For an official paper copy, contact the Florida Public ServiceCommission at contact@psc.state.fl.us or call (850) 413-6770. There may be a charge for the copy.
State of Florida
Public Service
Commission
Capital Circle Office Center 2540 Shumard
Oak Boulevard
Tallahassee, Florida 32399-0850
-M-E-M-O-R-A-N-D-U-M-
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DATE: |
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TO: |
Director, Division of the Commission Clerk & Administrative Services (Bayó) |
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FROM: |
Division of Economic Regulation (Merta, Baxter, Draper, Gardner, Kenny, Lester, Rendell, Revell, Wheeler, Winters) Office of the General Counsel (Jaeger) Division of Regulatory Compliance & Consumer Assistance (Hicks, Witman) |
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RE: |
Docket No. 040216-GU – Application for rate increase by Florida Public Utilities Company. |
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AGENDA: |
10/19/04 – Regular Agenda – Proposed Agency Action Except for Issue 60 - Interested Persons May Participate |
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SPECIAL INSTRUCTIONS: |
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FILE NAME AND LOCATION: |
Attachments 6 & 7 are not electronically submitted R:\PSC\ECR\123\040216-ATT6-7.XLS |
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Table of Contents
3 South Florida Operations Center
4 Sanford Office Building and Land
8 Bare Steel Replacement Program
10 Construction Work in Progress
11 Working Capital Allocations
14 Medical Self Insurance Reserve and Accrued Liability Insurance
18 Accumulated Deferred Taxes in Capital Structure
19 Unamortized Investment Tax Credits in Capital Structure
21 Weighted Average Cost of Capital
26 Fleet Image Improvement Program
27 Periodic Meter and Regulator Change-Out Expense
28 State Sales Tax on Company-Use Gas
30 Nonutility Advertising Expense
32 Account 920 Payroll Increase
33 Temporary Help and Relocation Expenses
34 Duplicate Legal Fees and Annual Report Costs and Audit Contingency
36 Other Post Retirement Benefits
40 Change in Depreciation Rates
COST OF SERVICE AND RATE DESIGN
46 Cost of Service Methodology
47 Revenue Allocation Across Rate Classes
50 Miscellaneous Service Charges
52 Pool Manager Service Charge
53 Elimination of LVIS and LVITS Rate Schedules
54 Transportation Fee for Change in Pool Managers
55 Gas Lighting Service Rate Schedule
56 Proposed Charges for Transportation Service Customers
57 Elimination of Charge for Historical Consumption Information.
58 Effective Date for Revised Rates and Charges
60 Required Entries and Adjustments
4 Net Operating Income Multiplier
6 Cost of Service................................................................................................................ 85
7 Recommended Rates..................................................................................................... 103
This proceeding commenced on May 10, 2004, with the filing of a petition for a permanent rate increase by Florida Public Utilities Company (FPUC or the company). FPUC requested an increase of $8,186,989 in additional annual revenues. The company based its request on a 13-month average rate base of $65,835,210 for a projected test year ending December 31, 2005. The requested overall rate of return is 8.66% based on an 11.50% return on equity.
By Order No. PSC-04-0721-PCO-GU, issued July 26, 2004, in this docket, the Commission granted an interim increase of $1,236,108. In that Order, the Commission found the company’s rate base to be $50,496,627 for the interim test year ended December 31, 2003, and its allowed rate of return to be 7.65%, using a return on equity of 10.40%.
The Commission last granted FPUC a $1,282,001 rate increase by Order No. PSC-95-0518-FOF-GU, issued April 26, 1995, in Docket No. 940620-GU, In Re: Application for a rate increase by Florida Public Utilities Company.
Pursuant to Section 366.06(4), Florida Statutes, (F.S.) FPUC requested that the Commission process its petition for rate relief using Proposed Agency Action (PAA) procedures. Customer meetings were held in West Palm Beach on July 7, 2004 and Deltona on July 8, 2004. The Commission has jurisdiction over this request for a rate increase and interim rate increase under Sections 366.06(2) and (4), and 366.071, Florida Statutes.
Discussion of Issues
Staff Analysis: The Company used actual data for the 2003 test year rate base, net operating income and capital structure. The projected test year was based on the projected level of customers, related revenues, expenses updated for cost increases and trending, and projected cost of capital. Plant additions for 2003 and the first seven months of 2004 have been audited by the Commission auditors and analyzed by staff. In addition, 2003, 2004, and the projected test year reflect the acquisition of the assets of South Florida Natural Gas Company.
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 test year is representative of current operations, and therefore, calendar year 2005 is an appropriate test year.
Issue 3: Is it appropriate for the utility to include the South Florida Division’s anticipated property purchase for the relocation of the South Florida Operations Center in its projections for 2005?
Chapter 366.06(1), Florida Statutes (F.S.), states that “…The Commission shall investigate and determine the actual legitimate cost of the property of each utility company, actually used and useful in the public service ….” There is no guarantee that the land will be purchased by the end of the projected test year. Further, it is being purchased solely for the location of a new operations center, and the utility has not indicated that construction will have begun by the end of the projected test year. As a result, the land will not be used for its intended purpose, and will not be used and useful in serving the public in the projected test year.
On September 9, 2004, in response, to staff’s data request concerning Taxes Other Than Income, the utility indicated that the property is now anticipated to cost $4.5 million, including attorney fees and closing costs. This is $2 million more than the projection in the utility’s MFRs. Further, there was no analysis provided on the retirement, and/or sale of the existing property. At this time, it is not possible to determine the appropriate treatment of the proposed building. At the time the new building is built and placed in service, an analysis would need to be completed. Staff would need to determine the appropriate allocation between utility and non-utility, and also whether the new building will be 100% used and useful in providing service. A further analysis would need to be completed on the retirement of the existing operations center. This would include any related gain on sale. Finally, additional analysis would need to be performed as to the prudency of purchasing this property, in light of the purchase price being increased by $2 million during this rate case. Section 366.06(1), Florida Statutes, further states, that such “value, as determined by the commission, shall be used for ratemaking purposes and shall be money honestly and prudently invested by the public utility company in such property used and useful in serving the public .…” (emphasis added)
Therefore, staff believes that this land should be considered non used and useful for the purpose of setting rates in this case and recommends that the $2,500,000 be removed from rate base. Additionally, Account 390, Structures and Improvements, and the associated accumulated depreciation and expense should be reduced by $26,340, $198 and $396, respectively, for associated building construction plans that are also considered non used and useful. The removal of the related property tax on the land will be addressed in a later issue.
Staff believes that 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.
Section 366.06(1), F.S., states “[T]he commission shall investigate and determine the actual legitimate costs of property of each utility company, actually used and useful in the public service.…” Staff believes that this building and property should be removed from rate base for ratemaking purposes in this case. Staff believes that once the utility has determined the environmental costs, the cost to remove the building, as well as, the gain on sale of the property, the utility can seek rate recovery. These factors should be analyzed in a future proceeding. The utility contends that if the Commission deems it not appropriate to include this property in rate base, that the return should be provided for through the environmental reserve. At a minimum, the building and related accumulated depreciation should be removed. This would be considered a retirement, due to the fact the building is no longer used. This building will not be used to provide any future service to the ratepayers, and in fact, must be destroyed to remediate the property underneath. The amount of the land in rate base and related return is then minimal.
Upon the company’s completion of the mediation process with the EPA, FPUC should request inclusion of the loss on the office building, mitigation expenses, and associated land in a separate proceeding before the Commission. Staff further believes that during this future proceeding addressing the environmental costs, that the cost of removal, potential gain on sale; rate of return on the land, and related property tax not included in rates should be addressed. At that time, staff can further analyze any sharing of the gain on sale, due to the lost return and related property tax during the period of time the land was not included in rate base.
For the 2005 projected test year, the net
effect of these two adjustments is a decrease of $1,076,150, $28,202, and
$26,846 $1,560,850, $38,915, and $53,694 to
plant, accumulated depreciation, and depreciation expense, respectively.
Issue 6: Should an adjustment be made to plant retirements for the projected test year?
For the 2005 projected test year, the net effect is a reduction to plant, accumulated depreciation, and depreciation expense for the projected test year of $30,112, $32,557, and $2,445, respectively.
Issue 7: Should the projected test year rate base be reduced to remove inactive service lines that have been inactive for more than five years?
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. Staff, recommends that the replacement period should be shortened to 50 years to reflect the average useful life of the equipment. This change would result in a yearly increase in amortization expense of $188,770 for a total of $566,308. Accumulated amortization for the projected test year would also be increased by $94,385.
Therefore, staff recommends that a 50-year amortization period be approved, with resulting increases to accumulated amortization and amortization expense of $94,385 and $188,770, respectively, for the projected test year.
The utility indicated that $960,376 of the total amount of $3,300,000 represented the fair market value over the book value of the acquired assets. Section 366.06(1), F.S., states that, “… the commission shall investigate and determine the actual legitimate costs of the property of each utility company, actually used and useful in the public service, and shall keep a current record of the net investment of each public utility company in such property which value, as determined by the commission, shall be used for ratemaking purposes and shall be the money honestly and prudently invested by the public utility company in such property used and useful in serving the public, less accrued depreciation, and shall not include any goodwill or going-concern value or franchise value in excess of payment made therefor.” (emphasis added) According to Title 18 of The Code of Federal Regulations (18 CFR), revised as of April 1, 2004, p. 580, an acquisition adjustment “… shall include the difference between (a) the cost to the accounting utility …, and (b) the original cost, estimated if not known….” The utility stated that its request for the inclusion of an additional $3,300,000 as an acquisition adjustment in rate base meets this standard.
However, staff believes the difference is goodwill. In its exhibit, the utility stated, “The total goodwill inclusive of intangible assets for the SFNG portion of the acquisition amounted to $3.3 million. Included in the total goodwill is the difference between the fair market value and book value (historical cost) of the plant acquired, amounting to $960,376.” As discussed above, 18 CFR, p.580, defines an acquisition adjustment as the cost to the utility over the original cost. In this case, this amounts to the $960,376 that staff is recommending for inclusion in rate base. The remaining $2,339,624 is goodwill and should not be included in rate base.
In order to properly evaluate the utility’s request, it is necessary to use objective standards to develop quantitative benefits to the former customers of SFNG and the pre-acquisition customers of FPUC. By Order No. 23858, issued December 11, 1990, in Docket No. 891353-GU, In re: Application of Peoples Gas Systems, Inc. for a rate increase, the Commission examined a number of potential benefits to the existing customers of the acquired Southern Gas Company. The Order stated, “It is our policy to disallow positive acquisition adjustments unless extraordinary circumstances can be proven”. The Commission ultimately approved a positive acquisition adjustment of $2,351,756 amortized over 30 years. In this case, staff also examined the potential benefits to analyze the effects of FPUC’s acquisition of SFNG. The benefits are listed below with staff’s analysis.
Increased Quality of Service
South Florida Natural Gas’s (SFNG) last full year of operations prior to its acquisition was 2001. For that year, there were a total of nine complaints filed with the Division of Regulatory Compliance and Consumer Assistance. SFNG had approximately 4,300 residential and 360 commercial customers. This translates into a complaint ratio of 1.93 complaints per 1000 customers for the 2001 calendar year. FPUC has approximately 49,200 gas customers, and as discussed in Issue 2, there were 27 complaints filed with the PSC for the period of August 2003 to early August 2004. FPUC’s complaint ratio is approximately .55 per 1000 customers; a ratio approximately three-and one-half times lower than SFNG.
The staff engineer assigned to the present case indicated that portions of the existing SFNG plant were old, and were not maintained to the standards of FPUC. In particular, pressure regulators and gate stations will need to be upgraded to meet the present standards of FPUC. This is a reliability issue not a safety issue. Many parts in use are no longer made due to their age. The staff engineer stated that expenses for the needed repairs and upgrades to the former SFNG plant are included in this case.
A Lower Overall Cost of Capital
SFNG’s
last Rate of Return Report for June 2001 filed with the Commission on September
17, 2001, prior to the acquisition, indicated that SFNG had a 10.28% allowable
rate of return, and an average achieved rate of return of 5.47%, which was
below the required rate of return of 9.47%. In this case, staff is
recommending a cost of equity of 11.25% and an overall rate of return of 7.62%
7.69%.
Lowered Operating Costs
In the past, the Commission has looked at cost savings to support any request to include acquisition adjustments in rate base. See Order No. 18716, issued January 26, 1988, in Docket No. 870118-GU, Petition of Central Florida Gas Company to increase its rates and charges. Also see Order No. 24013, issued January 23, 1991, in Docket No. 891175-GU, Petition of City Gas Company Inc. for a rate increase. In the present case, the utility provided an exhibit that indicated that there are measurable cost savings of at least $138,000 of net cost reductions that resulted from synergies realized from the merger. While certain expenses, such as additional printing and mailing costs do increase, it is more than offset by a reduction in expenses by eliminating duplicative staff and facilities, and the costs for SFNG’s billing subcontractor. Staff has reviewed FPUC’s documentation and the stated savings appear reasonable. Additionally, there does not appear to be any adverse financial consequences to the existing rate payers. These cost savings benefit not only the former SFNG customers, but FPUC’s pre-acquisition or existing customers as well; moreover, even after the inclusion of the acquisition adjustment in rate base, there appear to be net savings of approximately $65,000.
Additionally, the purchase of SFNG allows FPUC to reduce allocated costs to the pre-acquisition customers of FPUC. FPUC allocates plant and a number of expenses to both regulated and non-regulated operations based on such factors as percentage of customers, utility plant, or payroll. Adding additional non-regulated propane and additional natural gas customers has the effect of reducing the percentage allocated to the existing pre-acquisition regulated customers.
Also, while fuel
costs are removed in determining final base rates in a rate case, fuel costs
impact the total amount of a customer’s bill. To properly evaluate the total
impact on customers, fuel charges as well as base rates must be considered.
FPUC provided documentation indicating that its fuel charge per therm for 2001
was 15.5% less than the per therm cost for SFNG. This would translate into
potentially yearly cost savings of over $300,000 for the former SFNG customers,
based on rates in effect prior to the acquisition. As a result, if the staff
recommended rates are approved, the average bill reduction for a former SFNG
residential customer using 22 therms monthly is a decrease of 2.4% 2.5%
, or $0.83 $0.87 per month. reduction compared to the average
residential bill for SFNG customers approved by the Commission in Order No.
24608, issued June 3, 1991, in Docket No. 900623-GU, In re: Petition for general
rate Relief by South Florida Natural Gas Company.
Conclusion
Staff believes that FPUC has properly met its burden to justify the inclusion of an acquisition adjustment of $960,376 in rate base. The acquisition of the SFNG system has benefited the former customers of SFNG through expense reductions and reduced fuel prices, and a higher lever of customer service. The existing rate payers benefit from the acquisition because there is a net savings of approximately $65,000 even after the inclusion of this acquisition adjustment in rate base and a larger base to allocate common costs, and the average former SFNG customer will have a monthly bill reduction of 2.5%. FPUC’s larger size after the acquisition should allow FPUC to more easily attract capital at a lower cost rate, which will benefit all of its customers. Staff also believes that the acquisition adjustment should be amortized over 30 years. The utility has indicated that it believes this amortization period reasonably reflects the useful remaining life of the SFNG plant. Staff reviewed FPUC’s recent depreciation study and agrees that a 30-year amortization period reasonably reflects the useful remaining life of the SFNG plant.
Staff also recommends that the permanence of these cost savings be reviewed in FPUC’s next rate case. If it is determined at that time that the cost savings no longer exist, the acquisition adjustment should be partially or totally removed from rate base.
Issue 10: Is FPUC’s requested level of Construction Work in Progress (CWIP) in the amount of $194,004 for the projected test year appropriate?
Issue 11: Should an adjustment be made to allocate working capital to reflect nonutility operations and corporate allocations?
Issue 12: Should an adjustment be made to the amount of cash in working capital?
Issue 13: Should an adjustment be made to working capital to allocate Materials & Supplies to non-regulated operations?
Issue 14: Are the balances for the medical self insurance reserve and accrued liability insurance appropriate?
Recommendation: The balances in these liability accounts should be decreased by $10,781, thereby increasing working capital by $10,781. (Winters)
Staff Analysis: Injuries and Damages expense, Account 925, was decreased $9,676 by staff in Issue 23. The 13-month average effect of this decrease is $4,838. Therefore, staff recommends decreasing the balance in accrued liability insurance by $4,838.
Other Post Employment Benefits expense, Account 926.3, was decreased $11,886 by staff in Issue 36. The 13-month average effect of this decrease is $5,943. Therefore, staff recommends decreasing the balance in medical self insurance reserve by $5,943.
In summary, based on the above adjustments, working capital should be increased by $4,838 for accrued liability insurance and by $5,943 for medical self insurance reserve, resulting in a net increase to working capital of $10,781. This adjustment is in addition to the allocation factor adjustment made in Issue 11.
Issue 15: Is the Prepaid Pensions in working capital appropriate?
Issue 16: Is FPUC’s requested level of Working Capital Allowance in the amount of zero for the projected test year appropriate?
Recommendation: No. Working capital should be ($706,682). (Revell)
The utility stated in a response to staff’s data request that its use of a zero balance in working capital was consistent with its two prior gas cases, and that it was neither inappropriate nor unusual to use these prior proceedings as a precedent.
In the FPUC gas division’s last two interim orders, Order No. 23516, issued September 19, 1990, in Docket No. 900151-GU, In re: Application for a rate increase in natural gas operations by Florida Public Utilities Company and Order No. PSC-94-1519-FOF-GU, issued December 9, 1994, in Docket No. 940620, In re: Application for a rate increase by Florida Public Utilities Company, the Commission allowed adjustments to zero negative working capital. In addition, in the company’s full revenue requirements case, by Order No. 24094, issued February 12, 1991, in Docket No. 900151-GU, In re: Application for a rate increase in natural gas operations by Florida Public Utilities Company, the Commission also allowed an adjustment to bring negative working capital to zero. Further, in the water and wastewater industry, negative working capital is generally increased to zero.
There are also cases where the Commission has approved negative working capital. Most recently, by Order No. PSC-04-0369-AS-EI, issued April 6, 2004, in Docket No. 030438-EI, In re: Petition for rate increase by Florida Public Utilities Company, the Commission approved a negative working capital allowance for FPUC’s electric division. Negative working capital was also approved by the Commission in Order No. PSC-97-0135-FOF-EI, issued February 10, 1997, in Docket No. 961542-EI, In Re: Investigation of 1995 earnings of Florida Public Utilities Company – Fernandina Beach Electric Division, and in Order No. 21532, issued June 12, 1989, in Docket No. 880558-EI, In re: Petition of Florida Public Utilities Company for rate increase for Marianna Division. In that case the Commission stated:
Arbitrarily increasing working capital, by raising a negative working capital to zero, would require additional dollars of return on an inflated rate base. However, Section 366.06(1), Florida Statutes, allows a utility to earn a return only on funds actually invested in used and useful assets.
In certain instances it would be appropriate to use a zero working capital instead of a negative: (1) if a negative allowance would have the effect of penalizing a utility for subsidization received from its parent, or (2) large accumulated losses have resulted in a balance sheet which is not typical of a going concern.
See, 89 FPSC 7:185.
In its response to a question as to whether there were any economic factors particular to FPUC in this case that were unsustainable on a stand-alone basis, or that would result, if working capital had a negative balance, the utility stated that a negative working capital balance should not generally be viewed as an acceptable condition for a ongoing business entity. The utility further stated that the Commission’s restricting, redefining or otherwise modifying the traditional contents of working capital often artificially reduced working capital to a negative balance. However, the MFRs indicates that per books working capital, after utility adjustments, but prior to Commission adjustments, was ($8,381,014). After Commission adjustments, the negative balance was reduced to ($1,673,309).
In FPUC’s last electric rate case a negative working capital balance was approved since the negative balance was a fall out from other rate case adjustments. See Order No. PSC-04-0369-AS-EI, issued April 6, 2004, in Docket No. 030438-EI, In Re: Petition for rate increase by Florida Public Utilities Company. Staff believes that the same method for calculating working capital should be used in this docket. As noted in the prior cases, FPUC has utilized a negative working capital for many years. It appears that a negative working capital balance is sustainable by the utility on a stand alone basis.
For the above reasons, staff does not believe that the utility has met its burden to show that it would be harmed if working capital was not set at zero. In its filing, the utility made an adjustment of negative $1,673,309 to adjust its level of working capital to zero. Staff recommends that an adjustment of $1,673,309 be made to reduce the balance to the per books balance. After the additional adjustments discussed in other issues, staff recommends that net working capital be set at ($706,682).
Staff notes that for the projected test year, FPUC has an unfunded accumulated postretirement benefit obligation of $1,074,610. This is the FAS 106 liability, with the associated expense accrual discussed in Issue 36. FPUC treated this liability account as a reduction in the calculation of working capital. According to Rule 25-14.012(3), F.A.C., the FAS 106 liability should reduce rate base. If the Commission decides not to use a negative balance for working capital, the FAS 106 liability should be removed from the working capital calculation and become a separate line item in the calculation of rate base. This will reduce rate base and comply with the above-cited rule.
Working Capital is shown on Attachment 1A.
Issue 17: Is FPUC’s requested level of Rate Base in the amount of $65,835,210 for the projected test year appropriate?
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COMPARATIVE RATE BASE Projected Test year Ending 12/31/05 |
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Company |
Staff |
Staff Revised |
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Utility Plant in Service |
$89,939,143 |
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$86,086,339 |
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Common Plant |
3,429,181 |
3,429,181 |
3,429,181 |
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Construction Work in Progress |
194,004 |
235,540 |
235,540 |
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Acquisition Adjustment |
3,603,400 |
1,263,776 |
1,263,776 |
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Total Deductions |
(31,330,519) |
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(31,136,480) |
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Net Utility Plant |
65,835,210 |
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59,878,356 |
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Working Capital |
0 |
(706,682) |
(706,682) |
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Total Rate Base |
$65,835,210 |
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$59,171,674 |
Rate Base is shown on Attachment 1.
Issue 18: Should an adjustment be made to Accumulated Deferred Income Taxes in the capital structure?
After numerous discussions between company and staff, the company provided revised schedules C-24 and G-2(C-24) showing recalculated deferred income tax expense, as well as revised balance sheet amounts for accumulated deferred taxes for years 2003, 2004, and 2005. The deferred income tax expense matched the increase in the credit balance of accumulated deferred income taxes in these revised schedules. However, the company agreed that errors had been made in the calculation of excess tax depreciation amounts related to bonus depreciation. For tax purposes, property placed in service after May 5, 2003 and before January 1, 2005 qualifies for a 50 percent first-year depreciation allowance. Bonus depreciation for 2003 and 2004 plant additions had only been included in deferred taxes at 20 percent, rather than at 50 percent. Additionally, the smaller percentage adjustments for 2003 and 2004 were reflected in the year subsequent to the actual year the plant additions were made.
Staff increased the excess tax depreciation related to the bonus depreciation by 30 percent (bringing the bonus from 20 percent to the allowed 50 percent) of the company’s total 2003 and 2004 plant additions (provided by the company in an exhibit), and corrected the timing error. Staff then reduced the 2004 bonus depreciation amount by 50 percent of the additions that were disallowed by staff in Issue 5, as this adjustment related to 2004 additions. The company contends that a further adjustment is needed for 2003, due to the change in May 2003 from 30% to 50% bonus depreciation. Staff declined to make an adjustment based on the company’s response to staff’s 1st Set of Data Requests, wherein the company stated that “for purposes of this computation, we used 50% bonus although pre May 6, 2003 acquisitions are 30% bonus property because the majority of the property was acquired post May 6, 2003.”
In summary, the net result of the above
adjustments results in a recommended increase to the 13-month average balance
of accumulated deferred income taxes of $2,992,338 $2,397,521 for
the projected 2005 test year. Therefore, staff recommends the appropriate
amount of accumulated deferred income taxes to include in the capital structure
is $9,245,613 $8,650,796.
Issue 19: What is the appropriate amount and cost rate of the unamortized investment tax credits to include in the capital structure?
Recommendation: The appropriate amount of unamortized investment tax credits (ITCs) is $276,563. The ITCs should be included in the capital structure at a 9.28% cost rate. (Winters)
Staff Analysis: The company proposed to include ITCs of $276,563 in its projected 2005 test year capital structure at a 9.81% cost rate. Staff agrees that the amount, as filed, is appropriate. However, based on adjustments to the investor capital components and cost rates discussed in Issue 21, the appropriate cost rate for ITCs is 9.28%.
Issue 20: What is the appropriate cost rate for common equity for the projected test year?
Recommendation: The appropriate cost rate for common equity is 11.25% with a range of plus or minus 100 basis points. (Lester)
Staff Analysis: FPUC, through the pre-filed testimony of witnesses George Bachman, Doreen Cox, and Robert Camfield, requested 11.50% as the appropriate cost rate for common equity. FPUC supported this cost of equity with the results of four cost of equity models applied to both gas utilities and non-utility companies.
Using Value Line data, FPUC developed a sample of comparable gas utilities consisting of 12 natural gas distribution companies. The selection criteria included market liquidity of shares, business line, historical variations in cash flow and earnings per share, and beta – a measure of non-diversifiable risk. Using similar data and criteria (except for business line), FPUC also developed a sample of comparable non-utility companies consisting of 23 companies from various industries.
FPUC used a discounted cash flow (DCF) model, where the cost of equity is the discount rate that equates future cash flows of a company with its current stock price. FPUC applied a simple DCF model and a three-stage DCF model, which allows for various growth rates, to the sample of comparable gas utilities. The results ranged from 8.5% to 10.6%. FPUC included a 4.5% allowance for issuance costs, which added about 20 basis points to the results. The growth rate inputs included both historical growth and growth forecasted by security analysts.
FPUC employed a capital asset pricing model (CAPM), which is a risk premium model that uses as inputs a risk-free rate, an overall return for the market, and beta – a measure of systematic risk, which is risk that cannot be diversified away. FPUC applied its CAPM model to its sample of both groups of comparable companies. The results ranged from 9.6% to 12.5% for the gas utilities and 9.4% to 12.0% for the non-utility companies.
The next model FPUC used was a risk premium model that is based on realized returns on the S & P 500 for various time frames and a debt cost rate based on U.S. Treasury securities. The results are adjusted for issuance costs, diversifiable risk, and the small firm effect, i.e., firms with small market capitalizations may have higher required returns. The results of this model range from 11.9% to 13.8%.
Finally, FPUC relied on the historical returns, for various periods, for its gas utility and non-utility samples. For the gas utility sample, the returns ranged from 15.4% to 17.4% including the reinvestment of dividends. For the non-utility sample, the returns ranged from 11.6% to 14.5%.
FPUC’s four models rely heavily on historical information as inputs. FPUC primarily used historical growth rates for cash flow and earnings per share as well as analysts’ forecasted growth rates as inputs for its DCF model. Both the CAPM model and the risk premium model use historical earned, i.e., realized, returns as inputs. The historical returns model, as the name implies, uses historical returns exclusively.
Staff believes FPUC relied too heavily on historical information in its cost of equity models. The cost of equity is based on investor expectations and is forward-looking. FPUC attempted to find past periods that may reflect expectations for the economy and capital markets but that can never be a good fit. Staff believes the use of forecasted information is best for cost of equity models.
Staff also disagrees with FPUC’s use of earned or realized returns, which can differ significantly from required returns. Investors’ required returns are a function of investors’ expectations of risk and return. What an investor has earned on a stock for a particular holding period is only partially relevant. Past experience as well as expectations about earnings and risk are included in forecasted information.
Finally, staff disagrees with FPUC’s use of non-utility companies. Staff believes FPUC’s use of gas utilities in the models is appropriate since the business risk of the natural gas distribution industry is reflected in the stock prices and other inputs associated with the gas utilities.
Despite these disagreements, staff notes that the two most expectational models employed by FPUC are the DCF and CAPM models. The average of the two DCF results is approximately 9.7% and the CAPM result for the gas utilities is 12.5%. The average of these two approaches is 11.10%.
Staff notes that 11.25% is somewhat above the average of the DCF and CAPM models. Staff believes going above the average to 11.25% compensates for the business risk factors, such as small size and heavy dependence on commercial and industrial load. Staff notes that the Commission set the cost rate for common equity for City Gas at 11.25% in January 2004 (See Order No. PSC-04-0128-PAA-GU, issued February 9, 2004 in Docket No. 030659-GU – In Re: Application for a rate increase by City Gas Company of Florida.). For the reasons discussed above, staff recommends that the Commission set the cost of common equity for FPUC’s gas division at 11.25% with a range of plus or minus 100 basis points for all regulatory purposes.
Issue 21: 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 is 7.62% 7.69%. (Lester, Winters)
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 8.66%, which is based in part on an equity ratio of 52.17% and a cost rate for common equity of 11.50%.
The five differences between FPUC’s position on cost of capital and staff’s recommendation are as follows:
1) The appropriate cost rate for common equity (discussed in Issue 20);
2) The appropriate balance for deferred taxes (discussed in Issue 18);
3) Whether the capital structure should be revised to reflect the postponement of the planned equity (common stock) offering;
4) The treatment of non-utility investment in reconciling rate base and capital structure; and
5) The appropriate cost rate for short-term debt.
Regarding the planned equity offering, FPUC’s consolidated capital structures for 2004 and 2005 reflect net proceeds of $14.1 million from an equity offering that was planned for June 2004. Based on the advice of it underwriters, FPUC delayed the equity offering at a board of directors meeting on July 16, 2004.
The company now plans an equity offering for June 2005 and has filed a capital structure reflecting this postponement. However, the company’s position is that the capital structure as filed is appropriate for determining the cost of capital for this case. The company believes its capital structure as filed is appropriate because it is in the range of an optimal capital structure for a company of FPUC’s size, it is consistent with the company’s long term financial plans, and it avoids the financial risk of a more highly leveraged capital structure.
FPUC plans to meet any financing needs originally encompassed by the equity offering through short term debt, i.e., an extended line of credit. FPUC provided staff with a revised capital structure reflecting the postponement of the equity offering to June 2005. The equity ratio based on this revised capital structure is 45.96%, including the non-utility adjustment discussed below.
Staff recommends that the Commission use the revised capital structure in determining the cost of capital. Staff notes the company should not earn a return on equity it has not issued. Further, the replacement interim financing for the equity offering is short term debt priced at reasonable rates, and an equity ratio of approximately 46% is reasonable for a relatively small gas distribution utility.
Regarding the non-utility issue, FPUC has an investment in a propane gas distribution business – Flo-Gas. The amount of this investment for the projected test year is $2,248,022. 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.
(See Order No. 23573, p. 21, issued October 3, 1990, in Docket No. 891345-EI, In re: Petition of Gulf Power Company for an increase in its rates and charges.)
In FPUC’s filing, the company removed the investment in Flo-Gas on a pro-rata basis from investor sources of capital. FPUC noted that funds cannot be traced, i.e., assets cannot be identified with specific financing components. Also, FPUC argued that treating Flo-Gas as financed 100% by equity puts its propane business at a competitive disadvantage and that its capital structure, without removing the investment in Flo-Gas directly from equity, is reasonable.
Staff recommends that the Commission remove the investment in Flo-Gas directly from equity in reconciling capital structure and rate base. In response to FPUC’s tracing of funds and competitive disadvantage arguments, staff notes that removing non-utility investment from equity is a regulatory adjustment that prevents the relatively low risk utility from subsidizing a higher risk business. Staff believes that FPUC’s natural gas business faces significantly less competition, and, hence, risk, than its unregulated propane business. This adjustment is consistent with the Commission’s treatment of nonutility investment in Order No. PSC-04-0369-AS-EI, issued April 6, 2004, in Docket No. 030438-EI, In Re: Petition for Rate Increase by Florida Public Utilities Company.
Regarding the cost rate for short term debt, FPUC used 5.98%. The rate for FPUC’s short term debt is based on the 30-day London Interbank Offered Rate (LIBOR) plus 90 basis points. FPUC estimated the 5.98% by first estimating the Fed Funds rate and noting that the 30-day LIBOR is historically 20 basis points above the Fed Funds rate. For 2005, FPUC estimated the Fed Funds at 4.88% based on the period 1993 through 1999. Thus, the short term debt cost rate is the 4.88% Fed Funds rate estimate plus 110 basis points.
Staff disagrees with the company’s use of a 5.98% cost rate for short term debt. According to the September 1, 2004 Blue Chip Financial Forecast, the average Fed Funds rate for 2005 is projected to be 2.93%. Based on this forecast, the appropriate estimate for the cost rate of short term debt is 4.03%. Staff notes the Blue Chip forecast is a consensus forecast based on the forecasts of 46 business economists and encompasses the expectations for interest rates as well as the historical trend.
With theses
adjustments and cost rates, the appropriate weighted average cost of capital
for the projected test year is 7.62% 7.69%. Staff presents its
recommended cost of capital on Attachment 2.
Issue 22: Is FPUC’s projected level of Total Operating Revenues in the amount of $22,568,224 for the projected test year appropriate?
Recommendation: No. Other Operating Revenues should be increased by $3,600. The appropriate amount of Total Operating Revenues for the projected test year is $22,571,824. (Draper, Wheeler, Merta)
Issue 23: Is the level of overhead cost allocations for the projected test year appropriate?
Staff Analysis: FPUC is made up of two electric divisions, two natural gas divisions, four propane divisions, and four merchandise and jobbing divisions. Administrative and general expenses are charged to the appropriate division by using clearing allocations. Per Audit Exception No. 3, the company allocated workmen’s compensation insurance based on a combination of a claims and payroll allocation factor. However, the claims of headquarters employees, who work on all companies and go through the clearing account, were not allocated but instead were included in gas division claims. In addition, the company’s payroll factor did not allocate the headquarters employees’ payroll but instead included it in the gas division’s payroll. Further, the payroll allocation was not allocated to merchandising and jobbing. Staff corrected these items and calculated a $128,661 difference in the amount filed by the company. Of this amount, $57,084 is included in adjustments to OPEBs and pensions in Issues 36 and 37. Therefore, staff recommends that Account 926, Employee Pensions and Benefits, be decreased by $71,577. The company agrees with this adjustment.
In addition to the changes in the payroll factor described above, staff updated the company’s allocation factors using 2004 rates based on 2003 amounts. Staff recalculated the allocations to 2003 expenses which resulted in a $72,131 difference in the amount filed by the company. Therefore, staff recommends that expenses be reduced by $74,439 ($72,131 trended by various factors to 2005). The company agrees with this adjustment.
Further, in its response to the audit report, the company disclosed that the workers compensation allocation should also be adjusted. In the original projection an allocation of 59.77% was used, but this included claims from all corporate employees being allocated to natural gas. To correct the problem the company reviewed the corporate claims and calculated an adjustment to allocate corporate employees’ claims based on payroll. This produced an allocation factor of 58% and a reduction of $9,676. Therefore, staff recommends that Account 925, Injuries and Damages, be decreased by $9,676. The company agrees with this adjustment.
Issue 24: Should an adjustment be made to remove nonrecurring expenses?
Staff Analysis: According to Audit Disclosure No. 7, in 2003, FPUC paid $1,533 to replace SCADA equipment that was damaged by a lightning strike. In addition the company paid $3,701 for modifications to its bill printing program. Staff believes these expenses are nonrecurring in nature and recommends that Account 877, Measuring and Regulating Station Expenses, be decreased by $1,584 ($1,533 trended to 2005) for the SCADA equipment replaced and Account 921 be decreased by $3,823 ($3,701 trended to 2005) for modifications to the bill printing program. The company believes that though these specific items may be nonrecurring, similar types of charges occur periodically, and that these expenses should not be removed. However, staff believes that when and how frequently these costs will be incurred is uncertain. See Order No. 5471, issued June 30, 1972 in Docket No. 71342-EU, In re: Petition of Gulf Power Company for authority to increase its rates and charges so as to give said utility an opportunity to earn a fair return on the value of its property used and useful in serving the public.
In addition, according to Response to Data Request (RDR) 95, the company identified $70,420 in nonrecurring expenses recorded in Account 923 in 2003. They consist of: $1,219 in audit predecessor charges, $836 in legal fees for equity issuance costs, and $68,365 in legal fees pertaining to the Lake Worth Generation Project, for a total of $70,420. Therefore, staff recommends decreasing Account 923 by $72,720 ($70,420 trended to 2005)
In summary, staff recommends that Account 877 be decreased by $1,584, Account 921 be decreased by $3,823, and Account 923 be decreased by $72,720 for a total decrease to expenses of $78,127.
Several new positions were filled at annual salaries less than projected. Therefore, staff recommends that Account 874 be decreased by $4,077, Account 878 be decreased by $2,872, Account 880 be decreased by $1,981, and various accounts be decreased by $19,361, for a total decrease to expenses of $28,291.
In addition, one new position was filled at an annual salary higher than projected. Therefore, staff recommends that Account 887 be increased by $2,031.
The company updated its projections for four new positions. Therefore, staff recommends that Account 912 be decreased by $16,570, $38,641, $2,332, and $5,722 for a total decrease to expenses of $63,265.
The company projected $30,524 in Account 925 for a new Gas Safety position in 2005. Pursuant to RDR 73.25, this position was incorrectly allocated to the electric division. Therefore, staff recommends that Account 925 be increased by $19,593 ($50,117 - $30,524).
Issue 26: Are the expenses for the Fleet Image Improvement Program appropriately recovered through base rates?
Issue 27: Should an adjustment be made to Account 878, Meter & House Regulator Expense, for periodic meter and regulator change-out expense?
Recommendation: Yes. Account 878 should be decreased by $47,531 to correct the projection of periodic meter and regulator change-out expense for 2005. (Merta)
Staff Analysis: Rule 25-7.064, F.A.C., requires that utilities periodically test customer meters within a ten-year interval. According to RDR 78, in 2003, the company charged $129,776 to Account 878, Meter and House Regulator Expense, and trended it to 2005, for a total of $139,987. However, in RDR 79, the company projected its 2005 meter change-out expense to be $92,456. Therefore, staff recommends that this account be decreased by $47,531 ($139,987 - $92,456).
Issue 29: Should an adjustment be made to Account 904, Uncollectible Accounts, and Account 144, Allowance for Uncollectibles, for bad debt expense for the projected test year and what is the appropriate factor to include in the revenue expansion factor?
Staff Analysis: In 2003, the company included $188,003 in bad debt expense, $139,296 in Allowance for Uncollectibles and a 0.4000 bad debt component in its revenue expansion factor based on a three-year average of net write-offs to revenues. In prior cases, the Commission has tested the reasonableness of a company’s bad debt expense by using a three or a four-year average of net write-offs as a percent of revenues. A three-year average was used in the company’s last rate case. However, staff believes a five-year average should be used in this case because of the abnormal fluctuation in net write-offs over the past several years. Net-write-offs vary from $57,907 in 1999 to $240,491 in 2001 to $106,357 in 2002. Based on a calculation for the 1999 to 2003 period, the five-year average percent of net write-offs is 0.33%. This methodology results in an allowable expense of $156,055 for 2003. Therefore, staff recommends that an adjustment be made to decrease Account 904, Uncollectible Accounts, by $34,411 for 2005 ($188,003 - $156,055 trended to 2005). Staff believes this results in a reasonable amount of expense for the projected test year. A corresponding adjustment should be made to working capital. Allowance for Uncollectibles has a negative balance and is a contra account to Accounts Receivable. Therefore, staff recommends that Allowance for Uncollectibles be decreased by $17,205, the 13-month average of $34,411, thereby increasing working capital. Based on the above, staff also recommends that the bad debt component of the revenue expansion factor is 0.3300.
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.
Issue 30: Should an adjustment be made to remove nonutility advertising expense?
Based on the above adjustments, staff recommends that expenses in Account 913 be reduced by $91,357.
Staff Analysis: The officer bonus program has been in place since 2001. FPUC executive base salaries were reduced by 15% at the time of implementing this plan, and that portion was put at risk and awarded based on achieving certain goals and other criteria. In 2005, FPUC increased executive payroll by $40,000 for this plan, $20,800 or 52% of which was charged to the gas division. However, based on Audit Disclosure No. 12, if all goals are met, the bonus is now expected to be increased by only $20,000 at the total company level because one of the officer positions has been eliminated. Therefore, staff recommends that Account 920, Administrative and General Salaries, be reduced by $10,400 ($20,000 x .52). The company agrees with this adjustment.
Issue 33: Should an adjustment be made to Account 921, Office Supplies and Expenses for the projected test year?
Staff Analysis: Per RDR 110, in 2003, FPUC hired temporary help while the Network Administrator was on sick leave. The expense charged to the gas division was $11,574. This caused expenses to be overstated because the Network Administrator was still on the payroll. Therefore, staff recommends that Account 921, Office Supplies and Expenses be reduced by $11,952 ($11,574 trended to 2005).
The total adjustment is a $17,828 decrease to expenses.
Issue 34: Should an adjustment be made to Account 923, Outside Services, and Account 930, Miscellaneous General Expenses?
Staff Analysis: Per Audit Exception No. 9, in 2003, FPUC recorded $11,929 in legal fees associated with its Securities and Exchange Commission filing and $14,974 in costs associated with the design and printing of its annual report. At the end of 2003, the company decided to accrue for these types of expenses and began an accrual. In addition to recording the actual costs, the company accrued $10,200 for the SEC filing costs and $7,500 for annual report costs. Recording both the actual costs and the accrual created a duplication of charges. Therefore, staff recommends that Account 923, Outside Services, be reduced by $1,786 for duplicate legal fees and Account 930, Miscellaneous General Expenses, be reduced by $6,585 for duplicate annual report costs. The company agrees with this adjustment.
Per Audit Exception No. 6, the company does not pay its tax auditors unless they produce a tax savings. In 2005, FPUC included $10,200 for a property tax audit. This amount was based on a year when the company did pay the tax auditors; however, its tax bill was reduced by more than this amount. Staff believes this is a contingent expense and should be removed from expenses. Therefore, staff recommends that Account 923.3, Outside Services, be reduced by $10,200 for the property tax audit contingency. The company agrees with this adjustment.
The total adjustment is an $18,571 decrease to expenses.
Issue 35: Should an adjustment be made to Account 926, Employee Benefits, for the projected test year?
Staff Analysis: Per Audit Exception No. 8, to forecast Account 926, Employee Pensions and Benefits, the company obtained an estimate of health insurance costs from its insurance company and reduced it by 25% for the portion paid for by employees and for the amount related to retirees. This amount was then further reduced by capitalized payroll which was calculated using ten months of actual 2003 data and two months of 2002 data and trending by 3%. It was then increased for other miscellaneous payments made in 2002 which were trended up 3% for two years and decreased for the John Alden stop loss policy which has been eliminated. Capitalized payroll for November and December 2003 was $13,061 higher than the 2002 capitalized payroll used. This would reduce expense because capitalized wages were removed. Further, the company also used 2002 payments instead of 2003 payment amounts. If the 2003 payments were used, the account would be reduced by $1,566. Staff believes the 2003 amounts should be used instead of 2002 because the company used an actual 2003 test year and projections should be based on 2003 amounts. Therefore, staff recommends decreasing Account 926 by $14,626. The company agrees with this adjustment.
Issue 36: Should an adjustment be made to Other Post Employment Benefits Expense for the projected test year?
Recommendation: Yes. The other post employment benefits (OPEB) expense for the projected test year ending December 31, 2005 should be reduced by $11,886 to reflect a balance of $103,400. (Kenny, Lester)
Staff Analysis: Other post employment benefits (OPEB) primarily represent retiree health care costs. The financial reporting of OPEB is governed by Financial Accounting Standard No. 106, which prescribes accrual accounting. The company has included $115,286 of OPEB expense in its MFRs for the projected test year ending December 31, 2005. Staff notes that the Medicare Prescription Drug, Improvement and Modernization of Act of 2003 was not a factor that FPUC considered in determining the 2005 projected expense. The company received an updated actuarial study which reflects the accounting effects of implementing this Act. As a result, the expense is expected to be slightly less than originally projected. Additionally, in Audit Exception No. 3, staff has changed the allocation factor to the Natural Gas Division from 51% to 47%. Therefore, based on the updated study and the findings in the staff audit, the OPEB expense should be reduced by $11,886 to reflect a balance of $103,400.
Issue 37: Should an adjustment be made to pension expense for the projected test year?
Recommendation: Yes. The pension expense for the projected test year ending December 31, 2005 should be reduced by $26,645 to reflect a balance of $585,902. (Kenny, Lester)
Staff Analysis: The company included $612,547 of pension expense in its MFRs for the projected test year ending December 31, 2005. However, the company has since received an updated actuarial valuation of the employee’s pension plan. The updated valuation includes an assumed discount rate of 6.25%, a salary progression assumption of 3.5%, and an expected rate of return on assets of 8.5%. Staff believes these assumptions are reasonable. Additionally, in Audit Exception No. 3 staff has changed the allocation factor to the Natural Gas Division from 51% to 47%. Based on the updated valuation and the findings in the staff audit, pension expense should be reduced by $26,645 to reflect a balance of $585,902.
Issue 38: Should an adjustment be made to Account 928, Regulatory Commission Expense, for rate case expense for the projected test year and what is the appropriate amortization period?
|
|
MFR Estimated |
Actual |
Additional Estimated |
Total |
|
Legal Fees |
$118,000 |
$17,060 |
$33,540 |
$50,600 |
|
Consultant Fees |
333,000 |
208,705 |
46,845 |
255,550 |
|
Travel Expenses |
30,700 |
1,737 |
9,500 |
11,237 |
|
Paid Overtime & Temp Pay |
50,000 |
32,998 |
8,002 |
41,000 |
|
Other Expenses |
55,600 |
29,213 |
33,117 |
62,330 |
|
Total |
$587,300 |
$289,713 |
$131,004 |
$420,717 |
Staff 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 utility are reasonable.
Staff recommends that the appropriate rate case expense is $420,717, amortized at the rate of $105,179 over four years. Therefore, a reduction to Account 928, Regulatory Commission Expenses, of $41,646 should be approved. In addition, one-half of the unamortized rate case expense of $368,127, or $184,064, should be included in unamortized rate case expense in working capital for the projected test year. As a result, working capital should be reduced by $329,826.
Issue 39: Should an adjustment be made to Account 930, General Advertising and Miscellaneous General Expenses, projected test year?
Staff Analysis: The company recorded $13,035 in Florida Natural Gas Association (FNGA) dues in 2003. Per RDR 64, 15% of the FNGA dues, or $1,955, are attributed to lobbying activities. In addition, the company recorded $435 and $500 in dues to Volusia Home Builders Association and Home Builders Association, respectively. These organizations provide no benefit to the general body of ratepayers, therefore, the dues should be removed. Further, per RDR 65, the dues of the National Association of Corporate Directors should have been allocated to the electric and propane operations. This amounts to a decrease of $221. Therefore, staff recommends that Account 930, Dues and Economic Development Expense, be reduced by $3,213 ($3,111 trended to 2005).
Issue 40: What adjustments, if any, should be made to accumulated depreciation and depreciation expense to reflect the Commission’s decision in Docket No. 040352-GU In re: 2004 Depreciation Study for Florida Public Utilities Company to be implemented January 1, 2005?
Recommendation: No. The appropriate amount of Taxes Other
Than Income (TOTI) is $4,324,539, $4,310,816, a decrease of $140,180
$153,903. (Kenny)
Staff Analysis: The company included $4,464,719 of TOTI in its MFRs for the projected test year ending December 31, 2005. This amount includes $1,402,286 of State Gross Receipts Tax and $1,346,194 of Franchise Fees. The company has included the exact amounts as part of its 2005 revenue. Therefore no adjustment is necessary for the these two components of TOTI.
Payroll Taxes
Staff has made adjustments to payroll expense in Issues 25 and 32 which amount to a net decrease of $80,333. Staff has used a composite payroll tax rate of 8.37% to decrease the related payroll taxes associated with these adjustments. The result is a decrease to payroll taxes of $6,724 ($80,333 x 8.37%).
Regulatory Assessment Fees
In Issue 22, staff has increased revenues by $3,600. As a result, Regulatory Assessment Fees (RAF) should be increased by $18 ($3,600 x .005) to reflect the additional revenues. Also, in Audit Exception No. 10, staff has determined the revenue amount used for 2005 RAF calculation was understated. As a result, RAF should be increased by $6,692. The net effect of these RAF adjustments is an increase of $6,710.
Property Taxes
In Issues 3 – 7,
staff made adjustments to decrease net plant by $3,409,046 $4,193,209.
This amount includes $2,500,000 of land that has been determined to be non used
and useful. The property taxes related to this amount have been specifically
identified to be $42,500. The remaining balance of net plant that was removed
in other issues is $909,046 $1,693,209. Staff has used the 2003
property tax rate of 1.75% (net plant/property tax expense) to calculate the
decrease in property tax expense of $15,908 $29,631 ($909,046
$1,693,209 x 1.75%). In Issues 8 and 40, staff increased accumulated
depreciation by $171,530. As a result, property taxes should be increased by
$3,001 ($171,530 x 1.75%). Additionally, in Issue 9, staff decreased the
acquisition adjustment and related accumulated amortization which decreases net
plant by $2,417,813. Therefore, property taxes should be decreased by $42,312
($2,417,813 x 1.75%). In addition, in Audit Exception No. 11 staff removed
$42,448 of property taxes related to common property that was removed but the
related property taxes were not. Therefore, the net effect of these
adjustments is a decrease in property taxes of $140,166 $153,889
{($42,500)+($15,908 $29,631)+$3,001+($42,312)+($42,448)}.
As a result of
the above mentioned adjustments, the net effect is a decrease of $140,180
$153,903 [($6,724) + $6,710 + ($140,166 $153,889)] to
reflect a balance of $4,324,539 $4,310,816 in TOTI.
Issue 42: Is FPUC’s Income Tax Expense of ($1,093,873), which includes current and deferred income taxes, investment tax credit (ITC) amortization, and interest reconciliation for the projected test year, appropriate?
Issue 43: Is FPUC’s Net Operating Income of $641,221 for the projected test year appropriate?
Staff Analysis: This is a calculation based upon the decisions in preceding issues. The company and staff positions are reflected in the following table and are discussed in the appropriate issues.
|
COMPARATIVE NET OPERATING INCOME Projected Test year Ending 12/31/05 |
|||
|
|
Company |
Staff |
Staff Revised |
|
Operating Revenues |
$22,568,224 |
$22,571,824 |
$22,571,824 |
|
Operating Expenses |
|
|
|
|
O&M |
14,795,629 |
14,178,039 |
14,178,039 |
|
Depreciation & Amortization |
3,760,529 |
|
3,999,601 |
|
Taxes Other Than Income |
4,464,719 |
|
4,324,539 |
|
Income Taxes |
(1,093,873) |
|
(811,143) |
|
Total Operating Expenses |
21,927,005 |
|
21,691,037 |
|
Net Operating Income |
$641,219 |
|
$880,787 |
Issue 44: 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?
The revenue expansion factor and net operating income multiplier are shown on Attachment 4.
Issue 45: Is FPUC’s requested annual operating revenue increase of $8,186,989 for the projected test year appropriate?
COST OF SERVICE AND RATE DESIGN
Issue 46: What is the appropriate cost of service methodology to be used to allocate costs to the rate classes?
Recommendation: The appropriate methodology is contained in Attachment 6. (Wheeler)
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 Attachment No. 6, pages 1-18.
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.
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 recommended adjustments to rate base, expenses, net operating income, billing determinants and projected test year base rate revenues. In addition, staff’s study used a different methodology to develop the capacity allocators. This differing methodology results in a slight difference in the allocators that were used to allocate capacity costs among the rate classes.
Issue 47: If the Commission grants a revenue increase to FPUC, how should the increase be allocated to the rate classes?
Recommendation: Staff’s recommended allocation of the revenue increase to the rate classes is contained in Attachment 6, page 16 of 16. (Wheeler)
Staff Analysis: Staff’s recommended allocation of the revenue increase is contained in Attachment 6, page 18 of 18. Staff’s recommended allocation and the resulting per-therm charges will be adjusted subsequent to the agenda conference to reflect any change to the revenue requirement that results from the Commission’s votes on the issues. The staff recommended allocation of the increase was designed to move each rate class towards the system rate of return (i.e., to parity), while taking into account the rate impact on each customer class.
Issue 48: What are the appropriate Customer Charges?
Recommendation: Staff’s recommended customer charges are as follows:
|
Rate Class |
Staff Recommended Customer Charge |
|
Residential Service (RS) |
$8.00 |
|
General Service (GS) |
$15.00 |
|
General Service Transportation Service (GSTS) |
$15.00 |
|
Large Volume Service (LVS) >500 therms/mo. |
$45.00 |
|
Large Volume Transportation Service (LVTS) >500 therms/mo. |
$45.00 |
|
Interruptible Service (IS) |
$240.00 |
|
Interruptible Transportation Service (ITS) |
$240.00 |
(Baxter)
Staff Analysis: The customer charge is a fixed charge that applies to each customer’s bill no matter 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 no matter whether any gas is consumed.
Staff’s recommended customer charges are contained in the table below. The table also shows the existing customer charges and the company-proposed charges.
|
Rate Class |
Present Charge: Deland, Sanford, Palm Beach Districts |
Present Charge: New Smyrna Beach District |
Company Proposed Charge All Districts |
Staff Recommended Charge |
|
Residential Service (RS) |
$8.00 |
$7.00 |
$8.00 |
$8.00 |
|
General Service (GS) |
$15.00 |
$12.00 |
$15.00 |
$15.00 |
|
General Service Transportation Service (GSTS) |
$15.00 |
$12.00 |
$15.00 |
$15.00 |
|
Large Volume Service (LVS) >500 therms/mo. |
$45.00 |
$12.00 |
$45.00 |
$45.00 |
|
Large Volume Transportation Service (LVTS) >500 therms/mo. |
$45.00 |
$12.00 |
$45.00 |
$45.00 |
|
Interruptible Service (IS) |
$240.00 |
NA |
$240.00 |
$240.00 |
|
Interruptible Transportation Service (ITS) |
$240.00 |
NA |
$240.00 |
$240.00 |
As shown in the above table, FPUC has not proposed any change to its existing customer charges. However, because customers in its New Smyrna Beach district currently pay different base rates, the adoption of uniform rates for all customers in FPUC’s territory (as discussed in Issue 51) will result in changes to the customer charges paid by New Smyrna Beach customers. These changes are reflected in the table above. Staff believes that FPUC’s proposed customer charges are reasonable, and recommends that they be approved.
Issue 49: What are the appropriate per therm Energy Charges?
Recommendation: Staff’s recommended per therm Energy Charges are contained in Attachment 7, page 1. (Wheeler)
Staff Analysis: Staff’s recommended per therm Energy Charges are contained in Attachment 7, page 1. These charges are subject to change based on the Commission’s vote in other issues. The resulting bill impacts of staff’s recommended rates by rate class are shown on pages 2 through 9 of Attachment 7.
Staff Analysis: Staff’s recommended miscellaneous service charges are shown in the table below:
|
Type of Charge |
Time of Service |
Present Charges |
Staff Recommended |
|||||
|
Deland, Sanford, Palm Beach |
New Smyrna Beach |
|||||||
|
LVS & LVTS |
All Other |
Residential |
Commercial |
RS |
GS & GSTS |
LVS, LVTS, IS, & ITS |
||
|
Establishment of Service |
|
|||||||
|
|
Regularly Scheduled |
$57.00 |
$25.00 |
$20.00 |
$30.00 |
$42.00 |
$60.00 |
$90.00 |
|
|
Outside Normal Business Hours |
NA |
NA |
NA |
NA |
$56.00 |
$79.00 |
$119.00 |
|
Change of Acct. – Meter Read Only |
|
|||||||
|
|
Regularly Scheduled |
$12.00 all classes |
$10.00 all classes |
$19.00 all classes |
||||
|
|
Outside Normal Business Hours |
NA |
NA |
NA |
NA |
$24.00 all classes |
||
|
Reconnection after Disconnection |
|
$48.00 |
$21.00 |
$20.00 |
$30.00 |
This charge has been merged with the Establishment of Service Charge (see above) |
||
|
Reconnection after Disconnection for Non-Pay |
|
|||||||
|
|
Regularly Scheduled |
$58.00 |
$31.00 |
$20.00 |
$30.00 |
$60.00 |
$78.00 |
$108.00 |
|
|
Outside Normal Business Hours |
NA |
NA |
NA |
NA |
$74.00 |
$97.00 |
$137.00 |
|
Bill Collection in Lieu of Disconnection for Non-Pay |
|
$9.00 all classes |
$10.00 all classes |
$16.00 all classes |
||||
|
Failed Trip Charge |
|
|||||||
|
|
Regularly Scheduled |
NA |
NA |
NA |
NA |
$19.00 all classes |
||
|
|
Outside Normal Business Hours |
NA |
NA |
NA |
NA |
$24.00 all classes |
||
|
Electronic Bill Payment Charge |
|
NA |
NA |
NA |
NA |
$3.50 per transaction |
||
|
Worthless Check Charge |
|
In accordance with Section 68.065, F.S. |
In accordance with Section 68.065, F.S. |
|||||
|
Late Payment Charge |
|
Greater of 1.5% of Past Due Amount or $5.00 |
Greater of 1.5% of Past Due Amount or $5.00 |
|||||
Miscellaneous service charges are designed to recover the costs of initial connection of service, reconnection after a customer’s service has been disconnected for non-payment and similar activities. FPUC has proposed two new charges in this case.
The first new charge is a failed trip charge that is designed to recover the costs incurred by the company when a customer fails to keep a scheduled appointment and FPUC is not able to perform the requested activity. The proposed charge is $19.00.
The second new
charge is an electronic bill payment charge that is designed to recover the
bank and overhead costs incurred by the company in accepting payment by credit
card, debit card or electronic check. The proposed charge is equal to $3.50
3.5% per of the transaction amount. Currently, the
company does not accept payment by these methods. Staff believes that the
proposed charge is appropriate because it recovers these additional costs from
those customers who opt to pay by credit card, debit card or electronic check.
Staff has reviewed the cost support initially filed by FPUC for its proposed miscellaneous charges, and has requested additional information supporting those charges. Based upon its review of this cost support, staff believes that FPUC’s proposed charges are reasonable, and recommends that they be approved.
Issue 51: Is FPUC’s proposal to eliminate the separate base rate schedules applicable to its New Smyrna Beach District customers and charge all customers under uniform base rate schedules appropriate?
Recommendation: Yes. (Draper)
Staff Analysis: FPUC purchased the New Smyrna Beach gas distribution system from South Florida Natural Gas Company in December 2001. The rates and service charges for the New Smyrna Beach District customers remained unchanged following the purchase, and thus these customers currently pay different rates from those paid by FPUC’s other customers.
Customers in the New Smyrna Beach District are currently served under three rate schedules: Residential Service (NSB-RS), Commercial and Industrial Service (NSB-CI), and Commercial and Industrial Transportation Service (NSB-CITS). FPUC has proposed to eliminate the separate base rate schedules and service charges applicable to its New Smyrna Beach District customers and migrate these customers to the appropriate residential and commercial rate schedules and service charges applicable to all FPUC customers.
Combining the two districts will reduce the unnecessary duplication of costs associated with administering two sets of base rates and other tariff provisions.
The Commission has approved a similar proposal for Peoples Gas (Peoples) in its recent rate case. In 1997 Peoples acquired the West Florida Natural Gas Company; however, rates for the West Florida customers remained unchanged. In Peoples’ recent rate case, the Commission approved Peoples’ proposal to apply uniform rates and service charges to all customers, including customers formerly served by West Florida Gas. See Order No. 03-0038-FOF-GU, issued January 6, 2003, in Docket No. 020384-GU, In Re: Petition for Rate Increase by Peoples Gas System.
Staff recommends that FPUC’s proposal to eliminate the separate base rate schedules applicable to its New Smyrna Beach District customers and charge all customers under uniform base rate schedules should be approved. The consolidation will result in a uniform set of rates for all of FPUC’s customers, and will not result in a significant rate impact to current New Smyrna Beach district customers.
Issue 52: What is the appropriate monthly Pool Manager Service Charge?
Recommendation: The appropriate monthly Pool Manager Service Charge is $100. (Draper)
Staff Analysis: FPUC has not proposed to change the current monthly Pool Manager Service Charge of $100. This charge was approved in Order No. PSC-01-0073-TRF-GU, issued January 9, 2001, in Docket No. 000795-GU, In Re: Petition by Florida Public Utilities Company for approval of unbundled transportation Service.
FPUC provided cost data that support the current charge of $100. The charge is designed to cover FPUC’s cost to support the pool managers in providing transportation service to FPUC’s transportation-only customers. Specifically, FPUC provides daily reports to its pool managers specifying how much gas the pool managers must deliver to FPUC. This insures that the pool managers deliver the appropriate quantity of gas from the interstate pipeline to FPUC for delivery to its transportation-only customers.
Staff has reviewed the derivation of the Pool Manager Service Charge and believes that it is appropriate. Staff therefore recommends that the proposed charge be approved.
Recommendation: Yes. (Wheeler)
Staff Analysis: FPUC’s Large Volume Interruptible Service (LVIS) and the Large Volume Interruptible Transportation Service (LVITS) rate schedules have been closed to new customers since June 30, 1998, and there are no customers currently served under either rate schedule. Therefore, staff recommends that the schedules be eliminated from FPUC’s tariff, as proposed by the company.
Issue 54: What is the appropriate fee for transportation customers who change their pool managers?
Recommendation: The appropriate fee for transportation customers who change their pool manager is $19. (Draper)
Staff Analysis: FPUC has proposed to reduce the fee for transportation customers who change their pool manager after its initial designation from $50 to $19. The fee is designed to recover the same costs as the Change of Account fee, which is discussed in Issue 50. Staff believes that the proposed charge is appropriate and should be approved.
Issue 55: Is FPUC’s proposed new Gas Lighting Service (GLS) rate schedule appropriate?
Recommendation: Yes. (Draper)
Staff Analysis: FPUC’s proposed new Gas Lighting Service (GLS) rate schedule applies to customers that have a minimum of five gas lighting fixtures that are acceptable to the company. Service to the fixtures must also be capable of being discontinued without affecting other gas service provided to the customer.
Currently, customers with gas light fixtures are billed under FPUC’s existing otherwise applicable metered General Service or General Service Large Volume rate schedules. Service under the GLS schedule will be unmetered, and therm usage will be billed based on the estimated usage of each gas fixture. Customers that take both gas lighting and gas service under another FPUC rate schedule will pay only a per-therm GLS non-fuel energy charge. Customers who take only gas lighting service will pay the GLS non-fuel energy charge plus the customer charge of the otherwise applicable rate schedule.
FPUC has proposed that the gas lighting service will be subject to interruption at the discretion of the company. If a lighting customer continues to use gas after being notified that an interruption exists, the customer is billed at the higher of $1.50 per therm or the cost to FPUC by its supplier. This provision insures that customers comply with interruption orders. Any penalties paid under this provision are credited to the company’s Purchased Gas Adjustment clause.
Staff believes that FPUC’s new proposed GLS rate schedule is appropriate and should be approved.
Issue 56: Are FPUC’s proposed charges for transportation service customers appropriate?
Recommendation: Yes. FPUC’s proposed charges for transportation service customers are appropriate. FPUC should discontinue billing its customers the Transportation Cost Recovery and Non-monitored Transportation Administration Charge cost recovery factors at the time the revised rates in this case become effective. In addition, staff recommends that FPUC file a petition for the final true-up of the Transportation Cost Recovery Clause and the Non-monitored Transportation Administration Charge within 30 days of the effective date of the revised rates. (Draper)
Staff Analysis: FPUC has proposed three separate charges for transportation service customers, as discussed below:
A. Telemetry Maintenance Charge. FPUC has proposed a reduction in the monthly Telemetry Maintenance Charge (telemetry charge) from $82.50 to $30. The telemetry charge applies to transportation customers whose annual usage exceeds 50,000 therms. The telemetry equipment is installed at the customer’s premises and allows the measurement of real-time consumption data by the company. The reduction in the charge results from a reduction in the cost of the equipment. The charge includes the projected annual maintenance and replacement costs of the equipment.
B. Transportation Administration Charges:
1. Non-monitored Transportation Charge - FPUC has proposed a new fixed monthly Non-monitored Transportation Charge (non-monitored charge) of $4.50. This charge applies to all transportation customers and is designed to recover the additional costs FPUC incurs to provide transportation service. The charge will replace the variable Non-monitored Transportation Administration Charge, which is discussed below.
2. Monitoring and Reporting Charge - FPUC has proposed to reduce the monthly Monitoring and Reporting Charge from $54 to $16.50. This charge applies to all transportation customers that are required to have telemetry equipment installed.
In addition to the fixed telemetry and the Monitoring and Reporting charge, FPUC currently recovers the incremental transportation-related costs through two Commission-approved cost recovery mechanisms: (1) the Transportation Cost Recovery Clause (TCR), and (2) the Non-monitored Transportation Administration Charge (NTAC). See Order No. 01-0073-TRF-GU, issued January 9, 2001, in Docket No. 000795-GU, In Re: Petition by Florida Public Utilities Company for approval of unbundled transportation service.
Both cost recovery factors are billed as a cents-per-therm charge and are applied to the customer’s actual consumption. The TCR factors were designed to recover certain transportation-related start-up expenses. At the end of the recovery period, any over- or under-recovery is to be trued up. Order No. PSC-01-1963-TRF-GU, issued October 1, 2001, in Docket No. 010846-GU, In Re: Petition for Approval of initial transportation cost recovery factors by Florida Public Utilities Company.
In Order No. PSC-01-1963-TRF-GU the Commission also approved FPUC’s initial NTAC factors for the period October 2001 through December 2002, with any over- or under-recovery trued up at the end of the period. Since then, the Commission has approved several modifications to the NTAC factors.
FPUC states that it will discontinue billing its customers the TCR and the NTAC cost recovery factors at the time the revised rates in this case become effective. This will insure that customers are not billed twice for transportation-related costs. As stated earlier, the TCR factor is a temporary fee, and the proposed new fixed non-monitored charge is designed to replace the NTAC factor. In addition, staff recommends that within 30 days after the effective date of the revised rates, FPUC file a petition calculating the final true-up of both the TCR and NTAC factors. The petition should include a proposed treatment of the final disposition of any over- or under-recovery.
Issue 57: Is FPUC’s proposal to eliminate the charge for historical consumption information appropriate?
Staff Analysis: The charge for historical consumption information applies to customers on the General Service Transportation Service (GSTS), Interruptible Transportation Service (ITS) and Commercial and Industrial Transportation Service – New Smyrna Beach (CITS-NSB) rate schedules who request their historical consumption information. Customers taking service under theses rate schedules are provided with a free initial report showing their previous 12-month historical consumption information. For any additional requests for consumption information, a $15.00 fee is charged. Non-transportation customers requesting historical consumption information are provided this information at no charge.
In response to staff data requests, the company stated that it proposed to eliminate the charge since so few transportation customers had requested the reports, and because non-transportation customers are provided the consumption information without charge. Staff believes that the company’s proposal to eliminate the charge is reasonable, and recommends that it be approved.
Issue 58: 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. (Wheeler)
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 insure that customers are aware of the new rates before they are billed for usage under the new rates.
Issue 59: Should any portion of the $1,236,108 interim increase granted by Order No. PSC-04-0721-PCO-GU, issued July 26, 2004, be refunded to the customers?
An interim increase is reviewed when final rates are derived to determine if any portion should be returned to the ratepayers. In this case, interim rates went into effect August 5, 2004, and will be continued until final rates are scheduled to take effect in November 2004. Therefore, 2004 is the appropriate year to analyze for affirmation of the interim increase.
Staff believes that no refund of interim is required because the revenue requirement for the 2004 test year exceeds the revenue requirement awarded for the interim.
Issue 60: 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. To ensure that the utility adjusts its books in accordance with the Commission’s decision, FPUC should provide proof, within 90 days of the consummating order finalizing this docket, that the adjustments for all the applicable NARUC USOA primary accounts have been made to its annual report, rate of return reports, and its books and records. (Revell)
Staff Analysis: To ensure that the utility adjusts its books in accordance with the Commission’s decision, staff recommends that FPUC should provide proof, within 90 days of the consummating order that the adjustments for all the applicable NARUC USOA primary accounts have been made to its annual report, rate of return reports, and its books and records.
Issue 61: Should this docket be closed?)
|
FLORIDA PUBLIC UTILITIES COMPANY |
|
ATTACHMENT 1 |
||||
|
PTY 12/31/05 |
|
|
|
|
|
|
|
|
|
|
COMPANY |
STAFF |
||
|
ISSUE |
|
TOTAL |
COMPANY |
COMPANY |
STAFF |
STAFF |
|
NO. |
|
PER BOOKS |
ADJS. |
ADJUSTED |
ADJS. |
ADJUSTED |
|
|
PLANT IN SERVICE |
|
|
|
|
|
|
|
UTILITY PLANT |
93,956,032 |
|
|
|
|
|
|
Non-regulated |
|
(1,920,851) |
|
|
|
|
|
Misc. intang. plant-non-comp |
|
(1,900,000) |
|
|
|
|
|
Bare steel replacement program-amort. |
|
(188,772) |
|
|
|
|
|
Bare steel replacement program-retiremnts. |
|
(7,266) |
|
|
|
|
3 |
South Florida Operations Center (389) |
|
|
|
(2,500,000) |
|
|
3 |
South Florida Operations Center (390) |
|
|
|
(26,340) |
|
|
4 |
Sanford Office Building & Land |
|
|
|
(106,204) |
|
|
5 |
Plant additions |
|
|
|
(1,076,150) |
|
|
6 |
Plant retirements |
|
|
|
(30,112) |
|
|
7 |
Inactive service lines |
|
|
|
(113,998) |
|
|
|
Total Plant-In-Service |
93,956,032 |
(4,016,889) |
89,939,143 |
(3,852,804) |
86,086,339 |
|
|
|
|
|
|
|
|
|
|
COMMON PLANT ALLOCATED |
3,429,181 |
|
|
|
|
|
|
Total Common Allocated |
3,429,181 |
0 |
3,429,181 |
0 |
3,429,181 |
|
|
|
|
|
|
|
|
|
|
ACQUISITION ADJUSTMENT |
1,816,579 |
|
|
|
|
|
|
Include Atlantic Utilities |
|
3,300,000 |
|
|
|
|
|
Remove acquisition goodwill |
|
(1,513,179) |
|
|
|
|
9 |
Reduce SFNG acquisition adj. |
|
|
|
(2,339,624) |
|
|
|
Total Acquisition Adjustment |
1,816,579 |
1,786,821 |
3,603,400 |
(2,339,624) |
1,263,776 |
|
|
|
|
|
|
|
|
|
|
CONSTRUCTION WORK IN PROGRESS |
190,577 |
|
|
|
|
|
10 |
Increase for budget changes |
|
|
|
41,536 |
|
|
|
COMMON CWIP ALLOCATED |
3,427 |
|
|
|
|
|
|
Total Construction Work In Progress |
194,004 |
0 |
194,004 |
41,536 |
235,540 |
|
|
|
|
|
|
|
|
|
|
TOTAL PLANT |
99,395,796 |
(2,230,068) |
97,165,728 |
(6,150,892) |
91,014,836 |
|
|
|
|
|
|
|
|
|
|
DEDUCTIONS |
|
|
|
|
|
|
|
ACCUM. DEPR.- PLANT IN SERVICE |
29,479,477 |
|
|
|
|
|
|
Non-regulated |
|
(536,639) |
|
|
|
|
|
Bare steel replacement program-retiremnts. |
|
(6,132) |
|
|
|
|
|
Bare steel replacement program-retiremnts. |
|
(1,134) |
|
|
|
|
3 |
South Florida Operations Center (390) |
|
|
|
(198) |
|
|
4 |
Sanford Office Building & Land |
|
|
|
(104,123) |
|
|
5 |
Plant additions |
|
|
|
(28,202) |
|
|
6 |
Plant retirements |
|
|
|
(32,557) |
|
|
7 |
Inactive service lines |
|
|
|
(278,678) |
|
|
8 |
Increase for bare steel replacement prog. |
|
|
|
94,385 |
|
|
40 |
Change in depreciation rates |
|
|
|
77,145 |
|
|
|
|
|
|
|
|
|
|
|
Total Accum. Depr.- Plant In Service |
29,479,477 |
(543,905) |
28,935,572 |
(272,228) |
28,663,344 |
|
|
|
|
|
|
|
|
|
|
ACCUM DEPR. - COMMON PLANT |
1,039,014 |
|
|
|
0 |
|
|
Total Accum. Depr. - Common Plant |
1,039,014 |
0 |
1,039,014 |
0 |
1,039,014 |
|
|
|
|
|
|
|
|
|
|
ACCUM. AMORT. - ACQUISITION ADJ. |
308,262 |
|
|
|
|
|
|
Include Atlantic Utilities |
|
49,866 |
|
|
|
|
9 |
Reduce SFNG acquisition adj. |
|
|
|
78,189 |
|
|
|
Total Accum. Depr. - Acquisition Adj. |
308,262 |
49,866 |
358,128 |
78,189 |
436,317 |
|
|
|
|
|
|
|
|
|
|
CUSTOMER ADVANCES FOR CONSTR. |
997,805 |
|
|
|
|
|
|
Total Customer Advances for construction |
997,805 |
0 |
997,805 |
0 |
997,805 |
|
|
|
|
|
|
|
|
|
|
TOTAL DEDUCTIONS |
31,824,558 |
(494,039) |
31,330,519 |
(194,039) |
31,136,480 |
|
|
|
|
|
|
|
|
|
|
NET UTILITY PLANT |
67,571,238 |
(1,736,029) |
65,835,209 |
(5,956,853) |
59,878,356 |
|
|
|
|
|
|
|
|
|
|
WORKING CAPITAL ALLOWANCE |
(7,966,722) |
7,966,722 |
0 |
(706,682) |
(706,682) |
|
|
|
|
|
|
|
|
|
|
TOTAL RATE BASE |
59,604,516 |
6,230,693 |
65,835,209 |
(6,663,535) |
59,171,674 |
|
FLORIDA PUBLIC UTILITIES COMPANY ATTACHMENT 1A |
||||||
|
DOCKET NO. 040216-GU |
||||||
|
PTY 12/31/05 |
||||||
|
|
|
COMPANY AS FILED |
||||
|
ISSUE |
|
TOTAL |
COMPANY |
COMPANY |
STAFF |
STAFF |
|
NO. |
|
PER BOOKS |
ADJS. |
ADJUSTED |
ADJS. |
ADJUSTED |
|
|
ASSETS |
|
|
|
|
|
|
|
Other Funds |
6,100 |
|
6,100 |
|
6,100 |
|
12 |
Cash |
1,079,871 |
(635,573) |
444,298 |
(155,648) |
288,650 |
|
|
Insurance Proceeds Environmental Cleanup |
3,135,957 |
(3,135,957) |
0 |
|
0 |
|
|
Cash-Other |
9,400 |
|
9,400 |
|
9,400 |
|
|
Accounts Receivable-Customer |
4,775,265 |
|
4,775,265 |
|
4,775,265 |
|
|
Accounts Receivable-Other |
269,087 |
|
269,087 |
|
269,087 |
|
29 |
Allowance for Uncollectables |
(150,256) |
|
(150,256) |
17,205 |
(133,051) |
|
13 |
Materials & Supplies |
473,077 |
|
473,077 |
(42,577) |
430,500 |
|
|
Stores Expense |
19,318 |
|
19,318 |
|
19,318 |
|
11 |
Prepaid Insurance |
335,835 |
|
335,835 |
(74,383) |
261,452 |
|
11 & 15 |
Prepaid Pensions |
74,493 |
|
74,493 |
6,525 |
81,018 |
|
|
Prepaid Other |
72,008 |
|
72,008 |
|
72,008 |
|
|
Unbilled Revenues |
824,126 |
|
824,126 |
|
824,126 |
|
38 |
Other Deferred Debits-Rate Case Exp. |
513,890 |
|
513,890 |
(329,826) |
184,064 |
|
|
Other Deferred Debits-Allocated |
3,877 |
|
3,877 |
|
3,877 |
|
|
Other Deferred Debits-Direct |
23,647 |
|
23,647 |
|
23,647 |
|
|
Other Deferred Debits-AEP |
4,067,137 |
(4,067,137) |
0 |
|
0 |
|
|
Underrecoveries-PGA & Conserv. |
183,039 |
|
183,039 |
|
183,039 |
|
|
Deferred Piping & Conversion |
1,428,964 |
|
1,428,964 |
|
1,428,964 |
|
|
Misc. Deferred Debits |
19,603 |
|
19,603 |
|
19,603 |
|
|
Misc. Deferred Debits |
(29) |
|
(29) |
|
(29) |
|
|
TOTAL ASSETS |
17,164,409 |
(7,838,667) |
9,325,742 |
(578,704) |
8,747,038 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
|
|
Misc. Non-Current Liab-Insurance |
59,070 |
|
59,070 |
|
59,070 |
|
14 |
Misc. Non-Current Liab-Insurance |
1,379,753 |
|
1,379,753 |
(10,781) |
1,368,972 |
|
|
Provision for Rate Refund |
267,483 |
|
267,483 |
|
267,483 |
|
11 |
Accounts Payable-Operating |
3,642,270 |
|
3,642,270 |
(686,631) |
2,955,639 |
|
|
Accounts Payable-Other |
465,113 |
|
465,113 |
|
465,113 |
|
|
Taxes Payable-Gross receipts |
115,433 |
|
115,433 |
|
115,433 |
|
|
Taxes Payable-FPSC Assessment |
68,220 |
|
68,220 |
|
68,220 |
|
11 |
Taxes Payable-Income Taxes |
1,769,203 |
|
1,769,203 |
(211,555) |
1,557,648 |
|
|
Taxes Payable-Ad Valorem |
356,034 |
|
356,034 |
|
356,034 |
|
|
Taxes Payable-Other |
4,879 |
|
4,879 |
|
4,879 |
|
11 |
Interest Accrued-Debt |
639,545 |
|
639,545 |
(77,243) |
562,302 |
|
|
Interest Accrued-Customer Deposits |
114,589 |
|
114,589 |
|
114,589 |
|
|
Dividends Payable-Preferred Stock |
1,672 |
|
1,672 |
|
1,672 |
|
11 |
Taxes Payable-Employee & Sales |
66,476 |
|
66,476 |
7,188 |
73,664 |
|
|
Taxes Payable-Franchise |
759,548 |
|
759,548 |
|
759,548 |
|
|
Taxes Payable-Municipal |
174,147 |
|
174,147 |
|
174,147 |
|
|
Accrued Liability-Vacation Payroll |
705,722 |
|
705,722 |
(566,309) |
139,413 |
|
11 |
Accrued Liability-Misc. |
88,725 |
|
88,725 |
|
88,725 |
|
|
Misc. Deferred Liab-Misc. |
388 |
|
388 |
|
388 |
|
|
Misc Deferred Liab-Unamort. Gains |
221,283 |
(221,283) |
0 |
|
0 |
|
|
Overrecoveries-PGA & Conserv. |
594,244 |
|
594,244 |
|
594,244 |
|
|
Overrecoveries-Unbundle |
0 |
|
0 |
|
0 |
|
|
Environmental Liability Insurance Proceeds |
5,027,989 |
(5,027,989) |
0 |
|
0 |
|
|
Environmental Liability Pending Rate Recovery |
8,882,808 |
(8,882,808) |
0 |
|
0 |
|
|
Environ Costs Net of Customer Proceeds |
(273,463) |
|
(273,463) |
|
(273,463) |
|
16 |
Adjustment for Negative Working Capital |
|
(1,673,309) |
(1,673,309) |
1,673,309 |
0 |
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES |
25,131,131 |
(15,805,389) |
9,325,742 |
127,978 |
9,453,720 |
|
|
|
|
|
|
|
|
|
|
TOTAL WORKING CAPITAL ALLOWANCE |
(7,966,722) |
7,966,722 |
0 |
(706,682) |
(706,682) |
|
|
|||||||||
|
PTY 12/31/05 |
|
|
|
|
|
|
ATTACHMENT 2 |
|
|
|
13 Month Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPANY POSITION |
|
|
|
|
|
|
|
|
|
|
|
FPUC |
|
|
|
|
|
|
|
|
|
|
PER |
|
FPUC |
|
COST |
WEIGHTED |
|
|
|
|
|
BOOKS |
PRO RATA |
ADJUSTED |
RATIO |
RATE |
COST |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG TERM DEBT |
50,346,860 |
(24,654,534) |
25,692,326 |
39.03% |
8.04% |
3.14% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHORT TERM DEBT |
796,154 |
(389,871) |
406,283 |
0.62% |
5.98% |
0.04% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED STOCK |
600,000 |
(293,816) |
306,184 |
0.47% |
4.75% |
0.02% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON EQUITY |
56,448,772 |
(27,642,601) |
28,806,171 |
43.75% |
11.50% |
5.03% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CUSTOMER DEPOSITS |
4,094,408 |
|
4,094,408 |
6.22% |
6.28% |
0.39% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED TAXES |
6,253,275 |
|
6,253,275 |
9.50% |
0.00% |
0.00% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TAX CREDIT - ZERO COST |
0 |
|
0 |
0.00% |
0.00% |
0.00% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TAX CREDIT – OVERALL COST |
276,563 |
|
276,563 |
0.42% |
9.81% |
0.04% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
$118,816,032 |
($52,980,822) |
$65,835,210 |
100.00% |
|
8.66% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STAFF POSITION |
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED |
|
ADJUSTED |
|
|
|
|
|
|
|
|
TOTAL |
|
PER |
STAFF |
|
STAFF |
|
COST |
WEIGHTED |
|
|
COMPANY |
FLO GAS |
BOOKS |
SPECIFIC |
PRO RATA |
ADJUSTED |
RATIO |
RATE |
COST |
|
|
|
|
|
|
|
|
|
|
|
|
LONG TERM DEBT |
50,346,860 |
|
50,346,860 |
|
(28,476,024) |
21,870,836 |
36.96% |
8.04% |
2.97% |
|
|
|
|
|
|
|
|
|
|
|
|
SHORT TERM DEBT |
5,720,154 |
|
5,720,154 |
|
(3,235,301) |
2,484,853 |
4.20% |
4.03% |
0.17% |
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED STOCK |
600,000 |
|
600,000 |
|
(339,358) |
260,642 |
0.44% |
4.75% |
0.02% |
|
|
|
|
|
|
|
|
|
|
|
|
COMMON EQUITY |
50,449,234 |
(2,248,022) |
48,201,212 |
|
(27,262,453) |
20,938,759 |
35.39% |
11.25% |
3.98% |
|
|
|
|
|
|
|
|
|
|
|
|
CUSTOMER DEPOSITS |
4,094,408 |
|
4,094,408 |
|
|
4,094,408 |
6.92% |
6.28% |
0.43% |
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED TAXES |
6,253,275 |
|
6,253,275 |
2,992,338 |
|
9,245,613 |
15.63% |
0.00% |
0.00% |
|
|
|
|
|
|
|
|
|
|
|
|
TAX CREDIT - ZERO COST |
0 |
|
0 |
|
|
0 |
0.00% |
0.00% |
0.00% |
|
|
|
|
|
|
|
|
|
|
|
|
TAX CREDIT - OVERALL COST |
276,563 |
|
276,563 |
|
|
276,563 |
0.47% |
9.28% |
0.04% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
$117,740,494 |
($2,248,022) |
$115,492,472 |
$2,992,338 |
($59,313,136) |
$59,171,674 |
100% |
|
7.62% |
|
FLORIDA PUBLIC UTILITIES COMPANY |
|
ATTACHMENT 3 |
||||
|
DOCKET NO. 040216-GU |
|
|
|
|
Page 1 of 2 |
|
|
PTY 12/31/05 |
||||||
|
|
|
|
COMPANY |
|
STAFF |
|
|
|
|
|
|
|
|
|
|
ISSUE |
|
TOTAL |
COMPANY |
COMPANY |
STAFF |
STAFF |
|
NO. |
|
PER BOOKS |
ADJS. |
ADJUSTED |
ADJS. |
ADJUSTED |
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES |
|
|
|
|
|
|
|
Base Revenues |
17,717,851 |
|
|
|
|
|
|
Fuel |
36,236,758 |
(36,236,758) |
|
|
|
|
|
Conservation |
2,136,828 |
(2,136,828) |
|
|
|
|
|
Unbundling |
0 |
|
|
|
|
|
|
Gross Receipts Tax |
1,402,286 |
|
|
|
|
|
|
Franchise Tax |
1,346,194 |
|
|
|
|
|
|
Other Operating Revenues |
2,674,539 |
|
|
|
|
|
|
Area Expansion Program |
|
(572,646) |
|
|
|
|
22 |
Add pool manager revenue |
|
|
|
3,600 |
|
|
|
|
|
|
|
|
|
|
|
TOTAL REVENUES |
61,514,456 |
(38,946,232) |
22,568,224 |
3,600 |
22,571,824 |
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COST OF GAS |
36,055,579 |
(36,055,579) |
|
|
|
|
|
CONSERVATION |
2,126,144 |
(2,126,144) |
|
|
|
|
|
STORAGE & UNBUNDLING |
15,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATION & MAINTENANCE EXPENSE |
14,779,699 |
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
Decrease for overhead cost allocations (various) |
|
|
|
(155,692) |
|
|
24 |
Remove nonrecurring expenses (877, 921, 923) |
|
|
|
(78,127) |
|
|
25 |
Decrease for new positions (various) |
|
|
|
(69,932) |
|
|
26 |
Decrease for Fleet Image Improvement Prog.(874) |
|
|
|
(7,020) |
|
|
27 |
Decrease for meter change outs (878) |
|
|
|
(47,531) |
|
|
28 |
Remove tax credits-company use gas (903, 905) |
|
|
|
12,630 |
|
|
29 |
Decrease bad debt expense (904) |
|
|
|
(34,411) |
|
|
30 |
Decrease for nonutility advertising (912) |
|
|
|
(1,335) |
|
|
31 |
Decrease cooperative & duplicative ads (913) |
|
|
|
(91,357) |
|
|
32 |
Remove payroll increase (920) |
|
|
|
(10,400) |
|
|
33 |
Decrease for relocation & temporary help (921) |
|
|
|
(17,828) |
|
|
34 |
Decrease for duplicate fees & audit (923, 930) |
|
|
|
(18,571) |
|
|
35 |
Decrease for allocation of Acct. 926 |
|
|
|
(14,626) |
|
|
36 |
Decrease OPEB (926) |
|
|
|
(11,886) |
|
|
37 |
Decrease pension expense (926) |
|
|
|
(26,645) |
|
|
38 |
Decrease for rate case expense (928) |
|
|
|
(41,646) |
|
|
39 |
Decrease for membership dues (930) |
|
|
|
(3,213) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL O & M EXPENSE |
52,977,352 |
(38,181,723) |
14,795,629 |
(617,590) |
14,178,039 |
REVISED 10/18/04
|
FLORIDA PUBLIC UTILITIES COMPANY |
COMPARATIVE NOIs |
|
|
ATTACHMENT 3 |
||
|
DOCKET NO. 040216-GU |
|
|
|
|
Page 2 of 2 |
|
|
PTY 12/31/05 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
COMPANY |
||||
|
|
|
|
|
|
|
|
|
ISSUE |
|
TOTAL |
COMPANY |
COMPANY |
STAFF |
STAFF |
|
NO. |
|
PER BOOKS |
ADJS. |
ADJUSTED |
ADJS. |
ADJUSTED |
|
|
|
|
|
|
|
|
|
|
DEPRECIATION |
2,791,858 |
|
|
|
|
|
|
Include deferred gain |
|
120,420 |
|
|
|
|
|
Remove bare steel depreciation |
|
(5,449) |
|
|
|
|
|
Remove non-regulated depreciation |
|
(78,954) |
|
|
|
|
3 |
South Florida Operations Center (390) |
|
|
|
(396) |
|
|
4 |
Sanford Office Building & Land |
|
|
|
(2,542) |
|
|
5 |
Plant additions |
|
|
|
(26,846) |
|
|
6 |
Plant retirements |
|
|
|
(2,445) |
|
|
7 |
Inactive service lines |
|
|
|
(4,045) |
|
|
40 |
Change in depreciation rates |
|
|
|
154,289 |
|
|
|
|
|
|
|
|
|
|
|
AMORTIZATION |
568,823 |
|
|
|
|
|
8 |
Include bare steel amortization |
|
377,538 |
|
188,770 |
|
|
9 |
Include acquisition adj. amortization |
|
99,726 |
|
(67,713) |
|
|
|
Include environmental amortization |
|
456,350 |
|
|
|
|
|
Remove AEP amortization |
|
(569,783) |
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL DEPRECIATION & AMORTIZATION |
3,360,681 |
399,848 |
3,760,529 |
239,072 |
3,999,601 |
|
|
|
|
|
|
|
|
|
|
TAXES OTHER THAN INCOME |
|
|
|
|
|
|
41 |
Payroll taxes |
545,736 |
|
|
(6,724) |
|
|
|
Gross receipts, franchise fees |
1,402,286 |
|
|
|
|
|
|
Franchise fees |
1,346,194 |
|
|
|
|
|
|
Miscellaneous & emergency excise tax |
(3,676) |
|
|
|
|
|
41 |
Property tax |
1,068,026 |
|
|
(140,166) |
|
|
41 |
Regulatory Assessment Fee |
300,880 |
(194,726) |
|
6,710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL TAXES OTHER THAN INCOME |
4,659,446 |
(194,726) |
4,464,720 |
(140,180) |
4,324,539 |
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE |
|
|
|
|
|
|
|
Income taxes - current & deferred |
(688,670) |
(364,872) |
|
|
|
|
|
Investment tax credit |
(40,331) |
|
|
|
|
|
42 |
Tax effect of adjustments |
|
|
|
196,541 |
|
|
42 |
Interest Synch/Rec. Adj. |
|
|
|
82,832 |
|
|
42 |
Increase for permanent differences |
|
|
|
3,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL INCOME TAXES |
(729,001) |
(364,872) |
(1,093,873) |
282,730 |
(811,143) |
|
|
|
|
|
|
|
|
|
|
TOTAL OPERATING EXPENSES |
60,268,478 |
(38,341,473) |
21,927,005 |
(235,967) |
21,691,037 |
|
|
|
|
|
|
|
|
|
|
NET OPERATING INCOME |
1,245,978 |
(604,759) |
641,219 |
239,567 |
880,787 |
|
|
|
|
|
|
FLORIDA PUBLIC UTILITIES COMPANY |
ATTACHMENT 4 |
||
|
DOCKET NO. 040216-GU |
|
||
|
PTY 12/31/05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPANY |
|
|
|
DESCRIPTION |
PER FILING |
|
STAFF |
|
|
|
|
|
|
REVENUE REQUIREMENT |
100.0000% |
|
100.0000% |
|
|
|
|
|
|
GROSS RECEIPTS TAX RATE |
0.0000% |
|
0.0000% |
|
|
|
|
|
|
REGULATORY ASSESSMENT RATE |
0.5000% |
|
0.5000% |
|
|
|
|
|
|
BAD DEBT RATE |
0.4000% |
|
0.3300% |
|
|
|
|
|
|
NET BEFORE INCOME TAXES |
99.1000% |
|
99.1700% |
|
|
|
|
|
|
STATE INCOME TAX RATE |
5.5000% |
|
5.5000% |
|
|
|
|
|
|
STATE INCOME TAX |
5.4505% |
|
5.4544% |
|
|
|
|
|
|
NET BEFORE FEDERAL INCOME TAXES |
93.6495% |
|
93.7157% |
|
|
|
|
|
|
FEDERAL INCOME TAX RATE |
34.0000% |
|
34.0000% |
|
|
|
|
|
|
FEDERAL INCOME TAX |
31.8408% |
|
31.8633% |
|
|
|
|
|
|
REVENUE EXPANSION FACTOR |
61.8087% |
|
61.8523% |
|
|
|
|
|
|
NET OPERATING INCOME MULTIPLIER |
1.6179 |
|
1.6168 |
REVISED 10/18/04
|
|
COMPARATIVE REVENUE DEFICIENCY CALCULATIONS |
|
|||
|
|
|
ATTACHMENT 5 |
|||
|
DOCKET NO. 040216-GU |
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
COMPANY |
|
|
|
|
|
|
ADJUSTED |
|
STAFF |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RATE BASE (AVERAGE) |
|
$65,835,209 |
|
$59,171,674 |
|
|
|
|
|
|
|
|
|
RATE OF RETURN |
|
X |
8.66% |
X |
7.62% |
|
|
|
|
|
|
|
|
REQUIRED NOI |
|
|
$5,701,329 |
|
$4,508,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
$22,568,224 |
|
$22,571,824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation & Maintenance |
|
14,795,629 |
|
14,178,039 |
|
|
|
|
|
|
|
|
|
Depreciation & Amortization |
|
3,760,529 |
|
3,999,601 |
|
|
|
|
|
|
|
|
|
Amortization of Environ. Costs |
|
0 |
|
0 |
|
|
|
|
|
|
|
|
|
Taxes Other than Income Taxes |
|
4,464,720 |
|
4,324,539 |
|
|
|
|
|
|
|
|
|
Income Taxes |
|
|
(1,093,873) |
|
(811,143) |
|
|
|
|
|
|
|
|
Total Operating Expenses |
|
|
21,927,005 |
|
21,691,037 |
|
|
|
|
|
|
|
|
ACHIEVED NOI |
|
|
641,219 |
|
880,787 |
|
|
|
|
|
|
|
|
NET REVENUE DEFICIENCY |
|
5,060,256 |
|
3,628,094 |
|
|
|
|
|
|
|
|
|
REVENUE TAX FACTOR |
|
1.6179 |
|
1.6168 |
|
|
|
|
|
|
|
|
|
TOTAL REVENUE DEFICIENCY |
|
$8,186,989 |
|
$5,865,903 |
|