances in the capital structure for purposes of its request for a rate increase. However, FPUC argued in support of including the unregulated subsidiary Flo-Gas balances in the capital structure, since it believes these funds cannot be earmarked for specific purposes. FPUC stated that this treatment places the Company’s unregulated propane operations at a competitive disadvantage to other propane companies as justification for the inclusion of unregulated Flo-Gas balances in the capital structure. In reconciling rate base and capital structure, the Commission’s practice regarding non-utility investment is stated below:
. . . we believe all non-utility investment should be removed directly from equity when reconciling the capital structure to rate base unless the utility can show, through competent evidence, that to do otherwise would result in a more equitable determination of the cost of capital for regulatory purposes. In the case of Gulf, we believe that the non-utility investment should be removed from equity. This will recognize that non-utility investments will almost certainly increase a utility’s cost of capital since there are very few investments that a utility can make that are of equal or lower risk. Removing non-utility investments directly from equity recognizes their higher risks, prevents cost of capital cross-subsidies, and sends a clear signal to utilities that ratepayers will not subsidize non-utility related costs.[8]
Based on these reasons, staff recommends FPUC continue to remove non-utility investments directly from equity recognizing their higher risks and preventing cross subsidization through the cost of capital. This treatment is consistent with past Commission practice as well as in FPUC’s most recent rate cases.[9]
What is the appropriate weighted average cost of capital including the proper components, amounts and cost rates associated with the capital structure
Recommendation:
The appropriate weighted average cost of capital for the test year is 8.23 percent. This is a calculation based upon decisions in preceding issues. (Livingston)
Staff Analysis:
For its projected test year capital structure, FPUC allocated investor capital amounts from its consolidated 13-month average capital structure to its gas division. FPUC specifically identified customer deposits, deferred taxes, and investment tax credits for the gas division in developing the capital structure. The resulting overall cost of capital is 8.74 percent, which is based on an equity ratio as a percentage of investor-supplied capital of 48.13 percent and a return on common equity (ROE) of 11.75 percent.
As discussed in Issue 11, staff recommends the appropriate amount of ADITs to include in FPUC’s capital structure is $2,773,818. In Issue 12, staff recommends $115,553 as the appropriate amount of ITCs to include in the capital structure at a cost rate of 8.79 percent. Staff recommends a cost rate for short-term debt of 2.73 percent in Issue 13. In Issue 14, staff recommends 7.90 percent as the appropriate cost rate for long-term debt. As discussed in Issue 15, staff recommends 11.00 percent as the appropriate mid-point ROE. In Issue 16, staff recommends the capital structure shown on Schedule 2.
The net effect of these adjustments is a reduction in the overall cost of capital from the 8.74 percent return requested by the Company to a return of 8.23 percent recommended herein. Based upon the proper components, amounts, and cost rates associated with the capital structure for the test year ending December 31, 2009, staff recommends that the appropriate weighted average cost of capital for FPUC is 8.23 percent. Staff’s recommended test year capital structure is shown on Schedule 2.
Has FPUC eliminated the appropriate amount of expense attributable to non-regulated business?
Recommendation:
No. Account 912.1 – Demonstrating and Selling Expenses should be reduced by $73,751 for the projected 2009 test year. (Prestwood)
Staff Analysis:
The Company allocated the incorrect amount of payroll for merchandise and jobbing customers to its non-regulated operations in 2007 and 2008. In both years, warranty programs were counted as separate customers in addition to being counted as merchandise and jobbing customers. This resulted in an overstatement of the number of non-regulated customers. Also, the time studies used by the Company were based on historical periods that did not take into account the dramatic slowdown in the housing and construction industry that began in late 2007. To correct for these errors, the Company increased the expenses allocated to Account 912.1 Demonstrating and Selling Expenses for its regulated natural gas operations in 2008 and 2009 by an estimated $100,000. The Company indicated that it would record the actual amount required for this adjustment based on updated customer counts and time studies late in 2008.
In Audit Finding No. 4, staff auditors noted that subsequent to the filing, FPUC calculated the actual effect based on updated customer counts and time studies in December 2008, which increased regulated natural gas expenses for 2008 by $24,881. The Company trended the payroll costs in this account at 5.5 percent from 2008 to 2009. This produced a 2009 projected test year amount of $26,249 versus the $100,000 the Company had estimated.
Account 912.1 – Demonstrating and Selling Expenses should be reduced by $73,751 for the projected 2009 test year. The Company concurs with this adjustment.
Has FPUC eliminated all revenues and expenses associated with franchise fees?
Recommendation:
No. Both operating revenues and taxes other than income should be reduced by $1,441,002 for the 2009 projected test year. (Prestwood)
Staff Analysis:
The Company failed to remove both franchise fee revenue and franchise fee expense from its projected 2009 test year operations. Franchise fees are billed as a separate line item on the customers’ bills. Franchise fees are not considered a general expense applicable to all of the Company’s customers. The appropriate franchise fee rate is applied to only those customers’ bills that reside within the franchising entity’s boundaries. Therefore, neither the revenues nor the expenses related to franchise fees should be included in the income statement for ratemaking purposes. Both operating revenues and taxes other than income should be reduced by $1,441,002 for the 2009 projected test year. Since these amounts offset each other, there is no effect on the amount of net operating income.
Has FPUC eliminated all revenues and expenses associated with gross receipts tax?
Recommendation:
No. Both operating revenues and taxes other than income should be reduced by $2,315,886 for the projected 2009 test year. (Prestwood)
Staff Analysis:
The Company failed to remove both gross receipts tax revenue and gross receipts tax expense from its projected 2009 test year operations. Although the gross receipts tax is applicable to all of the Company’s customers, it is billed as a separate line item on the customers’ bills. Therefore, neither the revenues nor the expenses related to the gross receipts tax should be included in the income statement for ratemaking purposes. Both operating revenues and taxes other than income should be reduced by $2,315,886 for the projected 2009 test year. Since these amounts offset each other, there is no effect on the amount of net operating income.
Is FPUC’s inflation trend factor appropriate?
Recommendation:
Yes, FPUC’s inflation trend factor is appropriate. (Hewitt)
Staff Analysis:
FPUC used nationally known sources to derive its CPI trend factor of 2.7 percent. (Direct Testimony of Robert J. Camfield, p. 88) Because the trend factor was developed from mid 2008-data, the dramatic fall in energy prices and the economy were not foreseen. So, although the CPI has fallen since 2008, the State's National Economic Estimating Conference in February 2009 forecast that the CPI will reach 2.6 percent in 2010 and afterwards will not fall below 2.7 percent going out to 2019. Therefore, FPUC's trend factor of 2.7 percent is reasonable for use in this docket.
Should an adjustment be made for an invoice not recorded to Account 903 - Customer Records and Collections?
Recommendation:
Yes. Account 903 – Customer Records and Collections should be increased by $24,539 for the 2009 projected test year. (Prestwood)
Staff Analysis:
Audit Finding No. 3 disclosed that the December 2007 invoice from the entity that prepares and mails the bills was not accrued at year end. The December invoice, which totaled $42,018, was charged to a clearing account. The clearing account was allocated among the operations with 54 percent, or $22,690, being charged to natural gas. The December 2007 amount was trended up by 8.15 percent to arrive at $24,539 for 2009. Account 903 – Customer Records and Collections should be increased by $24,539 for the 2009 projected test year. The Company concurs with this adjustment.
Should FPUC’s Account 904 - Uncollectible Accounts expense be adjusted and what is the appropriate factor to include in the revenue expansion factor?
Recommendation:
Yes. Account 904 – Uncollectible Accounts expense should be reduced by $116,853. Also, the bad debt factor to include in the net operating income multiplier should be .51 percent. (Prestwood)
Staff Analysis:
The Company calculated Account 904 - Uncollectible Accounts expense for the 2009 test year based on the 2008 expense increased for the projected 2009 write-offs. The 2009 write-offs were expected to increase due to anticipated higher customer bills driven by the Purchased Gas Adjustment (PGA) clause. The Company reasoned that a projected increase in customer bills, due to a higher PGA, coupled with the inability to increase customer deposits until at least twelve months of higher bills had been rendered, would cause the write-off of bad debts to increase.
The Company’s calculation was based on an average of two typical bills. The typical bills were for a residential customer using 25 therms and for a commercial customer using 200 therms. The average of these two bills was estimated for the 12 months ended September 30, 2008, and the 12 months ended September 30, 2009. The Company determined that there was an 111 percent increase in the amount to be written off, net of the deposit, between the two periods. The deposit amount was held constant for both periods to reflect the Company’s inability to increase customer deposits in step with the increase in the typical bill. The Company applied the 111 percent increase to the 2008 uncollectible expense to determine the 2009 amount. In addition, it applied 2 percent for customer growth, plus 10 percent to reflect the effects of the current economic downturn. The Company’s total proposed projected Uncollectible Accounts Expense for 2009 is $639,175, which is an increase of $369,187 over 2008.
Traditionally, uncollectible expense has been calculated based on total historical write-offs expressed as a percentage of total revenue. This percentage is then applied to the test year revenue to determine the uncollectible expense. If revenue increases in the test year then the allowed uncollectible expense will also increase.
Staff analyzed the Company’s uncollectibles for the past five years. Staff is aware of the current economic conditions and the impact that it is having on uncollectible accounts. However, staff believes that using total actual write-offs and total actual revenue gives a more complete view of uncollectible accounts expense as opposed to only reviewing typical bills.
Staff recommends using the year 2008 average net write-off and increasing this percentage by 10 percent to recognize the effect of the current downturn in the economy. The 2008 net write-off percentage was .46 percent and when increased by 10 percent equals .51 percent. The year 2008 reflects the most recent known conditions and appears reasonable when compared with other years. For example, the net write off percentage for 2006 was also .46 percent. Applying the .51 percent net write-off percentage to the 2009 projected test year revenues of $102,416,152, produces an uncollectible accounts expense of $522,322 for the test year. This necessitates an adjustment to decrease Account 904 - Uncollectible Accounts expense by $116,853.
It should be noted that this adjustment is for ratemaking purposes only. For surveillance, annual report, and other reporting purposes, the Company’s actual bad debt expense should be reported.
Should an adjustment be made to expenses for misclassified travel expenses for the projected test year?
Recommendation:
Yes. Staff recommends an adjustment to decrease Account 912 - Demonstration and Selling Expenses by $2,093 for the test year. (Prestwood)
Staff Analysis:
Audit Finding No. 9 revealed that there were transactions inappropriately allocated between the different companies and divisions. Invoices totaling $2,610 were found in 2007 expenses that were allocated 75 percent or $1,957 to natural gas and should have been charged to electric. Staff used the compounded inflation factor for 2007 to 2009 of 6.97 percent to increase the 2007 amount of $1,957 to a 2009 amount of $2,093. Staff recommends an adjustment to decrease Account 912 - Demonstration and Selling Expenses by $2,093 for the test year. The Company concurs with this adjustment.
Should an adjustment be made to Account 913 - Promotional Advertising expense for the projected test year?
Recommendation:
Yes. Staff recommends an adjustment to reduce Account 913 - Promotional Advertising expense by $56,238, for the 2009 test year. (Prestwood)
Staff Analysis:
In Audit Finding No. 2, staff auditors noted that FPUC paid $52,000 in 2007 for a contract with St. Joe Arvida homes. Because the advertisement only includes the FPUC logo, it does not meet the requirements of Rule 25-17.015(5), F.A.C., for recovery through the Energy Conservation Cost Recovery clause (ECCR). Since it does not qualify for recovery through the ECCR, the Company charged this contract to Account 913 - Promotional Advertising expense. The amount was trended to $56,238, in the 2009 forecast.
In its response to the Audit Finding, the Company stated that the $56,238 forecast for 2009 expenses should be included in the Company’s base rate request as the advertising was valuable, cost effective, and beneficial to all customers. Further, while the FPUC logo was relatively small, the effort made by the developer in utilizing the advertising dollars was very effective. The money went into training the developer’s sales staff and promoting natural gas in Victoria Park. The Company contends that the advertising was more successful than FPUC’s broad based conservation advertising campaign across a greater number of customers.
In its order, dated August 21, 2007, concerning an investigation into the 2005 earnings of FPUC, the Commission stated:
The audit disclosed that a $52,000 payment was made to St. Joe/Arvida Homes for co-op advertising. This payment was booked as a promotional advertising expense. The ad promoted the sale of new homes in the St. Joe development at Victoria Park in the Deland, Florida area. The only reference to FPUC is a small generic FPUC logo in the lower left hand corner of the ad. The ad does not contain any safety, conservation, instructional or informational material regarding the use of natural gas. It appears that the sole purpose of the ad is to induce the public to purchase homes in Victoria Park.
. . . Our general policy regarding advertising expenses is to allow advertising that contains informational and instructional material. This type of advertising primarily conveys information as to what the utility urges or suggests customers should do in utilizing gas service to protect health and safety, to encourage environmental protection, to utilize their gas equipment safely and economically, or to conserve natural gas. Advertising that is considered to be institutional, goodwill, promotional or image-enhancing is usually not allowed for revenue requirement purposes.[10] We find that the Victoria Park ad does not meet the criteria for inclusion as an advertising expense for the purposes of determining the amount of overearnings for 2005. Therefore, advertising expenses shall be reduced by $52,000.[11]
Staff recommends an adjustment to reduce Account 913 - Promotional Advertising expense by $56,238, for the 2009 test year.
Should an adjustment be made to Account 920 - Administrative and General Salaries for officer’s salaries?
Recommendation:
Yes. Account 920 - Administrative and General Salaries should be decreased by $44,595 for the projected 2009 test year. (Prestwood)
Staff Analysis:
Audit Finding No. 5 noted that the forecast for Account 920 - Administrative and General Salaries, included an increase of 11.5 percent for 2008 and 2009. The increase was based on a study done during the last rate case for the Electric Division that showed that the officers’ salaries were lower than the rest of the industry. However, the Board of Directors gave the officers an eight percent increase in 2008, and a three percent increase has been authorized for 2009. The Utility has revised its estimated salaries for these three employees from $871,971 to $786,212 for the year 2009. The difference of $85,759 times the 52 percent allocation to natural gas results in a decrease of $44,595.
Account 920 - Administrative and General Salaries should be decreased by $44,595 for the projected 2009 test year. The Company agreed with these findings based on the known facts at the time of the audit (report dated March 4, 2009). However, the Company did point out that the Board of Directors could award additional compensation to these executives for 2009.
Should an adjustment be made for the cost of new flooring in the corporate office, for the projected test year?
Recommendation:
Yes. Account 935 – Maintenance of General Plant should be reduced by $6,750, for the projected test year, to reflect the economic life of the flooring. (Prestwood)
Staff Analysis:
In the test year, the Company included the cost associated with the new flooring for the corporate office. The anticipated cost for flooring is $100,000, based on a vendor quote. The total allocation was based on a four-year recovery period. The $25,000 annual cost, based on the four-year recovery period, was allocated to natural gas based on common plant allocation factors, and totals $13,500.
In response to a data request, the Company disclosed that the new floor has an eight-year life. The Company used the four-year recovery period because this is the period it expects the new rates to be in effect. Staff recommends that the flooring be amortized over the eight-year life of the floor. This results in an adjustment to decrease Account 935 – Maintenance of General Plant by $6,750.
Is the requested storm damage accrual appropriate?
Recommendation:
No. Staff recommends an adjustment to decrease Account 924 - Property Insurance by $162,080 and increase working capital $81,040. These adjustments include staff’s recommended an annual storm damage accrual of $6,000 with a target level of $1,000,000. (Prestwood)
Staff Analysis:
The Company is requesting an annual storm damage accrual of $87,000 and a total for Account 924 - Property Insurance of $214,531 for the 2009 test year.
FPUC began making accruals of $18,000 per year to the storm damage reserve in 1996 and accumulated a balance of $59,070 before ceasing the accruals in January 2003. In its 2005 rate case, FPUC did not request permission to make further accruals to its storm damage reserve, and the Commission did not allow any accrual in the setting of new rates.[12]
The only charge made to the storm damage reserve from 1996 until 2004 was a charge of $62,430 related to Hurricane Floyd in 1999. Over an eight-year period (1996–2003), the average annual charge to the storm damage reserve was $7,804.1
On December 28, 2004, FPUC filed a petition seeking authority to implement a Storm Cost Recovery Clause for recovery of extraordinary expenditures related to Hurricanes Charley, Frances, and Jeanne that struck its service territory in 2004. In Order No. PSC-05-1040-PAA-GU, the Commission determined that the amount of storm costs for the three storms was $543,602. Also in that proceeding, the Commission ordered that $117,773, of over earnings for the year 2002, be credited to the storm damage reserve account to establish a reserve amount for future storms.1
In Order No. PSC-07-0671-PAA-GU, the Commission found that:
Given the $534,602 of storm damage sustained by the Company during 2004, the current balance in the storm damage reserve is inadequate to offset damages from any future storms. Therefore, we find that the establishment of an adequate storm damage reserve is a reasonable disposition of the remaining amount of the 2005 excess earnings.
. . . The remaining amount of the 2005 excess earnings shall be applied to the storm reserve to cover future storm-related costs.[13]
The net amount recorded to the storm damage reserve as a result of the 2005 over-earnings was $612,774.
In the matter of FPUC’s 2006 earnings, the Commission determined that the excess earnings of $176,144 should be applied to increase the storm reserve balance. The Commission noted that the annual storm reserve accrual could be an issue in the Company’s forthcoming rate case in Docket No. 080366-GU.[14]
The Company’s storm reserve balance as of September 30, 2008, is $788,918, and has been collected from customers through the Company’s over-earnings. This amount is in excess of the storm damage of $543,602, which was incurred as a result of Hurricanes Charley, Frances, and Jeanne that struck its service territory in 2004. The storm damages in 2004 represent one of the worst years for storm damage for the utility industry in Florida’s history.
FPUC did not file a study in support of its request to establish an annual storm damage accrual of $87,000 or a target level for the reserve. Instead, the Company estimated the replacement basis for all mass property items, which are subject to some level of damage, to be $164 million. It then chose one half of one percent of the $164 million, as its target reserve level of $820,118. Comparing the current reserve balance of $788,918 to the target leaves a reserve deficiency of $31,200. The Company then spread this $31,200 over eight years to arrive at $3,900 per year. It added the $3,900 deficiency to an average annual storm damage of $83,000, based on actual storm damage for the 8-year period of 2000 through 2008. The Company arrived at $87,000 per year as its required accrual for storm damage.
The Company’s total 2009 projection for Account 924 - Property Insurance was based on the $87,000 annual accrual for storm damage discussed above, plus historical transactions for this Account in 2007, adjusted for inflation. Also, any previous storm damage cost in the account was removed. However, in its calculations, the Company failed to remove $81,080 related to electric operations from the account.
Staff believes that the Company should begin to build its storm reserve through an annual accrual process rather than through one-time entries resulting from excess earnings. However, staff also believes that the current balance may be near its optimal level given the current reserve balance of $788,918, compared to the $543,206 of storm damage that was incurred as a result of three hurricanes in 2004. Staff recommends an annual accrual of $6,000 with a target level of $1,000,000. These amounts can be reviewed again in the Company’s next rate case. Staff also notes that the Commission encouraged FPUC to file a storm damage study to determine an appropriate target level and annual accrual amount for its storm damage reserve in Order No. PSC-05-1040-PAA-GU, issued October 25, 2005.[15]
Staff recommends an adjustment to decrease Account 924 - Property Insurance by $81,080 to eliminate the expenses related to electric operations. Staff also recommends an adjustment to decrease Account 924 - Property Insurance by $81,000 to reflect staff’s recommended storm damage accrual of $6,000, versus the Company’s request of $87,000. This results in a total adjustment to decrease Account 924 - Property Insurance by $162,080. Also, working capital should be increased by $81,040.
Should an adjustment be made to Account 926.5 - Employee Benefits Medical, for the projected test year?
Recommendation:
Yes. Account 926.5 - Employee Benefits Medical should be reduced by $235,805. (Prestwood)
Staff Analysis:
The Company’s projections for Account 926.5 - Employee Benefits Medical were based on information provided by its insurance carrier. The insurance carrier estimated increases in the Company’s medical costs of 11.5 percent for 2008, 6.5 percent for 2009, and 15 percent for 2010 through 2012. The Company projected its 2008 medical costs based on an increase of 11.5 percent over the 2007 actual amount consistent with the information provided by the insurance carrier. However, even though the insurance carrier provided a specific estimate of a 6.5 percent increase for the year 2009, the Company based its projection on the average increase expected over the 4-year period from 2009 through 2012.
The Company explained the 2009 increase by stating that:
It is appropriate to request the additional adjustment for recovery of the average medical expense expected during the next four years as this period is historically used to represent the time period between rate cases.
(Witness Lundgren Direct Testimony, p. 54)
The Company’s adjustment is based on increases in medical cost that will occur during the three years beyond the end of the test year. However, the Company has not recalculated all of the elements that make up its operations for this same period. This produces an adjusted test year with information related to rate base, net operating income, and capital structure based on time periods that do not match.
In Audit Finding No. 7, staff auditors expressed concerns as to whether FPUC should be allowed to project its insurance costs to 2012. All other expenses were projected through 2009.
Staff recommends that the test year medical costs be based on the specific estimate of a 6.5 percent increase for the year 2009 provided by the Company’s insurance carrier. The Company’s 2008 medical cost is projected to be $958,713. Increasing this amount by 6.5 percent produces $1,021,029, which is a decrease of $235,805 compared to the Company’s original filing.
Issue 30: Should an adjustment be made to rate case expense for the projected test year and what is the appropriate amortization period?
Recommendation: Yes. Rate case expense should be reduced by $60,109 and the expense should be amortized over four years. Also, the unamortized portion of the allowed expense should be excluded from the projected test year working capital resulting in a decrease to working capital of $324,270. (Prestwood)
Staff Analysis: The Company originally requested $844,080 in rate case expense, amortized over four years. As a part of its analysis, the staff requested an updated expense to date through February 28, 2009, with supporting documents as well as an estimated amount to complete the case. The Company submitted a revised estimate of rate case expense through completion of the PAA process of $606,643.
The components of the Company’s estimated rate case expense are as follows:
|
Table 30-1 Rate Case Expense |
||||
|
|
Original Filing |
Actual as of 2/28/2009 |
Additional Estimated |
Total Revised |
|
Consultants |
$576,250 |
$369,762 |
$73,079 |
$442,841 |
|
Legal Fees |
107,500 |
12,430 |
30,319 |
42,749 |
|
Travel Expenses |
34,080 |
1,790 |
10,700 |
12,490 |
|
Paid Overtime |
39,000 |
422 |
33,000 |
33,422 |
|
Other Expenses |
87,250 |
15,840 |
56,300 |
72,140 |
|
Total |
$844,080 |
$400,244 |
$203,398 |
$606,643 |
Staff has examined the requested actual expenses and supporting documentation and believes these expenses are reasonable. Staff also reviewed the estimated expenses above and believes the estimated expenses submitted by the Company are reasonable.
In previous rate cases involving FPUC, the Commission has allowed one half of the balance of unamortized rate case expense to be included in working capital as a part of rate base. Staff notes that the Commission has a long-standing policy in electric and gas rate cases of excluding unamortized rate case expense from working capital, as demonstrated in a number of prior cases.[16] The rationale for this position was to adopt a sharing concept whereby the cost of a rate case would be shared between the ratepayer and stockholder, i.e., include the expense in the O&M expenses, but not allow a return on the unamortized portion. This approach recognizes that both the stockholders and the ratepayers benefit from a rate proceeding. It espouses the belief that customers should not be required to pay a return on funds expended to increase their rates.
While this is the approach that has been used in electric and gas cases, water and wastewater cases have included unamortized rate case expense in working capital, based on a simple average. The difference stems from a statutory requirement that water and wastewater rates be reduced at the end of the amortization period.[17] While unamortized rate case expense is not allowed to earn a return in working capital for electric and gas companies, it is offset by the fact that rates are not reduced after the amortization period ends.
In Docket No. 910778-GU, the issue was argued fully and the Commission reaffirmed its long-standing policy of excluding unamortized rate case expense from working capital in electric and gas rate cases.[18] Order No. PSC-92-0580-FOF-GU stated that unamortized rate case expense is excluded from working capital "in an effort to reflect a sharing of rate case expenses between the stockholders and the ratepayers since both benefit from a rate case proceeding." Staff notes that inclusion of unamortized rate case expense in working capital in the FPUC case is an exception to the Commission’s long-standing policy.
FPUC was initially allowed to include rate case expense in working capital in its 1993 rate proceeding.[19] At that time, the Commission found that the exclusion of the unamortized portion of rate case expense from working capital is a partial disallowance. The Commission concluded that rate case expense is a necessary cost of doing business. The order included a concurring opinion by Commissioner Lauredo, where it was stated that:
. . . his decision was based solely on the facts and circumstances involved with this case. He emphasized this result should not be standing Commission policy and that no precedential value should be assigned to his concurrence.[20]
Staff recommends that the appropriate rate case expense is $603,643, amortized at the rate of $150,911 over four years. This results in a reduction to Account 928 – Regulatory Commission expenses of $60,109. In addition, the staff recommends that none of the unamortized rate case expense should be included in working capital for the projected test year. As a result, working capital should be reduced by $324,270.
Should an adjustment be made to accumulated depreciation and depreciation expense to reflect the Commission’s decision in Docket No. 080548-GU, In re: 2008 Depreciation Study for FPUC to be implemented 2009?
Recommendation:
Yes. Staff recommends an adjustment to increase depreciation expense by $205,596 and an adjustment to increase depreciation reserve by $118,954 for the 2009 test year. (Prestwood, P. Lee)
Staff Analysis:
The Commission approved the staff recommendation for the new depreciation study file by the Company in Docket No. 080548-GU.[21] The approved rates have the following effect on depreciation expense for the 2009 test year:
|
Table 31-1 Depreciation Expense |
|
|
Increase in Depreciation Expense for Natural Gas Assets |
$178,133 |
|
Increase in Depreciation Expense for Shared Common Assets allocated to Natural Gas |
21,383 |
|
Increase in Depreciation Expense for Non-Regulated Assets (Decrease in depreciation on non-regulated plant creates increase for regulated operations) |
3,381 |
|
Decrease in Depreciation Expense for AEP Assets |
(2,460) |
|
Increase in Depreciation Expense for Bare Steel Replacement Program |
3,748 |
|
Increase in Depreciation for Land Recovery Rights |
1,411 |
|
Total Increase in Depreciation Expense |
$205,596 |
The approved rates have the following effect on the accumulated depreciation reserve for the 2009 test year:
|
Table 31-2 Accumulated Depreciation Reserve |
|
|
Increase in Depreciation Reserve for Natural Gas Assets |
$97,007 |
|
Increase in Depreciation Reserve for Shared Common Assets allocated to Natural Gas |
54,380 |
|
Decrease in Depreciation Reserve for Non-Regulated Assets (Decrease in depreciation on non-regulated plant creates decrease for regulated operations) |
(31,326) |
|
Decrease in Depreciation Reserve for AEP Assets |
(1,230) |
|
Increase in Depreciation Reserve for Bare Steel Replacement Program |
123 |
|
Total Increase in Depreciation Reserve |
$118,954 |
Should an adjustment be made to remove expenses associated with vacant positions?
Recommendation:
Yes. Staff recommends that operating expenses be reduced by $190,505 to reflect vacant employee positions as of April 2009. (Prestwood)
Staff Analysis:
In its original filing, the Company included projected expenses of several new or vacant positions to be filled by the beginning of the 2009 projected test year. Staff has reviewed the pre-filed testimony supporting the positions and obtained written job descriptions for each job. Staff believes the addition of these positions is appropriate but recommends that an adjustment be made to reflect the timing of when these positions will be filled.
In response to Staff Data Request No. 91, the Company provided the status of each of the original open positions including actual salary. Nine of the eleven positions that still remain open as of April 2009 were described as expecting to be filled in two to six months. If the Company does take an additional six months to fill these positions they would only be filled for approximately three months of the 2009 projected test year. There is no certainty that these positions will be filled at all.
Staff recommends that 75 percent of the projected salaries, or $190,505 associated with these positions be removed from the test year expenses. This decrease would be distributed to the following accounts:
|
Account 870 |
$32,625 |
|
Account 880 |
32,625 |
|
Account 887 |
21,763 |
|
Account 892 |
21,763 |
|
Account 903 |
37,500 |
|
Account 912 |
35,646 |
|
Account 925 |
8,583 |
|
Total |
$190,355 |
Should an adjustment be made to remove a portion of Account 408.1 - Taxes Other Than Income Taxes for property tax expense associated with the new South Florida Operations Facility?
Recommendation:
Yes. Staff recommends that Account 408.1 - Taxes Other Than Income Taxes be reduced by $114,079 for the property tax expense associated with the new South Florida Operations Facility. Staff also recommends that this expense be addressed with the new South Florida Operations Facility rate relief issue. (Prestwood)
Staff Analysis:
Audit Finding No. 10 states that FPUC is constructing a building for the South Florida Operations Facility that is not scheduled to be placed in service until mid 2010. However, the associated property taxes for this building, in the amount of $114,079, were included in the 2009 projected test year.
The Company discussed the property tax expense in its direct testimony as follows:
We now anticipate completion of the facility in 2010, however, we feel it is appropriate to seek recovery of the increase [in property taxes] as it is an uncontrollable increase the Company will incur over most of the period that the new rates will be in effect. The anticipated increase in property tax relating to the building is expected to be $114,079, . . . however as an alternative, the Commission may feel it is more appropriate to combine this tax expense with the special recovery of the new office building as an alternative.
(Witness Lundgren Direct Testimony, p. 59)
The Company has requested that the Commission consider granting special rate relief for recovery of the South Florida Operations Center, to be effective after the in-service-date of the facility which is expected to be in September of 2010. Staff recommends that Account 408.1 - Taxes Other Than Income Taxes be reduced by $114,079 and that this expense be addressed with the new South Florida Operations Facility rate relief issue (Issue 54).
Is an adjustment required for FPUC’s Taxes Other Than Income Taxes due to Common Plant Allocations for the projected test year appropriate?
Recommendation:
Yes. FPUC’s Account 408.1 – Taxes Other Than Income Taxes should be reduced by $66,363 for the projected test year. (Prestwood)
Staff Analysis:
In Audit Finding No. 8, staff auditors noted that property taxes associated with common plant were not allocated consistent with the allocation of the common plant. In its response to the audit finding, the Company agreed with the concept of this finding but recommended using a slightly different percentage in the calculation. The Company recommended using the 2008 net plant of each division excluding vehicles. The Company noted that vehicles are not part of its property tax base. Staff recommends an adjustment to decrease Account 408.1 – Taxes Other Than Income Taxes by $53,265 for the test year, based on the percentage recommended by the Company.
Staff auditors also noted in Audit Finding No. 8 that property taxes associated with non-regulated plant, located in the natural gas divisions, were not allocated consistent with the allocation of the non-regulated plant. In its response to the audit finding, the Company agreed with the concept of this finding but recommended using a slightly different percentage in the calculation. The Company recommended using the 2008 net plant allocated to non-regulated excluding vehicles. The Company noted that vehicles are not part of its property tax base. Staff recommends an adjustment to decrease Account 408.1 – Taxes Other Than Income Taxes by $13,098 for the test year, based on the percentage recommended by the Company.
The total of these 2 adjustments results in a decrease in Account 408.1 – Taxes Other Than Income Taxes of $66,363 for the test year.
What is the appropriate Income Tax Expense, including current and deferred income taxes, investment tax credit (ITC) amortization, and interest synchronization?
Recommendation:
The appropriate amount of Income Tax Expense, including current and deferred income taxes, ITC amortization, and interest synchronization is a negative $1,184,861 for the 2009 projected test year. (Kyle, Livingston)
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations, the requested total income tax expense of a negative $1,529,681 (current, deferred, and ITC) should be increased by $344,820 resulting in an adjusted total of a negative $1,184,861 for the 2009 projected test year. (See Schedule 3)
|
Amount Requested |
($1,529,681) |
|
Staff Adjustments: |
|
|
Effect of Other Adjustments |
281,830 |
|
Interest Synchronization |
62,990 |
|
Total Staff Adjustments |
344,820 |
|
Staff Adjusted Amount |
($1,184,861) |
Is FPUC’s Net Operating Income for the projected test year appropriate?
Recommendation:
No. FPUC’s Net Operating Income with staff’s recommended adjustments is $740,052, as shown on Schedule 3. (Prestwood)
Staff Analysis:
This is a fallout issue. The correct net Operating Income should is $740,052, as shown on Schedule 3.
What is the appropriate projected test year revenue expansion factor and the appropriate net operating income multiplier, including the appropriate elements and rates for FPUC?
Recommendation:
The appropriate Revenue Expansion Factor is 61.7400 and the appropriate Net Income Multiplier is 1.6197, as shown on Schedule 4. (Prestwood)
Staff Analysis:
The only change in the Net Operating Income Multiplier filed by the Company is the rate used for bad debt, as discussed in Issue 23. A comparison between the Company and staff is shown below:
|
Line No. |
Description |
Company |
Staff |
|
1 |
Revenue Requirement |
100.00% |
100.00% |
|
2 |
Gross Receipts Tax Rate |
0% |
0% |
|
3 |
Regulatory Assessment Rate |
.50% |
.50% |
|
4 |
Bad Debt Rate |
.73% |
.51% |
|
5 |
Net Before Income Taxes (1)-(2)-(3)-(4) |
98.77% |
98.99% |
|
6 |
State Income Tax Rate |
5.50% |
5.50% |
|
7 |
State Income Tax (5x6) |
5.43% |
5.44% |
|
8 |
Net Before Federal Income Tax (5-7) |
93.34% |
93.55% |
|
9 |
Federal Income Tax Rate |
34.00% |
34.00% |
|
10 |
Federal Income Tax (8x9) |
31.73% |
31.81% |
|
11 |
Revenue Expansion Factor (8)-(10) |
61.60% |
61.74% |
|
12 |
Net operating Income Multiplier 100%/Line 11 |
1.62330 |
1.6197 |
Is FPUC’s requested annual operating revenue increase of $9,917,690 for the 2009 projected test year appropriate?
Recommendation:
No. The appropriate annual operating revenue increase is $8,567,376, as shown on Schedule 5 for the projected test year. (Prestwood)
Staff Analysis:
This is a fall out issue and is shown on Schedule 5.
COST OF SERVICE AND RATE DESIGN
Are FPUC’s estimated revenues from sales of gas by rate class at present rates for the projected test year appropriate?
Recommendation:
Yes. FPUC’s estimated revenues from sales of gas by rate class at present rates for projected test year are appropriate. (A. Roberts)
Staff Analysis:
Staff has reviewed the Company’s calculations and FPUC’s estimated revenues from sales of gas by rate class at present rates for the projected test year are appropriate.
What is the appropriate cost of service methodology to be used in allocating costs to the rate classes?
Recommendation:
The appropriate methodology is contained in Schedule 6, pages 1-21. (Draper, Prestwood)
Staff Analysis:
The appropriate cost of service methodology to be used in allocating costs to the various rate classes is reflected in staff’s cost of service study contained in Schedule 6, pages 1-21.
The purpose of a cost of service study is to allocate the total costs of the utility system among the various rate classes. The results of the cost of service study are used to determine how any revenue increase granted by the Commission will be allocated to the rate classes. Once this determination is made, rates are designed for each rate class that recover the total revenue requirement attributable to that class. In rate design, the customer charge is typically determined first, with the per-therm energy charge being the fall-out charge.
The Company’s proposed cost of service study is contained in MFR Schedule H. Staff’s recommended study differs in several respects from the Company’s filed study. Staff’s study reflects the staff-recommended adjustments to rate base, rate of return, revenues, expenses, and resulting operating revenue increase as shown in Issue 38.
What are the appropriate customer charges?
Recommendation:
Staff’s recommended charges are as follows:
|
Rate Class |
Staff Recommended Customer Charges |
|
RS |
$11.00 |
|
GS-1/GSTS-1 |
$20.00 |
|
GS-2/GSTS-2 |
$33.00 |
|
LVS/LVTS |
$90.00 |
|
IS/ITS |
$280.00 |
|
RS-GS |
$21.30 |
|
CS-GS |
$35.86 |
(Draper, A. Roberts)
Staff Analysis:
The customer charge is a fixed charge that applies to each customer’s bill, regardless of the quantity of gas used for the month. The customer charge is typically designed to recover costs such as metering and billing that are incurred whether any gas is consumed or not.
Staff’s recommended customer charges are contained in the table below. The table also shows the current customer charges and the Company-proposed charges.
|
Proposed Rate Class |
Current Customer Charges |
Company- Proposed Customer Charge |
Staff Recommended Customer Charge |
|
RS |
$8.00 |
$12.00 |
$11.00 |
|
GS-1/GSTS-1 |
$15.00 |
$20.00 |
$20.00 |
|
GS-2/GSTS-2 |
$15.00 |
$33.00 |
$33.00 |
|
LVS/LVTS |
$45.00 |
$90.00 |
$90.00 |
|
IS/ITS |
$240.00 |
$240.00 |
$280.00 |
|
RS-GS |
$18.72 |
$22.45 |
$21.30 |
|
CS-GS |
n/a |
$36.31 |
$35.86 |
Staff’s recommended customer charge for the IS/ITS class is higher than FPUC’s proposed charge based on the customer unit cost shown in the cost of service ($276.99). For any given revenue requirement for a rate class, increasing the customer charge decreases the per therm charge. In addition, the customer charge is a small percentage of monthly bills for IS/ITS customers, who are large volume customers, compared to other rate classes, and therefore setting the customer charge at cost is reasonable.
This rate design for the residential standby generator service (RS-GS) rate has been approved in Docket No. 080072-GU.[22] The level of the RS-GS customer charge and the size of the initial block of usage that includes no per therm charge (0-19.80 therms) is derived to yield the same revenue for an average residential or generator customer. The current RS-GS customer charge is based on an average residential consumption of 22.17 therms and was based on FPUC’s 2004 rate case, Docket No. 040216-GU. In testimony, FPUC witness Schneidermann stated that the monthly average residential consumption fell to 19.8 therms per month. Based on the staff recommended residential customer charge ($11) and staff-recommended per therm charge as shown in Issue 42 (52.011 cents per therm) a residential customer using 19.8 therms will pay $21.30 (without the cost of gas). Therefore, based on the approved rate design for the RS-GS rate, the staff recommended RS-GS customer charge is $21.30. The rate design for the proposed new Commercial Standby Generator Service (CS-GS) rate is discussed in Issue 47.
Staff recommends that the customer charges as shown in the table above be approved.
What are the appropriate per therm non-fuel energy charges?
Recommendation:
The appropriate per therm non-fuel energy charges are shown in the table below:
|
Rate Class |
Staff Recommended Energy Charges (cents per therm) |
|
RS |
52.011 |
|
GS-1/GSTS-1 |
40.125 |
|
GS-2/GSTS-2 |
40.125 |
|
LVS/LVTS |
36.143 |
|
IS/ITS |
23.559 |
|
GLS/GLSTS |
24.704 |
|
RS-GS |
52.011 |
|
CS-GS |
40.125 |
(Draper)
Staff Analysis:
The non-fuel energy charge (energy charge) is the variable per-therm charge, and recovers FPUC’s cost of providing distribution service. The energy charge does not include the actual gas commodity, as that is shown separately on the bill and determined in the annual Purchased Gas Adjustment (PGA) proceedings. The energy charges are calculated to recover the class revenue requirement that remains after subtracting the revenues generated by staff’s recommended customer charges.
The table below shoes the energy charges that were in effect prior to the interim increase, the interim charges (effective March 12, 2009), the FPUC proposed charges, and the staff-recommended charges. All charges are shown in cents per therm. The staff-recommended charges are subject to change based on the Commission’s vote in other issues.
|
Rate Schedule |
Prior to interim |
Interim |
FPUC proposed |
Staff recommended |
|
RS |
48.340 |
51.938 |
52.786 |
52.011 |
|
GS-1 |
32.107 |
33.668 |
41.265 |
40.125 |
|
GSTS-1 |
32.107 |
33.589 |
41.265 |
40.125 |
|
GS-2 |
32.107 |
33.668 |
41.265 |
40.125 |
|
GSTS-2 |
32.107 |
33.589 |
41.265 |
40.125 |
|
LVS |
23.809 |
24.921 |
37.897 |
36.143 |
|
LVTS |
23.809 |
24.883 |
37.897 |
36.143 |
|
IS |
10.039 |
10.546 |
27.106 |
23.559 |
|
ITS |
10.039 |
10.493 |
27.106 |
23.559 |
|
GLS/GLSTS |
17.689 |
18.429 |
25.552 |
24.704 |
|
RS-GS |
0 (0-22.17 therms) 48.340 (< 22.17 therms) |
n/a |
0 (0-19.80 therms) 52.786 (< 19.80 therms) |
0 (0-19.80 therms) 52.011 (< 19.80 therms) |
|
CS-GS |
n/a |
n/a |
0 (0-39.52 therms) 41.265 (< 39.52 therms) |
0 (0-39.52 therms) 40.125 (< 39.52 therms) |
Schedule 7, page 1 of 6, shows a summary of the current and staff-recommended customer and energy charges for all rate schedules. Schedule 7, pages 2 through 6, show comparisons of monthly residential and commercial bills at various consumption levels. A residential customer using 20 therms per month currently pays $33.02 (including PGA and conservation costs). Under the recommended RS rates, the customer would see a $3.74 increase.
What are the appropriate miscellaneous service charges?
Recommendation:
The appropriate miscellaneous service charges are as follows:
|
Service Charge |
Staff Recommendation |
|
Establishment of Service - Regularly Scheduled |
|
|
RS, RS-GS |
$52.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$75.00 |
|
LVS, LVTS, IS, ITS |
$112.00 |
|
Establishment of Service - Same Day or Outside Normal Business Hours |
|
|
RS, RS-GS |
$69.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$96.00 |
|
LVS, LVTS, IS, ITS |
$144.00 |
|
Change of Account - Regularly Scheduled |
$23.00 |
|
Change of Account - Same Day or Outside Normal Business Hours |
$29.00 |
|
Reconnection After Disconnection for Non-Pay - Regularly Scheduled |
|
|
RS, RS-GS |
$81.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$104.00 |
|
LVS, LVTS, IS, ITS |
$141.00 |
|
Reconnection After Disconnection for Non-Pay - Same Day or Outside Normal Business Hours |
|
|
RS, RS-GS |
$98.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$125.00 |
|
LVS, LVTS, IS, ITS |
$173.00 |
|
Bill Collection in Lieu of Disconnection for Non-Pay |
$25.00 |
|
Trip Charge – Regularly Scheduled |
$23.00 |
|
Trip Charge - Same Day or Outside Normal Business Hours |
$29.00 |
(A. Roberts, Draper)
Staff Analysis:
The miscellaneous service charges are fixed charges that are paid when a specified activity occurs. The miscellaneous service charges are designed to recover the Company’s costs associated with the specific activity.
Staff’s recommended miscellaneous service charges are contained in the table below. The table also shows the present miscellaneous service charges and the Company-proposed charges.
|
Miscellaneous Service Charge |
Present Miscellaneous Service Charge |
Company Proposed Service Charge |
Staff Recommended Service Charge |
|
Establishment of Service - Regularly Scheduled |
|||
|
RS, RS-GS |
$42.00 |
$52.00 |
$52.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$60.00 |
$75.00 |
$75.00 |
|
LVS, LVTS, IS, ITS |
$90.00 |
$112.00 |
$112.00 |
|
Establishment of Service - Same Day or Outside Normal Business Hours |
|||
|
RS, RS-GS |
$56.00 |
$69.00 |
$69.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$79.00 |
$96.00 |
$96.00 |
|
LVS, LVTS, IS, ITS |
$119.00 |
$144.00 |
$144.00 |
|
Change of Account |
|||
|
Regularly Scheduled |
$19.00 |
$23.00 |
$23.00 |
|
Same Day or Outside Normal Business Hours |
$24.00 |
$29.00 |
$29.00 |
|
Reconnection After Disconnection for Non-Pay - Regularly Scheduled |
|||
|
RS, RS-GS |
$60.00 |
$81.00 |
$81.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$78.00 |
$104.00 |
$104.00 |
|
LVS, LVTS, IS, ITS |
$108.00 |
$141.00 |
$141.00 |
|
Reconnection After Disconnection for Non-Pay - Same Day or Outside Normal Business Hours |
|||
|
RS, RS-GS |
$74.00 |
$98.00 |
$98.00 |
|
GS-1, GS-2, CS-GS, GSTS-1, GSTS-2 |
$97.00 |
$125.00 |
$125.00 |
|
LVS, LVTS, IS, ITS |
$137.00 |
$173.00 |
$173.00 |
|
Bill Collection in Lieu of Disconnection for Non-Pay |
|||
|
All rate classes |
$16.00 |
$25.00 |
$25.00 |
|
Trip Charge |
|||
|
Regularly Scheduled |
$19.00 |
$23.00 |
$23.00 |
|
Same Day or Outside Normal Business Hours |
$24.00 |
$29.00 |
$29.00 |
FPUC incurs higher costs to connect or reconnect a commercial customer compared to a residential customer. When connecting a customer, FPUC typically first performs a pressure test on the line to ensure that there is no gas leakage. Then, FPUC tests each gas appliance on the premises to ensure the equipment operates properly and in a safe manner. Commercial customers are served by larger lines, and the pressure test takes longer. A large commercial customer may also have more specialized equipment, adding to the time required to perform a connection or reconnection.
The Company also proposed to eliminate from its tariff the processing fee associated with accepting credit cards or debit cards for customers who choose this payment method. In its last rate case, FPUC received approval to accept credit and debit card payments for $3.50 per transaction. The charge was designed for the Company to recover its bank and overhead costs associated with processing credit card payments. However, FPUC explained that VISA and MasterCard have rules in place that do not allow the taker of a credit card, i.e., FPUC, to charge a transaction fee. Therefore, FPUC contracted with an independent third party to process optional payments by credit and debit cards. The third party’s transaction fee is also $3.50. However, since the fee goes towards a third party vendor, not FPUC, the fee does not need to be in FPUC’s tariff. Most electric or gas companies have contracted with an outside vendor to process payment by credit or debit card.
Staff has reviewed the cost support filed by FPUC for its proposed miscellaneous charges. Based upon its review of this cost support, staff believes that FPUC’s proposed charges are reasonable, and recommends that they be approved.
Are the proposed new temporary disconnection charges appropriate?
Recommendation:
Yes. The new service charges for temporary disconnection of service ($29.00 for regularly scheduled and $35.00 for same day service) are appropriate. (A. Roberts)
Staff Analysis:
FPUC proposed two new miscellaneous service charges for temporary disconnection at the customers’ request. This charge covers the cost of shutting off a customer’s utilities when necessary to have other services performed such as termite tenting and similar situations that require the utilities to be turned off. The proposed charge for this service is $29.00 for regularly scheduled service performed within the Company’s regular business hours, and $35.00 for same day service performed outside of the Company’s normal business hours (this is a premium service offered at a higher charge to cover the cost of overtime paid to an employee working beyond their normal work schedule to provide this service).
Staff has reviewed the cost information submitted in schedule E-3 by the Company and has concluded the proposed charge for standard and premium service is cost-based and appropriate.
Is FPUC’s proposal to stratify the current commercial General Service (GS/GST) rate class into two rate classes (GS-1/GSTS-1 and GS-2/GSTS-2) appropriate?
Recommendation:
Yes. (Piper)
Staff Analysis:
Currently, small to medium-sized commercial customers take service under the GS rate class, which is available to customers who use 0-5,999 therms per year. Large volume customers who use more than 6,000 therms per year take service under the LVS rate. Sales customers take service under the GS class, while transportation customers take service under the GST class. Sales and transportation customers pay the same base rates.
The GS-1/GSTS-1 rate schedule will be available to commercial customers who use 0-599 therms per year, and the GS-2/GSTS-2 rate schedule will be available to commercial customers who use 600 to 5,999 therms per year. FPUC proposed a $20 customer charge for the GS-1/GSTS-1 class and a $33 customer charge for the GS-2/GSTS-2 class. Both classes will pay the same per therm rate. The lower GS-1 customer charge is intended to reduce the financial impact on the smaller commercial customers. A lower customer charge benefits small users, since the customer charge constitutes a larger component of the bill.
In addition to customer impact considerations, there is a cost basis to stratify the GS class into two classes. FPUC stated that customer costs vary between commercial customers due to the size of the meter required. The GS-2 customers are expected to have higher peak requirements due to higher sales, which would require a larger meter, regulator, and meter set piping compared to the smaller use GS-1 customers.
Staff believes that the proposed replacement of the existing GS rate class with two classes (GS-1 and GS-2) is appropriate and should be approved.
Should residential generator-only customers who currently take service under the residential rate be transferred to the residential standby generator service (RS-GS) rate schedule approved in Docket No. 080072-GU?
Recommendation:
Yes. (Draper)
Staff Analysis:
In Docket No. 080072-GU, FPUC received approval for a new RS-GS schedule.[23] The rate is available for residential customers whose only gas appliance is a gas-fired electric generator to provide service when electric service to the customer’s premises is interrupted. Prior to receiving approval for the RS-GS rate in October 2008, residential customers with generators were taking service under the residential rate. At the end of 2007, FPUC provided service to 432 generator-only residential customers under the residential rate. Since the RS-GS rate became effective in October 2008, FPUC stated that 14 new customers have requested service under that rate schedule. Generators are optional equipment and their installation costs range from $6,000 to $20,000, depending on the size of the generator.
In July 2008, FPUC provided customer notice of its proposed RS-GS rate schedule to the generator-only customers. Eighteen out of 432 customers objected to the new rate. The Commission determined that the residential rate does not provide the appropriate cost recovery of generator-only customers, and therefore approved the RS-GS rate for new customers effective September 16, 2008. However, in light of customer comments received, the Commission ordered that current generator-only customers should remain on the residential rate until the resolution of FPUC’s next rate case, which is this docket. A bill impact analysis provided by FPUC in Docket No. 080072-GU, showed that the monthly gas bill for generator-only customers would increase between $0 and $10.72, depending on usage, if they were to be transferred from the residential to the RS-GS rate.
The increase in bills for some generator-only customers is due to the rate design of the current RS-GS rate, which provides for a higher monthly customer charge ($18.72) than the residential customer charge ($8). However, the higher $18.72 customer charge includes an initial block of usage (0-22.17 therms) that has no per-therm base rate charge. Thus, a generator-only customer who uses 1 therm or 22.17 therms per month pays $18.72. Usage above 22.17 therms is billed at the residential therm charge. As discussed in Issue 46, the staff- recommended RS-GS customer charge is $21.30. The cost of gas is recovered through a separate Purchased Gas Adjustment (PGA) factor. If the customer uses no gas during the billing period, he will not be charged for gas. The customer charge represents the minimum bill that has to be paid whether any gas is used or not. The level of customer charge and the size of the initial block were derived to yield the same revenue for an average residential or generator-only customer. That is the same rate design the Commission approved for the Peoples’ generator-only rate schedules. [24]
Customer education campaign. FPUC explained that customers occasionally contact the Company during a storm event because the generator does not start when needed for back-up power. FPUC travels to the customer’s premises, only to find that the generator does not start because the customer is not running or exercising the generator for 15 minutes every week as required by the manufacturer. FPUC explained that it plans on mailing an educational bill insert to its customers who own generators about the required weekly running of the generator before this year’s hurricane season starts. FPUC believes that the rate design for the RS-GS, as described above, will encourage customers to exercise the generators. FPUC believes that if a customer understands that he is already paying through the customer charge for a certain amount of usage, the customer will exercise the generator. Running the generator on a weekly basis as required by the manufacturer will ensure the safety of the generator, alleviate customer frustration during a storm event if the generator does not start, and will free up FPUC personnel who will otherwise have to make a trip to the premises. FPUC projects that its educational program will result in increased generator usage that will most likely, on average, equal or exceed the minimum bill requirement for the RS-GS rate.
The Commission ordered FPUC in Docket No. 080072-GU to include a generator-only rate classification as part of its cost of service study in Docket No. 080366-GU. FPUC stated that it reviewed the facilities needed to serve a generator-only customer, and concluded that they are comparable to the facilities required to serve a residential customer with other gas appliances. FPUC explained that the Company used to install ½ inch gas service lines and 125 cubic feet per hour (cfh) meters to serve residential customers. These installations were not large enough to deliver sufficient gas quantities to serve a full-house generator. However, FPUC stated that the Company now uses ¾ inch service lines, and 250 cfh meters for all residential customers. These larger facilities are able to serve most residential generators. Customers who require very large generator installations are required to pay a contribution-in-aid-of-construction to cover the cost of the upgraded service line facilities.
Conclusion. In a rate case all costs, rates, and charges are subject to review and change. Staff believes that this rate case proceeding is the appropriate time to transfer all residential generator-only customers who currently take service under the residential rate to the RS-GS rate schedule approved in Docket No. 080072-GU. Staff believes that there is no basis to continue to allow generator-only customers to remain in the residential class, while requiring new customers to take service under the RS-GS rate. In addition, when the Commission approved generator-only rate schedules for Peoples Gas in Docket No. 070260-GU, the Commission approved the transfer of all residential and commercial generator-only customers who were taking service under the residential or commercial rate to People Gas’ new generator-only rate schedules.
Is the proposed new Commercial Standby Generator Service (CS-GS) rate schedule appropriate?
Recommendation:
Yes, the proposed new Commercial Standby Generator Service (CS-GS) rate schedule is appropriate, and all current commercial generator-only customers should be transferred to the CS-GS rate schedule. The Commission has previously approved residential and commercial generator rate schedules for Peoples Gas System. (Draper)
Staff Analysis:
FPUC proposed a new commercial standby generator service (CS-GS) rate schedule for commercial customers who are using natural gas for the purpose of fueling a generator to provide electricity to the premises during power outages and whose only gas appliance is the generator. Typical commercial customers using standby generators are restaurants or hospitals. Commercial customers with a generator and other gas appliance(s) will continue to take service under the otherwise applicable commercial rate. FPUC received approval for residential standby generator rate schedule (RS-GS) in Docket No. 080072-GU.[25] The Commission also approved residential and commercial generator rate schedules for Peoples Gas.[26]
FPUC’s proposed rate structure for commercial standby generator-only customers reflects the rate design approved for the RS-GS rate and for the Peoples Gas generator rate schedules. FPUC proposed a $36.31 customer charge and an initial block of usage (0-39.52 therms) that includes no per-therm base rate charge. Based on the staff-recommended revenue increase discussed in Issue 38, staff revised the customer charge to $35.86. The $35.86 charge is derived to yield the same revenue as a GS-1 customer who uses 39.52 therms per month. The customer charge represents the minimum charge that will have to paid every month. Usage above 39.52 therms is billed at the GS non-fuel energy charge. In both cases, cost of gas is recovered through a separate PGA factor. If the customer uses no gas during the billing period, he will not be charged for gas.
FPUC stated that the typical usage of a commercial generator rated at 1,900 cubic feet being exercised for 15 minutes weekly is 39.52 therms per month. FPUC stated that the proposed rate design is to encourage commercial customers to run their generators once a week as required by the manufacturer. As also discussed in Issue 46, FPUC explained that customers contact the Company during a storm event when the generator does not start when needed for back-up power, which requires FPUC to travel to the site. FPUC then determines that the generator does not start because the customer is not running the generator as required by the manufacturer to ensure the generator starts when needed. In addition, FPUC explained that customers may run the generator, however, it is done so under no load. Therefore, when there is an actual power failure, and the generator will try to keep up with electrical demand, the generator may not perform in a safe and reliable manner.
FPUC explained that it plans on educating its commercial generator customers through a bill insert prior to the start of hurricane season about the required maintenance, and that the monthly customer charge provides for no per-therm charge for usage up to 39.53 therms. FPUC believes that if a customer understands that he is already paying through the customer charge for a certain amount of usage, the customer will exercise the generator as required by the manufacturer to ensure the generator starts when needed.
Under FPUC’s proposal, all current generator-only customers will be transferred to the new CS-GS rate. FPUC currently serves 159 commercial generator only customers. The current generator-only customers take service under FPUC’s GS rate, and pay a monthly $15 customer charge and 32.1076 cents per therm energy charge. That reflects the current GS charges, prior to any increase approved in this docket. As shown in Issue 41, the staff-recommended GS-1 customer charge is $20, and the per-therm charge is 40.125 cents per therm (Issue 42).
Staff believes that FPUC proposed CS-GS rate is appropriate and should therefore be approved.
Is the proposed new Gas Lighting Service Transportation Service (GLSTS) rate schedule appropriate?
Recommendation:
Yes. (Piper)
Staff Analysis:
The Company previously offered transportation services for gas lights under the commercial transportation rate schedules. This new tariff separates gas lighting transportation service into its own category. This proposed tariff complies with Rule 25-7.0335(1) F.A.C., which states that gas companies must offer a transportation service option for every commercial rate plan.
This proposed tariff allows commercial gas lighting customers another option to purchase their gas from a gas marketer. The $4.50 administrative charge covers the estimated expense of having FPUC’s Energy Logistics staff coordinate the reporting, nominations and balancing of gas supplies with other parties on behalf of the transportation customers. This charge was established in FPUC’s 2004 rate case, in Docket No. 040216-GU, and FPUC decided not to increase the previously approved charge.
Are the proposed modifications to the Area Expansion Surcharge appropriate?
Recommendation:
The Commission should approve all adjustments proposed by FPUC to its Area Extension Program, with the exception of the requested rate of return. FPUC’s proposed modifications to the AEP equitably distributes charges in the various rate classes. The Commission should require FPUC to use the approved rate of return mid-point for all Area Expansion Programs. (Hadder)
Staff Analysis:
Upon receiving a request to extend facilities, the Company assesses numerous conditions, such as the potential customer’s credit worthiness and projected revenue generated from the extension. As provided for in Rule 25-7.054, F.A.C., the Company compares four times the expected annual revenue generated by the extension (Maximum Allowable Construction Cost or MACC) to the projected construction costs. If the construction costs are less then the MACC, the extension is provided free of cost to the customer. If the construction costs exceed the MACC, FPUC will require the customer to pay a Contribution in Aid of Construction (CIAC), also referred to as the Excess Construction Costs (ECC).
The AEP is an alternative method to collecting all ECC incurred from extending such facilities via a CIAC. The AEP allows customers to pay the CIAC over a time period of up to ten years, as opposed to collecting the total balance up-front. On or before May 1 of each year, the Company files a report with the Commission reconciling AEP facilities costs and surcharge revenues on an annual and total date. Any revenues collected by the Company in excess of the installed cost are refunded to the customers, and the AEP terminated.
Current Tariff Overview
The Commission approved FPUC’s AEP in 1995.[27] Currently, the recovery process is a cents-per-therm surcharge levied to customers served by AEP facilities on a monthly basis. This method has proven extremely volatile due to variables such as predicted therm usage embedded in the AEP surcharge equation. If the Company over-predicts the therm usage of any class, the Company may be unable to recapture the full ECC, placing the burden on FPUC, and ultimately other ratepayers in the next rate case. Additionally, the current program places an unfair burden on customers who use more gas than those who have very low or no gas use. A user with multiple gas appliances is impacted to a much greater extent than a customer who installs a standby natural gas generator that is used rarely, even though the investment to bring gas to each customer is the same.
Proposed Modifications to AEP
The Company proposed changing the AEP surcharge from a cents-per-therm charge to a fixed monthly per premises dollar amount. This consists of a three step process. First, for a requested extension of services, the Company will calculate the AEP Recovery Amount. Then, FPUC will divide the AEP Recovery Amount by the total estimated number of therms subject to the AEP surcharge. This is the Unitized AEP Recovery Amount. Finally, to determine an individual customer’s initial surcharge, the Company will multiply the Unitized AEP Recovery Amount by the projected average monthly usage by rate schedule. This value is the Initial AEP Surcharge. This is the individual customer’s CIAC required for an extension of services.
Upon completion of the initial five-year period from the in-service date of the AEP facilities extension, FPUC proposed an adjustment to allow for a recalculation of the outstanding AEP Recovery Amount, using a similar method as described above. This adjustment will permit FPUC to compare the actual ECC to the originally-calculated ECC and change the fixed monthly surcharge, either up or down. It has been the Company’s experience that build-out for most projects are completed in four years or less. Historically, 41 out of the total 45 AEP projects were never fully collected in the Commission approved ten year time frame. Allowing the Company to reassess the surcharge at the five-year point allows for better matching of revenues and costs. The Commission approved similar methods for a Recalculated AEP Surcharge and a True-Up for Chesapeake Utilities Corporation[28] and St. Joe Natural Gas.[29] It is the opinion of Staff that this approach may prevent further lags in uncollected ECC.
The Company requested to use the maximum authorized rate of return for determination of future AEP costs. In response to Staff’s Second Data Request, the Company claims its proposed approach will be conservative by raising the ‘hurdle’ rate for approval of an AEP project, in order to ensure the successful outcome in terms of covering ECC within the ten-year allowable collection period. Staff is not aware of any regulated gas utilities which use the currently authorized maximum rate of return for such calculations. FPUC has not demonstrated any critical need for use of such the maximum authorized rate of return for calculating AEP costs. Staff recommends that the Commission require FPUC to use the rate of return mid-point for all Area Expansion Programs cost estimates.
Conclusion
Staff recommends the approval of the changes requested by FPUC to its AEP, with the exception of the requested rate of return to be used in AEP calculations. Staff recommends that the Commission direct FPUC to use the mid-point of its approved rate of return for AEP calculations. The proposed methodology of collection appears much more precise in determining, monitoring and capturing the ECC incurred by Company. Staff further recommends that the proposed AEP modifications become effective on the effective date discussed in Issue 51, along with all other tariffs approved in this docket. FPUC requested an earlier effective date, but agreed with Staff that any tariff modifications can not become effective prior to the effective date discussed in Issue 51.
Is the proposed increase to all existing Area Expansion Surcharges to lower the projected unrecovered excess construction cost balances appropriate?
Recommendation:
Yes. The changes proposed to the existing Area Expansion Surcharges to lower the projected unrecovered excess construction costs balances allow for a reasonable capture of some outstanding excess construction costs before transferring the balance to all of FPUC’s rate base. (Hadder)
Staff Analysis:
FPUC is proposing a partial true-up of costs and revenues for existing AEP projects, by implementing an additional surcharge on customers served by the AEP projects. This surcharge represents a change in FPUC’s policy, in that the original AEP contracts did not contemplate a true-up in AEP charges. However, as noted in Issue 49, the Commission has approved the concept of a true-up mechanism for AEP projects for Chesapeake Gas Company and St. Joe Gas Company, in which the costs and revenues are reviewed during the 10 year period and adjusted as necessary to meet the revenue target. FPUC has also requested a true-up provision for future projects which is addressed in Issue 49. Unrecovered costs from AEP projects are transferred to the applicable capital plant construction account, and ultimately to the base rates of all FPUC customers, as discussed in Issue 7. FPUC proposed increasing the Surcharges to all existing 41 AEP participants to lower the projected unrecovered excess construction costs balances. This change would only apply to any AEP facilities constructed prior to January 1, 2009. As discussed in Issue 49, FPUC proposed a true-up mechanism for future AEP projects which should eliminate or significantly reduce any shortfalls for future AEP projects.
FPUC currently has 41 AEP projects with projected ECC balances totaling $3,913,429, through December 2008. If the programs are continued unaltered through their ten year timeline, the uncollectable balance would amount to $3,081,798. The Company stated the ECC shortfall is due to unpredictable events such as market downturns, increased appliance efficiency and housing market fluctuations which altered the predictive powers for FPUC to determine therm use. FPUC proposed, as discussed in Issue 7, to transfer $2,478,621 to plant-in-service accounts. The proposed increased AEP Surcharge would recover the remaining $603,177.
The Company originally asked to increase the AEP surcharge to $0.50 per therm for all customers. It has since modified its request to differentiate the charge by prorated rate class, to comply with the current Commission approved method. The Company seeks to increase the cents-per-therm AEP Surcharge for the Residential class to $0.50 per therm, the General Service class to $0.33, the Large Volume class to $0.25 and the Gas Lighting to $0.18. FPUC chose $0.50 for the residential class as a reasonable surcharge, stating that bills would be competitive in conjunction with any other approved rate increase in this docket. The ratio among classes index the Residential class at 100 percent, the General Service class at 66.4 percent, the Large Volume Service class at 49.2 percent and the Gas Lights class at 36.6 percent. FPUC derived these surcharge values using the same method currently approved by the Commission for allocating and structuring AEP Surcharges among rate classes.
If the Commission approves the proposed AEP true-up, $603,177 would be assessed to the customers who enjoy the benefits of the plant expansions paid for through the AEP, and not collected through higher rates to the general body of ratepayers.
Currently, the Residential AEP Surcharge has a range of $0.10 to $0.35 per therm, depending on the particular AEP project. Pending the approval of the proposed $0.50 per therm, residential AEP customers would see an AEP Surcharge increase of $0.40 to $0.15 per therm, respectively. For an average 20 therm residential monthly bill, this is approximately an $5.00 increase.
In conclusion, staff recommends that the Commission allow FPUC to implement the proposed true-up to its AEP Surcharge for all existing outstanding AEP customers. The movement and division of outstanding ECC between the current AEP customers and the base rate payers appears more equitable than moving any additional costs to rate base, while not imposing an unreasonable burden on current AEP customers. This true-up would allow FPUC to close up to 19 open AEP projects and decrease the ECC on many more. It is staff’s opinion that the Commission should approve the AEP Surcharge increase to all existing AEP Surcharges.
What is the appropriate effective date for FPUC’s revised rates and charges?
Recommendation:
The revised rates and charges should become effective for meter readings on or after 30 days following the date of the Commission vote approving the rates and charges. FPUC should file revised tariffs to reflect the Commission-approved final rates and charges for administrative approval within five (5) business days of issuance of the PAA order. Pursuant to Rule 25-22.0406(8), F.A.C., customers should be notified of the revised rates in their first bill containing the new rates. A copy of the notice should be submitted to staff for approval prior to its use. (Hadder)
Staff Analysis:
All new rates and charges should become effective for meter readings on or after 30 days from the date of the Commission vote approving them. This will ensure that customers are aware of the new rates before they are billed for usage under the new rates.
FPUC should file revised tariffs to reflect the Commission-approved final rates and charges for administrative approval within five (5) business days of issuance of the PAA order. Pursuant to Rule 25-22.0406(8), F.A.C., customers should be notified of the revised rates in their first bill containing the new rates. A copy of the notice should be submitted to staff for approval prior to its use.
Should any portion of the $984,054 interim increase granted by Order No. PSC-09-123-PCO-GU, issued March 3, 2009, be refunded to the ratepayers?
Recommendation:
No. The proper refund amount should be calculated by using the same data used to establish final rates, excluding rate case expense and other items not in effect during the interim period. This revised revenue requirement for the interim collection period should be compared to the amount of interim revenues granted. Based on this calculation, no refund is required. Further, upon issuance of the Consummating Order in this docket, the corporate undertaking should be released. (Slemkewicz)
Staff Analysis:
By Order No. PSC-09-0123-PCO-GU, issued March 3, 2009, the Commission authorized the collection of interim rates, subject to refund, pursuant to Section 366.071, F.S. The approved interim revenue requirement was $27,075,841, which represents an increase of $984,054 or 4.18 percent. The interim collection period is March 2009 through May 2009.
According to Section 366.071, F.S., any refund should be calculated to reduce the rate of return of the utility during the pendency of the proceeding to the same level within the range of the newly authorized rate of return. Adjustments made in the rate case test period that do not relate to the period interim rates are in effect should be removed. Rate case expense is an example of an adjustment which is recovered only after final rates are established.
In this proceeding, the test period for establishment of interim is the 12-month period ending December 31, 2007. FPUC’s approved interim rates did not include any provisions for pro forma or projected operating expenses or plant. The interim increase was designed to allow recovery of actual interest costs, and the lower limit of the last authorized range for return on equity.
To establish the proper refund amount, staff has calculated a revised interim revenue requirement utilizing the same data used to establish final rates for the 2009 projected test year. Items, such as rate case expense and the storm damage accrual, were excluded because these items are prospective in nature and did not occur during the interim collection period. Using the principles discussed above, because the $27,075,841 revenue requirement, granted in Order No. PSC-09-0123-PCO-GU, for the December 2007 interim test year is less than the revenue requirement for the interim collection period of $31,740,788, staff recommends that no refund is required. Further, upon issuance of the Consummating Order in this docket, the corporate undertaking should be released.
Should FPUC be required to file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records that will be required as a result of the Commission’s findings in this rate case?
Recommendation:
Yes. FPUC should be required to file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records which will be required as a result of the Commission’s findings in this rate case. (Prestwood)
Staff Analysis:
FPUC should be required to file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records which will be required as a result of the Commission’s findings in this rate case.
Should there be a step increase for the new South Florida Operations Center and, if so, what procedure should be used?
Recommendation:
No. Staff recommends that a step increase for the new South Florida Operations Center be denied at this time and that the Commission take no other action with respect to possible future proceedings for this matter. (Prestwood)
Staff Analysis:
The Company’s current South Florida Operations Center is located on the site of a former Manufactured Gas Plant (MGP) plant. It will have to be relocated prior to commencing any clean up of the existing site. The relocation will have to be permanent since the current site was rezoned for usages which are inconsistent with the current use of the site.
The new South Florida Operations Center was an issue in the Company’s last rate case in Docket No. 040216-GU. In that case, the Company had requested to include $2,500,000 for the purchase of land for the new center, in the projected test year 2005.
In Order No. PSC-04-1110-PAA-GU, the Commission stated:
. . . we find that this land shall be considered non used and useful for the purpose of setting rates in this case and the $2,500,000 shall be removed from rate base.
. . . Once the new operations building is placed in service, as well as the existing center retired, the utility may seek recovery in its next rate case.
In the present rate case, the Company did not include the cost of the new South Florida Operations Center as a part of the requested rate relief. Although the Company has purchased a 6.22-acre site located in the Town of Lake Park, the operations center is not expected to be completed until October 2010, or ten months after the end of the projected 2009 test year. The Company has been negotiating with three developers/builders to act as its agent to develop and to manage the site development and construction. The Company has also entered into an agreement with an Architectural/Engineering firm. The expected design fee is $186,500. The projected cost of site development and construction has been independently estimated at $4,744,000.
Due to the large amount of expenditures for the construction of the operations center, the Company has requested that the Commission consider granting special future rate relief. The Company estimated the revenue requirement associated with the operations center to be $909,488. The Company proposed two alternatives for consideration that would provide rate relief without the need for a “separate costly and time consuming rate proceeding.”
The first alternative would be to calculate a flat percentage increase as a part of the present proceeding, that would be added to base rates based on the information that is available in the testimony, exhibits, and MFRs, in this proceeding. This rate increase would become effective upon completion of the operations center.
The Company’s second proposed alternative would be for the Commission to conduct a limited proceeding at the conclusion of the operations center construction. The limited proceeding would specifically address the effects on rate base and net operating income relating to the incremental cost associated with the new operations center, and the cost of the limited proceeding.
Staff believes that there is a great deal of uncertainty as to the completion date and total cost of the new operations center. The current estimate calls for the completion of the center in 18 months or 10 months from the end of the 2009 projected test year. Staff believes that it is highly likely that the cost estimates for the operations center will change during the next approximate 18 months. Therefore, staff does not recommend the use of the Company’s first alternative of granting a step rate increase now to be added to customer bills when the center is operational.
The Company’s second alternative, a filing of limited proceeding is also problematic. FPUC, or any other utility, may petition the Commission for a limited proceeding. However, there can be no guarantee now that the Commission will agree that a limited proceeding is appropriate at the time the petition is filed. For example, the Commission may determine that the issue of overall earnings level should be addressed, based on the circumstances at the time of the proceeding. While staff believes that limiting the cost of proceedings before the Commission is desirable, we see no need for the Commission to take action at this time with respect to approving the use of limited proceeding in the future.
Therefore, staff recommends that the step increase for the new South Florida Operations Center be denied at this time and that the Commission take no other action with respect to possible proceedings for this matter in the future.
Should this docket be closed?
Recommendation:
Yes. If no substantially affected person files a protest within 21 days of the date of the Proposed Agency Action Order, this docket should be closed upon the issuance of a Consummating Order, and the utility's completion of refunds, if any, and filing of the appropriate notices and tariffs. (Jaeger)
Staff Analysis:
If no substantially affected person files a protest within 21 days of the date of the Proposed Agency Action Order, this docket should be closed upon the issuance of a Consummating Order, and the utility's completion of refunds, if any, and filing of the appropriate notices and tariffs.
[1] See Order No. PSC-04-1110-PAA-GU, issued November 8, 2004, in Docket No. 040216-GU, In re: Application for rate increase by Florida Public Utilities Company.
[2] See Order No. PSC-09-0010-PCO-GU, issued January 5, 2009, in Docket No. 080366-GU, In re: Petition for rate increase by Florida Public Utility Company.
[3] Order No. PSC-04-1110-PAA-GU, issued November 8, 2004, in Docket No. 040216-GU, In re: Application for rate increase by Florida Public Utilities Company, p.8.
[4] Order No. PSC-95-0162-FOF-GU, issued February 7, 1995, in Docket No. 941291-GU, In Re: Petition for approval of modification to tariff provisions governing main and service extensions by Florida Public Utilities Company.
[5] Federal Power Commission v. Hope Natural Gas Company, 320 U.S. 591 (1944) and Bluefield Water Works & Improvement Company v. Public Service Commission of West Virginia, 262 U.S. 679 (1923).
[6] 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.
[7] Order No. 10449, issued December 15, 1981, in Docket No. 810035-TP, In re: Petition of Southern Bell Telephone and Telegraph Company for a rate increase.
[8] Order No. 23573, issued October 3, 1990, in Docket No. 891345-EI, In re: Petition of Gulf Power Company for an increase in its rates and charges, p. 21.
[9] Order No. PSC-04-1110-PAA-GU, issued November 8, 2004, in Docket No. 040216-GU, In re: Application for rate increase by Florida Public Utilities Company; and 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.
[10] Order No. PSC-94-1519-FOF-GU, issued December 9, 1994, in Docket No. 940620-GU, In re: Application for a rate increase by Florida Public Utilities Company.
[11] Order No. PSC-07-0671-PAA-GU, issued August 21, 2007, in Docket No. 070107-GU, In re: Investigation into 2005 earnings of the gas division of Florida Public Utilities Company.
[12] Order No. PSC-05-1040-PAA-GU, issued October 25, 2005, in Docket No. 041441-GU, In re: Petition for approval of storm cost recovery clause to recover storm damage costs in excess of existing storm damage reserve, by Florida Public Utilities Company.
[13] Order No. PSC-07-0671-PAA-GU, issued August 21, 2007, in Docket No. 070107-GU, In re: Investigation into 2005 earnings of the gas division of Florida Public Utilities Company.
[14] Order No. PSC-08-0697-PAA-GU, issued October 20, 2008, in Docket No. 080514-GU, In re: Investigation into 2006 earnings of the gas division of Florida Public Utilities Company.
[15] Order No. PSC-05-1040-PAA-GU, issued October 25, 2005, in Docket No. 041441-GU, In re: Petition for approval of storm cost recovery clause to recover storm damage costs in excess of existing storm damage reserve, by Florida Public Utilities Company.
[16] Order No. 14030, issued January 25, 1985, in Docket No. 840086-EI, In Re: Application of Gulf Power Company for authority to increase its rates and charges; Order No. 16313, issued July 8, 1986, in Docket No. 850811-GU, In Re: Petition of Peoples Gas System, Inc. for authority to increase its rates and charges in Hillsborough County; Order No. 23573, issued October 3, 1990, in Docket No. 891345-EI, In Re: Application of Gulf Power Company for a rate increase.
[17] Rule 25-30.4705, F.A.C.
[18] Order No. PSC-92-0580-FOF-GU, issued June 29, 1992, in Docket No. 910778-GU, In re: Petition for a rate increase by WEST FLORIDA NATURAL GAS COMPANY, p. 15.
[19] Order No. PSC-94-0170-FOF-EI, issued February 10, 1994, in Docket No. 930400-EI, In re: Application for a rate increase for Marianna Electric Operations by Florida Public Utilities Company, p. 10.
[20] Ibid, pp. 10-11.
[21] Order No. PSC-09-0229-PAA -GU, Issued April 13, 2009, Docket No. 080548-GU, In re: 2008 depreciation study by Florida Public Utilities Company.
[22] See Order No. PSC-08-0643-TRF-GU, issued October 6, 2008, in Docket No. 080072-GU, In re: Petition for approval of residential standby generator rate schedule, by Florida Public Utilities Company.
[23] See Order No. PSC-08-0643-TRF-GU, issued October 6, 2008, in Docket No. 080072-GU, In re: Petition for approval of a residential standby generator rate schedule, by Florida Public Utilities Company.
[24] See Order No. PSC-07-0530-TRF-GU, issued June 26, 2007, in Docket No. 070260-GU, In re: Petition for approval of standby generator rate schedules RS-SG and CS-SG, by Peoples Gas System.
[25] See Order No. PSC-08-0643-TRF-GU, issued October 6, 2008, in Docket No. 080072-GU, In re: Petition for approval of residential standby generator rate schedule, by Florida Public Utilities Company.
[26] See Order No. PSC-07-0530-TRF-GU, issued June 26, 2007, in Docket No. 070260-GU, In re: Petition for approval of standby generator rate schedules RS-SG and CS-SG, by Peoples Gas System.
[27] Order PSC-95-0162-FOF-GU, issued February 7, 1995, in Docket No. 941291-GU, In re: Petition for approval of modification to tariff provisions governing main and service extensions by Florida Public Utilities Company.
[28] Order PSC-07-0427-TRF-GU, issued May 15, 2007 in Docket No. 060675-GU, In Re: Order Approving in Part Petition for Authority to Implement Phase Two of Experimental Transitional Transportation Service Pilot Program and for Approval of New Tariff to Reflect Transportation Service Environment
[29] Order PSC-04-0436-PAA-GU, issued July 8, 2008 in Docket No. 070592-GU, In Re: Order Granting Rate Increase by St. Joe Natural Gas Company, Inc.