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DATE: |
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TO: |
Office of Commission Clerk (Cole) |
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FROM: |
Office of the General Counsel (Klancke, Barrera, Young) Division of Regulatory Analysis (Clemence, Ma) Division of Safety, Reliability & Consumer Assistance (Vickery) |
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RE: |
Docket No. 110138-EI – Petition for increase in rates by Gulf Power Company. |
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AGENDA: |
02/27/12 – Special Agenda – Post hearing decision; participation is limited to Commissioners and Staff |
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COMMISSIONERS ASSIGNED: |
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PREHEARING OFFICER: |
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SPECIAL INSTRUCTIONS: |
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FILE NAME AND LOCATION: |
S:\PSC\ECR\WP\110138.RCM.DOC |
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Issue Description Page
1 Proposal to calculate deferred carrying charge (Klancke, Barrera, Young, Breman)
8 Environmental Cost Recovery Clause (Wu)
9 Plant Crist Units 6 and 7 Turbine Upgrade Project (Wu, Slemkewicz)
10 Adjustments to remove all non-utility activities (Kaproth, Gardner)
12 Incentive Compensation expenses (Kaproth)
14 Transmission Infrastructure Replacement Projects (Ma)
16 Wireless systems of Southern Company Services (Gardner)
17 SouthernLINC charges of SCS (Kaproth)
18 Requested level of Plant in Service (Kaproth, Gardner)
21 Requested level of Accumulated Depreciation (Slemkewicz, Ollila)
22 Requested Construction Work in Progress (Gardner, Kaproth)
23 Plant Held for Future Use for Caryville Plant (Gardner)
24 North Escambia Nuclear County Plant Site (Gardner)
25 Requested level of Property Held for Future Use (Gardner, Kaproth)
27 Requested storm damage reserve (L'Amoreaux, Gardner, Kaproth)
28 Unamortized rate case expense (Kaproth)
30 Requested level of working capital (Kaproth, Gardner)
31 Requested rate base (Gardner, Kaproth)
32 Accumulated deferred taxes (Springer, Cicchetti)
33 Unamortized investment tax credits (Springer, Cicchetti)
37 Appropriate return on equity (Buys, Cicchetti)
38 Appropriate weighted average cost of capital (Springer, Cicchetti)
39 Non-regulated affiliates (Trueblood, Mouring)
40 Compensation payment from non-regulated companies (Trueblood, Mouring)
41 Adjustments to increase test year revenue (Trueblood, Mouring)
42 Projected level of total operating revenues (Mouring)
47 Adjustments to remove all non-utility activities (Mouring)
48 Transactions with affiliates (Mouring)
49 Adjustments made to expenses (Trueblood)
51 Adjustments to allocation factors used (Trueblood)
52 Cost associated with SouthernLINC (Trueblood)
55 Costs associated with Work Orders (Mouring)
56 Costs related to Work Order 471701 (Mouring)
57 Costs related to Work Order 473401 (Trueblood)
59 Costs related to Work Order 4Q51RC (Trueblood)
60 Public relations expenses charged by SCS (Mouring)
61 Removal of legal expenses charged by SCS (Trueblood)
64 Removal of investor relations expenses (Trueblood)
66 Interest on deferred compensation (Trueblood)
67 SCS Early Retirement Costs (Wright)
69 Proposed increases to average salaries (Wright)
70 Proposed increases in employee positions (Wright)
71 Proposed Incentive Compensation expenses (Wright)
72 Appropriate amount of allowance for employee benefit expense (Wright)
74 Requested level of Salaries and Employee Benefits (Wright)
76 Appropriate amount of accrual for storm damage (L'Amoreaux, Slemkewicz)
77 Director's & Officer's Liability Insurance expense (Mouring)
79 Tree trimming expense (L'Amoreaux)
84 Appropriate amount of production plant O&M expense (Ma)
86 Appropriate amount of distribution O&M expense (L'Amoreaux, Ma)
88 Appropriate amount of Rate Case Expense (Mouring)
89 Appropriate amount of uncollectible expense (Trueblood)
90 Requested level of O&M Expense (Mouring)
91 Appropriate amount of depreciation and fossil dismantlement expense (Ollila)
92 Requested level of Depreciation and Amortization Expense (Mouring, Ollila)
93 Appropriate amount of Taxes Other Than Income Taxes (Mouring)
94 Parent debt adjustment (Springer, Cicchetti)
95 Appropriate amount of Income Tax expense (Mouring, Springer, Cicchetti)
96 Requested level of Total Operating Expenses (Mouring)
97 Projected Net Operating Income (Mouring)
98 Appropriate revenue expansion factor & net operating income multiplier (Mouring)
99 Requested annual operating revenue increase (Mouring)
Cost of Service and Rate Design
109 Appropriate customer charges (Draper)
110 Appropriate demand charges (Draper)
111 Appropriate energy charges (Draper)
112 Appropriate charges for outdoor service (OS) lighting rate schedules (Kummer)
113 Proposal to adjust annually existing lighting fixtures prices (Kummer)
114 Standby and Supplementary Service (SBS) rate schedule (Draper)
115 Appropriate transformer ownership discounts (McNulty)
117 Interim rate increase (Mouring, Slemkewicz)
119 Close Docket (Klancke, Barrera, Young)
This proceeding commenced on July 8, 2011, with the filing of a petition for a permanent rate increase by Gulf Power Company (Gulf or Company). The Company is engaged in business as a public utility providing electric service as defined in Section 366.02, Florida Statutes (F.S.), and is subject to the Commission’s jurisdiction. Gulf serves more than 431,000 retail customers in 8 counties in Northwest Florida.
Gulf requested an increase in its base rates and charges to generate $93,504,000 in additional gross annual revenues. This increase would allow the Company to earn an overall rate of return of 7.05 percent or an 11.70 percent return on equity (range 10.70 percent to 12.70 percent). The Company based its request on a projected test year ending December 31, 2012. Gulf also requested an interim rate increase in its base rates and charges to generate $38,549,000 in additional gross annual revenues. The Company based its interim request on a historical test year ended March 31, 2011.
Pursuant to a stipulation approved in Order No. PSC-11-0553-FOF-EI,[1] Gulf filed supplemental testimony on November 8, 2011, for an additional base rate increase of $8,104,000 for the inclusion of the Crist Units 6 and 7 turbine upgrade projects in the instant proceeding. As a result, Gulf’s total requested base rate increase was revised to $101,608,000.
Pursuant to Sections 366.06 and 366.071, F.S., by Order No. PSC-11-0382-PCO-EI, issued September 12, 2011, the Commission suspended Gulf’s proposed permanent rate schedules pending further review, and authorized an interim rate increase of $38,549,000.
The Office of Public Counsel (OPC), Federal Executive Agencies (FEA), Florida Retail Federation (FRF), and Florida Industrial Power Users Group (FIPUG) intervened in this proceeding.
Customer service hearings were held in Pensacola and Panama City on September 15, 2011. A total of 79 customers presented testimony at the two customer service hearings. The technical hearing was held December 12-15, 2011, in Tallahassee. At the start of the hearing, the following stipulated issues as listed in Prehearing Order No. PSC-11-0564-PHO-EI were approved: 2, 3, 4, 5, 6, 7, 15, 19, 20, 26, 34, 35, 36, 43, 44, 45, 46, 53, 58, 65, 68, 73, 75, 78, 85, 100, 101, 102, 103, 104, 105, 116, and 118. After the conclusion of the hearing, a Motion for Approval of Partial Settlement Agreements[2] was filed by the parties to drop Issues 11, 62, 63, 80, and to settle Issues 106, 107, and 108. Subsequently, the proposed settlement agreements were approved at the January 10, 2012 Commission Conference.
The Commission has jurisdiction over these matters pursuant to Sections 366.06 and 366.071, F.S.
Does Section 366.93, Florida Statutes, support Gulf's proposal to calculate a deferred carrying charge for the 4,000 acre Escambia Site and the costs of associated evaluations as nuclear site selection costs?
Recommendation:
No. Section 366.93, F.S., and Rule 25-6.0423, Florida Administrative Code (F.A.C.), establish a threshold criteria that Gulf must satisfy before it can calculate a deferred carrying charge for the 4,000 acre Escambia Site and the costs of associated evaluations as nuclear site selection costs. Gulf has not satisfied the threshold criteria that it must obtain a Commission order granting a determination of need for a nuclear power plant and must petition the Commission for authorization to use the alternative deferred accounting treatment for the expenses associated with the 4,000 acre Escambia Site and the costs associated with the evaluations as nuclear site selection costs. (Klancke, Barrera, Young, Breman)
Position of the Parties
Yes. Under the rule promulgated by the Commission pursuant to Section 366.93, Gulf is authorized to accrue a carrying charge on the cost of acquiring the Escambia site and the cost of the associated evaluations prior to any need determination.
OPC:
Rule 25-6.0423, F.A.C., authorizes a utility to defer accounting treatment of nuclear site selection costs and accrue carrying charges until recovered in rates after the Commission awards an affirmative determination of need for the unit. However, the rule does not contemplate a situation in which a utility attempts to combine this authority to accrue carrying charges with an effort to short-circuit the determination of need requirement and build such costs into a general rate case. Allowing this would lead, absurdly, to enabling Gulf to collect site selection costs years in advance of the extraordinary advanced recovery mechanism authorized by the Legislature, without ever having proven the need for the unit that is a prerequisite to collecting carrying charges.
FIPUG:
No. Section 366.93, Florida Statutes, explicitly provides for special treatment, including extraordinary advance cost recovery mechanism, for utilities that have applied for and received a determination of need for a nuclear unit. Section 366.93 does not authorize a utility that has not received a determination of need to apply a deferred charge to land that it claims is a potential future nuclear site many, many years later. This item should be removed from rate base.
FRF:
No.
FEA:
FEA strongly disagrees with Gulf’s position that the land purchase expenses can be included in the current rate case.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf Power Company (Gulf)
Gulf argued that under the rule promulgated by the Commission pursuant to Section 366.93, F.S., it is authorized to accrue a carrying charge on the cost of acquiring the Escambia Site and the cost of the associated evaluations prior to any need determination ($27,687,000). Gulf asserted that under Rule 25-6.0423(2)(e), F.A.C., a site is deemed to be selected upon the filing of a need determination petition. (Gulf BR 7) Gulf contended that costs incurred prior to the filing of the need petition are “site selection costs” under subsection (2)(f), while costs incurred after the filing are “pre-construction costs” under subsection (2)(g). (Gulf BR 7) Thus, the cost of acquiring the Escambia Site and the cost of the associated evaluations prior to any need determination should be deemed site selection costs because these costs have been incurred and Gulf has not filed a petition for a determination of need. Gulf contended because these cost are site selection costs under Rule 25-6.0423(2)(e), F.A.C., it is entitled to deferred accounting treatment pursuant to Rule 25-6.0423(3), F.A.C. Rule 25-6.0423(3), F.A.C., states that site selection costs shall be afforded deferred accounting treatment and shall accrue a carrying charge equal to the utility’s AFUDC rate until recovered in rates.
Office of Public Counsel (OPC)
OPC contended that Rule 25-6.0423, F.A.C., authorizes a utility to defer accounting treatment of nuclear site selection costs and accrue carrying charges until recovered in rates only after the Commission awards an affirmative determination of need for the unit. The rule does not contemplate a situation in which a utility attempts to combine this authority to accrue carrying charges with an effort to short-circuit the determination of need requirement and build such costs into a general rate case. (OPC BR 4) OPC asserted that allowing this would lead, absurdly, to enabling Gulf to collect site selection costs years in advance of the extraordinary advanced recovery mechanism authorized by the Legislature, without ever having proven the need for the unit that is a prerequisite to collecting carrying charges. (OPC BR 4) OPC contended that they are “alternative and mutually exclusive cost recovery mechanisms, not intersecting, mix-and-match cost recovery mechanisms.” (OPC BR 5) OPC asserted that Gulf’s request would abuse the provisions of Section 366.93, F.S., Rule 25-6.0423, F.A.C., and the Commission’s general rate making authority. Simply put, OPC argued that Gulf wants to thwart ratemaking policy, not implement it. (OPC BR 5) OPC contended that Gulf’s proposal attempts to short circuit the alternative “collection in advance” mechanism in hopes of the Commission allowing it to collect charges now that it may never be entitled to collect under the provision that both provides the authority for the accrual and prescribes the time and manner of its collection. (OPC BR 5)
OPC argued that any fair reading of the applicable provisions establishes that Rule 25-6.0423, F.A.C., is inextricably intertwined with the “determination of need” portion of the Power Plant Siting Act. (OPC BR 6) OPC contended that if Gulf, or any utility, seeks to invoke subsection (3) of Rule 25-6.0423, F.A.C., and accrue a carrying charge based on designating a property as a nuclear site, it would be unable to reflect those costs in rates through the alternative mechanism the Legislature provided until after the Commission has granted an affirmative determination of need for the nuclear unit. (OPC BR 6) OPC also argued that for the Commission to act otherwise and permit the collection of costs before the site has been officially “selected” would enable any utility to declare a piece of property to be a “nuclear site,” regardless of how serious (or non-serious) it is about actually constructing a nuclear unit. (OPC BR 6)
OPC also argued that if the Commission permits Gulf to continue accruing a carrying charge, the accrual must not affect its consideration of Gulf’s request to place the Escambia Site in rate base in this case. (OPC BR 7) OPC contended that because Gulf could not collect the accrued carrying charges unless and until the Commission awards an affirmative determination of need, there is no merit to the argument that the Commission should place the property in rate base to avoid an accumulation of carrying charges over time. (OPC BR 7) OPC asserted that the Commission should also make clear that any such accrual does not establish an asset or otherwise assure Gulf of ultimate recovery of the deferred costs, the prudence of which will not be evaluated until after the filing of a petition for determination of need (at which point the site will be “selected” for purposes of possible recovery) and the Commission issues a determination of need (at which time prudent site selection costs, and associated carrying costs, will be eligible for recovery). (OPC BR 7)
Florida Industrial Power Users Group (FIPUG)
FIPUG argued that Section 366.93, F.S., does not support Gulf's proposal to calculate a deferred carrying charge for the 4,000 acre Escambia Site and the costs associated with site evaluations as nuclear site selection costs. FIPUG contended that Section 366.93, F.S., explicitly provides for special treatment, including extraordinary advance cost recovery mechanism, for utilities that have applied for and received a determination of need for a nuclear unit. (FIPUG BR 2) FIPUG asserted that Section 366.93, F.S., does not authorize a utility that has not received a determination of need to apply a deferred charge to land that it claims is a potential future nuclear site many, many years later. Moreover, FIPUG argued that this item should be removed from rate base. (FIPUG BR 2)
Florida Retail Federation (FRF)
Similar to the other Intervenors, FRF maintained its position that Section 366.93, F.S., does not support Gulf's proposal to calculate a deferred carrying charge for the 4,000 acre Escambia Site and the costs associated with evaluations as nuclear site selection costs. FRF adopted the argument and analysis of OPC on this issue as set forth in OPC’s brief. (FRF BR 5)
Federal Executive Agencies (FEA)
FEA strongly disagreed with Gulf’s position that the land purchase expenses can be included in the current rate case. FEA contended that the law clearly bars Gulf’s ability to include the $27 million costs associated with the purchase of the property into the current rate case prior to a determination of need. (FEA BR 5) FEA asserted Section 366.93, F.S., completely contradicts Gulf’s argument that it may recover costs associated with the property purchase without first receiving a “determination of need.” (FEA BR 3-4) FEA argued that Section 366.63(3), F.S., clearly states, “After a petition for determination of need is granted, a utility may petition the commission for cost recovery as permitted by this section and commission rules.” (FEA BR 4) To date, Gulf has neither requested nor received a determination of need for either a nuclear or integrated gasification combined cycle power plant. (FEA BR 4) FEA contended that “Gulf witness Mr. M. L. Burroughs admitted that Gulf has no plan to request such a determination of need in the near future.” (FEA BR 4)
ANALYSIS
As explained below, staff believes the statute and rule do not support Gulf’s proposal because Gulf has not obtained a Commission order granting a need determination for a nuclear power plant pursuant to Section 403.519, F.S., and as required by Section 366.93, F.S.
Gulf Has Not Obtained a Determination of Need
Gulf witness Burroughs stated that Gulf identified the Escambia Site in north Escambia County as the only suitable site for a nuclear plant. (TR 758) The Escambia Site is also suitable for other generation technologies. (TR 758) Gulf witness Alexander explained that in 2007 Gulf began investigating the Escambia Site as a potential future power plant site. (TR 2210) On August 26, 2008, Gulf decided to purchase the Escambia Site. (TR 817, 2218, 2241, 2248, 2252) Witness Alexander asserted that the Escambia Site was “investigated and purchased to preserve a nuclear option for Gulf's customers because that option has such a high potential value to Gulf's customers and the site was unique.” (TR 2230)
Gulf did not assert it was engaged in nuclear power plant permitting or licensing actions, nor did Gulf assert it was seeking a determination of need for a nuclear power plant. (TR 769, 774, 2220, 2223, 2225, 2243-2244) Gulf witness Burroughs stated that Gulf did not have any planned development in the next ten years. (TR 769) Witness Burroughs stressed strategic planning concerns and Gulf’s desire to preserve a future nuclear power plant option as the basis for the actions taken and costs incurred. (TR 765) Gulf witness Alexander also stressed planning flexibility. (TR 2234-2235) Gulf witness Burroughs noted the following:
For me to be able to project out, we can’t do that. But we know we will have to make a decision come 2022 and we can’t wait ‘till then to do it. We have to be prepared in the next two, three, four years to make a decision what we’re going to do.
(TR 779) Gulf witness Alexander stated that “I can’t tell you for sure that we are going to build nuclear because there is so much uncertainty.” (TR 2244)
OPC witness Schultz stated Gulf had not filed for a determination of need. (TR 1535) FEA witness Meyer opined that Gulf had not obtained the necessary approvals required by Section 366.93, F.S. (TR 1764) Witness Schultz opined that the Gulf’s purchase of the Escambia Site was “based on nothing more than speculation that nuclear generation might be a viable option for its customers at some time in the future.” (TR 1536) FRF witness Chriss asserted that Gulf had not specified that the land would be used only for nuclear or integrated gasification combined cycle power plants. (TR 1306) Gulf did not rebut the assertions that it had not filed for, nor obtained an order granting a determination of need for a nuclear power plant.
Threshold Requirement
The absence of Gulf obtaining a need determination pursuant to Section 403.519, F.S., is significant because Section 366.93(3), F.S., establishes when a utility may avail itself of the alternative cost recovery mechanisms established by Section 366.93, F.S. Section 366.93(3), F.S., states, “After a petition for determination of need is granted, a utility may petition the commission for cost recovery as permitted by this section and commission rules.” (emphasis added)
Nevertheless, Gulf witness McMillan asserted that Gulf’s Escambia Site acquisition costs and deferred nuclear site selection costs through the end of 2011 were in accordance with Section 366.93, F.S. (TR 1079) Witness McMillan’s view was that Section 366.93, F.S., was applicable to Gulf’s request because the statute provided authorization to record a deferred return. (TR 2359, 2383-2384, 2385) He relied on the site selection cost definitions and accounting provisions in Rule 25-6.0423, F.A.C. (TR 1177-1178, 2386) Gulf witness Alexander further asserted that deferred carrying charges have been accrued monthly since January 2008 and will continue to be accrued until such time that these costs are included in rate base. (TR 2210)
Staff believes Gulf witnesses McMillan and Alexander fail to observe the plain language of Section 366.93, F.S., that places a statutory threshold criteria that Gulf obtain a Commission order granting a determination of need for a nuclear power plant before it can petition to take advantage of the alternative cost recovery mechanisms. Section 366.93(3), F.S., states, “After a petition for determination of need is granted, a utility may petition the commission for cost recovery as permitted by this Section and Commission rules.” (emphasis added) Thus, the alternative cost recovery mechanisms established by Section 366.93 F.S., are conditional based upon the Commission’s issuing a determination of need order for a nuclear power plant for Gulf. (OPC BR 22)
This statutory threshold criteria is also explicitly stated in Rule 25-6.0423(4), F.A.C., regarding site selection costs:
After the Commission has issued a final order granting a determination of need for a power plant pursuant to 403.519, F.S., a utility may file a petition for a separate proceeding, to recover prudently incurred site selection costs. This separate proceeding will be limited to only those issues necessary for the determination of prudence and alternative method for recovery of site selection costs of a power plant.
(Emphasis added) Thus, consistent with Section 366.93, F.S., Rule 25-6.0423, F.A.C., defers identification of a site as a nuclear power plant site until the Commission determines a nuclear power plant is needed pursuant to Section 403.519, F.S., and a utility has petitioned to recover prudently incurred site selection costs pursuant to Rule 25-6.0423(4), F.A.C.
Gulf argued that Rule 25-6.0423(2)(f), F.A.C., specifically defines site selection costs to be “costs that are expended prior to the selection of a site.” (Gulf BR 7) Rule 25-6.0423(2)(e), F.A.C., states “a site will be deemed to be selected upon the filing of a petition for a determination of need for a nuclear or integrated gasification combined cycle power plant pursuant to Section 403.519, F.S.” Reading these two sections of the rule together, witness McMillan believed that the rule addresses costs that are expended prior to filing a determination of need. (TR 1178; Gulf BR 8) Gulf witness McMillan asserted that Gulf’s Escambia Site acquisition costs and deferred nuclear site selection costs through the end of 2011 were in accordance with Section 366.93, F.S. (TR 1079) Witness McMillan clarified that Gulf relied on Rule 25-6.0423(3), F.A.C., in accruing carrying costs for pre-need site selection costs. (TR 1177-1178, 2386) Witness McMillan’s view was that Section 366.93, F.S., was important to Gulf’s request because the statute provided authorization to record a deferred return. (TR 2359, 2383-2384, 2385) Gulf argued that the rule authorizes the accrual of deferred carrying charges for both site selection costs and preconstruction costs. (Gulf BR 8)
Both Gulf’s brief and witness McMillan’s testimony fail to recognize that Section 366.93, F.S., and Rule 25-6.0423, F.A.C., are not permissive regarding when a site is deemed selected. If the Escambia Site were to be deemed selected without Gulf having obtained an order granting a determination of need petition, as proposed by Gulf, then the explicit rule language would be meaningless and confusing because there would not be any demonstration that a new nuclear power plant was needed to serve retail customers. Staff believes that using Gulf’s proposal, the provisions of Section 366.93, F.S., would become generally applicable to other instances where any utility can assert the potential for a site may be used at some future date for nuclear siting, regardless if a nuclear power plant need petition is filed, and approved or denied.
Staff believes the language in the statute and rule is clear and unambiguous by establishing a threshold criteria that limits consideration of deferred accounting treatment. Until an order is issued, pursuant to Rule 25-6.0423(2)(e), F.A.C., there are no site selection costs for consideration of deferred accounting treatment under subsection 25-6.0423(3), F.A.C. Thus, the statute and rule establish a threshold requirement for Gulf to have obtained a Commission order granting a determination of need for a nuclear power plant pursuant to Section 403.519 F.S. (OPC BR 6; FIPUG BR 2; FEA BR 4)
CONCLUSION
Rule 25-6.0423, F.A.C., is clear and unambiguous with respect to the timing criteria addressing when the provisions of Section 366.93, F.S., are ripe for Commission consideration. The threshold criteria requires Gulf to obtain an order granting a determination of need pursuant to Section 403.519, F.S. Consequently, Section 366.93, F.S., does not support Gulf’s proposal that its Escambia Site acquisition and evaluation costs are nuclear power plant site selection costs and that Gulf should be afforded deferred carrying charge on its Escambia Site costs.
Is Gulf's projected test period of the 12 months ending December 31, 2012 appropriate? (Category 2 Stipulation)
Approved Stipulation:
Gulf’s projected test period of the 12 months ending December 31, 2012 is appropriate.
Are Gulf's forecasts of Customers, KWH, and KW by Rate Class and Revenue Class for the 2012 projected test year appropriate? (Category 2 Stipulation)
Approved Stipulation:
Yes. Gulf’s forecasts of Customer, KWH, and KW by Rate Class and Revenue Class, for the 2012 projected test year are appropriate. Gulf’s econometric models and assumptions relied upon are reasonable and consistent with industry practice for developing its forecasts.
Are Gulf's estimated revenues from sales of electricity by rate class at present rates for the projected 2012 test year appropriate? (Category 2 Stipulation)
Approved Stipulation:
Gulf’s estimated revenues from sales of electricity by rate class at present rates for the projected 2012 test year are appropriate.
What are the appropriate inflation, customer growth, and other trend factors for use in forecasting the test year budget? (Category 2 Stipulation)
Approved Stipulation:
The appropriate inflation, customer growth and other trend factors for use in forecasting the test year budget are as follows:
a. Inflation:
2011 – 2.1%
2012 – 2.8%
b. Forecasted Composite Wage and Salary Increase Guidelines:
a. Exempt – 2.5%
b. Non-exempt – 2.5%
c. Covered – 2.25%
c. Customer Growth (Retail):
2012 – 1.2%
Is Gulf's proposed separation of costs and revenues between the wholesale and retail jurisdictions appropriate? (Category 2 Stipulation)
Approved Stipulation:
Gulf’s proposed separation of costs and revenues between the wholesale and retail jurisdictions is appropriate. Wholesale allocations are predominantly based upon the 12 MCP methodology with some revenues and expenses allocated upon the energy allocator. These methods are based upon cost causation and are consistent with the methodology used in Gulf’s prior rate case and approved by this Commission.
Is the quality and reliability of electric service provided by Gulf adequate? (Category 2 Stipulation)
Approved Stipulation:
The quality and reliability of electric service provided by Gulf is adequate.
Should the capitalized items currently approved for recovery through the Environmental Cost Recovery Clause (ECRC) be included in rate base for Gulf?
Recommendation:
No. Except for the Plant Crist Units 6 and 7 Turbine Upgrade Projects discussed in Issue 9, no other capitalized items should be moved from the ECRC into rate base. (Wu)
Position of the Parties
GULF:
Except for the Crist turbine upgrades discussed in Issue 9, no other costs should be moved from the ECRC into rate base.
OPC:
The Crist turbine upgrades are the only such items that OPC examined specifically and that OPC witness Donna Ramas recommended be treated as base rate – related. That said, as a general matter, and absent any countervailing consideration that would be to the detriment of customers, OPC favors placing capital items in rate base rather than cost recovery clauses.
FIPUG:
Yes. All capitalized items currently approved for recovery through the Environmental Cost Recovery Clause should be moved to rate base. Gulf should be required to clearly itemize such items so that they may be moved to rate base.
FRF:
Yes. Specifically, the reasonable and prudent costs of the Crist Turbine Upgrade Project should be included in rate base and recovered through base rates rather than through the Environmental Cost Recovery Clause. These costs should be included in rate base using the conventional average test year rate base methodology.
FEA:
FEA adopts the position of FIPUG.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf did not submit witness testimony on this issue. However, Gulf offered information that further clarifies and supports its position on this issue in its responses to staff’s interrogatories and its brief. (EXH 96, Gulf BR 9)
Intervenors OPC, FIPUG, FRF and FEA did not offer testimony, discuss the issue in their briefs or otherwise offer evidence on this issue.
ANALYSIS
Gulf did not propose to include in rate base any capitalized items currently recovered through the ECRC, except for the Plant Crist Units 6 and 7 Turbine Upgrade Projects (turbine upgrades) discussed in Issue 9. Gulf indicated in response to Staff’s Twelfth Set of Interrogatories, No. 140, that consistent with the treatment in Gulf’s last rate case, the Company believes it is reasonable and appropriate to continue recovering the capitalized ECRC items in the ECRC. (EXH 96) Gulf asserted that once a project has been in-service for 12 months, the impact on customers is essentially the same whether the costs are included in base rates or the clauses; therefore, it is reasonable and appropriate to continue to recover those costs through the clause. (EXH 96, BSP 268)
The determination of revenue requirements on projects included in the ECRC and on projects included in base rates essentially are calculated the same way. There is a slight difference in how the average investment balance is calculated. However, the difference in the averaging methodology is negligible. For calculating the average plant investment in the ECRC, the methodology used is to sum the prior month’s investment balance and the current month’s investment balance, and divide by two. For calculating the average plant investment in base rates, the methodology used is to sum the prior thirteen months of investment amounts and divide by thirteen. Therefore, after a capitalized project has been in-service for thirteen months, the project’s capital cost will be the same, and its impact on customers also will essentially be the same whether the costs are included in base rates or the ECRC. (EXH 106, BSP 573) As indicated by Gulf, the only adverse impact (to Gulf) that could occur by moving a project that has been in-service for twelve months from the ECRC into base rates relates to the timing of when recovery would begin under each cost recovery mechanism. For example, assuming a project were removed from the ECRC on December 31, 2011, and included in base rates that became effective on March 12, 2012, there would be no recovery of the project’s investment for 71 days, or 19 percent of the year. (EXH 106, BSP 574) However, staff would note that inclusion of projects in the ECRC allows the Company to earn an essentially “guaranteed” return on equity (ROE) on those projects. Inclusion of projects in base rates only provides the Company with the “opportunity” to earn its authorized ROE.
Section 366.8255(5), F.S., provides that “[r]ecovery of environmental compliance costs under this section does not preclude inclusion of such costs in base rates in subsequent rate proceedings, if that inclusion is necessary and appropriate. . .” Therefore, whenever deemed necessary and appropriate, a capitalized project currently recovered through the ECRC can be moved from the ECRC into base rates in a rate proceeding.
In its brief, Gulf argued that “Section 366.8255(5) does not preclude a shift of capitalized items out of the clause into base rates, if inclusion in base rates “is necessary and appropriate.” (Gulf BR 9) However, Gulf asserted that no party has provided testimony or evidence that such a shift is necessary and appropriate in this case, except for the turbine upgrades discussed in Issue 9. (Gulf BR 9)
Staff notes that the record in this proceeding has not established a compelling need to move any capitalized items currently in the ECRC into rate base, except for the turbine upgrades. Further, the record has demonstrated no harm to Gulf’s customers by Gulf continuing to recover those capitalized items through the ECRC. Based on the record in the case, staff believes that other than the turbine upgrades discussed in Issue 9, no other capitalized items should be moved from the ECRC into rate base.
CONCLUSION
Except for the Plant Crist Units 6 and 7 Turbine Upgrade Projects discussed in Issue 9, no other capitalized items should be moved from the ECRC into rate base.
Should the Plant Crist Units 6 and 7 Turbine Upgrade Projects be included in rate base and recovered through base rates, rather than through the Environmental Cost Recovery Clause? If so, what is the appropriate amount, if any, to be included in rate base and recovered through base rates?
Recommendation:
Yes. The Plant Crist Units 6 and 7 Turbine Upgrade Projects (turbine upgrades) should be included in rate base and recovered through base rates, rather than through the ECRC. Staff recommends using Gulf’s proposed step increase method to determine the appropriate amount to be included in rate base. Staff recommends the following adjustments to rate base and NOI for the 2012 test year: (1) increase plant in service by $29,396,000 ($30,424,000 system); (2) increase accumulated depreciation by $1,376,000 ($1,424,000 system); (3) increase depreciation expense by $934,000 ($967,000 system); and (4) decrease income taxes by $360,000 ($373,000 system). In addition, staff recommends a step increase of $4,021,905, effective on January 1, 2013, or the actual in-service date of the scheduled December 2012 upgrade, whichever is later, to capture the incremental full year impact associated with the portion of the turbine upgrades to be in-service in May and December 2012. The amount of the recommended step increase is subject to revision based on the Commission’s decisions in other issues. (Wu, Slemkewicz)
Position of the Parties
GULF:
Pursuant to the approved stipulation, the Crist 6 and 7 turbine upgrades should be included in rate base. This transition from ECRC to base rates involves significant investment going into service at two different dates during the test year. To allow a smooth transition and full cost recovery for the turbine upgrades beginning in 2013 without the need for additional proceedings, $58,747,000 (plant in service of $61,753,000 less accumulated depreciation of $3,006,000) [$60,802,000 system] should be included in rate base and recovered in base rates. To avoid recovering more than the 13-month average balance through rates during 2012, this should be accompanied by a one-time credit to the ECRC in 2012 effective the same day as the new base rates.
OPC:
The projects should be included in base rates using the traditional average test year approach. Effectively, Gulf wants to negate the stipulation to move the turbine upgrades from the ECRC to base rates by deforming and contorting the ratemaking process to accomplish the same “annual reset of factor” the upgrades would receive in the cost recovery clause. The Commission should reject the effort. In a base rate proceeding, the utility’s operations are viewed, revenue requirements are determined, and rates are set, on an overall rate base/ROR basis. Gulf presents no adequate justification for departing from this process, and there is no prejudice to Gulf in the conventional approach, as Gulf’s high earnings following its last rate case demonstrate vividly.
FIPUG:
The Crist Units 6 and 7 Turbine Upgrade Project should be included in rate base and recovered through base rates rather than in the Environmental Cost Recovery Clause. Such recovery should be based on traditional ratemaking principles, including application of a 1/13th average. However, if the Commission adopts Gulf’s position on this issue, FIPUG prefers Gulf’s alternative #1.
FRF:
Yes. The reasonable and prudent costs of the Crist Turbine Upgrade Project should be included in rate base and recovered through base rates rather than through the Environmental Cost Recovery Clause. These costs should be included in rate base using the conventional average test year rate base methodology.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
The Eligibility for Rate Base Inclusion
By stipulation filed October 28, 2011, in the ECRC docket and this docket and approved by the Commission in Order No. PSC-11-0553-FOF-EI,[3] Gulf and the other parties agreed that “recovery of the Crist 6 and 7 turbine upgrades through the ECRC should be discontinued on a prospective basis beginning with the ECRC recovery factors to be applied during 2012, and recovery on a prospective basis should be provided through the base rates.” All parties in this case agreed that the turbine upgrades should be included in this rate base proceeding.
The Appropriate Amounts for Rate Base Inclusion
Gulf
The transition in cost recovery of the turbine upgrades from the ECRC to base rates involves significant investments going into service at two different dates during the test year. The turbine upgrades consists of three projects: Crist Unit 7 High Pressure/Intermediate Pressure (HP/IP) upgrades which went in-service January 2010; Crist Unit 6 HP/IP upgrades which will be in-service May 2012; and Crist Unit 7 Low Pressure (LP) upgrades which will be in-service in December 2012.
Gulf witness McMillan offered two proposals regarding the appropriate method to calculate the amounts for rate base inclusion. His primary and preferred proposal is to include all three projects of the turbine upgrades in rate base as if they were in-service throughout the 2012 test year in setting base rates for 2012, and then to credit the revenue over-recovered in 2012 through base rates back to the customers through the ECRC for 2012. Witness McMillan’s alternative proposal is to set base rates for 2012 by including each of these three projects in rate base at their 13-month average balance, and then to implement a second increase to base rates on January 1, 2013, to reflect the remaining investment in the turbine upgrades in base rates. (TR 1112-1114) Witness McMillan testified that although the two proposals differ in their details, each is designed to afford fair ratemaking treatment to Gulf’s customers and to the Company, and the effect of these two proposals on Gulf and its customers is the same. (TR 1115) He indicated that Gulf prefers the primary proposal because it provides base rate stability by avoiding a second rate increase. (TR 1115)
Gulf witness McMillan argued that the Commission should not consider simply including an actual 13-month average balance in rate base, without making an allowance for the fact that all three projects of the upgrades will be completed in 2012. He asserted that unless some provision is made to include the full costs of the upgrades in rates in 2013 and beyond, the Commission would fail to recognize that Gulf will have incurred the full costs of, and customers will be receiving the full benefits from, all three projects of the turbine upgrades by 2013. (TR 1115) The Gulf witness further argued that the turbine upgrades provide significant fuel and capacity cost savings to customers, and thus it is only fair that beginning in 2013, Gulf should be allowed to recover the full cost of the projects’ investments, from which customers will be receiving the full benefits. (TR 1116) Witness McMillan asserted that if the Commission rejects Gulf’s primary and alternative proposals, and sets rates based on the 13-month average balance of the upgrades, Gulf would be forced to consider filing a separate limited proceeding during 2012 in order to recover its full cost of providing service beginning in January 2013. (TR 1116)
OPC
OPC opposed Gulf’s position on this issue. OPC asserted in its brief that each of Gulf’s proposals were intended to achieve the inclusion in rates of the annualized level of investment in the turbine upgrade projects that would have been realized in 2013 had the turbine upgrades remained in the ECRC. (OPC BR 9) OPC witness Ramas argued that there are, however, no compelling reasons to distort ratemaking procedures in this manner so as to allow for special treatment for the turbine upgrades. (TR 1499) She contended that to do so would be the equivalent of single issue ratemaking and would violate the matching principle. (TR 1499) She also asserted that Gulf had not presented compelling reasons that should cause the Commission to deviate from long-standing regulatory practices for the turbine upgrades. (TR 1499-1950) Witness Ramas requested that if the Commission accepts Gulf’s proposed treatment of the turbine upgrades, an additional adjustment to annualize the impacts on accumulated deferred income taxes should be made. (TR 1503)
FIPUG, FRF and FEA did not offer any testimony, discuss the issue in their briefs, or otherwise offer evidence on the issue.
ANALYSIS
The Eligibility for Rate Base Inclusion
Pursuant to the Commission-approved stipulation in the ECRC docket, staff believes that it is appropriate for Gulf to include the turbine upgrades in rate base and for this investment to be recovered through base rates rather than through the ECRC.
The Appropriate Amounts for Rate Base Inclusion
As part of its Plant Crist Units 4 through 7 Fuel Gas Desulfurization (scrubber) systems of the CAIR/CAMR/CAVR Compliance Program, which was approved by the Commission in Order No. PSC-07-0721-S-EI,[4] Gulf subsequently decided to install the Crist Units 6 and 7 turbine upgrades to offset increased station losses due to the installation of the scrubber. Gulf claimed that the turbine upgrades are part of the ECRC scrubber project.[5]
In the present proceeding, witness McMillan testified that performing the turbine upgrades in conjunction with the scrubber project was the most efficient decision.
If these turbine upgrades were performed independently of the scrubber project, they would have been required by environmental regulations to undergo a new source review analysis under the federal Clean Air Act as amended. This would likely have imposed additional costs on the turbine upgrades and could have precluded Gulf from undertaking them as stand-alone projects. Because of their direct tie to the scrubber projects, these turbine upgrades are different than normal maintenance and upgrade projects.
(TR 2370-2371)
The primary benefits associated with the turbine upgrades are the fuel savings derived from the improved heat rate on the units and the value of the additional 30 MW of capacity. (TR 1115-1116, 1129, EXH 23) The turbine upgrades appear cost-effective. For the period 2010 – 2021, the estimated total savings would be approximately $94 million, and the estimated savings in every year exceed the annual revenue requirement, which are approximately $75 million in total. (EXH 23)
With respect to the method used to determine the appropriate amounts of the turbine upgrades for rate base inclusion, Gulf witness McMillan believes that a fair ratemaking treatment to the Company and its customers should:
· Ensure that dollars collected from ratepayers during 2012 equal the amount that would be collected if the turbine upgrade projects were included in Gulf’s 2012 rate base at their 13-month average test year balance, and related depreciation expenses were included at their projected amount for the 2012 test year.
· Ensure that Gulf is also able to recover the full costs of these projects (both capital and expenses) beginning in 2013, after all three projects have been placed in service.
(TR 1112)
Gulf proposed two methods: annualization of the turbine upgrade investment in 2012, with a credit to the customers through the ECRC (primary and preferred method), and a step increase in 2013 (alternative). Witness McMillan testified that the primary proposal would be less confusing to the customers, but the alternative is more consistent with decisions that this Commission has made in the past for other companies. (TR 1171)
OPC opposed Gulf’s proposals. OPC witness Ramas asserted that through either of Gulf’s proposed methods for rate base inclusion, the Company would effectively accomplish the result that it would have realized had the turbine investments remained in the ECRC. (TR 1499) OPC argued that Gulf’s aim is to import clause-like treatment into setting base rates notwithstanding their ineligibility for this treatment, and the Commission should reject the attempt. (OPC BR 10)
Mismatching Issue
OPC witness Ramas argued that annualizing the turbine upgrade investments would result in a mismatch of test year investment, revenue, and costs, because the turbines are not to be completed until May and December of the test year. (TR 1499)
Gulf witness McMillan countered that there is no mismatch in the 2012 test year under either of the Company’s proposals because Gulf is not proposing to achieve full cost recovery before the turbine upgrades are completed. (TR 2152) He asserted that OPC witness Ramas would limit Gulf’s recovery in base rates to only the 13-month average test year amounts, which would ignore a substantial portion of the investment in these upgrade projects on a going-forward basis. (TR 2153) Gulf witness McMillan argued that this, in turn, would result in a mismatch in investment, revenue, and costs starting in 2013, when revenue would not be provided to support the full amount of Gulf’s investment in the turbine upgrades. (TR 2153; Gulf BR 12) Gulf witness McMillan further contended that witness Ramas’ proposed treatment would result in a mismatch of costs and benefits, since customers would be receiving the full benefits of the upgrades through lower fuel costs, but Gulf would be receiving a return on only a portion of the investment that generates those fuel savings. (TR 2153-2154, TR 2371; Gulf BR 12)
Staff notes that with either of Gulf’s proposals, the Company is not requesting a full annualization of the entire turbine upgrades that would result in rates collected before the two remaining component projects are completed. Gulf’s primary proposal contains a credit to the customers through the ECRC to address the “over-collection” in rates in 2012 associated with the Crist 6 HP/IP project to be in-service in May 2012 and Crist 7 LP project to be in-service in December 2012. Gulf’s alternative is to include the turbine upgrades at their 13-month average balance in rate base for the test year, and then to implement a subsequent year adjustment to recognize in rates the remaining investments in 2013 and forward. Staff believes that there would be no mismatch in terms of “being used and useful in providing service to” and “recovery of the associated investment from” Gulf’s customers.
In its brief, it appears that OPC raised the following argument for the first time, absent any cites to the record in its support:
If Gulf’s earned rate of return during 2013 falls within its authorized range, Gulf will by definition have recovered all costs, including the capital costs, associated with its investment in the turbine upgrades. This is because the turbine upgrades will be within the rate base to which Gulf will relate its net operating income to calculate its earned rate of return.
(OPC BR 10) While staff agrees that all three turbine upgrade projects will be in-service by 2013, the full investment in certain components (Crist 6 HP/IP and Crist 7 LP projects) of the upgrades will not be “within the rate base” if OPC’s recommendation is adopted. Under OPC’s recommended 13-month average approach, recognition in base rates is provided for less than half of the total turbine upgrade investments. (TR 2153; EXH 23) Hence, if OPC’s recommendation is adopted, starting January 1, 2013, absent taking further action, Gulf will not be able to recover the full amount of its investments in the turbine upgrades.
No party contested whether the actual costs of the turbine upgrades are reasonable, appropriate, legitimate and not speculative. The record in this case indicates that the in-service portion of the upgrades has resulted in fuel savings, and 2012 will bring more savings to Gulf’s customers. (EXH 23) No party challenged the cost-effectiveness of the turbine upgrades. Staff believes that Gulf should be allowed to recover its full investments in the turbine upgrades once all three of its projects are placed in-service. This would ensure a matching of the investment, revenue, and costs starting in 2013 and forward. It would enable the Commission to properly recognize and implement the used and useful requirement prescribed by Section 366.06(1), F.S.; and treat the Company and its ratepayers equitably.
Policy Issue
OPC witness Ramas asserted that approving Gulf’s proposed treatments would cause the Commission to deviate from its long standing regulatory practices. (TR 1499) Gulf witness Deason countered that both of Gulf’s proposals are consistent with Commission policy. (TR 2155) He testified that:
the Commission has a policy of setting rates based on costs that are reasonably known to be incurred during the time that rates are to be in effect. The goal is to set rates on a going forward basis that will enable a utility to recover its costs and have a reasonable opportunity to actually achieve its authorized rate of return. The Commission has implemented this policy by various means, including adjustments for known and measurable changes and allowing subsequent year adjustment in rates.
(TR 2155)
Witness Deason further specified that the aforementioned Commission policy is reflected in statute:
Section 366.076(2), F.S., authorizes the Commission to adopt rules that provide for “adjustments of rates based on revenues and costs during the period new rates are to be in effect and for incremental adjustments in rates for subsequent periods.” The Commission adopted Rule 25-6.0435, F.A.C., to implement this statutory provision.
(TR 2155)
Witness Deason testified that the Commission’s authority to set rates on a going-forward basis has been addressed by the Florida Supreme Court. In a 1985 challenge to a Commission order granting FPL a rate increase for 1984 and a subsequent year adjustment for 1985, the court found:
At the heart of this dispute is the authority of [the] PSC to combat “regulatory lag” by granting prospective rate increases which enable utilities to earn a fair and reasonable return on their investments. We long ago recognized that rates are fixed for the future and that it is appropriate for [the] PSC to recognize factors which affect future rates and to grant prospective rate increase based on these factors.[6]
(TR 2156)
Gulf witness Deason asserted that OPC’s position on this issue, if adopted, would result in regulatory lag, which is the difference in time between when a change in rates is needed due to changes in costs, and when rate change can be implemented. (TR 2157) He stated that the current rate case is an appropriate vehicle to recognize the costs of the turbine upgrades. Ignoring the costs now and requiring Gulf to seek recovery by other means would only add an element of increased risk and additional regulatory costs, and this would not be in the customers’ best interest. (TR 2157)
Although the facts and circumstances were different in each proceeding, step or subsequent year increases have been authorized previously for Florida Power & Light Company,[7] Progress Energy Florida, Inc.,[8] and Tampa Electric Company.[9] Staff believes that both of Gulf’s proposed turbine upgrades ratemaking treatments have merit in terms of satisfying the used and useful requirement. Staff believes, however, that adopting a step increase, which is essentially the same as Gulf’s alternative, is more compatible with the Commission’s long standing regulatory practices concerning the authorization of such increases when warranted.
Tax-related Issue
OPC witness Ramas recommended that if the Commission agrees with one of Gulf’s proposed recovery methods, then an additional adjustment should be made to annualize the associated impacts on accumulated deferred income taxes. (TR 1503)
Gulf opposed this recommendation. Witness McMillan stated that he did not agree that it would be appropriate to adjust one component of the weighted cost of capital. (TR 2372) He testified that the turbine upgrade projects were originally removed from the capital structure on a pro rata basis, and should be added back on a pro rata basis, and the approved cost of capital in the test year is the appropriate cost to use for setting rates. (TR 2372) He argued that to adjust one source without reflecting the many other changes in the capital structure and the weighted cost of capital is not appropriate. (TR 2372) He further argued that to adjust or annualize one component of capital structure or deferred taxes associated with these turbine upgrade projects without also annualizing the other cost components of Gulf’s cost of capital is not appropriate. (TR 2376) Gulf witness Deason asserted that OPC witness Ramas’ recommendation was based on the premise that a portion of the deferred taxes could be traced as being invested in the turbine upgrades. Witness Deason asserted that this, however, was inconsistent with a position taken by OPC witness Woolridge who stated that sources of capital cannot be traced. (TR 2162)
Staff believes that if the Commission approves either of Gulf’s proposed rate base inclusion calculation methods, no additional adjustment is necessary to annualize any impacts on accumulated deferred income taxes for the turbine upgrades.
Based on the above, staff recommends the Commission approve a step increase in this case related to the turbine upgrades. Staff believes that this will enable the Commission to act within its discretion and seek to balance the public interest. While ratepayers will not be paying in 2012 the amount for the portion of the turbine upgrades that is not in-service, Gulf will recover, in 2013 and forward, the full amount of capital expenditures it is incurring to place the entire turbine upgrades into service. The step increase will enable recovery of the full cost of the turbine upgrades once all of the component projects are in-service. By 2013, the entire investment in the turbine upgrades will be in-service and result in significant fuel and capacity cost savings to the customers, and consequently, the Company should be allowed to recover the full costs associated with the projects. This satisfies the used and useful requirement prescribed by Section 366.06(1), F.S.; results in no mismatch of investment, revenue, and costs starting from January 2013; and, is consistent with Commission practice.
CONCLUSION
The Crist Units 6 and 7 Turbine Upgrade Projects should be included in rate base and recovered through base rates rather than through the ECRC.
To determine the appropriate amount to be included in rate base, a step increase method should be used. Staff recommends the following adjustments to rate base and NOI for the 2012 test year: (1) increase plant in service by $29,396,000 ($30,424,000 system); (2) increase accumulated depreciation by $1,376,000 ($1,424,000 system); (3) increase depreciation expense by $934,000 ($967,000 system); and (4) decrease income taxes by $360,000 ($373,000 system). In addition, staff recommends a step increase of $4,021,905, effective on January 1, 2013 or the in-service date of the December 2012 upgrade, whichever is later, to capture the incremental full year impact associated with the portion of the turbine upgrades to be in-service in May and December 2012. The calculation of the $4,021,905 step increase is shown on Schedule 6. The amount of the recommended step increase is subject to revision based on the Commission’s decisions in other issues.
Has Gulf made the appropriate adjustments to remove all non-utility activities from plant in service, accumulated depreciation and working capital?
Recommendation:
Yes.
The appropriate adjustments have been made to remove all non-utility activities in plant in service, accumulated depreciation and working capital by removing $12,518,000 from the Working Capital Allowance. Therefore, no additional adjustment is necessary to working capital. (Kaproth, Gardner)
Position of the Parties
GULF:
Yes. The Company has removed from rate base the investment, accumulated depreciation, and working capital amounts related to the Company’s non-utility activities.
OPC:
No. See OPC’s positions on Issues 16 and 17.
FIPUG:
No. See Issues 16 and 17.
FRF:
No.
FEA:
FEA adopts the position of FIPUG as described in Issues 16 and 17.
Staff Analysis:
PARTIES’ ARUGMENTS
Gulf
Gulf stated that Issues 16 and 17, which relate to wireless system investments, are not appropriate for consideration in Issue 10 because neither issue relates to non-utility activities. Further, Gulf stated that no Intervenor has presented any testimony or evidence on this issue. (Gulf BR 14)
Gulf further stated that non-utility activities of $12,518,000 have been removed on MFR Schedule B-1, Column (4), Line 8. This adjustment to remove the non-utility activities to arrive at the total electric utility amount of working capital is shown in MFR Schedule B-1, Column (5), and is discussed in Gulf’s response to Staff’s Fourteenth Set of Interrogatories, No. 172. (EXH 98)
OPC
In its brief, OPC referenced its positions on Issues 16 and 17 regarding adjustments to remove wireless system investments. (OPC BR 12)
FIPUG, FRF and FEA
In their briefs, FIPUG, FRF and FEA agreed with OPC. (FIPUG BR 3; FRF BR 7; FEA BR 6)
ANALYSIS
The analysis is detailed in Issue 16 (wireless system) and Issue 17 (SouthernLINC) and no adjustments are recommended in either issue. Therefore, no additional adjustment is recommended in Issue 10. The Company has appropriately removed non-utility activities of $12,518,000 on MFR Schedule B-1, Column (4), Line 8. (Gulf BR 14) Therefore, no additional adjustment is necessary to working capital.
DROPPED PER STIPULATION.
How much, if any, of Gulf's Incentive Compensation expenses should be included as a capitalized item in rate base?
Recommendation:
The appropriate amount of non-clause and non-CWIP capitalized incentive compensation to be included in rate base is $1,191,000 ($1,217,206 system). Capitalized incentive compensation of $1,191,000 ($1,217,206 system) should be removed from rate base because of inadequate supporting information or lack of an estimate supporting capitalized labor costs. Similarly, depreciation expense and accumulated depreciation should each be reduced by $42,049 ($42,967 system). (Kaproth)
Position of the Parties
GULF:
The entire $3,245,884 of Gulf’s variable compensation capitalized in the 2012 test year should be included in rate base. Gulf’s total compensation approach, including variable compensation, was approved in Gulf’s last case and remains the same. Gulf’s compensation program is appropriately targeted at the median of the market and has allowed Gulf to retain valuable and attract new employees necessary to serve customers. Gulf’s use of variable compensation aligns the interests of employees with customers and shareholders, making employees accountable for their performance. The interveners’ proposed disallowance lacks any market analysis; is based on an erroneous premise that variable compensation does not serve customers; and completely fails to account for the adverse effects of such a disallowance on customers.
OPC:
None. The projected test year incentive compensation should not be capitalized to rate base and should instead be funded by shareholders. The structure of Gulf’s incentive compensation plans focuses on shareholder benefits (earnings per share and rate of return) and should be funded by the shareholders, who are the beneficiaries when the plan goals are achieved. The large emphasis on shareholder benefits could be detrimental to the customer service provided. Consistent with prior Commission practice, the test year incentive compensation expense should be disallowed and should instead be funded by shareholders. The costs should not be funded by the ratepayers, especially in light of today’s economic climate. Plant in service should be reduced by $1,217,206 ($1,191,000 jurisdictional).
FIPUG:
Agree with OPC.
FRF:
None. Gulf’s incentive compensation expenses should be borne entirely by Gulf’s shareholders, whose interests the incentive plan is designed to promote, and not by consumers. Moreover, no incentive compensation, which is clearly an operating expense, should be capitalized.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf stated that it was difficult to quantify the precise amount of test year capitalized labor costs that was included in the 13-month average plant in service balance. (TR 1480) Gulf stated that it would take an excessive effort to determine the precise jurisdictional allocation by the use of the cost of service study. (EXH 115, Interrogatory No. 184, p. 15) Secondly, Gulf explained that the capital base payroll and capital variable payroll will affect the 13-month rate base and revenue requirement calculation to the extent that associated projects are excluded from rate base such as clause-related projects that are not part of interest bearing CWIP. Gulf provided the associated dollar amounts to base and variable payrolls and further explained the difficulty to quantify capital labor costs in Gulf’s response to staff’s Fourteenth Set of Interrogatories, No. 184. (EXH 115, No. 184, pp. 15-16)
OPC
Witness Ramas stated that $1,217,206 in capitalized incentive compensation for the projected test year should be removed. Witness Ramas pointed out that the Company did not provide an estimate of the capitalized labor costs in rate base. (EXH 115, No. 184, pp. 15-16) Therefore, witness Ramas used a 75 percent factor to determine the portion of the $3,245,884 capitalized incentive compensation that was included in rate base. Witness Ramas then applied a 50 percent factor to the $2,434,413 to determine an average amount of capitalized incentive compensation for the test year. After applying this factor, the appropriate reduction to plant in service in rate base would be $1,217,206. (EXH 35, Schedule C-4, p. 1 of 2) The corresponding reduction to depreciation expense and accumulated depreciation would be $42,967 at a rate of 3.53 percent.
FIPUG, FRF and FEA agreed with OPC. (FIPUG BR 3; FRF BR 7; FEA BR 6)
ANALYSIS
Gulf witness McMillan stated that it was difficult to determine the dollar amount of capitalized labor because the CWIP projects are not closed into plant in service until the project is completed which may not be in the test year. Therefore, it is difficult to quantify the precise amount of the capitalized payroll that is included in the test year 13-month average plant in service balance. (EXH 115, No. 184, p. 16) OPC witness Ramas pointed out that Gulf did not provide an estimate. Therefore, witness Ramas calculated the adjustment to plant in service using a 75 percent estimate for the capitalized labor costs and then dividing this amount by 50 percent to estimate a 13-month average test year balance. (EXH 35, Schedule C-4, page 1 of 2) This methodology resulted in the removal of capitalized incentive compensation of $1,217,206, and corresponding reductions to depreciation expense and accumulated depreciation of $42,967. (TR 1479) Gulf did not provide supporting documentation or an estimate of the capitalized labor costs associated with this investment. It is important to have an accurate estimate of the capitalized incentive compensation cost that is reasonable and verifiable if the Commission is to determine the appropriate amount to include in test year rate base and revenue requirement.
CONCLUSION
Staff recommends that $1,191,000 ($1,217,206 system) is the appropriate amount of capitalized incentive compensation to be included in rate base. Therefore, staff recommends that $1,191,000 ($1,217,206 system) of capitalized incentive compensation be removed from plant in service. Depreciation expense and accumulated depreciation should each be reduced by $42,049 ($42,967 system). These adjustments are necessary because Gulf has made no attempt to quantify the capitalized labor costs by any method or provide an estimate of their costs. This information is needed to determine eligibility for inclusion of such costs in the test year revenue requirement.
DROPPED.
What amount of Transmission Infrastructure Replacement Projects should be included in Transmission Plant in Service?
Recommendation:
The evidence in the record shows that the Transmission Infrastructure Replacement Projects are reasonable and prudent expenditures necessary to provide reliable electric service to its customers. Therefore, no adjustment to Transmission Plant in Service related to the Transmission Infrastructure Replacement Project Expense is necessary. (Ma)
Position of the Parties
GULF:
For the period 2006 through projected year-end 2012, $69,056,000 ($71,335,000 system) will have been placed in Transmission Plant in service for Transmission Capital Infrastructure Replacement projects. These costs cover both the replacement of failed equipment and structures and the proactive replacement of equipment and structures which have reached the end of their useful life. This amount represents Gulf’s actual cost of replacing this equipment and structures for the 2006 through 2010 period along with the projected cost for 2011 and 2012. These proactive transmission infrastructure replacements are developed and prioritized based on sound methodology and engineering analysis.
OPC:
The amount of transmission capital infrastructure replacement projects in Gulf’s filing, excluding SGIG projects, are substantially higher than average historical levels. Gulf’s 2011 budget for transmission infrastructure replacement projects ($15,948,000) is more than double the average historic level from 2003 through 2010 ($7.3 million). This average is higher than normal operating conditions, given the fact that several hurricanes impacted Gulf’s service territory, resulting in a higher level of transmission replacement projects during that period. Gulf’s budgeted 2011 and 2012 transmission infrastructure replacement projects should be replaced with the average historical actual amount. This results in $8,695,699 reduction to budgeted 2011 transmission capital additions and $2.4 million increase in the 2012 level, for a net decrease to plant of $7,502,049.
FIPUG:
Agree with OPC.
FRF:
Gulf’s plant in service for the 2012 test year should be reduced by $7,502,049.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
In his testimony, Gulf witness Caldwell explained that capital infrastructure replacement projects entail “routine replacements of poles, transformers, voltage regulation equipment, switches, conductors, and other assets.” (TR 492) Witness Caldwell also justified the budgeted capital investment through a detailed explanation of the transmission planning process Gulf employed to develop the overall amount. (TR 489-492) Historically, Gulf’s total transmission capital expenditures has grown from $7,872,873 in 2003 to $46,635,680 in 2010. (EXH 35) Gulf planned even greater increases in total expenditures for the 2011, 2012, 2013 budget years: $66,748,000, $70,902,000, and $88,540,000, respectively. (Schedule 5, EXH 14) In comparison, the transmission capital infrastructure replacement portion, excluding distribution substation replacements, has grown from $3,245,476 in 2003 to $13,552,702 in 2010. (Schedule B-2, EXH 205) Gulf budgeted approximately $15,948,000 in 2011, $4,865,000 in 2012, and $5,030,000 in 2013 for this specific item. (Schedule 5, EXH 14) The values are consistent with a gradual trend of annually-increasing costs up to 2010, with historical costs greater than the average since 2009. To explain the significant increase in capital budget starting in 2010, Gulf witness Caldwell asserted in his testimony that, “a significant amount of Gulf’s transmission assets were installed in the 1960 to 1980 time period and are now approaching or are at the end of their useful lives.” (TR 497) According to witness Caldwell, these components have been used beyond their expected lifespan and replacement is necessary to prevent disruptions in service. In response to concerns regarding the continued increase after 2011 in overall transmission costs, witness Caldwell noted in his rebuttal testimony that the Sinai-Callaway and Crist-Air Products transmission line projects in particular will require major repair and replacement, resulting in the relatively greater amounts starting in 2011. (TR 2464)
OPC
Issue 14 was raised by OPC in regards to transmission infrastructure replacement project expenses, which is a subset item of the Transmission Plant in Service. Additionally, transmission infrastructure replacement projects are divided into two categories: transmission and distribution substation projects. OPC asserted that Gulf’s budgeted amount for 2011 for transmission capital infrastructure replacement projects, excluding distribution substation replacements, is substantially higher than historical levels, and that the capital expense for this item should be reduced by $7,502,049. OPC witness Ramas justified this reduction by a series of calculations replacing the budgeted 2011 and 2012 expense amounts with an average of the historic expenses from 2003 to 2010 of $7,252,301. (TR 1456) This resulted in a $8,685,699 reduction to the 2011 budget and a $2,387,301 increase to the 2012 budget. Witness Ramas continued her calculations by taking half of the $2,387,301 increase for 2012 and combining it with the $8,685,699 reduction to 2011 for a net adjustment of $7,502,049. Witness Ramas explained, “in determining the amount of adjustment to plant in service, I have assumed that the projected 2012 expenditures are added evenly throughout the year.” (TR 1456) Although there is no official explanation or justification for the additional process, staff interpreted the most valid reason for this calculation to be an averaging of the adjusted 2012 value ($7,252,301) and the budgeted 2012 value ($4,865,000).
FIPUG, FRF and FEA agreed with OPC. (FIPUG BR 3; FRF BR 7; FEA BR 6)
ANALYSIS
Staff believes OPC’s method of calculating an adjusted expense for the Transmission Capital Infrastructure Replacements is not appropriate. Replacement capital costs depend heavily on the lifespan of the item and the incident of it being replaced, which cannot be represented by a trend of historical costs during a period when major replacements were not necessary. Therefore, the averaging of historical costs to predict expenses is not appropriate for capital costs. Averaging in such a method ignores any significant replacements that may be required for those particular years and necessary for reliable service.
Additionally, staff notes that OPC raised concerns regarding hurricanes that occurred during the 2003 to 2010 time period that could have caused greater costs for infrastructure replacements. (OPC BR 12) However, OPC has not produced any financial information to support this assertion.
Gulf provided information that supports the Company’s claim that the transmission infrastructure replacement projects are reasonable and prudent expenditures necessary to provide reliable electric service to its customers. No analyses, records, or discussions presented by OPC refute the legitimacy of Gulf’s items required for replacement that cause the significant rise in costs. Therefore, staff does not recommend any adjustment to Transmission Plant in Service related to Transmission Capital Infrastructure Replacement Projects.
CONCLUSION
Although OPC disputed that the total budgeted transmission amounts for 2011 and 2012 are significantly greater than historic levels, OPC’s method of analysis ignored the cost of specific transmission items outlined by Gulf that require replacement and repair. Furthermore, there is no substantial evidence presented by the intervenors that indicated the items of infrastructure replacements are not prudent and necessary. The evidence in the record shows that the Transmission Infrastructure Replacement Projects are reasonable and prudent expenditures necessary to provide reliable electric service to its customers. Therefore, staff does not recommend any adjustment to Transmission Plant in Service related to Transmission Capital Infrastructure Replacement Projects.
What amount of Distribution Plant in Service should be included in rate base? (Category 2 Stipulation)
Approved Stipulation:
Gulf’s requested level of Distribution Plant in Service, $1,029,829,000 ($1,034,325,000 system) should be reduced by $803,000 ($803,000 system) to reflect an error identified by the Company in the course of responding to discovery. The corrected amount of Distribution Plant in Service, $1,029,026,000 ($1,033,522,000 system) is appropriate to be included in rate base.
Should the wireless systems that are the subject of Southern Company Services (SCS) work orders be included in rate base?
Recommendation:
Yes. Staff recommends that the wireless systems that are the subject of the Southern Company Services work orders should remain in rate base. (Gardner)
Position of the Parties
GULF:
Yes. These wireless infrastructure costs are an integral part of Gulf’s communications system which is necessary and appropriate for inclusion in rate base.
OPC:
No. Work Order 46C805 for Wireless Systems relates to capital equipment purchases that were incurred after the conversion to Enterprise Solutions. After the conversion, it became necessary for Georgia Power (“GPC”) billing to flow through the SCS Work Order system and then get billed to the individual operating companies. This Work Order amounted to $2.2 million charged to Gulf, and was for capital equipment which should be offset with a reduction of direct bill materials from GPC. Gulf provided no documentation or other evidence that the savings that will offset these capital dollars have been reflected in the test year. In the absence of such a showing, $401,146 ($387,596 jurisdictional) should be removed from the test year.
FIPUG:
No. Agree with OPC.
FRF:
No. The Commission should reduce Gulf’s test year rate base by $387,596 on a retail jurisdictional basis ($401,146 system).
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan testified that Work Order 46C805 includes the material costs for a wireless system upgrade and replacement project. (Gulf BR 17, TR 2349) He contended that the capitalized material costs reflect the change in the Company’s billing procedures. (TR 2349) In his response to a discovery request, he stated that after Gulf had implemented the new accounting software (Enterprise Solutions), the cost of the wireless materials were billed by SCS to the Company rather than by Georgia Power Company (Georgia Power) as had been the arrangement previously. (Gulf BR 18, TR 2349, EXH 119, No. 266) He contended that Work Order 46C805 relates to material costs for wireless infrastructure improvements which includes wireless and supervisory control and data acquisition (SCADA), voice and data converged network, and power delivery technology improvements (distribution SCADA). (EXH 113, No. 26, TR 2349-2350)
OPC
OPC’s witness Dismukes referred to Gulf’s discovery response to Citizens’ Interrogatory No. 229, that acknowledged Work Order 46C805 is the billing for capital equipment required for Converge Networks projects. (EXH 117, No. 229) She stated that the billing occurred after the Company’s conversion to Enterprise Solutions. (TR 1632) This occurred because the billing flowed from Georgia Power Company Oakbrook warehouse through the SCS work order system, and then billed to the individual companies. (TR 1632) She argued that the Company provided no documentation or other evidence that there were savings that would offset the capital dollars for the test year. (TR 1632) Therefore, Work Order 46C805 material costs in the amount of $387,596 should be disallowed for the projected test year. (OPC BR 14 -15; TR 1632; EXH 117, No. 229)
The FIPUG, FRF, and FEA agreed with OPC’s position. (FIPUG BR 3; FRF BR 7; FEA BR 6)
ANALYSIS
Gulf witness McMillan testified that prior to the introduction of Enterprise Solutions, Georgia Power bought materials in bulk and stored them in a centrally located warehouse in Atlanta. These materials, including IT resources, were made available to the entire Southern Company. (TR 150, p. 58) Under this arrangement, Georgia Power billed each Southern Company subsidiary directly, including Gulf. After the introduction of Enterprise Solutions, SCS purchased the materials from the warehouse and began to bill the costs to the operating companies. The amount of the bill remained the same, the only difference was the operating companies, including Gulf, were billed by SCS instead of Georgia Power. (EXH 150, p. 58)
The wireless system is included under general plant additions as communication equipment. (EXH 113, No. 26) As stated by witness McMillan, the work order relates to materials that will continue to be necessary for the Company’s wireless infrastructure. Also, witness McMillan stated that the amount of the bill did not change. (TR 2349, Gulf BR 18)
Staff believes that although the billing arrangement changed, there would not necessarily be any savings if the materials were still needed and there was no change in the amount billed to Gulf.
CONCLUSION
In summary, staff recommends no adjustment is warranted related to Work Order 46C805. Also, staff believes that since the billing amount did not change and only the Southern Company affiliate that billed the amount changed, there would not necessarily be any savings. Therefore, staff recommends that the wireless systems that are the subject of the Southern Company Services work orders should remain in rate base.
Should the SouthernLINC charges that are the subjects of SCS work orders be included in rate base?
Recommendation:
Yes. The SouthernLINC capitalized charges of $79,141 that are the subject of SCS Work Order 48LC01 should be included in rate base. (Kaproth)
Position of the Parties
GULF:
Yes. The portion of the SouthernLINC charges that are booked to capital accounts are appropriately included in rate base. SouthernLINC provides unique communication services to Gulf that have no commercial comparison in the marketplace. These communication services support service crew work management, interoperability between transmission and distribution automation systems, and voice/data communication. SouthernLINC’s service characteristics are vital to Gulf’s operations and its ability to provide reliable and efficient service to its customers.
OPC:
No. Southern Company charges all affiliates for the total SouthernLINC Wireless charges that are not able to be recovered through commercial revenues, and in 2012, the charges to Gulf Power are projected to increase because of the “larger than anticipated drop in commercial customer revenue.” SouthernLINC is an unregulated affiliate, and its losses should not be subsidized by Gulf Power’s ratepayers. The Commission should remove $79,141 from the test year capital additions related to the expense reduction recommended in Issue 52.
FIPUG:
No. Agree with OPC.
FRF:
No. The Commission should remove $79,141 from Gulf’s 2012 test year rate base, because to allow these expenses to be included would force Gulf’s customers to subsidize losses incurred by SouthernLINC, an unregulated affiliate of Gulf Power.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf stated that the $79,141 in test year capital additions related to wireless connections should not be removed from rate base. These capital additions are documented by SouthernLINC as the items in SCS Work Order 48LC01 contain in Gulf’s response to Citizens’ Sixth Set of Interrogatories, No. 229. (EXH 117, pp. 9-10) Gulf included the $79,141 in FERC Account No. 397, Communication Equipment which is for wireless communication equipment. (TR 1643-1644) Account No. 397 includes the cost installed for wireless equipment for general use in connection with utility operations. The Company further explained that the wireless equipment is necessary for the SCS Work Order System and in the interoperability of the transmission and distribution system of the electric grid. (EXH 119, No. 265)
OPC
OPC believes the $79,141 in capitalized costs in rate base should be removed because it relates to the unregulated expense which is addressed in Issue 52. (TR 1631)
FIPUG, FRF, and FEA agreed with OPC. (FIPUG BR 3; FRF BR 8; FEA BR 6)
ANALYSIS
Gulf included $79,141 in FERC Account No. 397 related to wireless communication equipment. Gulf witness Jacobs testified that this equipment is needed to facilitate hurricane damage restoration and safety for the Gulf customers. (EXH 13, p. 30) He further noted that the Company needs to have a wireless work order system to facilitate the employees’ workload and to install additional smart grid equipment on its transmission and distribution systems. (EXH 119, No. 265) This interoperability service will enhance monitoring, switching, and fault location which provide enhanced service for Gulf’s customers. A detailed discussion of the appropriateness of the SouthernLINC charges in the 2012 test year is found in Issue 52. (Gulf BR 19)
CONCLUSION
Based on the record and consistent with the staff recommendation in Issue 52, the SouthernLINC capitalized charges of $79,141 that are the subject of SCS Work Order 48LC01 should be included in rate base.
Is Gulf's requested level of Plant in Service in the amount of $2,612,073,000 ($2,668,525,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. Based on staffs’ recommendations in other issues, the appropriate level of plant in service for the 2012 projected test year is $2,641,510,416 ($2,699,116,619 system). This is an increase to plant in service of $29,437,416 ($30,591,619 system). (Kaproth, Gardner)
Position of the Parties
GULF:
No. The appropriate level of Plant in Service for the 2012 test year is $2,672,964,000 ($2,731,576,000 system). This amount includes adjustments to Gulf’s original request to included the Crist 6 and 7 turbine upgrades (Issues 8 and 9) and to correct an ECCR adjustment error which includes the error in Distribution Plant in Service identified in the stipulation on Issue 15.
OPC:
No. OPC’s recommended plant in service includes adjustments related to transmission capital additions, the Crist turbine upgrade transfer to base rates, the incentive compensation capital additions and SCS work orders for Wireless Systems and LINC Charges. OPC’s adjustment related to the Smart Grid Investment Grant Program Projects has not been included. The resulting balance in plant in service should be no more than $2,625,391,000. Plant in service should be increased by $13,318,000 on a jurisdictional basis.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate level of Plant in Service for the 2012 test year is $2,625,391,000 on a retail jurisdictional basis.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
This is a fall-out issue. Based on staff’s recommendations in other issues, the appropriate level of plant in service for the 2012 projected test year is $2,641,510,416 ($2,699,116,619 system). This is an increase to plant in service of $29,437,416 ($30,591,619 system) as shown in Table 18-1 below.
Table 18-1
|
2012 Projected Test Year – Plant in Service - Jurisdictional |
||
|
Description |
Gulf |
Staff |
|
Plant in Service as filed |
$2,612,073,000 |
$2,612,073,000 |
|
Issue 9 Crist Units 6 & 7 Upgrade |
61,753,000 |
29,396,000 |
|
Issue 12 Capital Costs - Incentive Compensation |
0 |
(1,191,000) |
|
Issue 14 Transmission Infrastructure Replacements Project |
0 |
0 |
|
Issue 15 Stip. Distribution PIS |
(803,000) |
(803,000) |
|
Issue 16 Wireless Systems subject to SCS work orders |
0 |
0 |
|
Issue 17 Southern Link Charges Work Order No. 45LC01 |
0 |
0 |
|
Issue 22 CWIP issues impact PIS |
0 |
2,470,000 |
|
Issue 25 Property Held for Future Use |
0 |
167,847 |
|
Issue 44 ECCR Adjustment Error |
(59,000) |
(59,000) |
|
Issue 71 Incentive Compensation |
0 |
(543,431) |
|
Total Proposed Adjustments |
60,891,000 |
29,437,416 |
|
Adjusted Plant in Service |
$2,672,964,000 |
$2,641,510,416 |
What are the appropriate depreciation parameters and resulting depreciation rate for AMI Meters (Account 370)? (Category 2 Stipulation)
Approved Stipulation:
The appropriate depreciation parameter for Gulf’s AMI meter depreciation is a 15-year life with 0 percent net salvage. The resulting rate is 6.7%.
Should a capital recovery schedule be established for non-AMI meters (Account 370)? If yes, what is the appropriate capital recovery schedule? (Category 2 Stipulation)
Approved Stipulation:
An eight-year capital recovery schedule should be established for non-AMI meters (Account 370), modifying the four-year recovery period for the analog meters being retired establish when the Commission approved Gulf’s most recent depreciation study in Order No. PSC-10-0458-PSS-EI. Changing the amortization period from 4 to 8 years would result in decreasing the depreciation expense adjustment to NOI by one-half or $886,000 jurisdictional ($886,000 system). The rate base adjustment related to accumulated depreciation would be decreased by $443,000 jurisdictional ($443,000 system). The unrecovered balance to be recovered is $7,088,000.
Is Gulf's requested level of Accumulated Depreciation in the amount of $1,179,823,000 ($1,207,513,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate level of Accumulated Depreciation for the 2012 projected test year is $1,181,207,803 ($1,208,946,435 system). (Slemkewicz, Ollila)
Position of the Parties
GULF:
No. The appropriate level of Accumulated Depreciation for the 2012 test year is $1,182,844,000 ($1,210,639,000 system). This amount includes adjustments to Gulf’s original request to include the Crist 6 and 7 turbine upgrades (Issues 8 and 9), to correct an ECCR adjustment error, and to reflect the revised amortization period for non-AMI meters addressed in the stipulation on Issue 20.
OPC:
No. OPC’s recommended accumulated depreciation includes adjustments related to transmission capital additions, the Crist turbine upgrade transfer to base rates, and the incentive compensation capital additions. OPC’s adjustment related to the Smart Grid Investment Grant Program Projects has not been included. The resulting balance in accumulated depreciation should be $1,180,779,000. Accumulated depreciation be increased by $956,000 on a jurisdictional basis.
FIPUG:
No. Agree with OPC.
FRF:
No. Consistent with the adjustments recommended by OPC’s witnesses related to transmission capital additions, the Crist turbine upgrade transfer to base rates, capitalized incentive compensation, and the Smart Grid Investment Grant Program projects, the appropriate 2012 test year jurisdictional amount of Accumulated Depreciation is $1,180,779,000.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
This is a fall-out issue. Based on stipulations and staff’s recommendations in other issues, the appropriate level of Accumulated Depreciation for the 2012 projected test year is $1,181,207,803 ($1,208,946,435 system).
Table 21-1
|
2012 projected Test Year – Accumulated Depreciation – Jurisdictional |
||
|
Description |
Gulf |
Staff |
|
Accumulated Depreciation - MFR B-1 |
$1,179,823,000 |
$1,179,823,000 |
|
Issue 9: Turbine Upgrade |
3,006,000 |
1,376,000 |
|
Issue 12: Capitalized Incentive Compensation |
0 |
(42,049) |
|
Issue 20-S: Non-AMI Meter Amortization |
(443,000) |
(443,000) |
|
Issue 22: Construction Work in Progress |
0 |
55,000 |
|
Issue 44-S: ECCR Adjustment Error |
458,000 |
458,000 |
|
Issue 71: Incentive Compensation |
0 |
(19,148) |
|
Total Adjustments |
3,021,000 |
1,384,803 |
|
Adjusted Accumulated Depreciation |
$1,182,844,000 |
$1,181,207,803 |
Is Gulf's requested Construction Work in Progress in the amount of $60,912,000 ($62,617,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate jurisdictional level of Construction Work in Progress (CWIP) for the 2012 projected test year is $58,449,000 ($60,087,000 system), which is a reduction of $2,463,000 ($2,530,000 System) from Gulf’s requested level. As a result of this adjustment to CWIP, increases should be made to plant in service of $2,470,000 ($2,633,000 system), accumulated depreciation of $55,000 ($57,000 system), and depreciation expense of $102,000 ($106,000). (Gardner, Kaproth)
Position of the Parties
GULF:
Yes. Construction Work in Progress (CWIP) in the amount of $60,912,000 is needed to maintain reliability and meet customer demands. This amount is not eligible to accrue an Allowance for Funds Used During Construction (AFUDC) and should be allowed in rate base consistent with Commission policy.
OPC:
No. By definition, the CWIP has not entered service and is not being used by customers. It is therefore no different in character than the $232,012,000 of CWIP that Gulf excluded from rate base. Gulf has made no showing that the CWIP is needed to maintain its financial integrity. The requested balance of CWIP should be removed completely from rate base.
FIPUG:
No. Agree with OPC.
FRF:
No. This amount does not represent investment in any asset that is, or will be, used and useful in providing electric service to Gulf’s customers during the 2012 test year, and Gulf has not shown that it needs any part of this amount to maintain its financial integrity. Accordingly, the full amount should be removed from Gulf’s rate base in setting rates for the 2012 test year.
FEA:
No. Gulf has made no showing that the CWIP is needed to maintain its financial integrity. Including CWIP would unnecessarily increase rates to an unjust and unreasonable level. The requested balance of CWIP should be removed from rate base.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf stated that the appropriate levels of CWIP for the 2012 projected test year should be $60,912,000 to maintain reliability and meet customer demands. (Gulf BR 20) Gulf witness Deason argued that the projects included in CWIP provide a benefit to customers and should be permitted to earn a return. (Gulf BR 23, TR 2134) He stated that:
The $60.9 million represents short-term construction projects which do not qualify for AFUDC. If they are not allowed in rate base, Gulf will be denied an opportunity to earn a return on capital that it has deployed to adequately meet its customers’ need for service.
(TR 2130)
He further stated that the Commission had addressed the proper accounting and ratemaking treatment of CWIP in Order No. 3413.[10] This Order addressed the two options available to companies, which include: (1) charge AFUDC on CWIP and not include CWIP in rate base, and (2) not charge AFUDC and include CWIP in rate base. (TR 2132)
OPC
OPC witness Ramas testified that:
Construction Work in Progress (CWIP), by its very nature, is plant that is not completed and is not providing service to customers. It is not used or useful in delivering electricity to Gulf’s customers. As a general regulatory principle, CWIP should be excluded from rate base and excluded from costs being charged to customers until such time as it is providing service to those customers.
(TR 1459 - 1460) She further stated that allowing the inclusion of CWIP in rate base would create a mismatch in the ratemaking process since the revenue from new customers are not included in the calculations of the revenue requirement during the period the assets are being constructed. (TR 1460) OPC stated that Gulf has made no showing that CWIP is needed to maintain its financial integrity. In addition, OPC believes it is best to remove all CWIP, including short term projects, from rate base. (OPC BR 19)
FIPUG, FRF, and FEA agreed with OPC’s position. (FIPUG BR 4; FRF BR 9; FEA BR 7)
ANALYSIS
Staff agrees with Gulf witness Deason that the inclusion of CWIP (not eligible for AFUDC) in rate base is consistent with Commission practice. (TR 2132-2133)
While staff agrees with Gulf’s position that non-interest bearing CWIP should be included in rate base, Gulf witness McMillan acknowledged that there were additional adjustments that should be made to plant in service, CWIP, accumulated depreciation, and depreciation expense to close the projects. (EXH 150, p. 39) The adjustments acknowledged by witness McMillan that impacted CWIP were provided in Exhibit 98 (Nos. 175 through 177) and are shown in Table 22-1 below. These adjustments were for projects completed prior to December 2012, cancelled or delayed projects, or projects not closed to plant-in service in the 2011 budget for the following plant functions: (1) Steam Production-Minor Projects, (2) Other Production–Minor Projects, (3) Transmission-Minor projects, and (4) General Plant-Minor Projects. In addition, the adjustments to close the projects resulted in a decrease to CWIP of $2,463,000 ($2,530,000 system) and increases to: (1) plant in service of $2,470,000 ($2,633,000 system), (2) accumulated depreciation of $55,000 ($57,000 system), and 3) depreciation expense of $102,000 ($106,000 system). (EXH 98, Nos. 175-177) Finally, the above adjustments for the 2012 test year to plant in service, accumulated depreciation, and depreciation expense are included in the calculations for Issues 18, 21, 91, and 92. The overall 2012 CWIP adjustments are provided in Table 22-1 below.
Table 22-1
|
Construction Work In Progress - 2012 Adjustments (Jurisdictional |
||
|
Description |
Gulf |
Staff |
|
CWIP in Rate Base |
$60,912,000 |
$60,912,000 |
|
Item No. 175 |
0 |
(2,007,000) |
|
Item No. 176 |
0 |
(243,000) |
|
Item No. 177 |
0 |
(213,000) |
|
Total Adjustments |
0 |
(2,463,000) |
|
Adjusted CWIP |
$60,912,000 |
$58,449,000 |
CONCLUSION
Staff recommends that the appropriate level of CWIP for the 2012 projected test year is $58,449,000 ($60,087,000 system), which is a reduction of $2,463,000 ($2,530,000 system). As discussed above, the adjustments to close the projects to plant in service decreases CWIP, requiring additional adjustments to increase plant in service by $2,470,000 ($2,633,000 system), accumulated depreciation by $55,000 ($57,000 system), and depreciation expense by $102,000 ($106,000).
Should an adjustment be made to Plant Held for Future Use for the Caryville plant site?
Recommendation:
No. Staff recommends that no adjustment be made to Plant Held for Future Use for the Caryville plant site. (Gardner)
Position of the Parties
GULF:
No. The Caryville site has been included in Gulf’s rate base as Plant Held for Future Use through prior Commission decisions in previous Gulf rate cases and should continue to be included in rate base. The site’s acquired cost is small relative to the cost of acquiring a new plant site. The site is already certified under the Power Plant Siting Act for coal capacity, but the site cannot be used for a nuclear plant. Inclusion of the Caryville site in rate base as Plant Held for Future Use is still a prudent decision. No witness has testified that the Caryville site should not be included in rate base.
OPC:
No position.
FIPUG:
Yes. The Caryville site has been in rate base and been paid for by ratepayers for many years. Gulf has yet to begin any construction for any sort of power plant on this site; thus, it should be removed from rate base as it is no longer prudent for Gulf to continue to hold this site.
FRF:
Yes.
FEA:
FEA takes no position on this issue.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Burroughs stated that the Caryville site consists of approximately 2,200 acres of land in Holmes County with a book value of $1,356,000. He stated that the site was certified under the Power Plant Siting Act and is suitable for a steam electric generating plant. He further stated that it was evaluated for a nuclear site and that it was determined it was not a viable option for nuclear generation. (TR 759)
At the hearing, witness Burroughs was specifically asked if the Company had any planned generation units for the next ten years. He answered that, “We don’t have any particular units planned for development in the next ten years at Gulf Power.” (TR 769) He was also asked if Gulf had any plans to put a power plant on the Caryville site. He testified as follows:
We don’t have any plans in the present or in the near future to put a facility on the Caryville site. It is an option for us, and we will use it depending on what loading is, what the economic growth is, and whatever environmental regulations that come down in the near future that will force us into one direction or the other. So it serves as an option.
(TR 772)
OPC and FEA took no position. FRF recommended that there should be an adjustment related to the Caryville site, but provided no details related to an adjustment. (FRF BR 9) FIPUG recommended the Caryville site be removed from rate base since it is no longer prudent for Gulf to continue to hold the site. (FIPUG BR 4)
ANALYSIS
The Company acknowledged that there were no plans to construct a generating plant at the Caryville site. (TR 769) Although the property was purchased in 1963, the Company placed the land in plant held for future use (PHFU)[11] during a 1972 rate case. The land for the Caryville site at that time totaled $126,417.[12] Additionally, the Caryville site was expanded by the purchase of more land in the amount of $1,255,585, and was placed in PHFU in a 1980 rate case.[13] Witness McMillan acknowledged that there were non-utility activities occurring at the site that provide revenue to Gulf which benefit the ratepayers. (EXH 150, p. 40-41) Of the 2,200 acres of land, the Company has leased approximately 1,485 acres to the Brunson Hunting Club. (TR 759, EXH 107, No. 281, p. 1) The Company began leasing to the hunting club on November 9, 2000, and recently renegotiated a new lease on September 30, 2011, which will end on July 31, 2012. Additionally, the Caryville and Mossy head land is being used to grow or produce timber. There were timber sales in 2011 totaling $124,477, of which $61,367 was from the land currently in PHFU. Furthermore, in 2011, the Company received revenue from leasing the land as farmland and a residential house, which totaled $15,444. (EXH 107, No. 281, pp. 1-5)
The Company accounts for the revenue by: (1) crediting timber revenue to “Other Electric Revenue - P & L Natural Resources,” and (2) crediting lease revenue to “Rent From Electric Property-Miscellaneous.” In total, the Company has received $76,811 in revenue that is recorded above-the-line for PHFU. The current assessed value of the Caryville plant site is $429,754. Other than the revenue from leasing and timber sales, the Company stated that the site continues to be evaluated as a potential generating site during its planning process. (EXH 107, No. 281, pp. 2-4)
Witness Burroughs testified that it was his understanding that the Caryville site is certified for two 500 megawatt coal units. (EXH 147, p. 31) He further stated that the Caryville site also could support combined cycle units, combustion turbines, and other options except for the nuclear option. (EXH 147, p. 37)
CONCLUSION
In staff’s opinion, the Caryville site should remain in PHFU because it already has been certified under the Power Plant Siting Act and can support many different types of generation facilities. In addition, the revenue received from timber sales and leasing of the land helps to offset a portion of the revenue requirement for the site. Staff recommends that no adjustment be made to PHFU for the Caryville plant site.
Should the North Escambia Nuclear County plant site and associated costs identified by Gulf be included in Plant Held for Future Use? If not, should Gulf be permitted to continue to accrue AFUDC on the site?
Recommendation:
No. Staff recommends that the North Escambia Nuclear County plant site and associated costs identified by Gulf not be included in the balance of Plant Held for Future Use for ratemaking purposes. Therefore, Plant Held for Future Use should be reduced by $26,751,000 ($27,687,000 system). As recommended in Issue 1, Gulf was never authorized to accrue AFUDC on the site costs. As a result, Gulf should be required to adjust its books to remove $2,977,838 in carrying charges that have accrued on the plant site. (Gardner)
Position of the Parties
GULF:
$27,687,000 of North Escambia site costs should be included in rate base. Gulf was prudent: in 2007 investigating nuclear generation as an option; in considering nuclear to meet potential resource needs; in finding nuclear to be cost-effective; in performing site investigations; and in beginning permitting and licensing of a nuclear site. When Gulf learned that the North Escambia site was the only potential nuclear site in Northwest Florida, Gulf was prudent in preserving the nuclear option for its customers by acquiring the land. When circumstances changed, Gulf was prudent to defer its permitting efforts. By placing these costs in rate base, the Company can cease accruing carrying charges on the deferred nuclear site costs, which will save customers money.
OPC:
The Commission should deny Gulf’s request to place the property in rate base, because neither Gulf’s premature effort to portray the North Escambia property as a potential nuclear site nor (given the availability of Crist, Smith, Scholz, Mossy Head, and Caryville for the purpose) the potential use of the property for conventional generation provides adequate justification to do so in this proceeding. Carrying costs are specific to and unique to the extraordinary advance collection mechanism of Rule 25-6.0423, F.A.C.; therefore, Gulf must be prepared to absorb any and all carrying costs that the Commission permits Gulf to accrue unless and until the Commission awards a determination of need for a nuclear unit on the site.
FIPUG:
No. Inclusion of this site to “preserve the nuclear option” for some time in the future that is not even specified is inappropriate. Even the Gulf witnesses did not know when, if ever, the site would be utilized. Gulf has not shown that the purchase of the site is a reasonable and prudent investment that will be used for utility purposes in the reasonably near future and should not be allowed to accrue any AFUDC carrying costs on the Escambia site.
FRF:
No. Gulf should not be allowed to include the site in rate base, nor should Gulf be allowed to accrue AFUDC on the site, as there is no construction being done on the site, because the site is not used and useful, and because the site is unlikely to become used and useful for well over a decade, if ever.
FEA:
No. Please refer to FEA’s response to Issue 1.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Burroughs stated that, as part of the ongoing planning processes, the Company evaluated many generation resources to meet its future needs. He further stated that prudence dictated the Company needed to consider all viable technology types that would provide the greatest benefit to customers. Also, he stated that the Company employed a broad technology evaluation approach to evaluate land held for future use. He argued that the resource planning process would not be constructive for the full range of resources if the land was not available for consideration. Furthermore, the Company must make the appropriate investments in land that would support any or all of the options. (TR 755; Gulf BR 25)
Witness Burroughs testified that the Company’s next planned addition for capacity will not be until 2022. (TR 756; Gulf BR 25) He further testified that:
The primary benefit of that planning flexibility has been Gulf’s ability to avoid having to commit to specific generation technologies during a time of high uncertainties associated with potential environmental requirements. There are major environmental initiatives being proposed that could change the face of the electric utility industry. These potential environmental regulatory requirements could drive new generation additions.
(TR 756)
He argued that due to uncertainties, there are situations where nuclear could be a cost effective solution to meet long term generation additions. (TR 757) In addition, while considering nuclear technology, the Company reviewed over two dozen locations before deciding on the purchase of the 4,000 acre Escambia Site. (TR 758) The site was more suitable than the other locations due to its proximity to transmission, natural gas pipelines, railroad facilities, major highways, and access to water. Further, the site had a limited number of individuals and home owners. In addition, the site was suitable for other generation technologies including coal, gas, and renewables. The Escambia Site was owned by 35 property owners, including timber companies, who were the largest land holders. (TR 758; Gulf BR 25) Witness Burroughs further stated that, “Gulf’s decision to purchase land as a site suitable for new generation, including possible nuclear generation, is reasonable, prudent and necessary to continue to provide our customers with the most cost effective generating resources in the future.” (TR 759)
Witness Burroughs testified that the Company had no units planned for development in the next ten years. (TR 759) He also testified that, as stated in the Company’s 2011 Ten Year Site Plan, the Company’s next need for capacity would be 30-megawatts. (TR 781; EXH 190) He further testified that in 2023, there would be a need for an additional 885 megawatts due to the expiration of the Central Alabama Power Purchase agreement. (TR 781)
Gulf witness McMillan testified that the incurred costs for the Escambia Site and other charges should be included in rate base to defer nuclear site selection costs. He further stated that according to Section 366.93, F.S., the costs and a return were deferred by the Company through the end of 2011. Furthermore, he believed that: (1) nuclear is a viable option that will benefit the customers based on a range of scenarios; (2) the Escambia Site is the only site suitable for nuclear generation in Gulf’s service territory; (3) the purchase of the site is necessary to allow Gulf to preserve a nuclear option for its customers; and (4) the site provides water, rail, and gas which is necessary for other forms of generation. (TR 1079)
Witness McMillan testified that the deferred charges included preliminary survey site selection type costs and a deferred return. (TR 1121) He further testified that the statute instructed the Commission to set rules to implement that statute. (TR 1122) Witness McMillan stated that Rule 25-6.0423, F.A.C., defines site selection and site selection costs as:
Site selection. A site will be deemed to be selected upon the filing of a petition for a determination of need for a nuclear or integrated gasification combined cycle power plant pursuant to Section 403.519, F.S.
Section 4, Site selection costs. After the Commission has issued a final order granting a determination of need for a power plant pursuant to Section 403.519, F.S., a utility may file a petition for a separate proceeding to recover prudently incurred site selection costs.
(TR 1123, EXH 195) Witness McMillan acknowledged that the Company had not filed a petition for nor obtained an order granting a need determination for the nuclear plant. He stated that the Company had deferred the filing for a determination of need. (TR 1124)
Gulf witness Alexander testified that the $27,687,000 for the Escambia Site consisted of site acquisition and costs other than site acquisition. (TR 2208) She further stated that the costs included approximately $18.8 million for site acquisition and $8.8 million for costs other than site acquisition. She argued that based on the Company’s request, the revenue requirement for the site was approximately $3.1 million, which is less than 0.6 percent of total base rates. Furthermore, the inclusion of the Escambia Site in rate base would amount to approximately 26 cents on a 1,000 kilowatt hour residential bill. (TR 2209; Gulf BR 26)
Witness Alexander contended that the site costs were initially incurred in 2007 and the site acquisition costs were incurred from 2008 through 2011. Also, she stated that the carrying costs were accrued on a monthly basis and will continue until the costs go into rate base. (TR 2210; EXH 216) She argued that considering all the factors and the Company’s extensive studies, it was apparent that a self-build nuclear option was feasible. These factors were: (1) federal and state government targeting reductions of greenhouse gas (GHG) emissions; (2) state policy promoting the development of nuclear power; (3) Gulf’s capacity needs; (4) possible coal retirements, and (5) high gas prices. (TR 2211)
Witness Alexander argued that the Company’s consideration of the nuclear option was due to possible coal retirements and forecasted system load growth requirements. Furthermore, she maintained that if the Company pursued the nuclear option, it could “bridge its needs” with the use of Power Purchase Agreements (PPAs) to bridge capacity to move its 2009 forecasted need to 2014. (TR 2215) She stated that circumstances changed and the Company deferred its nuclear licensing, permitting, and determination of need efforts for the future. (TR 2220)
Witness Alexander contended that:
Gulf has not abandoned the nuclear option. Gulf deferred those efforts until a later time, if and when nuclear is needed and is the most cost effective option. In fact, a nuclear option for Gulf cannot be ruled out at this time given Gulf’s projected load requirements and given the great uncertainty surrounding the future of its coal-fired generation due to environmental regulations. In the summer of 2023, Gulf is currently projected to have a need of approximately 943 MW.
(TR 2221)
Witness McMillan argued that Section 366.93, F.S., provided authorization to record a deferred return on assets. He believed that there existed an apparent misunderstanding with the intervenor witnesses about the role that Section 366.93, F.S., played for the inclusion of the Escambia Site costs. (TR 2368) He argued that the Company was requesting to discontinue the deferral and move the dollars into rate base based on the Commission’s general ratemaking authority. He further argued that the request was not based on specific provisions of Section 366.93, F.S. (TR 2359)
OPC
OPC witness Schultz argued that Gulf neither requested nor filed a petition for determination of need. He contended that the Company acknowledged that it does not have plans to file a petition for a determination of need for a nuclear plant in the near future. (TR 1536; EXH 113, No. 24) He further argued that since no petition for a determination of need was filed to satisfy the requirements of Section 366.93(3), F.S., then the costs associated with the purchase of the land should not be included in PHFU. (TR 1536; OPC BR 20) It was his understanding both FPL and PEF “have been delaying the construction of nuclear plants further into the future because they cannot be justified on the basis of need.” Furthermore, he argued that it was hard to believe that a company which is so much smaller than Florida Power & Light Company (FPL) and Progress Energy Florida, Inc. (PEF) could justify a nuclear plant to meet its own needs. (TR 1538)
Witness Schultz referred to Gulf‘s discovery response to OPC’s Interrogatory No. 109, related the following:
Depending on the actual type and timing of an eventual generating resource addition constructed on the site, Gulf may seek the participation of potential co-owners in order to facilitate the addition. Such co-owners may potentially be other companies within the Southern electric system or unaffiliated companies.
(TR 1538; EXH 114, No. 109) He further stated that in Gulf’s response to OPC’s Interrogatory No. 108, the Ten-Year site plans showed a “potential generation need of approximately 30 MW in 2022.” He contended that the amount does not justify the addition or construction of a nuclear plant with 1150 MW of capacity or the recovery of $26 million in PHFU. (TR 1545; EXH 114, No. 108) He maintained that a base rate case is not the appropriate proceeding to evaluate future plant growth and needs. He argued that if there were a situation where nuclear was the solution, then the Company should have presented it to the Commission in the form of a petition for determination of need in order to justify any future generation additions, or otherwise demonstrated that a nuclear is cost effective option for the ratepayers. (TR 1547)
FIPUG
FIPUG argued that the inclusion of the Escambia Site to preserve the nuclear option was not appropriate. In addition, FIPUG further argued that Gulf did not show that the Escambia Site would be used for utility purposes in the reasonably near future and thus no carrying charges should be accrued on the site. (FIPUG BR 4)
FRF
FRF witness Chriss testified that Gulf will not use the Escambia Site before 2022 and maybe not at all. He further stated that according to the Company’s 2011-2012 Ten Year Site Plan, there were no plans to add any generating capacity until after 2020. He argued that when there is a need for capacity, then Gulf could evaluate the existing sites at Plants Crist, Smith, Scholz, and the greenfield site at Shoal River in Walton County. (TR 1308; FRF BR 9) He argued that because the Company has no plans to use the site in the next ten years, the Commission should reject the Company’s request to earn a return on a future power plant site that is not used and useful for the ratepayers. (TR 1308-1309; FRF BR 9)
FEA
FEA witness Meyer testified that Gulf was premature to include the investment for the Escambia Site based on Section 366.93, F.S. He further stated that there was no testimony from the Company’s witnesses that the Commission had approved a determination of need. Also, he contended that it was unclear if Gulf could accumulate the carrying costs prior to the Commission granting the need determination. He maintained that the Escambia Site costs should be disallowed. (TR 1764)
ANALYSIS
Staff reviewed the site acquisition and investigation costs provided by Gulf. The documents revealed a steady increase in the cost of land and carrying charges. For instance, in reviewing a response to OPC’s Interrogatory No. 24, the Company stated that as of December 31, 2010, deferred costs related to pursuing the nuclear option at the Escambia Site were $12,814,000 ($12,381,000 jurisdictional) and as of July 31, 2011, were $19,582,000 (18,920,000 jurisdictional). (EXH 113, No. 24, p. 2) Also, in reviewing a response to staff’s Interrogatory No. 174, the Company stated that the total project cost to date was $19,933,632 ($19,260,085 jurisdictional) as of September 2011. (EXH 98, No. 174) The Company asserted that the variance was due to the timing of land acquisitions. In their testimonies, Gulf witnesses Burroughs and McMillan included $27,687,000 of deferred nuclear site costs in PHFU for the period ending December 31, 2012. Gulf provided a detailed breakdown of the $27,687,000 site costs. (EXH 163, No. 47) Furthermore, the Company projected 2012 carrying costs in the amount of $1,046,131, which increased the total to $28,734,000. In its working capital adjustment, Gulf removed the 2012 carrying cost of $1,046,131. However, the 2012 carrying cost was not included in the Company’s adjustment to increase PHFU for the Escambia Site. The Company concluded that if the deferred site costs were included in the 2012 rate base, there would not be any carrying costs for 2012. (EXH 90, No. 59; EXH 113, No. 47; EXH 114, Nos. 97 and 98, p. 2) A summary of the above discussed site costs excluding the 2012 carrying charges is shown in Table 24-1 below.
Table 24-1
|
North Escambia County Plant Site Costs |
||
|
|
System |
Jurisdictional |
|
Land Costs |
$18,140,286 |
$17,527,000 |
|
Other Site Acquisition Costs |
778,485 |
752,000 |
|
Site Investigation Costs |
4,548,772 |
4,395,000 |
|
Need Determination Filing |
187,238 |
181,000 |
|
Project Support Costs |
650,742 |
629,000 |
|
Project Frank |
370,460 |
358,000 |
|
UWF Study |
33,620 |
32,000 |
|
Subtotal Land Costs |
24,709,603 |
23,874,000 |
|
Carrying Costs thru 12/31/11 |
2,977,838 |
2,877,000 |
|
Total Site Costs |
$27,687,441 |
$26,751,000 |
Gulf witness McMillan confirmed that the costs are currently classified on the Company’s books as regulatory assets based on the deferred accounting requirements of Rule 25-6.0423, F.A.C. (TR 2386) However, as discussed in Issue 1, the Escambia Site never qualified for treatment under that rule. Unless specifically authorized by statute or rule, a regulated company must have the approval of its regulator to defer costs and create a regulatory asset.[14] There is no evidence in the record that the Company sought the required approval of the Commission to create a regulatory asset for any of the costs incurred for the Escambia Site.
OPC witness Schultz stated that it was his understanding both FPL and PEF “have been delaying the construction of nuclear plants further into the future because they cannot be justified on the basis of need.” He further stated that “[I]f a nuclear unit ever makes sense, it will be in the context of shared ownership or sales to other entities.” (TR 1539) He also argued that allowing Gulf to include the cost of the Escambia site in rate base would require the ratepayers to pay an additional $3,083,000 in annual revenue. This would represent a ratepayer subsidy of future owners until the time, if ever, when a nuclear unit is built. (TR 1539) Staff agrees with OPC witness Schultz’s assertion that it is unlikely that Gulf would ever build a nuclear unit solely for its own capacity needs. Staff also agrees with FRF witness Chriss and OPC witness Schultz that Gulf already owns other sites included in PHFU that are available for the construction of conventional generating facilities. (TR 1308, 1541)
CONCLUSION
In summary, staff agrees with OPC, FIPUG, FRF, and FEA that: (1) the Caryville site is available for any needed future generating plant(s); (2) Gulf may share the ownership of the Escambia Site with its sister companies; and (3) there was not an order granting a determination of need that would allow the Company to petition for and the Commission the opportunity to review the “nuclear option” and all the various corresponding costs. With the recommended retention of the Caryville site in Issue 23 and the other available sites already included in rate base, it is staff’s opinion that Gulf has sufficient options for its future generation needs. Staff believes that Gulf has failed to support the inclusion of the North Escambia County Nuclear plant site and associated cost in PHFU. Therefore, PHFU should be reduced by $26,751,000 ($27,687,000 system). In addition, Gulf should not be permitted to accrue AFUDC for this site. As recommended in Issue 1, Gulf was never authorized to accrue AFUDC on the site costs. As a result, Gulf should be required to adjust its books to remove the $2,977,838 in accrued carrying charges.
Is Gulf's requested level of Property Held for Future Use in the amount of $32,233,000 ($33,352,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. Staff recommends that the appropriate level of Property Held for Future Use should be $5,314,153 ($5,496,000 system) for the 2012 projected test year. The proposed levels of Property Held for Future Use for 2012 should be reduced by $26,918,847 ($27,856,000 system). Plant in service should be increased by $167,847 ($169,000 system). (Gardner, Kaproth)
Position of the Parties
GULF:
Yes. The requested level of Property Held for Future Use in the amount of $32,233,000 ($33,352,000 system) for the 2012 projected test year is appropriate for purposes of computing base rate revenue requirements.
OPC:
No. PHFU should be reduced by $26,751,000 to reflect a jurisdictional balance of $5,482,000.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate jurisdictional amount of Property Held for Future Use to be included in rate based for the 2012 test year is $5,482,000.
FEA:
No. Property (Plant) Held for Future Use should be reduced by $27,687,000 (system).
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf contended that the level of Property Held for Future Use was appropriate for the purpose of computing base rate revenue requirement. The Company further stated that the Property Held for Future Use for the 2012 test year should be $32,233,000. (Gulf BR 29)
OPC
OPC argued that the level of Property Held for Future Use is not appropriate. OPC further stated that the jurisdictional level of Property Held for Future Use should be $5,482,000 for the 2012 test year, which is a reduction of $26,751,000. (OPC BR 22)
FIPUG, FRF, and FEA agreed with OPC’s position. (FIPUG BR 4; FRF BR 10; FEA BR 7)
ANALYSIS
This is a fall-out issue. Two of the properties in PHFU, totaling $28,061,000 ($29,043,000 system) were identified and discussed in Issues 23 and 24. The remaining properties included in this account amount to $4,172,000 ($4,309,000) as shown on MFR Schedule B-15. (EXH 7, Schedule B-15)
Staff reviewed the testimony and other record evidence related to PHFU to determine the appropriate projected test year amount. Staff has identified two additional properties that should be removed from PHFU, namely the Sandestin substation land $86,000 ($86,000 system) and the Panama City Office land $81,847 ($83,000 system). The Sandestin substation site is currently being used as a substation and the land should have been transferred to plant in service along with the substation facilities. The land actually was transferred in April 2011. (EXH 90, No. 50; EXH 196, No. 2) The Panama City Office land is being held for a future parking lot expansion, but is currently being used as a pole yard and for training. The Company intended to move the land to plant in service before the end of 2011. (EXH 90, No. 50; EXH 107, No. 281)
CONCLUSION
As recommended in Issues 1 and 24, the Escambia Site and other charges totaling $26,751,000 ($27,687,000 system) should be removed from PHFU. As discussed above, the Sandestin and Panama City land should be removed from PHFU and placed into plant in service requiring an additional adjustment of $167,847 ($169,000 system). In total, staff recommends that PHFU be reduced by $26,918,847 ($27,856,000 system) resulting in an adjusted level of $5,314,153 ($5,496,000 system).
Should any adjustments be made to Gulf's fuel inventories? (Category 2 Stipulation)
Approved Stipulation:
Gulf’s requested fuel inventory $83,871,000 ($86,804,000 system) should be reduced by $338,174 ($350,000 system) to reflect the necessary adjustment for Scherer In-transit fuel. In addition, consistent with Gulf’s response to staff interrogatory 216, the fuel inventory should be reduced by $$443,491 ($459,000 system) to reflect the test year gas storage inventory amount based on updated gas prices for 2012. The result of these two adjustments is a total test year fuel inventory amount of $83,089,332 ($85,995,000 system).
Should any adjustment be made to Gulf’s requested storm damage reserve, annual accrual of $6,539,091 ($6,800,000 system), and target level range of $52,000,000 to $98,000,000?
Recommendation:
Yes. The annual storm damage accrual should remain at its current annual level of $3.5 million but with a new target range of $48 to $55 million. This results in a decrease in jurisdictional O&M expense of $3,173,382 ($3,300,000 system) and an increase in the jurisdictional working capital of $1,586,500 ($1,650,000 system) for the test year. The storm damage accrual should not stop when the target level is achieved. Staff believes this issue should be readdressed if and when the target level is actually achieved. (L'Amoreaux, Gardner, Kaproth)
Position of the Parties
GULF:
No. Gulf’s request for working capital related to the reserve and an increased accrual related to property damage is prudent and in the best interest of Gulf’s customers. If the property damage accrual is changed from the amount proposed by Gulf, the working capital related to the reserve must also be adjusted. Since Gulf’s target reserve level has not been adjusted since 1996, the reserve target should be increased to the range of $52 million to $98 million to reflect Gulf’s actual experience. Issue 76 also discusses the appropriateness of the storm damage accrual.
OPC:
Yes. Gulf’s requested increase in the annual accrual is excessive and unjustified based on the historical charges to the reserve, the storm standards established for Florida electric utilities, and the storm hardening measures implemented after 2005. Gulf’s unreliable storm study included extraordinary storm repair costs which historically have been recovered by surcharge mechanisms. The annual storm accrual should be reduced to $600,000, which reflects a decrease to O&M expense of $6.2 million ($5,962,113 jurisdictional). Because the storm reserve has almost reached the specific target range that was previously determined by the Commission, it currently is sufficiently funded to cover ordinary storm costs that are likely to occur based on recent history, excluding the extraordinary storm costs incurred in 2004-2005.
FIPUG:
The Commission should not approve any increase in Gulf’s annual storm accrual because Gulf’s proposal is not based on historical charges to the storm reserve, fails to account for storm hardening measures, and fails to consider the Commission’s prompt action on storm surcharge requests.
FRF:
Yes. Gulf should not be allowed to include an accrual for its storm damage reserve in base rates of any more than $600,000 per year. Moreover, Gulf’s existing reserve, together with its ability to obtain prompt storm cost relief from the Commission, with or without securitization, are adequate to address any reasonably foreseeable storm damages, such that the Commission should consider suspending accruals to Gulf’s storm reserve when setting rates in this case.
FEA:
Yes.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Erickson sponsored a storm damage study related to the proposed storm damage reserve, annual accrual, and target level range. In her direct testimony, she stated:
The current target level for the reserve is $25.1 million to $36 million, as approved by the Commission in Docket No. 951433-EI, Order No. PSC-96-1334-FOF-EI, and affirmed in the Company’s last rate case. The storm study shows that with the current accrual level, the balance in the fund is expected to decrease, rather than increase, over the next five years. Increasing the annual accrual to $6,800,000 with a target reserve balance between $52 million and $98 million will provide our customers with the best long term solution to storm restoration.
(TR 965)
Witness Erickson’s proposed increase in the annual accrual from $3.5 million to $6.8 million is based on her own personal judgment and the storm study prepared by an outside firm, EQECAT. (TR 984; EXH 19) The study noted that EQECAT’s proprietary computer software, USWIND, is one of only four models evaluated and determined acceptable by the Florida Commission on Hurricane Loss Projection Methodology for projecting hurricane loss costs and approved for use in insurance rating. (EXH 19, p. 7) There are two sections to the storm study. The first section is The Hurricane Loss Analysis section, which uses a probabilistic approach that considers the full range of potential hurricane characteristics and corresponding losses. The second section is The Reserve Performance Analysis, which is a dynamic financial analysis simulation that evaluates the performance of the reserve in terms of the expected balance in the reserve and the likelihood of positive reserve balances over a five-year period, incorporating the potential uninsured loss amounts determined in the Hurricane Loss Analysis, at various annual accrual levels. (EXH 19, p. 21) Gulf witness Erickson described key factors considered in the model:
[A] probabilistic annual damage and loss is computed using the results of thousands of random variable hurricanes considering the long term 100-year hurricane hazard. Primary factors considered in the analysis include the location of Gulf’s overhead Transmission & Distribution (T&D) assets, the probability of hurricanes of different intensities and/or landfall points impacting those assets, the vulnerability of those assets to hurricane damage, and the costs to repair and restore electric service.
(TR 2299)
The storm study yielded statistical probabilities of storm damage of varying magnitudes occurring in a given year, and the resulting impacts to the storm damage reserve balance over a five-year period. Key assumptions in this analysis include:
· An initial reserve balance of $27 million.
· Annual reserve accruals of $3.5 million.
· Hurricane losses are assumed to increase by 4 percent per year as the replacement value of T&D assets increases due to inflation and system growth.
· Negative reserve balances are assumed to be financed with an unlimited line of credit costing 3.8 percent.
· Positive reserve balances are assumed to earn at an annual rate of 3.6 percent.
· Of the $8.3 million Expected Annual Damage (EAD) determined in the Loss Analysis, $6.8 million is assumed to be charged each year to the storm damage reserve.
(EXH 19, p. 21)
Based on this study, witness Erickson asserted that the requested annual accrual of $6.8 million represented the level of the expected average annual loss to be covered by the reserve. However, she noted it is unlikely that this amount would allow Gulf to achieve its proposed targeted reserve balance of $52 million to $98 million. She argued that “An annual accrual in excess of the expected average annual loss would be required to have an expected increase in the reserve balance over time.” (TR 966) The storm study showed that the proposed target range of $52 million to $98 million would cover all category 1 and 2 hurricanes and most category 3 hurricanes. (EXH 19, p. 16) Witness Erickson opined that the accrual level over time is intended to provide the necessary dollars required for restoration after most storms but not from the most severe storms. In addition, she stated that having an accrual in place reduces the potential burden on customers of extremely high storm damage surcharges. (TR 2300)
Gulf witness Erickson discussed the potential impact of storm surcharges on customers. She asserted that:
Each generation of customers should contribute to the cost of storm restoration, even if no storm strikes in a particular year. Since storms will occur, and only their timing is uncertain, the true cost of providing electric service should include an allowance for a level of restoration that approximates the EAD charged to the property damage reserve.
(TR 2308)
Witness Erickson stated that Gulf experienced a two percent loss in customers after Hurricane Ivan. She asserted that the two percent customer loss “demonstrate[s] that an appropriate property damage reserve included in customer rates over time is more equitable to customers than a storm surcharge implemented after a storm that could likely be assessed on a smaller customer base. Storm restoration is a cost of providing electric service in Florida and should be properly reflected in Gulf’s base rates.” (TR 2308)
OPC
OPC witness Schultz argued that Gulf’s proposed increase to the annual accrual should be denied, and instead that the accrual should be decreased below its current level of $3.5 million. Witness Schultz contended that the annual accrual should be set at $600,000. He based his recommendation on the unreliability of Gulf’s storm study and his own calculations.
Witness Schultz had many concerns with the storm study. First, he claimed that Gulf relied on a single study that used a single set of inputs to determine the appropriate annual accrual and target range for the storm reserve. Witness Schultz implied that since no alternative scenarios were conducted, the outcome was predetermined. (TR 1549) Witness Schultz also noted that in Exhibit 115 it stated that “There is only one Expected Annual Damage (EAD) calculated,” and “Only one storm reserve simulation was performed.” (TR 1550)
Second, witness Schultz did not agree that the storm study should have used thousands of simulated storms not specific to Gulf’s territory. He asserted that “historical storm information is relevant” and the impact of a storm’s landfall varies depending on geographic location. (TR 1550) OPC described in its brief what it believed is the difference between Gulf’s 1996 storm study and the current study. OPC asserted that the 1996 storm study relied only on historical storms whereas the current study used thousands of random, variable, synthetically created storms combined with historical storms that caused ordinary and extraordinary damage. (OPC BR 25)
OPC witness Schultz argued that Gulf’s storm study improperly included the impact of the 2004 and 2005 hurricane seasons. He stated that including such costs in its calculations increased Gulf’s proposed annual accrual amount. Witness Schultz also cited the storm cost recovery decision for Progress Energy Florida, Inc., where “the Commission stated that the 2004 hurricane season was ‘unprecedented and extraordinary in nature.’” (TR 1550) OPC witness Schultz disagreed with the statement in Gulf’s storm damage study that “The 2004-2005 loss history is believed to be the most reflective of the current Gulf hurricane restoration practices and cost experience.” (EXH 19, p. 10) He argued that this assumption is inappropriate because the reserve is not intended to account for losses from storms that are considered extraordinary and should only cover major storm years. (TR 1552) He asserted that if the extraordinary damage caused by the 2004 and 2005 storm season is excluded from the historic data, Gulf’s average actual storm damage costs charged to the reserve since 2001 have averaged less that $600,000 per year, which is less than the long-term average annual amount of $1.3 million projected by Gulf in 1996. (TR 1551; OPC BR 29)
Witness Schultz observed that the storm damage study did not take into account Gulf’s storm hardening initiatives. (TR 1552) He contended that the exclusion of improvements to Gulf’s infrastructure is unacceptable since “the Company has been under the direction of the Commission to perform storm hardening at a heightened level since the 2004-2005 extraordinary storms occurred.” (TR 1552)
OPC witness Schultz recommended an annual accrual of $600,000 based upon his analysis of Gulf’s ten-year storm history. Witness Schultz calculated the total average annual amount charged to the storm damage reserve from 2001 until 2010, excluding data for the years 2004 and 2005. This average of $575,566, was rounded up to $600,000. Witness Schultz contended that at a $600,000 annual accrual, the reserve would remain within the current target range of $25.1 million to $36 million over the next five years, assuming no hurricanes made landfall in Gulf’s service territory. (TR 1551, 1553, 1556)
FIPUG
While FIPUG witness Pollock argued that the level of funds in the storm reserve is sufficient to cover the cost of storm restoration even if the accrual is stopped altogether, he recommended that the Commission maintain the accrual at its current level of $3.5 million annually. Witness Pollock stated in his testimony that “Gulf is at little or no risk for recovering storm restoration costs regardless of the amount in the storm reserve.” (TR 1333) He asserted that the Commission previously allowed recovery of storm restoration costs after the storm reserve had been depleted. (TR 1334)
FIPUG witness Pollock argued that the $3.3 million annual increase in the storm damage accrual is unwarranted for various reasons. He stated that under the Commission framework, “the storm reserve accrual and reserve balance are designed to provide coverage for some, but not all, storms.” (TR 1335) Witness Pollock alleged that the current reserve balance is sufficient to cover all category 1 hurricanes and some category 2 hurricanes. He noted that Gulf was previously approved to assess a storm damage surcharge to provide for recovery of storm damage amounts after the reserve had been depleted due to the 2004 and 2005 hurricanes.[15]
Witness Pollock also had issues with the storm damage study presented by Gulf witness Erickson. First, witness Pollock opined that the EAD does not represent the annual costs that should be covered by funds from the storm reserve. He asserted “I believe the EAD is overstated because it ignores the Commission’s directive that the storm reserve should be adequate to accommodate most, but not all storm years.” (TR 1335-1336)
Second, similar to OPC witness Schultz, he argued that Gulf has only charged $5.3 million to the reserve during the last five and a half years. Witness Pollock stated that “This equates to an annual average charge to the reserve of less than $1 million.”[16] (TR 1336)
FIPUG witness Pollock also observed that Gulf has not taken into account the impacts of Gulf’s storm hardening initiatives in the Company’s storm damage study. He believed that if ratepayers contribute to the hardening of Gulf’s system, then the impact of these initiatives should be accounted for in the study or credited to the ratepayers. (TR 1336, 1339-1340)
FRF
In its brief, FRF argued that Gulf does not need an increase in its annual storm reserve accrual, “nor does it even need the current accrual of $3.5 million per year in order to provide safe, adequate, and reliable service.” (FRF BR 10) FRF observed that after Hurricane Ivan struck Gulf’s service territory in 2004, the Commission ensured that Gulf had adequate funds to restore service promptly. (FRF BR 10) FRF concluded that Gulf should be allowed at most an annual accrual of $600,000, relying on the testimony of OPC witness Schultz. (FRF BR 12) OPC witness Schultz noted that even though Gulf had a storm reserve in 2004 lower than its current level, and Ivan caused damages several times higher than Gulf’s 2004 storm reserve, the Company was able to respond and restore service. Accordingly, FRF argued that this proves that Gulf does not need a storm reserve greater than its current level of $31 million. (FRF BR 12)
FEA
FEA witness Meyer testified that the Commission should approve an annual storm damage accrual of no more than $5.0 million. He asserted that Gulf’s proposed annual accrual of $6.8 million is excessive. (TR 1759) Witness Meyer explained: “I believe that no more that $5.0 million is an appropriate level for the annual accrual for this case. The increase in the accrual would recognize an increase in storm recovery costs over that level of expense approved by this Commission in Gulf’s last rate case.” (TR 1759)
The current target range for the reserve is $25.1 to $36 million.[17] Gulf’s storm study revealed that the reserve has “an 89% probability that the fund balance would be greater than $25 million after five years.” (TR 1760) Witness Meyer asserted that this is still within the target range for the reserve the Commission set in Docket No. 951433-EI. In addition, the reserve balance only has a 29 percent chance of going negative in five years. (TR 1760)
Witness Meyer testified that if no storms occur during the next five years, the reserve balance would grow to approximately $51 million. (TR 1760) He believed that an accrual of $5.0 million would more adequately fund storm restoration than the current $3.5 million. (TR 1761)
Witness Meyer further explained his reasoning regarding a $5.0 million annual accrual. He stated that:
In these economic times, the storm reserve should be maintained at what the Commission feels is a reasonable level. Some parties may argue that because the Commission has allowed surcharges in the past, no reserve amount should be maintained. Gulf witness Erickson has testified that the Commission has previously found that a target reserve between $25.1 million and $36 million is reasonable. With an annual accrual of $5.0 million, I believe this standard will be achieved.
(TR 1762)
FEA witness Meyer noted that Gulf can seek recovery of storm restoration costs that exceed the reserve through a surcharge. (TR 1762) He observed that “[T]o the extent the Commission continues to support this position, the necessity to have large reserves is diminished.” (TR 1763)
ANALYSIS
Resolution of this issue requires decisions on two matters: Gulf’s appropriate annual storm damage accrual and the target level of Gulf’s storm damage reserve. Gulf’s current accrual is $3.5 million and its storm reserve range is $25.1 to $36 million. (TR 965) The record reflects that four parties offered proposals on one or both of these matters: Gulf, OPC, FIPUG, and FEA.
Gulf witness Erickson sponsored the storm damage study that was prepared for Gulf by EQECAT. The storm study is comprised of two sections. The first section is The Hurricane Loss Analysis section, which uses a probabilistic approach that considers potential hurricane characteristics and equivalent losses from thousands of random variable hurricanes. (EXH 19, p. 7) The second section is The Reserve Performance Analysis, which is a financial analysis simulation that evaluates the performance of the reserve in terms of the expected balance in the reserve and the likelihood of positive reserve balances over a five-year period, incorporating the potential uninsured loss amounts determined in the Hurricane Loss Analysis, at the annual accrual level. (EXH 19, p. 21)
This study indicated that Gulf’s Expected Annual Damage (EAD) is $8.3 million, of which Gulf proposed that $6.8 million be funded through the annual accrual. (EXH 19, pp. 6, 19, 21) Witness Erickson proposed that the target reserve range be increased to a range of $55 to $98 million. (TR 965) During cross-examination, witness Erickson was questioned at length regarding her detailed knowledge of the storm study. For example, she was asked if the persons that work with EQECAT would be the ones who know the intricacies of how the storm study works. Her response was yes. (TR 981) She also stated that she is only familiar with certain details of the storm study about which she asked the preparers of EQECAT. In addition, she stated in cross-examination that she does not have any experience in running the EQECAT computer simulation model, or any of the other currently approved models. (TR 988) During her deposition, witness Erickson was questioned by FIPUG about her knowledge of the study. Counsel for FIPUG inquired specifically if witness Erickson considered herself to be an expert in performing analytical studies that the EQECAT outfit completed. Witness Erickson responded by acknowledging that she was not an expert in performing analytical studies such as those performed by EQECAT. (EXH 149)
Accordingly, staff believes that Gulf witness Erickson lacks sufficient familiarity with the EQECAT model, including its inputs and its algorithms, to attest to the reasonableness of the storm study and its results submitted in this proceeding. Staff notes that no other Gulf witness testified on the study.
Staff and OPC sent multiple discovery questions in an attempt to obtain an understanding of the EQECAT model’s inputs and internal processes. Gulf witness Erickson testified that she was responsible for responding to these discovery questions. (TR 982) However, neither staff nor OPC was able to determine and track the various calculations and iterations of the model that ultimately yielded the proposed $8.3 million EAD which was the basis for Gulf’s proposed $6.8 million annual accrual. (TR 965; EXH 19, p. 21) Therefore, staff recommends that Gulf’s proposed annual accrual of $6.8 million not be adopted by the Commission.
In contrast to the approach used in the EQECAT study, OPC witness Schultz derived his recommended annual accrual using historical data covering the period 2001-2010 on storm damage actually incurred by Gulf. He first excluded the costs associated with the storms in 2004 and 2005, and then averaged the remaining amounts. Witness Schultz testified that it was appropriate to exclude the 2004-2005 data because it reflected extraordinary storms. This calculation yields $575,566, which the OPC witness rounded up to $600,000 to arrive at his recommended annual accrual. (TR 1551, 1553, 1556)
Gulf witness Erickson disagreed with the OPC proposal. She disputed the claim that the 2004-2005 storms that hit Gulf’s territory were extraordinary, noting that they were Category 3 storms. (TR 2303) Witness Erickson observed that by including the 2004-2005 storm data, the 10-year average would be $15.7 million. (TR 2302)
Witness Erickson responded to OPC witness Schultz’s claim that the study’s results were predetermined to reflect what amount the Company wanted to collect in rates. (TR 2302, 2304) Witness Erickson countered this claim, noting: “The ground work for this Study began early in 2010, since the Study was required to be filed with the Commission in January, 2011. This filing was independent of any rate case proceedings. There was absolutely no communication with the consultant that tried to direct or sway the outcome of the Study.” (TR 2304)
Staff agrees with witness Erickson that it was unreasonable for the OPC witness to exclude the 2004-2005 storm data from his analysis. Excluding storm damage costs for Hurricanes Ivan, Dennis, and Katrina effectively assigns a zero weighting to the likelihood of storms of such magnitude occurring in the future. While acknowledging that the computational approach employed by OPC witness Schultz does not readily lend itself to accounting for probabilities of occurrence, staff believes assigning a zero probability that storms such as those that hit Gulf’s territory in 2004-2005 will recur, is questionable. Accordingly, staff believes that OPC witness Schultz’s recommended annual accrual should not be adopted by the Commission.
FIPUG witness Pollock and FEA witness Meyer advocated similar positions. FIPUG witness Pollock testified that the annual accrual should remain at its current level of $3.5 million. (TR 1338) FEA witness Meyer proposed an annual accrual of no higher than $5.0 million, which he derived by increasing the Commission-approved accrual of $3.5 million for inflation. (TR 1759; FEA BR 8) However, in its brief FEA appeared to have modified its position: “FEA recommends that the Commission not establish the annual accrual to exceed $5.0 million, but support FIPUG’s position of no change.” (FEA BR 10) On balance, staff believes the record supports maintaining the existing annual accrual at $3.5 million. No pressing need has been identified to warrant an increase in the accrual at this time. Staff believes that a $3.5 million accrual coupled with the 2011 year-end reserve level of approximately $31 million should be sufficient to cover the costs of most, but not all storms. If circumstances change, it would be appropriate to revisit this decision in a future proceeding.
While staff recommends that the annual accrual should remain unchanged, staff believes there is merit in making a modest adjustment to the target reserve level. The current range of $25.1 to $36 million was set over 14 years ago. (TR 2305) Gulf’s storm study indicates that a reserve of $52 million is adequate to cover all Category 1 and Category 2 hurricanes. (EXH 19, p. 15) In her rebuttal testimony, Gulf witness Erickson asserted that if the target reserve level had been adjusted for inflation, as FEA witness Meyer did to the current annual accrual to arrive at his proposal in his testimony, the range would be approximately $48 to $69 million.
Staff recommends that the target reserve level be increased slightly, to $48 to $55 million. Staff believes a range of $48 to $55 million represents a composite of the amounts suggested by Gulf witness Erickson, FEA witness Meyer, and Exhibit 19. (TR 2305; EXH 19) Staff’s recommended upper end of $55 million is slightly above the $52 million amount indicated by Gulf’s storm damage study to be sufficient to cover all Category 1 and 2 storms. However, the Commission should take into account, as Gulf witness Deason stated in his testimony, that charges are made against the reserve for items in addition to charges associated with property damage from storms. (TR 2180) While storms are the main reason for the reserve, the reserve may be charged for damage resulting from such events as a fire or other natural occurrences. Staff believes that the record reflects that a target reserve range of $48 to $55 million should be sufficient to cover the costs of all Category 1 and Category 2 storms, with a small margin for unnamed storms and other damage. Thus, staff believes that this reserve level best fits the Commission’s goal that the reserve should cover most, but not all storms. At this time, staff believes it would be premature to determine whether or not the accrual should cease when the upper end of the target range is achieved. Should this occur, staff believes this question should be addressed at that time.
CONCLUSION
The annual storm damage accrual should remain at its current annual level of $3.5 million but with a new target range of $48 to $55 million. This results in a decrease in jurisdictional O&M expense of $3,173,382 ($3,300,000 system) and an increase in the jurisdictional working capital of $1,586,500 ($1,650,000 system) for the test year. The storm damage accrual should not stop when the maximum target level is achieved. Staff recommends that this issue should be readdressed if and when the target level is actually achieved.
Should unamortized rate case expense be included in Working Capital?
Recommendation:
No. The unamortized rate case expense of $2,450,000 should be removed from the 2012 test year working capital. (Kaproth)
Position of the Parties
GULF:
Yes. Rate case expenses are prudently incurred business expenses. The Company should be allowed to fully recover these costs, including a return on the unamortized investment. This unamortized balance should be included in working capital, consistent with the Commission’s treatment of these expenses in Gulf’s previous rate case.
OPC:
No. The Commission has consistently disallowed the inclusion of unamortized rate case expense in working capital. This long standing Commission policy was recently reaffirmed in Commission Order No. PSC-10-0131-FOF-EI, involving Progress Energy Florida. Working capital should be reduced by $2,450,000.
FIPUG:
No. Agree with OPC.
FRF:
No. Consistent with the Commission’s long-standing policy rejecting the inclusion of unamortized rate case expense in Working Capital, Gulf’s test year Working Capital should be reduced by $2,450,000.
FEA:
No.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf included $2,450,000 of unamortized rate case expense in working capital for 2012. (MFR Schedule B-17, p. 1 of 6) Gulf witness McMillan stated that rate case expenses are prudently incurred business expenses. (TR 2365-66, Gulf BR 31) These costs should be allowed to be recovered as well as earn a return on the unamortized investment. Gulf pointed out that the Company was allowed to recover unamortized rate case expense in Docket No. 010949-EI.[18]
OPC
OPC witness Ramas testified that the Commission has consistently disallowed the inclusion of unamortized rate case expense in working capital. OPC further pointed out that this policy was reaffirmed in Order No. PSC-10-0131-FOF-EI involving Progress Energy Florida, Inc. (PEF Order).[19] (OPC BR 32) In the PEF Order, the Commission found:
We have a long-standing policy in electric and gas rate cases of excluding unamortized rate expense form working capital, as demonstrated in a number of prior cases. The rationale for this position was that ratepayers and shareholders should share the cost of a rate case: i.e., the cost of the rate case would be included in the O&M expenses but the unamortized portion would be removed from working capital. It espouses the belief that customers should not be required to pay a return on funds expended to increase their rates.
While this is the approach that has been used in electric and gas cases, water an wastewater cases have included unamortized rate case expenses in working capital. The difference stems from a statutory requirement that water and wastewater rates be reduce at the end of the amortization period.
We agree with the long-standing policy that the cost of the rate case should be shared and therefore, find that the unamortized rate case expense amount of $2,450,000 shall be removed from working capital.
Witness Ramas also cited the cases listed in the footnote on page 71 of the PEF Order that identified other cases which demonstrate the Commission‘s long-standing practice in electric and gas cases of excluding the unamortized rate case expense from working capital.[20] (TR 1490)
FEA
FEA stated that normalizing rate case expense would prevent the inclusion of unamortized rate case expense in working capital. (FEA BR 11) FEA explained the parties would need to agree only on the amount to be amortized as rate case expense. In this case, FEA proposed to establish a normalized annual level of rate case expense at $700,000. (FEA BR 11)
ANALYSIS
The intervenors argued that unamortized rate case expense should not be included in working capital because of the Commission’s previous orders. The Order in Docket No. 010949-EI does not include an adjustment to reduce unamortized rate case expense nor does it show the inclusion of unamortized rate case expense. OPC, FIPUG, FRF, and FEA agree that unamortized rate case expense should be removed from working capital.
The Commission has a long-standing practice in electric and gas rate cases of excluding unamortized rate case expense from working capital, as demonstrated in a number of prior cases.[21] The rationale for this position is that ratepayers and shareholders should share the cost of a rate case; i.e., the cost of the rate case would be included in O&M expense, but the unamortized portion would be removed from working capital. This practice underscores the belief that customers should not be required to pay a return on funds spent to increase their rates.
While this is the approach that has been used in electric and gas cases, water and wastewater cases have included unamortized rate case expense in working capital. The difference stems from a statutory requirement that water and wastewater rates be reduced at the end of the amortization period.[22] While unamortized rate case expense does not earn a return in working capital for electric and gas companies, it is offset by the fact that rates are not reduced after the four year amortization period ends. Thus, the amount in O&M expense continues to be collected after total rate case expense has been recovered.
Staff agrees with the long-standing practice that the cost of the rate case should be shared, and therefore recommends that the unamortized rate case expense amount of $2,450,000 be removed from working capital.
CONCLUSION
Staff recommends that the unamortized rate case expense of $2,450,000 be removed from working capital consistent with the Commission’s long-standing practice.
DROPPED.
Is Gulf's requested level of Working Capital in the amount of $150,609,000 ($155,044,000 system) for the 2012 projected test year appropriate?
Recommendation:
Based on staff’s recommendations in other issues, the appropriate 13-month average of working capital for the 2012 projected test year is $148,963,835 ($153,435,000 system). This is a decrease to working capital in the amount of $1,645,165 ($1,609,000 system). (Kaproth, Gardner)
Position of the Parties
GULF:
No. The appropriate level of Working Capital for the 2012 test year is $149,828,000 ($154,235,000 system). This amount includes an adjustment to Gulf’s original request to reflect the effect of the stipulation on Issue 26 relating to fuel inventories.
OPC:
No. Working capital should be reduced by $2,788,000 to reflect a balance of $147,821,000. This includes adjustments to remove unamortized rate case expense and the stipulated corrections to fuel inventories.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate amount of Working Capital to be allowed for setting base rates for the 2012 test year is $147,821,000, reflecting adjustments to remove unamortized rate case expense and stipulated corrections to Gulf’s fuel inventories.
FEA:
No. Please refer to FEA’s response to Issue 28.
Staff Analysis:
This is a fall-out Issue. Based on staffs’ recommendations in other issues, the appropriate 13-month average of working capital for the 2012 projected test year is $148,963,835 ($153,435,000 system). (See Table 30-1)
Table 30-1
|
2012 Projected Test Year – Working Capital - Jurisdictional |
||
|
Description |
Gulf |
Staff |
|
Working Capital as filed |
$150,609,000 |
$150,609,000 |
|
Issue 26 Stip Fuel Inventory Adj |
(338,000) |
(338,174) |
|
Issue 26 Stip Gas Storage Inventory |
(443,000) |
(443,491) |
|
Issue 27 Storm Damage Reserve |
0 |
1,586,500 |
|
Issue 28 Unamortized Rate Case Exp. |
0 |
(2,450,000) |
|
Total Proposed Adjustments |
(781,000) |
(1,645,165) |
|
Adjusted Working Capital |
$149,828,000 |
$148,963,835 |
Is Gulf's requested rate base in the amount of $1,676,004,000 ($1,712,025,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. Staff recommends that the appropriate 2012 projected test year rate base is $1,673,029,601 ($1,709,188,184 system), which is a reduction of $2,974,399 ($2,836,816 system) from Gulf’s requested level as originally filed. (Gardner, Kaproth)
Position of the Parties
GULF:
No. The appropriate level of rate base for the 2012 test year is $1,733,093,000 ($1,771,141,000 system). This amount includes adjustments to Gulf’s original request to include the Crist 6 and 7 turbine upgrades (Issues 8 and 9), to reflect the stipulated adjustment to accumulated depreciation for non-AMI meters (Issue 20), to correct an ECCR adjustment error, and to reflect the stipulated adjustment to fuel inventories (Issue 26).
OPC:
No. The appropriate rate base should be decreased by $78,089,000 to reflect a balance of $1,597,915,000 on a jurisdictional basis.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate jurisdictional rate base for the 2012 test year is $1,597,915,000.
FEA:
No. Please refer to FEA’s response to Issue 28.
Staff Analysis:
This is a fall-out issue. Staff recommends that the appropriate 2012 projected test year rate base is $1,673,029,196 ($1,709,187,769 system), which is a reduction of $2,974,804 ($2,837,231 system) from Gulf’s original requested level, as shown in Table 31-1.
Table 31-1
|
2012 Rate Base - Jurisdictional |
|||
|
|
Gulf as Filed |
Gulf Revised |
Staff |
|
Utility Plant-In-Service |
$2,612,073,000 |
$2,672,964,000 |
$2,641,510,416 |
|
Less: Accumulated Depreciation |
1,179,823,000 |
1,182,844,000 |
1,181,207,803 |
|
Net Plant-In-Service |
1,432,250,000 |
1,490,120,000 |
1,460,302,613 |
|
CWIP |
60,912,000 |
60,912,000 |
58,449,000 |
|
Property Held for Future Use |
32,233,000 |
32,233,000 |
5,314,153 |
|
Net Utility Plant |
1,525,395,000 |
1,583,265,000 |
1,524,065,766 |
|
Working Capital |
150,609,000 |
149,828,000 |
148,963,835 |
|
Total Rate Base |
$1,676,004,000 |
$1,733,093,000 |
$1,673,029,601 |
What is the appropriate amount of accumulated deferred taxes to include in the capital structure?
Recommendation:
The appropriate amount of accumulated deferred taxes to include in the capital structure for the 2012 projected test year is $256,641,729 as shown on Schedule 2. (Springer, Cicchetti)
Position of the Parties
GULF:
The appropriate amount of accumulated deferred taxes to include in capital structure is $265,856,000. This amount includes adjustments to Gulf’s original request to reflect the pro-rata portion of the rate base adjustments identified in Issue 31.
OPC:
The appropriate amount of accumulated deferred income taxes is $245,119,000, which reflects a pro rata reduction to Gulf’s requested balance of $257,098,000. Also, if the Commission grants Gulf’s request to annualize the impacts of the Crist Units 6 and 7 turbine upgrades in rate base, which OPC recommends against, the Commission should either increase the amount of deferred income taxes in the capital structure or lower rate base by $916,000 for the resulting impact of those projects on deferred income taxes.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of deferred income taxes for the 2012 test year is $245,119,000. If the Commission were to allow Gulf to annualize the Crist turbine upgrades in rate base, contrary to the positions of the Consumer Intervenors, the Commission should either increase the amount of deferred income taxes in Gulf’s capital structure or reduce rate baser to reflect the impact of those projects on deferred income taxes.
FEA:
FEA takes no position on this issue.
Staff Analysis:
This issue addresses the appropriate amount of accumulated deferred income taxes (ADITs) to include in Gulf’s capital structure for the 2012 projected test year.
PARTIES’ ARGUMENTS
In its MFRs, Gulf recorded a balance of jurisdictional Accumulated Deferred Income Taxes (ADITs) to include in the Company’s capital structure for the test year of $257,098,000. (MFR Schedule D-1a) Gulf witness McMillan testified that Gulf’s capital structure has been reconciled to rate base pro rata over all sources of capital consistent with prior Commission treatment. (TR 1094) Witness McMillan also stated that tax normalization problems could result if the treatment is not consistent for all regulatory purposes. (TR 1094-1095)
OPC argued that Gulf’s deferred taxes should be decreased to $245,119,000, which is a reduction from Gulf’s requested balance of $257,098,000 and reflects a pro rata reduction associated with OPC’s recommended rate base adjustments. (OPC BR 33) OPC witness Ramas asserted that if the Commission agrees with recovery of the two turbine upgrade projects, an adjustment to ADITs should either increase the amount of deferred income taxes in the capital structure or lower rate base by $916,000 for the resulting impact of those projects on deferred income taxes. (OPC BR 34; TR 1503)
FIPUG and FRF agreed with OPC’s position on this issue. (FIPUG BR 7, FRF BR 15) FEA took no position on this issue. (FEA BR 12)
ANALYSIS
ADITs represent a cost-free source of funds resulting from timing differences associated with depreciation for book purposes versus depreciation allowed for tax purposes. (TR 1503) As the deferred taxes are included in the capital structure at zero cost, the increase in the percentage of the capital structure associated with deferred taxes is a benefit to ratepayers as it reduces the overall required rate of return. (TR 1493)
Staff believes that Gulf has reasonably relied on the Commission’s previous treatment of ADITs to include in the capital structure. Additionally, in reconciling rate base and capital structure, Gulf and the other parties agree the capital structure should be reconciled to rate base pro rata over all sources of capital. By adjusting the capital structure on a pro rata basis for the Crist Units 6 and 7 turbine upgrades, deferred taxes are increased in proportion to the percent of deferred taxes in the capital structure.
CONCLUSION
Staff recommends that the appropriate amount of accumulated deferred taxes to include in Gulf’s capital structure for the 2012 projected test year is $256,641,729.
What is the appropriate amount and cost rate of the unamortized investment tax credits to include in the capital structure?
Recommendation:
The appropriate amount and cost rate of unamortized investment tax credits to include in the capital structure are $2,923,802 and 7.66 percent, respectively, as shown on Schedule 2. (Springer, Cicchetti)
Position of the Parties
GULF:
The appropriate amount of unamortized investment tax credits to include in capital structure is $3,026,000. This amount includes adjustments to Gulf’s original request to reflect the pro-rata portion of the rate base adjustments identified in Issue 31. The appropriate cost rate is 8.34% for purposes of calculating the weighted average cost of capital. This rate includes adjustments to Gulf’s original request to reflect changes in the rates of long-term debt and preference stock as stipulated in Issues 34 and 36.
OPC:
Gulf’s requested balance of ITCs should be reduced by $136,000 related to OPC’s recommended adjustments to rate base to reflect a reconciled balance of $2,793,000. Consistent with Commission practice, the appropriate ITC cost rate should be 7.10%, calculated as a fall out by taking the weighted average cost of long-term debt, preferred stock and common equity as approved by the Commission.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of unamortized ITCs is $2,793,000, and the appropriate ITC cost rate is 7.10%.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
This issue addresses the appropriate amount and cost rate of unamortized investment tax credits (ITCs) to include in Gulf’s capital structure for the 2012 projected test year.
PARTIES’ ARGUMENTS
In its MFRs, the Company proposed that the balance of ITCs to be included in its capital structure for the test year is $2,929,000, with a cost rate of 8.45 percent. (MFR Schedule D-1a) Witness McMillan testified that the cost for ITCs of 8.45 percent was calculated in accordance with current IRS regulations and past Commission practice, using the weighted average of long-term investor sources of capital. (TR 1093) Gulf updated the balance of unamortized ITCs to be included in its capital structure for the test year to $3,026,000; and, modified the ITC cost rate to 8.34 percent to reflect changes in the stipulated cost rates of long-term debt (5.26 percent) and preferred stock (6.39 percent). (Gulf BR 33-34)
OPC asserted that Gulf’s requested balance of ITCs should be reduced by $136,000 related to OPC’s recommended adjustments to rate base to reflect a reconciled balance of $2,793,000. (OPC BR 34) OPC further asserted that the appropriate ITC cost rate should be 7.10 percent, calculated as a fall out by taking the weighted average cost of short-term debt, long-term debt, preferred stock and common equity as approved by the Commission. (OPC BR 34)
FIPUG and FRF agreed with OPC on this issue. (FIPUG BR 7, FRF BR 15) FEA adopts the position of OPC on this issue. (FEA BR 12)
ANALYSIS
Staff believes Gulf’s methodology for calculating the balance and cost rate of ITCs is appropriate and is in accordance with IRS requirements and past Commission practice. Staff recalculated the ITC cost rate based on staff’s adjustments to rate base and staff’s recommended return on equity of 10.25 percent, resulting in an ITC balance of $2,923,802 and a 7.66 percent weighted average cost rate. Staff’s weighted average cost rate for ITCs was calculated using long-term investor sources of capital in accordance with current IRS regulations and past Commission practice.
CONCLUSION
Staff recommends that the appropriate amount and cost rate of unamortized ITCs to include in Gulf’s capital structure for the 2012 projected test year are $2,923,802 and 7.66 percent, respectively.
What is the appropriate cost rate for preferred stock for the 2012 projected test year? (Category 1 Stipulation)
Approved Stipulation:
The appropriate cost rate for preference stock for the 2012 projected test year is 6.39%.
What is the appropriate cost rate for short-term debt for the 2012 projected test year? (Category 1 Stipulation)
Approved Stipulation:
The appropriate cost rate for short-term debt for the 2012 projected test year is 0.13%.
What is the appropriate cost rate for long-term debt for the 2012 projected test year? (Category 1 Stipulation)
Approved Stipulation:
The appropriate cost rate for long-term debt for the 2012 projected test year is 5.26%.
What is the appropriate return on equity (ROE) to use in establishing Gulf's revenue requirement?
Recommendation:
The appropriate ROE for the projected 2012 test year is 10.25 percent with a range of plus or minus 100 basis points. (Buys, Cicchetti)
Position of the Parties
GULF:
Evaluating both the operational and financial risks facing Gulf Power indicates that the market would expect a company with Gulf Power’s profile to earn a return of 11.7% commensurate with the risk to investors’ equity capital.
OPC:
When developing his recommendation of 11.7% ROE, Gulf witness Dr. Vander Weide gave new meaning to the expression, “Aim high.” To narrowly selected, upwardly biased assumptions and sources of data he added an unwarranted, after-the-fact, apples-to-oranges, 90 basis point upward “leverage adjustment.” (The Missouri PSC rejected his “leverage adjustment” rationale and methodology so emphatically that one of his Missouri clients directed him not to incorporate it again.) By contrast, OPC’s Dr. Woolridge drew on a robust variety of sources, which he evaluated in light of the advantages and drawbacks of each to more properly assess the conditions of capital markets and the return that is appropriate for Gulf. The Commission should adopt his recommendation of 9.25% ROE.
FIPUG:
No higher than 9.25%.
FRF:
9.25%.
FEA:
The appropriate and fair ROE for Gulf is 9.75%.
Staff Analysis:
The statutory principles for determining the appropriate return on equity (ROE) for a regulated utility have been framed by the U.S. Supreme Court in its Hope and Bluefield decisions.[23] (TR 308-310, 1374; Gulf BR 35) These two decisions define the fair and reasonable standards for determining rate of return for regulated public utilities. These standards provide that the authorized ROE for a public utility should be: (1) commensurate with returns on investments in other enterprises of similar risk; (2) sufficient to maintain the financial integrity of the utility, and (3) sufficient to maintain its ability to attract capital under reasonable terms. (TR 308-310, 1374)
While the legal and economic concepts of a fair rate of return are straight forward, the actual implementation of these concepts is controversial. Unlike the cost rate on debt that is fixed and easily measured due to its contractual terms, the return on equity is a forward-looking concept that must be estimated. (TR 306) Financial models have been developed to estimate the investor-required ROE for a company. Market-based approaches such as the Discounted Cash Flow (DCF) model, the Capital Asset Pricing Model (CAPM), and the ex ante Risk Premium (RP) model are generally recognized as being consistent with the standards for determining a fair rate of return as set forth in the Hope and Bluefield decisions.
Three witnesses testified in this proceeding regarding the appropriate ROE for Gulf. These witnesses also provided/recommended an appropriate ROE in this case. Gulf witness Vander Weide recommended an ROE of 11.7 percent. (TR 346) OPC witness Woolridge recommended an ROE of 9.25 percent. (TR 1694) FEA witness Gorman recommended an ROE of 9.75 percent. (TR 1398) Gulf’s current authorized ROE is 11.75 percent and was set in 2002.[24] Because Gulf is a wholly-owned subsidiary of Southern Company, its common stock is not publicly traded and the ROE must be estimated by applying ROE models to a proxy group of companies with comparable risk to Gulf. (OPC BR 35; TR 301, 1374, 1650) All three witnesses used variants of generally accepted financial models to derive their respective recommended ROE for Gulf. (Gulf BR 35; FEA BR 16; TR 1665-1666) The dispute among the parties is not about the models themselves, but how the models are applied and the assumptions and inputs used in the models. (Gulf BR 36; TR 1669, 1732-1734)
All three witnesses testified that the results of their respective CAPM analyses underestimate a fair ROE for Gulf at this time, and therefore, recommend the Commission give little or no weight to their CAPM results. (TR 343, 1398, 1666) Witness Vander Weide concluded that the CAPM underestimates the ROE for companies such as his proxy companies with betas significantly less than 1.0, and recommended that the Commission give little or no weight to his ROE estimates obtained from his CAPM analysis. (TR 343) Witness Woolridge testified that he relied primarily on the DCF model and gave less weight to the results of his CAPM study because he believes that the risk premium studies, of which the CAPM is one form, provide a less reliable indication of equity cost rates for public utilities. (OPC BR 41; TR 1665-1666) Witness Gorman testified that he was concerned with the low estimates produced by his CAPM analysis, and as such, he placed minimal weight on the results of his CAPM study in this proceeding. (TR 1398; FEA BR 18) Based on the witnesses’ testimony in this proceeding regarding the results obtained using the CAPM, in the interest of efficiency, staff will not address the witnesses’ arguments and testimony regarding the CAPM in this recommendation. Staff wants to be clear that it is not recommending rejecting the use of the CAPM as a generally accepted method to estimate the ROE, but in this case, the record supports assigning no weight to the witnesses’ CAPM results for purposes of determining the appropriate ROE for Gulf.
PARTIES’ ARGUMENTS
Gulf
Gulf argued that an 11.7 percent ROE is required to give investors an opportunity to earn a return commensurate with investments in other utilities having similar business and financial risk. (Gulf BR 35; TR 346) Gulf witness Vander Weide arrived at an estimate of 11.7 percent by applying several generally accepted ROE estimation methodologies to a proxy group of 24 utility companies with risk characteristics similar to those of Gulf. (Gulf BR 35; TR 316) Witness Vander Weide used the DCF model, the ex ante risk premium approach, the ex post risk premium approach, and the CAPM to estimate the appropriate ROE for Gulf. (TR 316) The average results of these ROE models, excluding the CAPM, for the proxy group was 10.8 percent. (Gulf BR 35; TR 343-344) Witness Vander Weide contended that Gulf’s rate making capital structure contains more financial leverage than the average market-value capital structure of the proxy group, and hence, has greater financial risk. (Gulf BR 35; TR 301-302) To account for the greater financial risk, witness Vander Weide made an upward adjustment of 90 basis points to the 10.8 percent ROE of his proxy group. (Gulf BR 35; TR 301) The final result of witness Vander Weide’s analysis was an ROE of 11.7 percent. (Gulf BR 35; TR 345-346; EXH 11, JVW-1, Schedule 10)
Gulf argued that the need for a financial risk adjustment is necessary because Gulf has more debt and preferred stock contained in its capital structure (54 percent on a book value basis) than the companies in witness Vander Weide’s proxy company group (45 percent on a market value basis). (Gulf BR 42; TR 1924, 1927) Gulf contended that although it has comparable business risk to the companies in the proxy group, Gulf has more financial risk for which investors will require compensation in the form of higher returns on their equity investment. (Gulf BR 42; TR 1924-1925) Therefore, Gulf argued that an upward adjustment to Gulf’s ROE is required to recognize its greater financial risk. (Gulf BR 42, TR 345, 1925)
OPC
OPC argued that the appropriate ROE for Gulf is 9.25 percent. (BR 48; TR 1650) Witness Woolridge applied the DCF model and CAPM to a proxy group of 28 electric companies. (TR 1651) Witness Woolridge’s DCF model produced a result of 9.3 percent and his CAPM produced a result of 7.6 percent. (TR 1693) Witness Woolridge testified that he relied primarily on the DCF model to estimate the ROE and believes that the DCF model provides the best measure of equity cost rates for public utilities. (TR 1665-1666) Based on the results of witness Woolridge’s DCF analysis, OPC recommends the Commission set an authorized ROE for Gulf of 9.25 percent. (OPC BR 41)
FIPUG
FIPUG did not sponsor any witness testimony regarding the appropriate ROE for Gulf. In its brief, FIPUG argued that Gulf’s request for an ROE of 11.7 percent is inflated and more than 100 basis points higher that the average authorized ROE awarded during rate cases in 2011. (FIPUG BR 8) FIPUG supported a reduction of at least 200 basis points to Gulf’s requested ROE of 11.7 percent. (FIPUG BR 8) In its brief, FIPUG stated that the dire economic conditions experienced by most of Gulf’s customers argue strongly, when combined with OPC’s expert witness testimony, that Gulfs’ request should be significantly reduced. (FIPUG BR 8)
FRF
FRF did not sponsor any witness testimony regarding the appropriate ROE for Gulf. In its brief, FRF argued that Gulf’s requested ROE of 11.7 percent is excessive and unjustified relative to current capital market conditions and the minimal risks that Gulf faces as a monopoly provider of electric service. (FRF BR 16) FRF contended that the fact Gulf recovers approximately 66 percent of its total revenue through recovery clauses reduces the risks, such as regulatory lag, that Gulf faces. (FRF BR 16) In its brief, FRF agreed with OPC that an ROE of 9.25 percent is fair, just, and reasonable for Gulf under current capital market conditions, and accordingly, Gulf does not need an ROE greater than 9.25 percent to provide safe, adequate, and reliable service. (FRF BR 16)
FEA
FEA argued that the appropriate ROE for Gulf is 9.75 percent, which FEA opined is fair compensation and would support Gulf’s financial integrity. (FEA BR 13; TR 1429) In his financial analysis, FEA witness Gorman applied three variations of the DCF model, two risk premium models, and a CAPM study to a proxy group of 21 publicly traded utilities that he determined reflects investment risk similar to that of Gulf. (FEA BR 16; TR 1374) The average results from witness Gorman’s three DCF models indicated an ROE of 9.75 percent. (FEA BR 16; TR 1387) FEA argued that using three DCF models provided a more robust estimate than relying on a single DCF model. (FEA BR 16) Witness Gorman’s risk premium analysis produced an ROE estimate in the range of 9.6 to 9.9 percent with a midpoint of 9.75 percent. (TR 1392) Witness Gorman also testified that an ROE of 9.75 percent and Gulf’s proposed capital structure are supportive of its current investment grade bond rating. (TR 1402)
ANALYSIS
DCF Model
All three witnesses relied on the results of their respective DCF models to arrive at their recommended returns on equity for Gulf. (TR 316, 1399, 1665) Gulf witness Vander Weide obtained a result of 10.7 percent, OPC witness Woolridge obtained a result of 9.3 percent, and FEA witness Gorman obtained a result of 9.75 percent. (TR 327, 1387, 1693) The DCF model is based on the assumption that investors value an asset based on the present value of the future cash flows they expect to receive from the asset. (Gulf BR 36; OPC BR 36; TR 317-318) The DCF model assumes that a company’s stock price is equal to the value of all future dividends discounted back to the present at the required rate of return. (Gulf BR 36 OPC BR 35-36; TR 319) The main differences in the results of the witnesses’ DCF models is attributed to the mathematical form of the DCF model used, quarterly or annual, and the growth rate used in the model.
Proxy Group Selection
Gulf witness Vander Weide selected his proxy group from electric companies followed by Value Line that met the following criteria: (1) paid dividends during every quarter of the past two years and did not decrease its dividends during any quarter; (2) had at least three analysts included in the EPS growth forecasts reported from Thomson Reuters I/B/E/S; (3) had an investment grade bond rating; (4) had a Value Line Safety Rank of 1, 2, or 3, and (5) were not the subject of a merger offer that has not been completed. (TR 326) Based on this selection criteria, witness Vander Weide indentified 24 companies to include in his proxy group that he testified were similar in risk to Gulf. (EXH 11, JVW-1 Schedule 1; TR 345)
OPC witness Woolridge selected his proxy group of companies from all the companies listed as electric utilities by Value Line Investment Survey and AUS Utilities Report that: (1) have at least 50 percent of its revenue from regulated electric operations; (2) have an investment grade bond rating; (3) pay a cash dividend; (4) have analysts’ long-term growth forecasts available from Yahoo, Reuters, and Zacks, and (5) are not involved in any merger or acquisition activity in the past year. (TR 1656-1657)
In its brief, Gulf argued that witness Woolridge used unreliable and inappropriate sources to select the companies in his proxy group. (Gulf BR 44) Witness Vander Weide disagreed with witness Woolridge’s selection criteria because, in his opinion, the average investor does not rely on AUS Utility Reports. (TR 1821) Witness Vander Weide also disagreed with witness Woolridge’s criterion that a proxy company must have at least 50 percent of revenue from regulated electric utility service and cited that the Hope and Bluefield decisions do not require that a proxy company must have a specific percentage of revenue from electric utility service, only that it have similar risk. (TR 1821-1822)
FEA witness Gorman selected the same electric utilities for his proxy group relied on by Gulf witness Vander Weide, but eliminated Duke Energy, Progress Energy, and Nextera Energy from his proxy group because they were involved in merger and acquisition (M&A) activity. (TR 1375)
Gulf DCF Model Application
Witness Vander Weide testified that he relied on the quarterly DCF model as opposed to the annual model because the companies in his proxy group all paid dividends quarterly and a quarterly DCF model best estimates the ROE for his proxy group. (TR 319) Witness Vander Weide obtained his estimated growth rate from the mean earnings per share (EPS) forecasts published by Thomson Reuters I/B/E/S as of December 2010, which represented three-to-five year forecasts of EPS growth by financial analysts working at Wall Street firms. (TR 321; EXH 11, JVW-1 Schedule 1) Witness Vander Weide testified that he relied on Wall Street analysts’ projections of future EPS growth rates rather than historical or retention growth rates because, “there is considerable empirical evidence that analysts’ forecasts are the best estimate of investors’ expectation of future long-term growth.” (TR 322) The simple average growth rate of his proxy group was 6 percent. (EXH 145) Witness Vander Weide included a 5 percent allowance for flotation costs in his DCF calculations. (TR 324) The 5 percent allowance equates to an upward adjustment of 26 basis points to his ROE estimate. (EXH 145) Witness Vander Weide’s DCF analysis produced a market-weighted average of 10.7 percent and a simple average of 11.4 percent for his proxy group of electric companies. (TR 327)
In his rebuttal testimony, witness Vander Weide updated his DCF model using a proxy group of 32 companies. (TR 1831; EXH 158) The simple average DCF model result decreased from 11.4 percent in his direct testimony to 10.7 percent in his rebuttal testimony. (TR 1831; EXH 11, 145, 158) Witness Vander Weide agreed that the growth component of his DCF model decreased from 6.0 percent in his direct testimony to 5.5 percent in his rebuttal testimony. (EXH 145, 158) Witness Vander Weide also agreed that based on the decrease in growth rates, one could conclude that the analysts’ EPS growth projections have decreased since the time he calculated his original DCF results in his direct testimony. (EXH 145, 158)
OPC witness Woolridge testified that witness Vander Weide’s quarterly DCF Model approach compounds the quarterly dividend payment over the first year to compute the dividend yield. Witness Woolridge contended that this adjustment essentially reinvests the dividend payments back into the stream of cash flows and generates a compounding of the dividend payments, thus inflating the return to the investor. Witness Woolridge explained that the error in this approach assumes the investor receives the quarterly dividend payments and has the option to reinvest the proceeds. (TR 1697) This reinvestment option generates its own compounding, but is not included in the actual dividend payments of the issuing company. (TR 1697)
OPC’s argument was corroborated by the academic text, New Regulatory Finance, by Roger A. Morin, PhD. (EXH 185) The text explained the result obtained from the quarterly model is an effective market-based rate of return that, although appropriate for unregulated companies, requires modification to reflect a nominal return for regulated companies because of the manner in which their revenue requirement is set. (EXH 185) In the case of a projected test year for a growing utility, the equity balance at the end of the test year exceeds the equity balance at the beginning of the test year. (EXH 185) Applying the effective return from the quarterly DCF model to the average annual equity balance will produce a higher actual effective return to the investor, and therefore, the use of the nominal return is preferable to the use of the effective return. (EXH 185) Gulf witness Vander Weide disagreed that the quarterly DCF model produces an effective return that must be adjusted to a nominal return when determining the revenue requirement. (EXH 98, 145, TR 437) Witness Vander Weide argued that the nominal return does not represent the ROE for Gulf which is determined by finding the discount rate which equates the present value of the cash flows to the market price. (TR 437) However, witness Vander Weide acknowledged that Gulf may be able to over earn or under earn its allowed cost of capital for a variety of reasons, including a change in the value of the rate base. (EXH 145) Witness Vander Weide further stated that the only thing he could do was provide the best estimate of the ROE, and someone else can determine whether Gulf would be able to over or under earn in that regard. (EXH 145)
Witness Woolridge contended that witness Vander Weide was in error by relying exclusively on the long-term EPS growth rate forecasts of Wall Street analysts in developing his DCF growth rate of 6.0 percent. (TR 1698) Witness Woolridge cited numerous studies of analysts’ earnings forecasts and testified that the studies almost unanimously concluded that analysts’ earnings forecasts are overly optimistic. Specifically, witness Woolridge cited a study reported by McKinsey on Finance in the spring of 2010, entitled “Equity Analysts: Still too Bullish” whereby he testified the study indicated that even after a decade of stricter regulation to prevent investment bankers from pressuring analysts to provide favorable projections, analysts’ long-term earnings forecasts continue to be excessively optimistic. (TR 1705) Witness Woolridge testified that he conducted a similar study using electric utility companies and the results showed that during the twenty-year period 1988 through 2008, the average quarterly three-to-five year projected and actual EPS growth rates were 4.6 percent and 2.9 percent, respectively. (TR 1706; EXH 64) Witness Woolridge concluded that, overall, the upward bias in EPS growth rate projections for electric utility companies is not as pronounced as it is for all companies, but is still upwardly-biased. (TR 1706)
Witness Vander Weide disagreed with witness Woolridge that the quarterly DCF model allows investors to earn more than their required rate of ROE. (TR 1852) Witness Vander Weide also disagreed with witness Woolridge’s assertion that the appropriate dividend yield adjustment for growth in the DCF model, according to Dr. Myron Gordon, is the expected dividend for the next quarter multiplied by four. (TR 1851) Witness Vander Weide contended that although Dr. Gordon was an early proponent of the DCF model, it does not imply that Dr. Gordon was correct is his arguments regarding the DCF model. (TR 1852) He maintained that when dividends are paid quarterly, the quarterly DCF model must be used. Witness Vander Weide testified that the quarterly DCF model offers a better estimate of investors’ required ROE than the annual DCF model, and whether a company earns more than its cost of equity depends on other external factors which cannot be known at the time the ROE is being estimated. (TR 1852)
Witness Vander Weide also refuted witness Woolridge’s criticism of his statistical studies of the relationship between analysts’ growth forecasts and stock prices. (TR 1853) Witness Vander Weide testified that his study was updated in 2004 and not outdated as claimed by witness Woolridge. (TR 1853) Witness Vander Weide testified that the updated study continues to support his conclusion that the analysts’ growth rates are more highly correlated with stock prices than historical measures such as those employed by witness Woolridge. (TR 1853-1854)
Witness Vander Weide further contended that witness Woolridge’s claim that the long-term EPS growth rate forecasts of Wall Street securities analysts are overly optimistic and upwardly biased is incorrect. (TR 1855) Witness Vander Weide testified that, to the contrary, the academic literature presents compelling evidence that analysts’ EPS forecasts are unbiased. (TR 1855) As support for his argument, witness Vander Weide identified eight published research studies that compare the accuracy of analysts’ growth forecasts to the accuracy of forecasts based on historical data. (TR 1838) He also identified seven studies that use regression techniques to test whether analysts’ growth forecasts are good proxies for investor growth expectations, and cited nine articles that studied whether analysts’ forecasts are biased toward optimism. (TR 1839-1840) However, during cross examination, OPC showed that the studies discussed in the nine articles relied upon by witness Vander Weide related to annual EPS growth and not three-to-five year growth rate forecasts. (TR 1903) Based on the empirical evidence identified in his rebuttal testimony, witness Vander Weide concluded that analysts’ EPS growth forecasts are not optimistic and are reasonable proxies for investor growth expectations, while the historical growth extrapolations and retention growth rates used by witness Woolridge are not. (TR 1843) Witness Vander Weide contended that witness Woolridge failed to recognize that the DCF model requires the growth forecasts of investors, whether accurate or not. (TR 1843)
FEA witness Gorman contended that the ROE result of 10.7 percent produced by witness Vander Weide’s DCF analysis overstated the investor-required ROE because: (1) he used excessive and unreasonable growth estimates, and (2) he relied on a quarterly compounding DCF methodology. (TR 1409-1410) Witness Gorman testified that the constant growth DCF model used by witness Vander Weide requires an estimated long-term sustainable growth rate. (TR 17409) Witness Gorman reasoned that because the growth rate used by witness Vander Weide in his DCF model (6.0 percent) exceeds the projected nominal growth rate of the U.S. Gross Domestic Product (GDP) (4.9 percent), witness Vander Weide’s DCF result of 10.7 percent is inflated and should be rejected. (TR 1409) Witness Gorman further testified that the quarterly compounding of the DCF model overstates a utility’s ROE because it provides shareholders with an opportunity to earn the dividend reinvestment return twice. (TR 1410) Witness Gorman explained that shareholders would earn the dividend reinvestment through a higher authorized ROE and through the actual receipt of the dividend and the reinvestment of the dividends throughout the year. (TR 1411) Witness Gorman contended that the double counting of the dividend reinvestment return is not reasonable and will unjustly inflate Gulf’s rates. (TR 1411) Witness Gorman further testified that the quarterly compounding component of the return is not a cost to the utility and only Gulf’s cost of common equity should be included in the authorized ROE. (TR 1411)
Witness Vander Weide disagreed with witness Gorman’s testimony that the use of a quarterly DCF model is inappropriate because the quarterly compounding component of the return is not a cost to the utility. (TR 1889) Witness Vander Weide contended that the ROE is greater when the company makes four quarterly dividend payments than when it makes a single dividend payment at the end of the year because the quarterly payment of dividends requires the company to make dividend payments sooner on average than the annual payment, and sooner payments are always more costly than later payments. (TR 1892)
OPC DCF Model Application
Witness Woolridge applied the DCF model to a proxy group of 28 electric companies that was similar to the proxy group used by Gulf witness Vander Weide. (TR 1651) Witness Woolridge’s DCF model produced a result of 9.3 percent. (TR 1693) Witness Woolridge testified that he relied primarily on the DCF model to estimate the ROE and believes that the DCF model provides the best measure of equity cost rates for public utilities. (TR 1665-1666)
Witness Woolridge testified that the constant growth version of the DCF model is appropriate for estimating the ROE for utilities. (TR 1668) This version can be expressed mathematically as the expected dividend yield in the coming year plus the expected growth rate of dividends. (TR 1668) In his DCF model, witness Woolridge derived an expected dividend yield for his proxy group of 4.6 percent and added an expected growth rate of 4.75 percent to the dividend yield to obtain an equity cost rate of 9.3 percent. (TR 1680; Exhibit JRW-10, attached to the direct testimony of J. Randall Woolridge)
To determine the dividend yield for his proxy group, witness Woolridge first obtained the dividend yields for each company in his proxy group from AUS Utility Reports for the period May 2011 through October 2011. (TR 1669-1970; Exhibit JRW-10) Witness Woolridge then determined the median dividend yield for his proxy group for the six months ended October 2011 (4.5 percent) and for the month of October 2011 (4.4 percent). (TR 1669-1670; Exhibit JRW-10) He then calculated the average of the median six-month dividend yield and the median October 2011 dividend yield to arrive at a dividend yield of 4.45 percent for his proxy group. (TR 1670; Exhibit JRW-10; EXH 155)
Witness Woolridge made an adjustment to the dividend yield to account for dividend growth in the coming year by multiplying the dividend yield by one-half of his expected growth rate. (TR 1670-1671) Witness Woolridge testified that it is common for analysts to adjust the dividend yield by some fraction of the long-term expected growth rate. (TR 1670) Witness Woolridge explained that he used this approach because companies tend to increase their dividends at different times during the year and you don’t know when a dividend increase is going to occur. (TR 1732; EXH 155) Witness Woolridge also indicated that this is the same approach used by FERC in its application of the DCF model. (TR 1732; EXH 155)
Witness Woolridge used 4.75 percent as the expected growth rate in his DCF model. (TR 1679) Witness Woolridge testified that the primary problem and controversy in applying the DCF model entailed estimating investors’ expected dividend growth rate. (TR 1669) Witness Woolridge explained that investors use some combination of historical and/or projected growth rates for earnings and dividends per share and for internal or book value growth to assess long-term potential. (TR 1671) To estimate his growth rate, witness Woolridge analyzed several measures of growth for his proxy group. (TR 1671) Those measures included a review of: (1) historical and projected growth rate estimates for EPS, dividend per share (DPS), and book value per share (BVPS) as published by Value Line; (2) average 5-year EPS growth rate forecasts of Wall Street Analysts as published by Yahoo, Reuters, and Zacks, and (3) prospective earnings retention rates and earned returns on common equity. (TR 1671) The results of witness Woolridge’s analyses showed that the average of the projected and prospective growth indicators for his proxy group was 4.6 percent. (TR 1679) Witness Woolridge testified that, giving more weight to the projected growth rates, an expected growth rate in the range of 4.5 to 5.0 percent is reasonable. He then chose the midpoint of the range, or 4.75 percent, as the growth rate in his DCF analysis. (TR 1679)
In its brief, Gulf argued that OPC’s recommended ROE of 9.25 percent is based on a flawed application of the DCF model and should be rejected. (Gulf BR 44) Gulf argued that in his DCF model, witness Woolridge used: (1) unreliable and inappropriate sources to select the companies in his proxy group; (2) an annual version of the DCF model rather than a quarterly model; (3) historical and internal growth rates and not analysts’ projected growth rates, and (4) mistakenly used zero percent instead of a 10 percent projected rate of return for Xcel Energy when calculating the average rate of return for his proxy group. (Gulf BR 44-45; TR 1821-1828)
Witness Vander Weide contended that witness Woolridge incorrectly used an annual DCF model based on the assumption that companies pay dividends only at the end of each year. (TR 1824) Witness Vander Weide explained that witness Woolridge should have used the quarterly DCF model since his proxy companies all pay dividends quarterly. (TR 1824) Witness Vander Weide disagreed with witness Woolridge’s application of the annual DCF model wherein he used one-half of the estimated growth rate as the first period growth rate. (TR 1825-1826) Witness Vander Weide contended that under witness Woolridge’s assumption that dividends grow at the same constant rate forever, he should have applied the full estimated growth rate for his first period dividend. (TR 1825)
Witness Vander Weide also disagreed with witness Woolridge’s inclusion of historical growth rates and internal growth rates to estimate his proxy group’s ROE. (TR 1826-1827) Witness Vander Weide contended that historical growth rates are inherently inferior to analysts’ forecasts because analysts’ forecasts already incorporate the historical growth rates in addition to current conditions and future expectations. (TR 1826) Witness Vander Weide contended that the internal growth rate method is logically circular and requires an estimate of the expected rate of return on equity which is multiplied by the retention ratio. (TR 1827) Witness Vander Weide testified that witness Woolridge’s DCF model would have produced an average result of 10.3 percent if witness Woolridge used the quarterly DCF model, incorporated an allowance for flotation costs, and relied on analysts’ growth forecasts to estimate the growth rate. (TR 1830-1831)
FEA DCF Model Application
Witness Gorman used three variations of the DCF model to estimate the appropriate ROE for Gulf: (1) a constant growth model using analysts’ growth projections; (2) a constant growth model using sustainable growth estimates; and (3) a multi-stage model. (TR 1387) Based on his DCF studies, witness Gorman found that a reasonable DCF return estimate is 9.75 percent. (TR 1387)
In his constant growth model using analysts’ growth estimates, witness Gorman relied on the average of the weekly high and low stock prices over a 13-week period ended September 13, 2011. (TR 1378) For his dividend estimate, witness Gorman used the most recently paid quarterly dividend as reported by Value Line Investment Survey, multiplied by four, and adjusted for next year’s growth. (TR 1378) For the analysts’ growth estimates, witness Gorman relied on the average of analysts’ projected growth rates as published by Zacks, SNL Financial, and Reuters, on September 22, 2011. (TR 1379) The average growth rate for his proxy group was 5.26 percent. (TR 1380) Witness Gorman obtained an indicated average ROE of 10.5 percent from his constant growth DCF model. (TR 1380) However, witness Gorman testified that he believed the three-to-five year growth rate estimated by analysts’ exceeds a long-term sustainable growth rate that is required by the constant growth DCF model. (TR 1380) Witness Gorman contended that utilities cannot sustain indefinitely a growth rate that exceeds the growth rate of the overall economy. (TR 1381) Witness Gorman testified that the consensus of published economists projects that the U.S. GDP will grow at a rate of no more than 4.7 percent to 5.1 percent over the next five to ten years. (TR 1380)
Witness Gorman also applied a constant growth DCF model using an estimated sustainable growth rate to his proxy group. (TR 1382) This growth rate in this method was based on the percentage of a utility’s earnings that are retained and not paid out in dividends. (TR 1382) The earnings are typically reinvested in the utility’s plant at the company’s expected ROE. (TR 1382) Witness Gorman relied on data from Value Line to estimate an average long-term sustainable growth rate of 4.66 percent for his proxy group. (TR 1383; EXH 72) Witness Gorman used the same stock price and dividend data from his DCF model using analysts’ growth estimates, but replaced the analysts’ growth rate with the sustainable growth rate. (TR 1383) Witness Gorman obtained an average result of 9.43 percent using a constant growth DCF model and an estimated sustainable growth rate. (TR 1383)
Witness Gorman performed a multi-stage DCF analysis to reflect changing growth rate expectations over time. (TR 1384) The multi-stage DCF model reflects three growth periods consisting of: (1) short-term growth for the first five years; (2) a transition period from year six to year ten, and (3) a long-term growth period starting in year eleven. (TR 1384) Witness Gorman relied on the same stock price and dividend data he used in his constant growth DCF models. (TR 1386) For the first stage short-term growth rate, witness Gorman used the same average analysts’ growth rate of 5.26 percent he used in his constant growth DCF model. For the third stage long-term growth rate, witness Gorman relied on the midpoint (4.9 percent) of the consensus economists’ projected average five-year (5.1 percent) and ten-year (4.7 percent) GDP growth rates as published by Blue Chip Economic Indicators on March 10, 2011. (TR 1385) For the second stage transition period, witness Gorman either increased or decreased the growth rate by an equal amount each year to reflect the difference between the first stage growth rate and the third stage growth rate. (TR 1384) The results of witness Gorman’s multi-stage DCF analysis indicated an ROE of 9.78 percent. (TR 1386)
Gulf argued that witness Gorman’s DCF model contained flaws similar to those of witness Woolridge’s DCF model and should be rejected. (Gulf BR 46; TR 1876-1877) Gulf’s witness Vander Weide disagreed with witness Gorman’s use of the annual DCF model to estimate Gulf’s ROE since all of the companies in his proxy group pay dividends quarterly. (TR 1876-1877) Witness Vander Weide also disagreed with witness Gorman’s exclusion of the allowance for flotation costs in his DCF model. (TR 1877) Witness Vander Weide also objected to witness Gorman’s use of a sustainable growth method to estimate the growth rate because analysts’ growth forecasts are a better proxy for investors’ growth expectations, and sustainable growth methods are logically circular regarding the rate of return. (TR 1879-1880)
Witness Vander Weide contended that witness Gorman’s three-stage DCF model is based on the assumption that investors growth expectations follow the growth rates in his three-stage DCF model. (TR 1880) Witness Vander Weide argued that witness Gorman simply assumes that rational investors would make this assumption. (TR 1880) Witness Vander Weide agreed with witness Gorman that a company cannot grow at a rate in excess of the rate of growth of the U.S. economy indefinitely, and reasoned that if so, the company would eventually take over the economy. (TR 1881) However, witness Vander Weide testified that witness Gorman failed to recognize that companies do not have to grow at the same rate forever for the single-stage DCF model to be a reasonable return on equity estimation methodology. (TR 1881)
Witness Vander Weide also disagreed with witness Gorman that investors’ growth expectations have to be rational. (TR 1879) Witness Vander Weide pointed out that in hindsight, most economists would agree that investors’ growth expectations during the tech stock boom of the late 1990s and early 2000 were irrational. (TR 1879) Witness Vander Weide contended that the DCF model requires the use of investors’ growth expectations, whether rational or irrational. (TR 1879) Witness Vander Weide testified that witness Gorman obtained a result of 10.1 percent from his DCF analysis when using analysts’ growth forecasts. (TR 1877)
Risk Premium Model
In addition to the DCF model, Gulf witness Vander Weide and FEA witness Gorman both used risk premium approaches to estimate the ROE for Gulf. (TR 327, 1388) OPC witness Woolridge did not perform a stand-alone risk premium analysis in his testimony.
Gulf RP Model
Gulf witness Vander Weide used two versions of the risk premium approach to estimate the required risk premium on an equity investment in Gulf. (TR 329) His ex ante risk premium approach produced a result of 11.0 percent and his ex post risk premium approach produced a result of 10.8 percent.
In his ex ante risk premium approach, witness Vander Weide applied his quarterly DCF model to the Moody’s group of 24 electric companies for each month from September 1999 through December 2010. (TR 329; EXH 11, JVW-1, Schedule 2; EXH 11, JVW-2, Appendix 4) He compared the results of his DCF analysis to the concurrent interest rate on Moody’s A-rated utility bonds. Witness Vander Weide then performed a regression analysis on this comparison to derive an estimated risk premium of 4.9 percent. (TR 330) He then estimated a forecasted yield to maturity on A-rated utility bonds of 6.15 percent. Witness Vander Weide then added his estimated risk premium of 4.9 percent to his forecasted yield to maturity on A-rated utility bonds of 6.15 percent to arrive at an ROE estimate of 11.0 percent. (TR 330)
In his ex post risk premium approach, witness Vander Weide performed two studies of the comparable historical earned returns for an investment in a portfolio of stocks and the yield on Moody’s A-rated Utility Bonds during the 73 year period from 1937 through 2010. (TR 330-331) In his first study, witness Vander Weide compared the return on the S&P 500 to the return on the Moody’s A-rated Utility Bonds. (TR 331) The average annual return on an investment in the S&P 500 portfolio was 11.06 and the average annual return on an investment in Moody’s A-rated Utility Bond portfolio was 6.42. (TR 331; EXH 11, JVW-1, Schedule 3) Witness Vander Weide concluded that the risk premium on the S&P 500 stock portfolio was 4.64 percent. (TR 331) Witness Vander Weide performed a second ex post risk premium study using the S&P Utility Stock Index instead of the S&P 500. (TR 331) The average annual return on an investment in the S&P Utility Stock Index was 10.5 percent which exceeded the return on an investment in Moody’s A-rated Utility Bond portfolio by 4.1 percent. (TR 331) Based on these results, witness Vander Weide concluded that equity investors today require a risk premium of approximately 4.1 to 4.6 percentage points above the expected yield on A-rated utility bonds of 6.15 percent. (TR 335) By adding the risk premium to the assumed yield on A-rated utility bonds, witness Vander Weide obtained an expected ROE in the range of 10.2 percent to 10.8 percent with a midpoint of 10.5 percent. (TR 335) Witness Vander Weide added a 26 basis point allowance for flotation costs to his midpoint estimate of 10.5 percent to obtain a result of 10.8 percent for his ex post risk premium ROE. (TR 335)
OPC argued that witness Vander Weide selected inputs to his ex post and ex ante risk premium studies that imparted an upward bias to the results. (OPC BR 41) OPC contended that when calculating the risk premium in his analysis, witness Vander Weide again used Wall Street analysts’ projections exclusively and obtained an overall return on the market of 13.3 percent which OPC believed to be unrealistic. (OPC BR 42; TR 1720)
OPC witness Woolridge testified that witness Vander Weide made errors in his RP analysis that included: (1) an inflated base interest rate; (2) excessive risk premiums, and (3) the inclusion of flotation costs. (TR 1710) Witness Woolridge contended witness Vander Weide’s projected yield on A-rated utility bonds of 6.15 percent is well above the current market rate, which is 4.5 percent. (TR 1710) In addition, he contended that witness Vander Weide’s use of A-rated utility bonds is subject to credit risk since they are not default risk-free like U.S. Treasury bonds. (TR 1710) Witness Woolridge also contended that witness Vander Weide’s DCF-based ex ante risk premium approach used the same DCF methodology employed in his stand-alone DCF model, and therefore, produced an inflated estimate of the risk premium. (TR 1711) Witness Woolridge further testified that there are a number of inherent flaws in witness Vander Weide’s ex post risk premium analysis which relies on historical returns to estimate expected equity risk premiums. (TR 1713) Measuring the equity risk premium based on historical stock and bond returns is subject to substantial forecasting errors. (TR 1716-1719)
Witness Vander Weide disagreed with witness Woolridge’s criticism of his use of A-rated bond yields as the interest rate component in his risk premium analysis. (TR 1860) Witness Vander Weide contended that the risk premium approach does not require that the interest rate be risk-free. (TR 1860) Witness Vander Weide testified the only requirement of the risk premium approach is that the same interest rate used to estimate the interest rate component be used to estimate the risk premium component. (TR 1860) Witness Vander Weide explained the interest rate derived from A-rated utility bonds is higher than the interest rate derived from government bonds, but the higher interest rate is offset by a lower risk premium. (TR 1860) The lower risk premium arises because the spread between the ROE and yield on A-rated bonds is lower than the spread between the ROE and the yield on long-term government bonds. (TR 1860)
FEA RP Model
FEA’s witness Gorman’s risk premium analyses produced an ROE estimate in the range of 9.60 percent to 9.90 percent, with a midpoint estimate of approximately 9.75 percent. (TR 1392) Witness Gorman based his risk premium analysis on two estimates of an equity risk premium over the 26-year period 1986 through the second quarter 2011. (TR 1388) In both models, witness Gorman based the common equity required returns on the average authorized returns on common equity for electric utilities as reported by Regulatory Research Associates, Inc. (TR 1388)
Witness Gorman’s first risk premium estimate was based on the difference between the required return on utility common equity investments and U.S. Treasury bonds. (TR 1388; EXH 76) Witness Gorman relied on Blue Chip Financial Forecasts, published on September 1, 2011, for the projected 30-year Treasury bond yield. (TR 1391) The average indicated equity risk premium over U.S. Treasury bond yields has been 5.21 percent with a range of 4.40 percent to 6.09 percent. (TR 1389; EXH 76) Witness Gorman added the projected 30-year Treasury bond yield of 4.2 percent to his risk premium result to obtain an indicated return on equity in the range of 8.60 percent to 10.29 percent. Witness Gorman testified that he believes an estimated range of risk premiums provides the best method to measure the current return on common equity using the risk premium methodology. (TR 1389) Witness Gorman explained that because there is a very large difference between current (3.88 percent) and projected (4.20 percent) Treasury bond rates, he recommended an equity risk premium between the midpoint and maximum of his range, or 9.90 percent. (TR 1392)
Witness Gorman based his second risk premium estimate on the spread between regulatory commission authorized returns on common equity and A-rated utility bonds. (TR 1388) Witness Gorman testified that the average indicated equity risk premium was 3.79 percent with a range of 3.03 percent to 4.62 percent. (TR 1389; EXH 77) Witness Gorman relied on the 13-week average yield on Baa-rated utility bonds for the period ended September 16, 2011, as reported by Moodys.com, to estimate his base interest rate of 5.36 percent. (TR 1392; EXH 79) Witness Gorman then added the risk premium estimate to the base interest rate and obtained a result in the range of 8.39 percent to 9.98 percent. (TR 1392) Recognizing the current low bond yields, witness Gorman recommended a return on equity of 9.60 percent. (TR 1392)
Witness Vander Weide disagreed with witness Gorman’s method of estimating the required risk premium. (TR 1882) He contended that because witness Gorman relied on the average authorized returns for other utilities, he failed to recognize that the Commission has a responsibility to make an independent assessment of the required ROE for Gulf. (TR 1882) Further, witness Vander Weide testified that witness Gorman failed to recognize that the indicated risk premium in his data tends to increase as interest rates decline. (TR 1882-1883) Witness Vander Weide contended that witness Gorman should have adjusted his result to account for the relationship between the allowed risk premium on equity and the yield on A-rated utility bonds and Treasury bonds. (TR 1883) Witness Vander Weide testified that if witness Gorman had used Value Line’s forecasted 4.9 percent yield on long-term Treasury bonds and a forecasted yield of 5.89 percent on A-rated utility bonds, he would have obtained a risk premium of 6.06 percent over Treasury bonds and 4.48 percent over utility bonds. (TR 1886) Witness Vander Weide concluded that if witness Gorman had used these risk premium estimates, he would have obtained an indicated ROE for Gulf in the range of 10.5 percent to 10.7 percent. (TR 1886)
Witness Vander Weide also addressed witness Gorman’s objection to his use of a forecasted interest rate, rather than a current interest rate in his risk premium analysis. (TR 1892) Witness Vander Weide explained that he used a forecasted interest rate because a fair rate of return standard requires that Gulf have an opportunity to earn its ROE during the period when rates are in effect, and the rates in this case will not come into effect until some time in 2012. (TR 1892) Witness Vander Weide refuted witness Gorman’s claim that his ex ante risk premium analysis would have produced an indicated ROE equal to 9.82 percent if he used the current interest rate on A-rated utility bonds equal to 4.92 percent. (TR 1893) Witness Vander Weide contended that if witness Gorman had used the current interest rate of 4.92 percent in his ex ante risk premium analysis, the resulting risk premium would have been 5.57 percent which would have indicated a ROE equal to 10.47 percent, not the 9.82 percent calculated by witness Gorman. (TR 1893-1894)
Gulf Flotation Cost Adjustment
Gulf witness Vander Weide applied an upward adjustment of 26 basis points to the results of each of his models to account for flotation costs associated with obtaining equity capital. (Gulf BR 37; TR 324) Witness Vander Weide explained that all firms that have sold securities in the capital markets have incurred some level of flotation costs and those costs must be recovered over the life of the equity issue. (TR 324)
Witness Woolridge testified that witness Vander Weide’s upward adjustment to the return on equity for flotation costs is erroneous. (TR 1725) Witness Woolridge contended that witness Vander Weide has not identified any actual flotation costs for Gulf, and those costs consist primarily of the underwriting spread or fee and not out-of-pocket expenses. (TR 1725-1726) Witness Woolridge testified that flotation costs, in the form of the underwriting spread, represent the difference between the price paid by investors and the amount received by the issuing company, and hence, these are not expenses that must be recovered through the regulatory process. (TR 1726-1727)
Witness Gorman testified that witness Vander Weide’s flotation cost adjustment is not based on Gulf’s actual common stock flotation cost and should therefore be rejected. (TR 1409) Witness Gorman contended that witness Vander Weide derived his flotation cost adjustment based on published academic literature. (TR 1409) Witness Gorman reasoned that because witness Vander Weide does not show that his adjustment is based on Gulf’s actual and verifiable flotation expenses, there simply are no means of verifying whether witness Vander Weide’s proposal is reasonable or appropriate. (TR 1409)
Witness Vander Weide disagreed with witness Woolridge’s assertion that Gulf did not provide any evidence it incurs flotation costs when it issues new equity. (TR 1869) Witness Vander Weide explained that although Gulf does not issue equity in the capital markets, Southern Company must issue equity to provide financing to Gulf to make investments in its electric utility operations in Florida. (TR 1869) Witness Vander Weide reasoned that if Southern Company is not able to recover its flotation costs through Gulf’s rates, it will not be able to recover the full cost of issuing equity invested in Gulf. (TR 1869)
Gulf Financial Leverage Adjustment
Witness Vander Weide testified that the ROE for his proxy company group depends on the companies’ financial risk, which is measured by the market values of debt and equity in their capital structures. (TR 301) Witness Vander Weide testified that the financial risk of Gulf as reflected in its rate making capital structure is greater than the financial risk embodied in the ROE estimates for his proxy group. (TR 302) Gulf’s rate making capital structure contains 46 percent common equity and the average market value capital structure for his proxy group contains 55 percent common equity. (TR 302) Therefore, witness Vander Weide reasoned that the ROE for his proxy group must be adjusted to reflect the higher financial risk associated with Gulf’s rate making capital structure as compared to the average market-value capital structure of his proxy group. (TR 301)
Witness Vander Weide contended that one must adjust the indicated ROE for his proxy group upward in order for investors to have an opportunity to earn a return on their investment in Gulf that is commensurate with returns they could earn on other investments of comparable risk. (TR 301-302) Witness Vander Weide made an upward adjustment of 90 basis points to the indicated ROE for Gulf so that mathematically the weighted average cost of capital for Gulf is equal to that of his proxy group. (TR 301, 304; EXH 11, JVW-1, Schedule 10) Making this adjustment resulted in witness Vander Weide’s recommended ROE for Gulf of 11.7 percent. (TR 301)
Gulf asserted that the market value of equity was determined by multiplying the stock price by the number of common equity shares outstanding. (EXH 108, No. 286) Witness Vander Weide agreed that the stock price reflects the risks associated with the security as perceived by informed investors, and those investors understand that the traditional rate base - rate of return form of regulation used by the Commission is applied to the book value of the assets. (TR 362-363) Gulf asserted that because the market value and book value of debt are generally similar, analysts typically use the book value of debt as a proxy for the market value of debt. (EXH 108, No. 286) Witness Vander Weide was asked several times to compare Gulf’s rate making capital structure to the equivalent book value capital structures of the companies in his proxy group but declined to do so. (EXH 108, 145) Witness Vander Weide argued that the book value capital structure is not relevant for the purpose of estimating the cost of equity because the cost of equity does not reflect the book value capital structures, it reflects the market value capital structures. (EXH 145)
OPC argued that there was no basis for witness Vander Weide’s upward financial leverage adjustment of 90 basis points. (OPC BR 42) OPC argued that investors are aware of both book value-based and market value-based capital structures and the different uses made of them. (OPC BR 42; TR 362-363) OPC contended that investors assess all risks associated with a security, regardless of how financial risk is measured, and those perceptions are reflected in the price they are willing to pay for the stock. (OPC BR 42; TR 362; EXH 145) OPC argued that the Commission should reject witness Vander Weide’s rationale and the adjustment that accompanies it. (OPC BR 46)
Witness Woolridge testified that witness Vander Weide’s leverage adjustment of 90 basis points is unwarranted because the market value of Gulf’s equity exceeds the book value which indicates the Company is earning an ROE in excess of its cost of equity. (TR 1727-1728) Witness Woolridge testified that a firm that earns an ROE above its cost of equity will see its common stock sell at a price above its book value, and conversely, a firm that earns an ROE below its cost of equity will see its common stock sell at a price below its book value. (TR 1661) To assess the relationship by industry, witness Woolridge performed a regression study between the estimated ROE and market-to-book ratios using gas distribution, electric utility and water utility companies. (TR 1662) Witness Woolridge concluded that the results of his study demonstrate that there is a strong relationship between returns on equity and the market-to-book ratios for public utilities. (TR 1662) Hence, witness Woolridge contended that for a utility with a relatively high market-to-book ratio and ROE, the leverage adjustment will increase the estimated equity cost rate. (TR 1729) Witness Woolridge further testified that Gulf’s financial statements and fixed financial obligations remain the same, and thus, there is no need for a leverage adjustment because there is no change in leverage. (TR 1728) Witness Woolridge also testified that financial publications and investment firms report capitalizations on a book value and not a market value basis. (TR 1728) Finally, witness Woolridge contended that witness Vander Weide’s leverage adjustment has not been accepted by regulatory commissions because it increases the ROE for utilities that have high returns on common equity and decreases the ROE for utilities that have low returns on common equity. (TR 1728)
Witness Gorman testified that witness Vander Weide’s leverage adjustment is without merit and should be rejected. (TR 1406) Witness Gorman contended that the implicit premise of witness Vander Weide’s leverage adjustment is that book value capitalization is measured differently than market value capitalization. (TR 1405) Witness Gorman contended that Gulf’s financial risk is tied to its book value capitalization which in turn drives its market value capitalization, and therefore, are not separate factors. (TR 1405-1406) Witness Gorman contended that a utility’s financial risk relates to its ability to generate the internal cash flows necessary to meet its financial obligations. (TR 1406) Witness Gorman testified that these internal cash flows drive stock valuations which produce the market capitalization structure. (TR 1407) Witness Gorman explained that book value leverage represents the utility’s contractual obligations to pay debt interest and principal payments, and therefore, best describes the financial obligations in relation to the cash flows produced. (TR 1407)
Witness Gorman further testified that witness Vander Weide’s leverage adjustment is nothing more than a flawed market-to-book ratio adjustment which would produce an excessive return on incremental utility plant investments. (TR 1406) Witness Gorman explained that if Gulf were to repurchase its own stock, it would expect to earn a market-based return of 10.8 percent based on witness Vander Weide’s recommended ROE results. (TR 1408) However, witness Gorman explained, if the Commission accepted witness Vander Weide’s leverage adjusted ROE, Gulf could earn a return of 11.7 percent on incremental utility plant investments. Witness Gorman contended that under witness Vander Weide’s proposal, Gulf would be encouraged to gold-plate utility plant investment because it would be provided with an above-market risk adjusted return on such investments. (TR 1408) Witness Gorman concluded that providing Gulf with an incentive to earn more than a fair risk adjusted return on utility plant investments would result in rates not being just and reasonable. (TR 1408)
Witness Vander Weide testified that witness Woolridge’s regression analysis for his electric utilities does not support his claim that a market-to-book ratio above 1.0 indicates that a company is earning more than its cost of equity. (TR 1849) Witness Vander Weide testified that of the 54 electric utilities in witness Woolridge’s market-to-book study, 25 have returns on equity less than 9.25 percent, and only seven of those 25 companies have market-to-book ratios less than 1.0. (TR 1849) The average ROE for the 25 companies is 7.1 percent and their average market-to-book ratio is 1.23. Witness Vander Weide contended that the data contradicts witness Woolridge’s claim. (TR 1849) Witness Vander Weide testified that he updated witness Woolridge’s study using current Value Line data as of October 2011. (TR 1850) He found that of the 53 electric utilities followed by Value Line, 19 have returns on equity below 9.25 percent and only four of the utilities have market-to-book ratios less than 1.0. (TR 1850) Witness Vander Weide concluded that the data provided evidence that witness Woolridge’s hypothesis regarding the relationship between returns on equity and market-to-book ratios is incorrect. (TR 1850)
Witness Vander Weide disagreed with witness Woolridge’s criticism of his financial leverage adjustment. He disagreed that his financial risk adjustment assumes a change in Gulf’s capital structure as expressed by witness Woolridge. (TR 1873) Witness Vander Weide testified that the observation that financial publications report capitalization on a book value basis, as testified to by witness Woolridge, does not undermine the validity of his financial risk adjustment. (TR 1874) Witness Vander Weide testified that he did not state, as witness Woolridge claimed, that he could not indentify any proceeding in which he testified wherein the regulatory commission adopted his leverage adjustment. (TR 1874) Witness Vander Weide clarified his statement that he does not maintain records of regulatory decisions or a list of all cases in which commissions have accepted his recommendations. (TR 1874) Witness Vander Weide reiterated that he was generally aware that financial adjustments similar to that which he proposed have been adopted in Pennsylvania and Canada, and that many states use market value structures to determine utility property taxes. (TR 1874)
Witness Vander Weide reiterated that he made an upward adjustment of 90 basis points to the results of his ROE analysis for his proxy group of companies to reflect the average difference between the financial risk of his proxy group as measured by market value capital structure and the financial risk reflected in Gulf’s recommended book value capital structure. (TR 1887) Witness Vander Weide disagreed with witness Gorman’s definition of financial risk and contended that witness Gorman’s definition reflects the viewpoint of debt investors, not the viewpoint of equity investors. (TR 1888) Witness Vander Weide testified that debt investors are concerned with a company’s ability to cover the interest and principal payments on its debt, while equity investors are primarily concerned with the forward-looking variance of return on their investment. (TR 1888) Witness Vander Weide contended that the forward-looking variance of return on investment depends on a company’s market value capital structure, not its book value capital structure. (TR 1888) Witness Vander Weide contended that the equity investors’ point of view is the only one that is relevant for determining the return on equity. (TR 1888)
Gulf witness Vilbert responded to the testimony of witnesses Woolridge and Gorman regarding the measurement of financial leverage and its impact on a regulated utility’s allowed ROE. (TR 1908) Witness Vilbert testified that the disregard of market value capitalization in measuring a company’s financial leverage and risk is a fundamental flaw in witnesses Woolridge’s and Gorman’s testimony. (TR 1909) Witness Vilbert testified that witnesses Woolridge and Gorman made an incorrect assertion when they claimed that no leverage adjustment is needed because financial risks are properly measured by the book value capital structure. (TR 1911) Witness Vilbert contended that the notion that financial leverage is and should be measured on a market value basis is supported in every textbook on corporate finance of which he is aware. (TR 1912) Witness Vilbert testified that even witness Woolridge’s text, Applied Principles of Finance, uses market values to illustrate the computation of the overall cost of capital. (TR 1912)
Witness Vilbert testified that, based on the financial leverage theorems on the relationship between the ROE and financial leverage developed by Franco Modigliani and Merton Miller, financial leverage does not increase the market value to a firm as long as different combinations of debt and equity can be selected by the investors themselves. (TR 1914-1915) Witness Vilbert explained that to implement this financial construct, investors have to be able to buy and sell debt and equity at market prices to achieve their desired combination. (TR 1915) Witness Vilbert also testified that economists generally prefer to use market values rather than historical values because market values convey timely information about the assets. (TR 1915)
Witness Vilbert criticized witness Gorman’s claim that financial leverage is measured by the sufficiency of the firm’s operating cash flows to meet the contractual book value obligations. (TR 1918) He agreed that a firm’s debt obligations are typically defined in book value terms, and a firm’s cash flows are their primary source of debt repayment, but explained that the market value of the firm is also a key determinant of a firm’s debt capacity and borrowing cost. (TR 1918) Witness Vilbert disagreed with witness Woolridge that market values in excess of book values indicates a company is earning an ROE greater than its cost of equity. (TR 1918) Witness Vilbert agreed that, all else being equal, mathematically, a higher ROE gives rise to a higher market value of equity, and a higher market to book ratio. (TR 1918) However, witness Vilbert contended that all else is not equal in real life. (TR 1919) Witness Vilbert testified that witness Woolridge provided very little information on how he created his statistical analysis in Exhibit 57, on which he relied upon, that graphically showed a positive correlation between a utility’s estimated ROE and its market-to-book ratio. (TR 1919) Witness Vilbert contended that statistically, correlation does not necessarily mean a cause-and-effect relationship, and the empirical evidence to support witness Wooldridge’s contention falls short. (TR 1919) Witness Vilbert testified that due to flaws in witness Wooldridge’s statistical assumptions, the positive correlation simply shows that the price to earnings ratio is positive for the utility companies. (TR 1919)
Witness Vilbert contended that the results of witness Woolridge’s analysis did not support his contention that above-market returns on equity, and no other factors, contribute to the utilities’ market value exceeding book value. (TR 1919-1920) Witness Vilbert testified that some of the factors not considered by witness Wooldridge were: (1) some of the companies used in his regression analysis have unregulated lines of business that may have higher growth opportunities; (2) the utilities are subject to an allowed ROE and actual returns depend on external factors such as consumer demand, supply shocks, weather, etc.; (3) investor demand for safe haven investment could also increase the market-to-book ratios for utilities, and (4) estimated accounting returns could be affected by rate freezes, regulatory lag, and adjustments to rate components such as depreciation. (TR 1920)
Financial Integrity
FEA witness Gorman testified that an authorized ROE of 9.75 percent will support internal cash flows that will be adequate to maintain Gulf’s current investment grade bond rating. Witness Gorman reached his conclusion by comparing the key credit rating financial ratios for Gulf at its proposed capital structure, with a 9.75 percent ROE to Standard and Poor’s (S&P) benchmark financial ratios using S&P’s new credit metric ranges. (TR 1399) Witness Gorman testified that by performing this analysis he was attempting to determine whether the rate of return and cash flow generation opportunity reflected in his proposed rate of return for Gulf will support target investment grade bond ratings and Gulf’s financial integrity. (TR 1400-1401) Witness Gorman testified that Gulf currently has an “A” corporate bond rating from S&P. (TR 1368) Witness Gorman testified that, “At my recommended return on equity and Gulf Power’s proposed capital structure, the Company’s financial credit metrics are supportive of its current investment grade bond rating.” (TR 1402)
Gulf witness Teel testified that the ROE of 9.75 percent recommended by FEA witness Gorman is not supportive of Gulf’s credit ratings. Witness Teel contended that witness Gorman’s conclusion that 9.75 percent would allow Gulf to maintain its current investment grade bond rating is wrong. (TR 1956) Witness Teel testified that the lower threshold for an investment grade rating are BBB- for S&P and Fitch, and Baa3 for Moody’s. (TR 1951) Witness Teel testified that S&P rates Gulf’s long-term debt as A, while Fitch and Moody’s ratings are A and A3, respectively. (TR 1950) Witness Teel testified that Gulf targets A ratings by S&P and Fitch, and A2 by Moody’s for its long-term debt. (TR 1951) Witness Teel testified that witness Gorman used bond ratings below that of Gulf’s current bond rating as the basis for his analysis, and his analysis was too limited to reach any conclusions regarding the effect a 9.75 percent ROE would have on Gulf’s credit ratings. (TR 1950) Witness Teel contended that witness Gorman’s evaluation was limited to only one of three credit rating agencies (S&P) and did not consider the qualitative factors, such as the agencies’ assessment of the regulatory environment in Florida, which are key drivers of a utility’s credit ratings. (TR 1951) Witness Teel testified that an authorized rate of return below the return required by investors would increase the concerns of the rating agencies about the regulatory environment in Florida. (TR 1954)
Witness Gorman acknowledged that S&P used to have a very detailed matrix of credit rating metrics that assigned business risk and bond ratings as BBB, A, and AA, but that S&P changed its credit metric calculations about five years ago. (EXH 156) Witness Gorman acknowledged as much by stating, “So unfortunately when they [S&P] did that, it’s not as direct to be able to state that the credit metrics at this range with this business risk corresponds with either a BBB or a single A bond rating because the metrics themselves are not that transparent any longer.” (EXH 156)
Average Authorized Returns
Exhibit 186 contains a list of the authorized returns on equity awarded by state regulatory authorities to integrated electric utility companies throughout the country during 2011 as reported by SNL Financial. The document showed that the authorized returns on equity ranged from a low of 9.8 percent to a high of 12.3 percent and averaged 10.4 percent for the group. (EXH 186) However, witness Gorman testified that the average was skewed upward due to the 12.3 percent ROE awarded to Virginia Electric Power Company (VEPCO). (TR 1436) Witness Gorman testified that the 12.3 percent ROE was dedicated to a specific generating facility only, not the overall integrated utility company. (TR 1436) If the 12.3 percent ROE awarded to VEPCO was removed from the group, the average authorized ROE for 2011 would be about 10.1 percent. (TR 1436) Witness Gorman acknowledged his recommended ROE of 9.75 percent was less than the industry average in 2011. (TR 1437) Excluding the two VEPCO decisions related to the specific generating plants, witness Vander Weide’s recommended 11.7 percent ROE would be the highest allowed ROE authorized in 2011. (EXH 186)
CONCLUSION
The witnesses’ recommended returns on equity suggest the appropriate authorized ROE for Gulf is within the range of 9.25 percent to 11.7 percent. (TR 346, 1398, 1694) Based on a review of the testimony and evidence regarding the witnesses’ models presented in this proceeding, staff believes the record supports an ROE for Gulf in the range of 9.75 percent to 10.75 percent. (TR 1387, 1693)
Each witness relied heavily on the results of their respective DCF models to arrive at their recommended ROE for Gulf. (TR 346, 1398, 1694) The results of the witnesses’ DCF analyses produced a range of 9.3 percent to 10.7 percent. (TR 327, 1387, 1693) The primary reasons for the differences in the witnesses’ DCF model results relate to the version of model used, and the growth rate included in the DCF model. (Gulf BR 36; TR 1653, 1669, 1732-1734) As discussed in staff’s analysis, each witness testified to the merits of their own analysis and the flaws of their counter-party’s analyses. Recognizing that the top end of the range represents results from a quarterly compounded DCF model based exclusively on Wall Street analysts’ EPS growth forecasts, staff believes 10.7 percent is a high estimate of the investor-required return. (TR 320-321, 1697-1698) Conversely, staff believes the bottom end of the range is a low estimate based on an annual DCF model that relied on an average of historical and projected growth rates for EPS, dividends per share, and an internal growth rate based on retained earnings. (TR 1671, 1825-1827)
Academic studies and other empirical research have shown that risk premium models based on historical earned returns are poor predictors of current market expectations. (TR 1713-1719) Consequently, staff has reservations regarding the reliability of the results of the witnesses’ ex post risk premium studies. (TR 335, 1391) Staff notes that witness Vander Weide’s risk premium of 4.9 percent used in his ex ante risk premium model is not significantly greater than the 4.62 percent risk premium witness Gorman’s used in his ex ante risk premium model. (TR 330, 1392) Witness Gorman’s ex ante RP result was 9.75 percent and witness Vander Weide’s was 11.0 percent. (TR 330, 1392) Witness Vander Weide revised his result to 10.9 percent using more recent projections. (EXH 98) Staff concurs with witnesses Woolridge and Gorman that the projected yield on A-rated utility bonds of 6.15 percent used in witness Vander Weide’s ex ante RP analysis is unreasonably high based on more recent bond yield projections. (TR 1710; EXH 98)
While it has been the Commission’s practice to recognize an adjustment for flotation costs in certain applications, such as the leverage formula for water utilities, staff believes the evidence in the record does not support a specific allowance for flotation costs that should be added to the ROE. (Gulf BR 37-38, TR 1831) However, staff recognizes that there are costs incurred when a firm issues equity and those costs should be recovered within the ROE. (TR 1869) In this context, the debate over whether to include or not include an allowance for flotation costs is similar to the debate over whether to use an annual or quarterly DCF model or a composite growth rate or an earnings-only growth rate in the DCF analysis. Staff’s recommendation does not recognize a specific adjustment for flotation costs but takes into consideration the witnesses’ testimony and analyses regarding an allowance for flotation costs. (TR 1408-1409, 1725-1727, 1869-1870)
Staff does not believe witness Vander Weide’s proposed 90 basis point leverage adjustment to his estimated ROE is appropriate. (FEA BR 21, TR 1727-1728) Staff believes the mixing of market value and book value capitalization ratios in the formula is flawed. (TR 1727-1728) Witness Vander Weide acknowledged that Gulf’s book value capital structure was appropriate for ratemaking purposes. (EXH 145) In addition, he was asked several times to make a comparison of Gulf’s ratemaking capital structure to the equivalent book value capital structures of the companies in his proxy group but declined to do so. (EXH 108, 145) Although witness Vander Weide testified that his leverage adjustment was accepted in part in an order issued March 10, 2005, by the Missouri Public Service Commission, subsequent orders by the same Commission rejected the methodology. (OPC BR 44, TR 373-375, EXH 98, 181, 182) The record showed that witness Vander Weide was unable to identify any other Commission decisions involving an electric utility that had recognized his leverage adjustment.
Due to the reliance on historical earned returns to estimate the current risk premium in the ex post RP models, concerns over the exclusive reliance on Wall Street analysts’ EPS growth rates in the DCF analysis, use of a quarterly DCF model without an adjustment to recognize the difference between the effective and nominal rate of return, and the decision to recognize an inappropriately quantified leverage adjustment, staff believes Gulf’s requested ROE of 11.7 percent overstates the current investor-required ROE for Gulf. Conversely, staff believes that OPC’s recommended ROE of 9.25 percent may understate Gulf’s required rate of return because Gulf’s most recent issuance of long-term debt was completed at an effective cost rate of 5.75 percent and OPC witness Woolridge testified that academic studies indicate the forward-looking risk premium is between 4 percent and 5 percent. (TR 1655, 1659)
Finally, Exhibit 186 showed that the authorized ROEs set during 2011 for integrated electric utilities as reported by SNL Financial ranged from a low of 9.8 percent to a high of 11.35 percent and averaged 10.1 percent. (EXH 186; TR 1435-1436) While staff’s recommended ROE for Gulf is based upon an independent assessment of the testimony and evidence in the record, the authorized ROEs from Commissions in other jurisdictions serve as a gauge to test the reasonableness of staff’s recommended ROE for Gulf.
Based on its review of the record, staff recommends an authorized ROE of 10.25 percent with a range of plus or minus 100 basis points. In arriving at this return, staff has identified and weighed the strengths and weaknesses associated with the respective witnesses’ analyses and also taken into account Gulf’s need to continue to access the capital markets under reasonable terms. Staff believes, at an equity ratio of 46 percent, an authorized ROE of 10.25 percent is supported by competent, substantial evidence in the record and satisfies the standards set forth in the Hope and Bluefield decisions of the U.S. Supreme Court regarding a fair and reasonable return for the provision of regulated service.
What is the appropriate weighted average cost of capital including the proper components, amounts and cost rates associated with the capital structure?
Recommendation:
The appropriate weighted average cost of capital for the projected test year is 6.39 percent. (Springer, Cicchetti)
Position of the Parties
GULF:
Based on an 11.7% cost of equity, the appropriate weighted average cost of capital for Gulf is 6.94% for the projected 2012 test year. The weighted average cost of capital has been revised from 7.05% as originally filed to reflect actual rates of all permanent financing impacting the projected test year, including senior notes and preference stock, revised rates for short-term debt and variable rate pollution control bonds.
OPC:
Using Gulf’s proposed capital structure ratios, and after adjustments for the rates for the stipulated rates for short-term debt, long-term debt, and preferred stock, and OPC witness Woolridge’s recommended ROE and ITC amortization rates, the appropriate weighted average cost of capital is 6.00%.
FIPUG:
5.89%.
FRF:
5.89% (Regulatory Capital Structure basis).
FEA:
Using Gulf’s proposed capital structure ratios, costs, and FEA witness Gorman’s ROE of 9.75%, the appropriate weighted average cost of capital is 6.30%.
Staff Analysis:
Based upon the decisions in preceding issues and the proper components, amounts, and cost rates associated with the capital structure, staff calculated a weighted average cost of capital of 6.39 percent. The capital structure has been reconciled to rate base pro rata over all sources of capital.
As discussed in Issue 32, staff recommends the appropriate balance of ADITs is $256,641,729. As discussed in Issue 33, staff recommends the appropriate amount and cost rate of unamortized ITCs are $2,923,802 and 7.66 percent, respectively. A stipulation between the parties in Issues 34, 35, and 36 has established the appropriate cost rate rates for long-term debt at 5.26 percent, short-term debt at 0.13 percent, and preferred stock at 6.39 percent. As discussed in Issue 37, staff recommends 10.25 percent as the appropriate mid-point return on common equity.
The net effect of these adjustments is a decrease in the overall cost of capital from the 7.05 percent return requested by Gulf to a return of 6.39 percent recommended herein. Schedule 2 shows the recommended test year capital structure. Based upon the proper components, amounts, and cost rates associated with the capital structure for the test year ending December 31, 2012, staff recommends that the appropriate weighted average cost of capital for Gulf for purposes of setting rates in this proceeding is 6.39 percent.
Is Gulf compensated adequately by the non-regulated affiliates for the benefits, if any, they derive from their association with Gulf Power? If not, what measures should the Commission implement?
Recommendation:
Yes. Gulf is adequately compensated by the non-regulated affiliates through services that it receives at-cost, shared resources it uses to augment its employees that result in cost savings, and access to a centralized pool of professionals that would be difficult to replicate at the Company level. Thus, no additional measures should be implemented by the Commission to compensate Gulf, and no adjustment should be made to compensate the regulated operating companies as discussed in Issue 40. (Trueblood, Mouring)
Position of the Parties
GULF:
The Commission should not implement any measure to “compensate” Gulf Power for alleged benefits derived by Southern Company’s non-regulated affiliates from their association with Gulf Power.
OPC:
No. The non-regulated companies receive significant intangible benefits that the regulated electric companies developed over the years and have provided to the non-regulated companies at no cost simply by their close affiliation and association. An adjustment should be made to compensate the regulated electric companies as discussed in Issue 40.
FIPUG:
No. Agree with OPC.
FRF:
No.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan testified that Southern Company Services (SCS) is a subsidiary of the Southern Company, and an affiliate to Gulf, which provides services at-cost to Southern Company and its other subsidiaries. Gulf is a subsidiary of the Southern Company and receives professional and technical services from SCS, such as general design and engineering for transmission and generation; system operations for the generating fleet and transmission grid; and various corporate services and support in areas such as accounting, supply chain management, finance, treasury, human resources, information technology, and wireless communications. (TR 1101)
Gulf argued the services SCS provides to Gulf would normally be performed by Gulf’s employees. By using the services of the affiliate company, SCS, which is provided at-cost, Gulf is able to augment its personnel in specialized areas which provides Gulf the advantages of a stable utility workforce and economies of scale associated with specialized employees serving a larger organization. Gulf argued that if additional employees were hired instead of relying on SCS employee time or employee time of another operating company, Gulf’s costs would be higher. (EXH 117, No. 228)
Witness McMillan argued that Gulf and its customers receive several benefits from the services provided by SCS. Gulf is a smaller operating company and SCS provides Gulf access to shared resources, which enables Gulf to avoid duplication of personnel and to utilize the talent of a centralized pool of professionals on an ongoing basis. He asserted that the Company and its customers also benefit from the services received from SCS through cost savings due to economies of scale and access to highly trained professionals that would be difficult to replicate at the Company level. (TR 1102; TR 1153-1154) Witness McMillan testified that SCS provides technical and professional services and costs are allocated based on the service provided and the most cost causative type allocator identified for that type of service. He added, Gulf has personnel that helps with hiring and personnel activities, but services are not duplicated. (TR 1152-1154)
Furthermore, witness McMillan contended Rule 25-6.1351(3), F.A.C., cited by OPC witness Dismukes that addresses transactions with affiliates, does not apply to services provided by SCS to Gulf because SCS exists solely to provide services to the Southern Company corporate family. Also, the Rule does not apply to services provided between Gulf and its regulated affiliates.[25] (TR 2341) In addition, Gulf provided explanations and documentation that show how affiliate costs were allocated for years 2007 through June 30, 2011 and explained why certain revenues and expenses increased and decreased during these years. (EXH 113, No. 48; EXH 117, No. 230; EXH 138, No. 37)
Gulf witness Teel pointed out that OPC witness Dismukes’ testimony may be interpreted to state that Southern Company’s non-regulated affiliates receive benefits to their credit ratings from association with the regulated operating companies. However, he testified that Southern Power Company (SPC) is the only non-regulated affiliate of the Southern Company that is rated by the credit rating agencies, and neither the Southern Company nor its subsidiaries are incorporated into the rating of SPC. (TR 1955-1956)
Gulf witness Deason addressed OPC witness Dismukes’ contention that a 2 percent compensation payment in the amount of $1.5 million should be assessed the non-regulated companies to compensate the regulated companies for intangible benefits they receive, at no cost, through their affiliation with the regulated companies. He asserted that such payment would be imputed and Gulf would not actually receive revenue because imputed revenue is not real payments but an amount used for regulatory purposes to assign a benefit from one company to another. (Gulf BR 51) Witness Deason, however, stated that the imputed revenue would result in Gulf having less actual revenue per year to pay its actual expenses or to invest in infrastructure to serve its customers. (TR 2111)
Witness Deason argued the financial implications would be real and the Company’s actual achieved ROE and its interest coverage would decline and the Company would have to go to the capital markets to cover its short term cash needs. He asserted that the real effect of OPC witness Dismukes recommendation would result in reduced customer rates simply because the Southern Company investments in the non-regulated markets have created additional revenues for the Southern Company. (TR 2112)
Under OPC witness Dismukes’ recommendation, witness Deason stated that real benefits from the non-regulated businesses would flow to Gulf’s customers, even though Southern Company made the investment and is at risk for its capital investment. He argued that Gulf’s customers made no investment and they are not at risk should the non-regulated businesses fail, yet they would still receive benefits equal to two percent of the non-regulated companies’ revenue. (TR 2112)
Gulf’s witness Deason testified that OPC witness Dismukes cited the United Telephone Company Order[26] issued by the Commission in 1989 as support for the imputed revenues she recommends. Witness Deason argued that the language quoted by witness Dismukes is incorrect, not relevant to the facts in this case, pre-dates the adoption of the Rule 25-6.1351, F.A.C., which sets forth the Commission’s policy on cost allocations and affiliate transactions, and should not be used as a basis to impute non-regulated revenue to Gulf. He maintained that witness Dismukes’ language appears to indicate that the Commission embraced the concept of imputing revenue as an ongoing practice, even though the Commission subsequently struck the paragraph in the Order that she cited as support for her assertion. Moreover, witness Deason argued that in the United Telephone Company’s decision, the Commission did not require an imputation based on total revenue, instead, it allowed the revenue of United Telephone Long Distance (UTLD) to be reduced by the access charges UTLD had to pay to reach the local network. He also argued that the facts and circumstances leading to the Commission’s decision in 1985 (sic) and witness Dismukes recommendation to impute revenues to Gulf in 2011 are contrastively not the same. (TR 2113-2118; Gulf BR 51-52)
Finally, witness Deason asserted that the Commission’s policy on cost allocations and affiliate transactions are found in Rule 25-6.1351, F.A.C., and non-regulated subsidiaries are not required to impute revenues to a regulated utility pursuant to this Rule. Therefore, he testified that the Commission should reject witness Dismukes recommendation because it is unsupported by the facts, violates principles of good regulatory policy, and would penalize Gulf for being part of the Southern Company. (TR 2112-2118; Gulf BR 51)
OPC
OPC witness Dismukes testified about the importance of examining transactions between affiliates and regulated companies. She argued that Gulf and its affiliates have a close relationship as members of the same corporate family, which makes it necessary for the cost allocation and pricing methodologies to be periodically scrutinized to ensure that the regulated companies are not subsidizing the non-regulated companies. As a result of the relationship between Gulf and its affiliates, which contributes to expenses included on the Company books, there still exists an incentive to allocate or shift costs from non-regulated companies to regulated companies to reap higher profits for shareholders, even though an established methodology for the allocation and distribution of affiliate costs are in place. Witness Dismukes pointed out that Commission Rule 25-6.1351, F.A.C., specifies criteria for electric utilities that do business with affiliates and she cites subsection (3) which states that the purchases from the utility by the affiliate must be at the higher of fully allocated cost or market price. It further states that purchases from the affiliate must be at the lower of fully allocated cost or market price. (TR 1601-1602; TR 1639-1641)
Witness Dismukes testified that the Commission has addressed affiliate transactions in a prior order.[27] She maintained that it is the utility’s burden to prove its costs are reasonable, and the standard to use in evaluating affiliate transactions is whether those transactions exceed the going market rate or otherwise are inherently unfair. (TR 1603-1605)
Gulf is one of four regulated utilities of the Southern Company, which includes several non-regulated subsidiaries.[28] Witness Dismukes pointed out that Southern Company’s non- regulated activities have increased in recent years and Gulf engages its affiliates for a variety of services. Specifically, Gulf contracts with SCS for a variety of managerial and professional services, Alabama Power for mail processing services, Georgia Power and Mississippi Power for shared plant costs, Southern Nuclear for sitting services, SouthernLINC for wireless services, and Southern Management for financial services. Witness Dismukes also asserted that Gulf provides various services to its affiliates, such as office space, information technology, and power sales. (TR 1605-1608)
Background information regarding the Southern Company was provided that recounts the history of the company, when operations were diversified, and how it expanded over the years to address the whole market. (TR1610-1612) Witness Dismukes asserted that the non-regulated companies benefit from the operating companies’ reputation, goodwill, and corporate image; association with large, financially strong, well-entrenched electric companies; and personnel from the service company. She also attributed, in part, Southern Company’s high credit rating to the stable cash flows and financial support it receives from its four regulated utility operating companies. (OPC BR 50) Witness Dismukes argued that the benefits the non-regulated affiliates receive stem from the regulated companies that was the foundation of Southern Company before it ventured into the non-regulated market. (TR 1610-1613)
Witness Dismukes contended that an affiliate of Gulf, Southern Renewable Energy, was recently formed and no costs have been allocated from SCS to Southern Renewable Energy. Thus, witness Dismukes asserted that it’s equitable to assess a two percent compensation to balance the benefits received by the non-regulated companies from their association with the regulated companies and to address the fact that no costs were allocated to Southern Renewable Energy. (OPC BR 49) To support her assertion she cited the cost accounting standards that were provided by the Cost Accounting Standards Board as an authoritative source. Moreover, witness Dismukes argued the Commission has imposed a compensation payment in a prior case. She asserted a two percent payment should be assessed the non-regulated companies based on their earned revenues to compensate the regulated operating companies for the significant intangible benefits the regulated operating companies provided to the non-regulated companies by their close affiliation and association. Witness Dismukes contended that such payment would increase the Company’s test year revenue by $1.5 million and compensate the regulated companies for the intangible benefits they provide the non-regulated companies through their affiliation. (TR 1618-1621)
In its brief, OPC argued Fitch Ratings recognized benefits the regulated companies provide Southern Company and maintained that those benefits flow through to the non-regulated affiliates. (OPC BR 49)
FIPUG, FRF, and FEA all agreed with the position of OPC on this issue. (FIPUG BR 8; FRF BR 17; FEA BR 24)
ANALYSIS
Staff agrees with Gulf that per Rule 25-6.1351(2)(g), F.A.C., non-regulated products and services are not subject to price regulation by the Commission, are not included for ratemaking purposes, and are not reported in surveillance. (TR 2341)
Staff notes that the crux of this issue centers around OPC’s contention that the non-regulated companies receive benefits, at no cost, through their association with the four operating companies.[29] According to OPC witness Dismukes, the non-regulated companies benefit from their:
(1) use of the companies’ reputation, goodwill, and corporate image;
(2) association with large, financially strong, well-entrenched electric companies;
(3) use of personnel from the service company, SCS; and
(4) the high credit ratings that the Southern Company’s receives, in part, that stems from stable cash flows and financial support from the operating companies.
(TR 1610-1613)
Staff agrees with OPC’s arguments regarding the importance of examining transactions between affiliates and regulated companies, such as Gulf, and the necessity to periodically scrutinize the cost allocation and pricing methodologies to ensure they are valid. Staff believes the allocation factors used by the Company incorporate the benefits the non-regulated companies receive from their affiliation with Gulf. Staff notes that OPC witness Dismukes argued that Gulf is not adequately compensated from the non-regulated companies for the intangible benefits they receive; however, she failed to provide record evidence to support her allegation. Moreover, Gulf witnesses McMillan and Deason sufficiently rebutted OPC witness Dismukes’ benefits argument and recommendation regarding assessment of a 2 percent compensation payment on the non-regulated companies to balance the intangible benefits they receive from their affiliation and association with the regulated companies.
Staff notes that the Court has addressed assessing a compensation payment in a previous order.[30] However, staff believes Gulf’s witnesses McMillan and Deason’s arguments more accurately reflect the proper interpretation of the authoritative sources, and the United Telephone Order cited by OPC witness Dismukes as support for her recommendation. (TR 1603-1619; TR 2341-2343; TR 2111-2118; Gulf BR 56)
Staff agrees with Gulf that the record before us does not provide a legal or factual basis for assessing the compensation payment recommended by OPC, FIPUG, and FEA. Staff also agrees that if the payment was assessed, it would be unprecedented and thus reduce the actual revenue of the Company by $1.5 million because the revenue would be imputed. (TR 2111-2118)
Staff notes that Gulf witness McMillan testified that Gulf is a smaller operating company and it:
(1) receives, at-cost, many professional, technical, corporate, and support services from SCS that would normally be performed by Gulf’s employees and result in higher costs.
(2) is able to keep its costs down by augmenting its employees in specialized areas with SCS employees, instead of hiring additional employees.
(3) shares resources with SCS that enables Gulf to utilize the talent of a centralized pool of professionals on a ongoing basis that results in cost savings due to economies of scale and access to highly trained professionals that would be difficult to replicate at the Company’s level.
(TR 1101-1102;TR 1153-1154; EXH 117, No 228)
Based upon the record evidence stated above, staff believes that Gulf is adequately compensated by the non-regulated companies for the intangible benefits they receive from their association with Gulf and the non-regulated companies do not benefit from high credit ratings as alluded to by OPC witness Dismukes. (TR 1601-1607; TR 1612-1613; TR 1955-1956)
Staff believes that Issue 40 is subsumed in this issue (Issue 39) as OPC has suggested in its position statement. FIPUG, FRF, and FEA agree with OPC’s position.
CONCLUSION
Gulf is adequately compensated by the non-regulated affiliates through services that it receives at-cost, shared resources it uses to augment its employees that results in cost savings, and access to a centralized pool of professionals that would be difficult to replicate at the Company level. Thus, no additional measures should be implemented by the Commission to compensate Gulf, and no adjustment should be made to compensate the regulated operating companies as discussed in Issue 40.
Should an adjustment be made to increase operating revenues by $1,500,000 for a 2 percent compensation payment from non-regulated companies?
Recommendation:
No. Operating revenue should not be increased by $1,500,000 for a 2 percent compensation payment from non-regulated companies. (Trueblood, Mouring)
Position of the Parties
GULF:
No. There is no such payment from non-regulated companies. The imputation of imaginary revenues serves no legitimate regulatory purpose and is inconsistent with Commission policy. The imputation would unjustly penalize Gulf for being part of the Southern Company and deny Gulf the opportunity to earn its authorized return.
OPC:
Yes. The Commission should assume a two percent compensation payment on the revenue earned by the non-regulated companies, which should be allocated to the regulated companies on the basis of the amount of revenues earned by the non-regulated companies. A two percent compensation payment applied to the non-regulated revenue of several affiliates would result in an increase to Gulf’s test year revenue of $1.5 million.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. The Commission should impute a 2 percent compensation payment from Gulf’s non-regulated affiliates to Gulf, thereby increasing Gulf’s 2012 test year operating revenues by $1,500,000.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
The discussion for Issue 40 is subsumed in Issue 39. Therefore, the Parties’ Arguments and the Analysis for Issue 40 are presented in Issue 39. Consistent with the recommendation in Issue 39, staff recommends that operating revenue should not be increased by $1,500,000 for a 2 percent compensation payment from non-regulated companies.
Should an adjustment be made to increase test year revenue for Gulf’s non-utility activities?
Recommendation:
No. Gulf has appropriately accounted for the revenue, expenses and investments associated with the non-regulated operations and no adjustment is necessary to increase test year revenue for Gulf’s non-regulated products and services. The revenue and expenses for these non-regulated activities are not subject to price regulation by the Commission, not included for ratemaking purposes, and not reported in surveillance, pursuant to Rule 25-6.1351(g), F.A.C. (Trueblood, Mouring)
Position of the Parties
GULF:
No. Gulf has properly accounted for and allocated all costs associated with its unregulated products and services, including labor and overheads. Gulf’s customers are not subsidizing the Company’s non-regulated operations. Consistent with the Commission’s past practice, these costs and revenues should continue to be recorded “below the line” for ratemaking purposes.
OPC:
Yes. Gulf is able to earn an excessive rate of return from three non-regulated products and services which stem from the regulated electric operations. These non-utility operations could not be offered without the close association with and good will of Gulf’s regulated electric utility. Revenues of $572,000 should be moved above-the-line because Gulf has failed to demonstrate that Gulf has been compensated for the use of its reputation, goodwill, and logo. Alternatively, the Commission could require that the non-regulated operations provide Gulf a compensation payment of at least two percent of annual revenue. OPC also recommends that Gulf should be ordered to conduct a thorough examination of these operations and develop appropriate cost allocation procedures for non-regulated operations.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Neyman asserted that Gulf offers two non-regulated products and one non-regulated service to its residential and commercial customers. The products are Premium Surge and Commercial Surge, which are installed at the customers’ home or business to provide them protection from electric surges. Customers who elect to use these products are charged a fee for the equipment and billed through Gulf’s monthly bill process, and these products are available to Gulf’s customers to offer them additional protection for their property. (TR 2260; Gulf BR 54)
Witness Neyman stated that new customers have the option to be transferred to a third-party provider and sign up for AllConnect. AllConnect is a service that allows them to one-stop shop for cable, telephone, home security, etc. There is a large military presence in the area and new customers often ask Gulf’s customer service representatives (CSRs) about other service providers. Witness Neyman testified that in response to their questions, the CSR informs them about the AllConnect service and offers to transfer them to the third-party provider that can assist them with other connection needs, at no cost to them. (TR 2260-2261; TR 2264-2270; EXH 113; Gulf BR 54)
Witness Neyman disagreed with OPC witness Dismukes’ claim that the non-regulated operations obtain substantial benefits from their association with Gulf’s regulated operations. She argued that Gulf’s customers look for products and services that offer them the best value and Gulf competes with other providers for customers. Witness Neyman argued that, contrary to witness Dismukes’ assertion, overheads are charged to Gulf’s non-regulated products and services. She argued that OPC witness Dismukes’ assertion that SCS labor expenses were not being charged to non-regulated products is mistaken. Overheads are charged via journal entries and examples and responsive documents were provided. (Gulf BR 55; EXH 141, No. 136; EXH 117, No. 255) Witness Neyman also testified that overheads are charged to AllConnect and calculations were provided illustrating how customer service employees’ labor was calculated and charged to AllConnect. A predetermined, per call factor multiplier is used to allocate labor, overheads, administrative and general expenses, and telephone expenses for Gulf’s CSC representatives, and this factor is reviewed and adjusted annually. (TR 2261, 2265; EXH 113)
Witness Neyman testified that through a partnership with other operating companies, Gulf is able to provide services to its customers that it would not be able to provide if it was not a part of the Southern Company. (TR 696) She also stated that profits from the non-regulated operations are credited to the shareholders, not the ratepayers. (TR 2267) Witness Neyman testified that Gulf’s cost allocations and overheads are detailed appropriately to the non-regulated products. Further, she opined that revenues from the Premium Surge customers reduce the cost resulting in Gulf over-allocating costs to the non-regulated business unit. (TR 2273)
Gulf witness McMillan argued that Gulf’s non-regulated test year revenues of $1.298 million are less than 0.1 percent of its total retail revenue, and consistent with Rule 25-6.1351(2)(g), F.A.C., are properly recorded below-the-line. Thus, it does not impact its revenue requirement request. Witness McMillan asserted that OPC witness Dismukes’ recommendation to move the non-regulated revenue, expenses, and investments above-the-line is not appropriate and her revenue requirement calculations are incorrect. (Gulf BR 55) He disagreed with witness Dismukes’ recommendation and provided a corrected calculation of what the adjustment would be if the Commission accepts her recommendation. He contended that Gulf’s investment in its non-regulated operations is removed 100 percent from equity and, according to Commission policy and ratemaking treatment, return on investment should be calculated on a 13-month average basis. (TR 2353-2354; EXH 150, pp. 91-92)
In its brief, Gulf argued that OPC provided no evidence demonstrating that costs were misallocated or any precedential authority to support its recommendations. OPC witness Dismukes cited as support the United Telephone Order, which was a 1980’s era telecommunications order. However, she failed to mention the 2010 PEF Order,[31] where the Commission rejected her same arguments in the Commission’s most recent rate base proceeding for an investor-owned electric utility. Gulf further argued that if the Commission were to accept OPC witness Dismukes’ recommendation to move Gulf’s non-regulated operations above-the-line, the correct adjustment would be $258,000, not $572,000. (Gulf BR 56)
OPC
Gulf’s non-regulated products and services were discussed by OPC witness Dismukes. Witness Dismukes argued that the Commission should ensure that Gulf’s regulated operations do not subsidize its non-regulated operations or products, as an incentive exists for the non-regulated affiliates to shift costs to the regulated operations in order to yield higher profits for Gulf’s parent company. She contended the Commission’s Cost Allocation and Affiliate Transactions Rule 25-6.1351(1), F.A.C., addresses costs charged between regulated and non-regulated operations of electric utilities. (TR 1622-1623) Further, witness Dismukes stated:
Utility nonregulated activities should be covered by this rule, and the Commission can utilize the same principles embodied in subsection (3) of Rule 25-6.1351, F.A.C., as guidelines for examining the relations between the Company’s regulated and nonregulated operations, thus, ensuring that the regulated operations do not subsidize the nonregulated operations.
(TR 1623; OPC BR 53)
Witness Dismukes asserted the Company’s Cost Accountability and Control Manual does not address how the non-regulated costs and revenue are treated for ratemaking purposes. She testified that three non-regulated products and services, Premium Surge, Commercial Surge and AllConnect, are offered to Gulf’s customers through a third-party contractor. A description of these products and services was provided highlighting the protection, warranties, fees and discounts that apply to each of them. A more detailed description and discussion were provided regarding the AllConnect service, which allows customers to one-stop shop for telephone, cable, home security, and newspaper providers when they initiate service with Gulf. Witness Dismukes asserted Gulf’s CSRs offer the AllConnect service to customers when the call for electric service with the Company is completed, and if they consent, the caller is transferred to the AllConnect CSR and Gulf receives 25 percent of the revenues generated from services the customers obtain from AllConnect. (TR 1623-1625)
Witness Dismukes expressed concern about Gulf’s non-regulated operations and asserted that Gulf incurs minimal costs associated with the revenue earned from its non-regulated products and services that are recorded below-the-line, revenue that could not be earned if it was not for the regulated operations. (OPC BR 54) She argued the non-regulated operations receives substantial benefits such as the use of Gulf’s name, logo, reputation, goodwill, and corporate image, etc., and these intangible benefits are received at no cost. (TR 1625; EXH 113)
OPC witness Dismukes argued that based upon data supplied by Gulf for its non-regulated operations, Gulf earned a return of 21.6 percent in 2009, 24.2 percent in 2010, and 28.9 percent for the projected test year of 2012. She contended the high returns on investment suggest that the costs attributed to the non-regulated operations are abnormal and understated. Witness Dismukes asserted the Company’s response to OPC’s First Set of Interrogatories, No. 65 indicates that direct costs are associated with the non-regulated products and services, but no overhead costs are allocated or assigned to the surge products. (EXH 113) She did concede, however, that the Company indicated that direct labor expenses for Gulf’s employees are charged through its payroll system. (TR 1626-1627)
Witness Dismukes testified that all customers that purchase the three non-regulated products and services are Gulf ratepayers, and she presented three options the Commission should consider to ensure the regulated operations are not subsidizing the non-regulated operations. The options address allocating overhead costs, assessing a compensation payment for intangible benefits, returning a portion of the rate of return achieved by the non-regulated operations to the ratepayers, and moving revenues, expenses and investments above-the-line. Witness Dismukes asserted that Gulf has failed to properly allocate costs to the non-regulated operations or demonstrate that it has been adequately compensated for the use of reputation, goodwill, logo, and trained personnel. Thus, the Commission should treat the revenue, expenses and investments above-the-line for rate setting purposes. (TR 1628-1629)
To implement OPC’s recommendation, witness Dismukes developed an adjustment to test year revenue based upon revenue being moved above-the-line. She also testified that if the revenue, expenses and investments are not moved above-the-line, the Commission should order the Company to examine the non-regulated operations, to develop procedures for allocating costs to the non-regulated operations, and to assess the Company a compensation payment of at least 2 percent of annual revenue. (TR 1629)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 8; FRF BR 17; FEA BR 24)
ANALYSIS
Gulf witness McMillan asserted that Gulf’s non-regulated test year revenue of $1.298 million is less than 0.1 percent of its total retail revenue. (TR 2353-2354; EXH 150) Gulf addressed OPC witness Dismukes’ recommendation and alternate recommendation that the Commission order that Gulf’s non-regulated activities be audited. Primarily, OPC recommends that the Commission move all the revenue, expenses, and investment associated with these non-regulated operations above the line for ratemaking purposes. (TR 1629) Gulf argued the Commission should reject OPC’s recommendation because the Commission lacks legal authority to regulate non-regulated operations. (TR 2353-2354; EXH 150)
Staff agrees with Gulf that its non-regulated activities and associated expenses should be recorded below-the-line and should not impact the Company’s revenue requirement request. Staff notes that Gulf points to Rule 25-6.1351(2)(g), F.A.C., which defines non-regulated operations as “services or products that are not subject to price regulation by the Commission or not included for ratemaking purposes and not reported in surveillance.” (TR 2353-2354; EXH 150)
Staff notes that the basis for OPC witness Dismukes’ belief is that high returns on investment suggest that costs attributed to the non-regulated operations are abnormal and understated. Witness Dismukes asserted the Company’s response to OPC’s First Set of Interrogatories, No. 65 indicated that direct costs are associated with the non-regulated products and services but no overhead costs are allocated or assigned to the surge products. (EXH 113) She conceded, however, that the Company indicated that direct labor expenses for Gulf’s employees are charged through its payroll system. (TR 1626-1627) Staff notes that witness Dismukes’ arguments appear to have been based upon Gulf’s response to a discovery question regarding SCS labor expenses not being charged to non-regulated products. (TR 2261; TR 2265; EXH 113) Staff notes that cost allocation and overheads are assigned appropriately to the non-regulated products, and agrees with Gulf’s witness Neyman that, based on how the Premium Surge costs are allocated, they reduce the cost and result in Gulf over-allocating costs to the non-regulated business unit. (TR 2273)
Furthermore, staff notes that no evidence was provided that supports OPC’s allegation that specific costs were not allocated properly. Moreover, OPC witness Dismukes acknowledged that Rule 25-6.1351(1), F.A.C., does not cover utility non-regulated activities. (TR 1623; EXH 113)
Based upon the record evidence, staff believes the methodology used by the Company for allocating costs is reasonably effective and Gulf has appropriately accounted for revenue, expenses, and investments associated with the non-regulated operations.
CONCLUSION
Gulf has appropriately accounted for revenue, expenses, and investment associated with the non-regulated activities and no adjustment is necessary to increase test year revenue for Gulf’s non-regulated products and services. The revenue and expenses for these non-regulated activities are not subject to price regulation by the Commission, not included for ratemaking purposes, and not reported in surveillance, pursuant to Rule 25-6.1351(g), F.A.C.
Is Gulf's projected level of Total Operating Revenues in the amount of $481,909,000 ($499,311,000 system) for the 2012 projected test year appropriate?
Recommendation:
Yes. The appropriate projected level of total operating revenue for the 2012 projected test year is $481,909,000 ($499,311,000 system). (Mouring)
Position of the Parties
GULF:
Yes. Gulf’s projected level of Total Operating Revenues in the amount of $481,909,000 ($499,311,000 system) for the 2012 test year is appropriate.
OPC:
No. The appropriate amount of operating revenues is $484,019,000 (jurisdictional). This reflects an increase to test year revenues of $2,110,000 for the 2% compensation payment on the revenue earned by the non-regulated companies and the imputed revenue for non-regulated services and products.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate jurisdictional amount of operating revenues for the 2012 test year is $484,019,000.
FEA:
No. The appropriate amount of operating revenue should reflect FEA’s position on Sales for Resale.
Staff Analysis:
This is a fallout issue based on the resolution of other issues. Staff has not recommended any adjustments to total operating revenues for the test year. Therefore, staff recommends that the total operating revenue of $481,909,000 ($499,311,000) as filed is the appropriate amount for the 2012 projected test year.
Has Gulf made the appropriate test year adjustments to remove fuel revenues and fuel expenses recoverable through the Fuel Adjustment Clause? (Category 2 Stipulation)
Approved Stipulation:
Gulf has made the appropriate test year adjustments to remove fuel revenues and fuel expenses recoverable through the Fuel Adjustment Clause.
Has Gulf made the appropriate test year adjustments to remove conservation revenues and conservation expenses recoverable through the Conservation Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
As adjusted, Gulf has made the appropriate test year adjustments to remove conservation revenues and conservation expenses recoverable through the Conservation Cost Recovery Clause. As shown on Mr. McMillan’s direct testimony Exhibit RJM-1, Schedule 6, Gulf’s ECCR depreciation and property tax adjustments were $352,000 and $146,000, respectively. The ECCR depreciation expense adjustment should be increased to $375,000 and the ECCR property tax expense should be increased to $156,000.
Has Gulf made the appropriate test year adjustments to remove capacity revenues and capacity expenses recoverable through the Capacity Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
Gulf has made the appropriate test year adjustments to remove capacity revenues and capacity expenses recoverable through the Capacity Cost Recovery Clause.
Has Gulf made the appropriate test year adjustments to remove environmental revenues and environmental expenses recoverable through the Environmental Cost Recovery Clause? (Category 2 Stipulation)
Approved Stipulation:
Gulf has made the appropriate test year adjustments to remove environmental revenues and environmental expenses recoverable through the Environmental Cost Recovery Clause. Consistent with the Stipulation entered into by all parties and approved by the Commission on November 1, 2011, the Crist Units 6 and 7 turbine upgrade investments and expenses were removed from the Environmental Cost Recovery Clause and are now being included for recovery in base rates in this proceeding.
Has Gulf made the appropriate adjustments to remove all non-utility activities from net operating income?
Recommendation:
Yes. Based on staff’s recommendations in Issues 39-41, Gulf has made the appropriate adjustments to remove non-utility activities from net operating income. (Mouring)
Position of the Parties
GULF:
Yes. The Company has removed all non-utility activities from net operating income.
OPC:
No. See OPC’s positions on Issues 39-41 and 48-68.
FIPUG:
No. See Issues 39-41 and 48-68.
FRF:
No.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
The merits of this issue have been discussed previously in Issues 39-41, and staff recommends no further adjustments. Based on staff’s recommendations for Issues 39-41 concerning non-utility activities, Gulf has made the appropriate adjustments to remove non-utility activities from net operating income.
Should adjustments be made to the expenses allocated or charged to Gulf as a result of transactions with affiliates?
Recommendation:
Yes. Individual adjustments related to affiliate transactions are discussed in Issues 49-68. No further adjustments are required. (Mouring)
Position of the Parties
GULF:
No adjustments should be made to the expenses allocated or charged to Gulf except for the two adjustments totaling $363,296 ($363,334 system) covered by the approved stipulations on Issues 53 and 58.
OPC:
Yes. See OPC’s positions on Issues 49-68.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
The merits of this issue are discussed in Issues 49-68, and staff recommends no further adjustments. Transactions with affiliates are addressed separately in Issues 49-68 and any adjustments are discussed in those issues. No further adjustments are necessary.
Should adjustments be made to expenses to allocate SCS costs to Southern Renewable Energy?
Recommendation:
No. Pursuant to Commission Rule 25-6.1351, F.A.C., Cost Allocation and Affiliate Transactions, adjustments are not appropriate and the Commission should not require SCS to allocate costs to Southern Renewable Energy. Consequently, the Commission should not assess SCS a two percent compensation payment. (Trueblood)
Position of the Parties
GULF:
No. If the fixed allocation factors were updated to use 2010 data in order to include an allocation of SCS costs to Southern Renewable Energy, Gulf’s O&M expenses would increase by approximately $1,159,000.
OPC:
Yes. Because Southern Renewable Energy was formed in 2010 and the allocations provided by Gulf date from 2009, neither Southern Company Services overhead nor costs allocated on the basis of megawatts have been allocated to Southern Renewable Energy. The omission means costs allocated to Gulf Power are overstated and it should be assessed a two percent compensation payment analogous to that described in Issue 41.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Southern Renewable Energy (SRE) is listed in the Company’s Form 10-K that is provided in MFR Schedule F, as a new subsidiary of the Southern Company that was formed on January 25, 2010, to construct, acquire, own, and manage renewable generation assets. The Company stated that new business opportunities are more risky; however, they offer potential higher returns than rate-regulated operations. (EXH 7, Schedule F, p. I-3)
Witness McMillan testified that “Southern Company Services (SCS) is a subsidiary of Southern Company which provides various services to Gulf and other subsidiaries of Southern Company.” (TR 1101) He stated that Gulf receives professional and technical services such as general and design engineering for transmission and generation; system operations for the generating fleet and transmission grid; and various services and support in accounting, supply chain management, finance, treasury, human resources, information technology, and wireless communications. (TR 1101)
Witness McMillan argued that SCS provides all services at cost and that these costs are determined and billed using two methods. (TR 1102) Costs are either directly assigned to the company receiving the services or allocated among the subsidiaries receiving the services based on a pre-approved cost allocator based on the services received. Typical allocators include employees, customers, loads, generating plant capacity, and financial factors. The methodology for developing the allocators has not been changed since Gulf’s last rate case. The allocators are approved by SCS and by management of the applicable operating companies, and updated annually based on objective historical information. (TR 1102, 1151-1152) Witness McMillan stated that SCS supports the activities of each company and maintained that the regulated companies require more support than the unregulated companies. (TR 2345)
In its brief, Gulf argued that since SRE was not in operation in 2009, costs were not allocated to it for the test year. (Gulf BR 59) To remedy the situation, OPC proposed a 2 percent compensation payment on SRE analogous to that described in Issues 39-41. The Company argued that such payment would result in additional imputed revenue to Gulf and asserted that it is inappropriate in this instance for the same reasons discussed in Issues 39-41. Gulf argued that evidence shows that the total O&M allocation to Gulf would increase by approximately $1,159,000 if all the SCS fixed factors were updated based on 2010 data. Gulf’s used the 2009 data for its rate request and no adjustment should be made for SRE. (TR 2347-2348; Gulf BR 60)
OPC
Witness Dismukes testified that it is important to review cost allocation methods and techniques used by affiliates to ensure that the company’s regulated operations are not being subsidized by the non-regulated operations. (TR 1601) She argued that Commission Rule 25-6.1351, F.A.C., Cost Allocation and Affiliate Transactions, details the Commission policy that must be followed by electric utilities when transacting with affiliates. (TR 1602)
Witness Dismukes asserted that SRE, an unregulated affiliate, was formed in January 2010, and she pointed out that the Southern Company 2010 Form 10-K indicated that the new business investments offer higher returns and involve a higher risk than the regulated operations. (TR 1607) She stated that the charges from SCS to Southern Company subsidiaries have increased by $513 million or 57 percent since 2005 and the charges to Gulf have increased by $44 million or 82 percent over the same time period. Witness Dismukes opined that SCS’ total billings have increased in part because amounts billed to the utility operating companies have increased while the amounts billed to the non-regulated companies have decreased. (TR 1608)
Witness Dismukes stated SCS uses three methods to assign costs to affiliates. Expenses are assigned on fixed percentage distribution when they are for the benefit of two or more affiliates. The direct method is used when the costs are incurred solely for the benefit of one company, and the direct accumulative distribution method is used for work orders when there is no established fixed percentage allocator available. (TR 1608-1609; OPC BR 55)
Because no costs have been allocated to SRE since it was formed in 2010, witness Dismukes argued the Commission should assess a 2 percent compensation payment based on the amount of revenue earned by the non-regulated companies. (TR 1619-1620)
In its brief, OPC argued that as a result of SRE not being allocated costs from SCS, Gulf’s cost have been overstated. Ratepayers should not be forced to subsidize SRE, which is a non-regulated company. (OPC BR 56)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 9; FRF BR 18; FEA BR 27)
ANALYSIS
SRE is a subsidiary of the Southern Company, which was formed in 2010 and SCS has not allocated any costs to SRE. Staff notes that there was little testimony provided specific to costs being assigned or allocated to SRE, which is a non-regulated affiliate of Gulf. The facts presented for this issue show that costs are either directly assigned to the company receiving the services, or allocated among the subsidiaries receiving the services based on a pre-approved cost allocator based on the services they receive from SCS.
Gulf used factors based on the 2009 data that was available for its budget for the 2012 test year. Gulf provided supporting documentation that shows the allocators used to assign costs are updated annually based on objective historical information, approved by SCS and by management of the applicable operating companies, and reported annually to the Federal Energy Regulatory Commission (FERC) and state commissions that have authority to supervise these factors. As discussed in Issue 51, the factors have been used for more than 25 years, reviewed by the Commission in Gulf’s last two rate cases, and neither the FERC nor the Commission have recommended a change to the factors. (TR 1102; TR 1151-1152; TR 2345)
Staff notes that the record evidence shows that charges from SCS to Southern Company subsidiaries have increased by $513 million or 57 percent since 2005 and that charges to Gulf have increased by $44 million or 82 percent over the same time period. However, staff notes that no evidence was provided that indicated Gulf was allocated a higher percentage of SCS costs as a result of SCS costs not being allocated to SRE, or that SRE obtained services from SCS that were misallocated.
Gulf argued that SCS supports the activities of each company in the Southern corporate family, and the regulated companies require more support than the unregulated companies. (TR 2345) The record also shows that if all the updated 2010 allocation factors are used, Gulf’s revenue request would actually increase by approximately $1.2 million. (TR 2348; EXH 168; Gulf BR 60)
Staff believes OPC’s argument that SCS costs allocated to Gulf are overstated as a result of costs not being allocated to SRE is not supported by the record. Staff believes an adjustment to the expenses to allocate costs to SRE is inappropriate absent evidence that shows costs were misallocated. Staff also believes that it is inappropriate to assess SCS a 2 percent compensation payment based on the amount of revenue earned by the non-regulated companies simply because no costs were charged to SRE since it was formed in 2010. (TR 1619-1620)
CONCLUSION
SCS and SRE are non-regulated affiliates of Gulf and subsidiaries of the Southern Company. Pursuant to Commission Rule 25-6.1351, F.A.C., Cost Allocation and Affiliate Transactions, adjustments are not appropriate and staff does not believe that the record provides a legal or factual basis for requiring SCS to allocate costs to SRE. Consequently, the Commission should not assess SCS a two percent compensation payment as recommended by OPC.
DROPPED.
Should adjustments be made to the allocation factors used to allocate SCS costs to Gulf?
Recommendation:
No. The allocation factors SCS used to allocate costs to Gulf should not be adjusted. The factors are provided annually to the FERC, they have been used for over 25 years, they were reviewed and approved by the Commission in Gulf’s last two rate cases, and neither the FERC nor the Commission has recommended that the factors be changed. (Trueblood)
Position of the Parties
GULF:
No adjustments should be made to any of the allocation factor calculations. The overall allocation methodology has been in use for over 25 years, was approved by the SEC, has not been changed by the FERC, and has been accepted as a basis for allocation by this Commission in prior Gulf rate cases. If the Commission finds that it is appropriate to update any fixed allocation factors, then it should update them all using the actual 2010 factors that will apply to 2012 costs. Using the recently developed 2010 fixed allocation factors would increase Gulf’s share of SCS billings by approximately $1,262,500, of which approximately $1,159,000 represents increased O&M expenses.
OPC:
Yes. Allocation factors should be based upon cost-causative relationships to the extent possible and also recognize the benefits received from the service provided. Gulf used a “financial” factor to allocate many affiliate administrative and general expenses, which overstates allocations to regulated companies and understates allocations to non-regulated companies. On the expense side, the factor apparently includes fuel and purchased power expenses, which over allocates costs to the regulated operating companies. OPC recommends that the financial factor be adjusted to remove the revenue component in the factor and the fuel and purchased power from the expense component of the factor. The impact is to reduce expenses by $832,284.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Allocation factors should be based on cost-causative relationships to the extent possible and should also recognize the benefits received from the services provided. Gulf inappropriately uses a “financial” factor to allocate affiliate administrative and general expenses to regulated companies. In particular, the factor includes fuel and purchased power expenses, which over-allocates costs to regulated operating utility companies. Correcting for this over-allocation, Gulf’s test year expenses should be reduced by $832,284.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan testified that SCS is a subsidiary of the Southern Company, and an affiliate of Gulf, which provides services at-cost to Southern Company and its other subsidiaries. Gulf is a subsidiary of the Southern Company and receives professional and technical services from SCS, such as general design and engineering for transmission and generation; system operations for the generating fleet and transmission grid; and various corporate services and support in areas such as accounting, supply chain management, finance, treasury, human resources, information technology, and wireless communications. (TR 1101; Gulf BR 60)
All SCS costs are either directly charged or allocated based on a pre-approved cost allocator for the type of services performed. (TR 1102) The methodology for developing the allocators has not changed since Gulf’s last rate case and it includes employees, customers, loads, generating plant capacity and financial factors. Witness McMillan argued that the allocators are approved by SCS and management of the applicable operating companies and updated annually based on objective historical information. (TR 1102)
Gulf argued the affiliate transactions are provided at cost, with no mark-up for profit, under a rigorous process of direct billings and rational allocations, consistent with Southern Company policy, the FERC, and Commission requirements. (TR 1102) The services provided to Gulf are services that would normally be performed by utility employees and by using SCS, Gulf can augment its personnel in specialized areas, have the advantages of a stable utility workforce, and have the advantage of the economies of scale associated with specialized employees serving a larger organization. Moreover, Gulf argued that if additional employees were hired instead of SCS or another operating utility’s employees, Gulf’s costs would be higher. (EXH 117, No. 228; Gulf BR 61)
Gulf provided detailed documentation and explanations showing how costs are allocated to affiliates. The documentation included spreadsheets reflecting the different expenses that Gulf incurs and how they are allocated by the affiliates. (EXH 117, No. 230; EXH 138, No. 37) Documentation was also provided that showed affiliate costs, recorded as revenue and expenses, for years 2007 through June 30, 2011, with explanations why certain revenue and expenses increased and decreased during these years. (EXH 113, No. 48)
Witness McMillan asserted that Gulf and its customers receive several benefits from the services provided by SCS. As a smaller operating company, Gulf has access to shared resources that enables Gulf to avoid duplication of personnel and to utilize the talent of a centralized pool of professionals on an ongoing basis. The services Gulf receives from SCS benefits its customers through cost savings due to economies of scale and access to highly trained professionals that would be difficult to replicate at the Company level. (TR 1105-1106, 1153-1154; BR 61) Witness McMillan testified that SCS provides technical and professional services and costs are allocated based on the service provided and the most cost-causative type allocator identified for that type of service. He maintained that Gulf has staff who help with hiring and personnel activities but services are not duplicated. (TR 1151-1154)
Witness McMillan asserted that the Rule 25-6.1351(3), F.A.C., cited by OPC witness Dismukes that addresses transactions with affiliates, does not apply to services provided by SCS to Gulf because SCS exists solely to provide services to the Southern Company corporate family. This Rule also does not apply to services provided between Gulf and its regulated affiliates.[32] (TR 2341) Witness McMillan stated that OPC witness Dismukes referenced a 2001 NARUC letter and Guidelines for Cost Allocations and Affiliate Transactions that are not applicable to Gulf and it affiliates. He asserted that she also failed to point out the Commission’s policies and procedures for cost allocations and affiliate transactions that were adopted after the NARUC guidelines were issued. (TR 2342) Witness McMillan argued that the standards issued by the Cost Accounting Standards Board (CASB) that OPC witness Dismukes cited as support for her recommendation state the importance of benefits in distributing common costs only apply to federal procurement contracts. He maintained, however, the cost allocation methods used by SCS are consistent with the CASB principles. (TR 2343)
The allocation methodology used by SCS was approved by the SEC in 1985 prior to the repeal of the Public Utility Holding Company Act (PUHCA) and it has been used for more than 25 years to allocate costs among Southern Company’s affiliates. Witness McMillan asserted FERC and the state commissions have authority to supervise the allocation methodologies that SCS reports annually to the FERC. He pointed out that the financial factor and other fixed allocation factors are recalculated each year and FERC has made no changes to the factors. Further, the allocations based on the financial factor were used by the Company in its last two rate cases and were reviewed and approved by the Commission. Witness McMillan argued that Gulf’s test year costs were based on 2010 factors that used 2009 data, which was the most recent actual data available at the time Gulf prepared its filings for this case. (TR 2343-2344)
Witness McMillan asserted that OPC witness Dismukes’ recommendation to: (1) convert the financial factor to a two component factor, (2) exclude fuel and purchased power from the operating expense factor, and (3) recalculate some of the fixed allocation factors using 2010 data is flawed and would reduce Gulf’s operating budget by $832,284. Witness McMillan testified that witness Dismukes provided an example using Gulf’s and Southern Power’s revenue per kWh to support her claim that the use of operating revenue in the financial factor could bias the factor. He asserted that she failed to take into account that a larger infrastructure is necessary to support Gulf’s regulated retail revenue stream than the non-regulated sales. SCS supports all the affiliate companies activities and the level of support for the regulated companies is greater than that required for the non-regulated companies. (TR 2345-2346)
Witness McMillan argued that OPC witness Dismukes’ recommendation is unrealistic because it arbitrarily shifts costs from the regulated operating companies to the non-regulated businesses, ignores activities necessary to support the operating companies, and would result in an unfair allocation that does not adhere to the principle of matching costs allocations with cost incurrence and benefits. Witness McMillan asserted that it is inappropriate to pick and choose factors to update as recommended by OPC witness Dismukes. If the 2010 factors are used, all the updated factors should be used, which would result in an increase to Gulf’s share of SCS billing by approximately $1,262,500. (TR 2346-2348; Gulf BR 62-63)
In its brief, Gulf argued that the factors apply to all companies in the Southern Company system and a change in Florida would result in SCS total costs being under or over recovered until a change was made by the FERC and other state commissions.[33] Gulf further argued that OPC should not be allowed to pick and choose the factors that would result in an artificially reduced revenue requirement. (Gulf BR 63)
OPC
OPC witness Dismukes testified about the importance of examining transactions between affiliates and regulated companies. She argued that Gulf and its affiliates have a close relationship as members of the same corporate family, which makes it necessary for the cost allocation and pricing methodologies to be periodically scrutinized to ensure that the regulated companies are not subsidizing the non-regulated companies. The relationship between Gulf and its affiliates contributes to expenses being included on the Company’s books and an incentive exists to allocate or shift costs from non-regulated companies to regulated companies so that the shareholders can reap higher profits, even though an established methodology for the allocation and distribution of affiliate costs is in place. Witness Dismukes argued that Rule 25-6.1351, F.A.C., provides criteria for electric utilities to use when transacting with affiliates and she cited subsection (3) which states that the purchases from the utility by the affiliate must be at the higher of fully allocated cost or market price. Subsection (3) of the Rule also states that purchases from the affiliate must be at the lower of fully allocated cost or market price. (TR 1601-1602; TR 1639-1641)
Witness Dismukes argued that the Commission has addressed affiliate transactions in a prior order. She asserted that the company has the burden to prove that its costs are reasonable, and the standard to use in evaluating affiliate transactions is whether those transactions exceed the going market rate or otherwise are inherently unfair. She also stated that the National Association of Regulatory Utility Commissioners (NARUC) has guidelines that address cost allocations and affiliate transactions for electric and gas operations. According to witness Dismukes, the “4 Guidelines” promulgated by NARUC state that all direct and allocated costs between regulated and non-regulated services should be traceable on the books to the applicable Uniform System of Accounts, indirect costs of each business unit should be spread to the services and products to which they relate using relevant factors, and the allocation methods should not result in regulated companies subsidizing the non-regulated companies. Moreover, witness Dismukes asserted NARUC’s Guidelines are based on two assumptions: (1) affiliate transactions raise the concern of self-dealing, and (2) an incentive exists to shift costs from non-regulated operations to regulated operations. She testified that the SCS Cost Accountability and Cost Control Manual states that the factors used to allocate costs between Gulf and its affiliates were approved by the Security Exchange Commission (SEC), but the authority now rests with the FERC and state legislators. (TR 1603-1605)
Gulf is one of four regulated utilities of the Southern Company, which also has several non-regulated subsidiaries. Witness Dismukes pointed out that Southern Company’s non- regulated activities have increased in recent years and Gulf engages its affiliates for a variety of services. Gulf contracts with SCS for a variety of managerial and professional services, receives mail processing services from Alabama Power, shares plant costs with Georgia Power and Mississippi Power, receives siting services from Southern Nuclear, wireless services from SouthernLINC, and financial services from Southern Management. (TR 1607)
Witness Dismukes asserted that Gulf provides various services to its affiliates, such as office space, information technology, and power sales. She testified that, during the projected test year, Gulf’s transactions with its affiliates were approximately $155 million with nearly $81 million in charges from its affiliates included in test year Operations and Maintenance (O&M) and Administrative and General (A&G) expenses. Witness Dismukes asserted that the total O&M and A&G expenses indicate that 28 percent of the costs are charged from affiliates. And for just total A&G expenses, 73 percent are charged from SCS. Since 2005, charges from SCS to subsidiaries have increased by 57 percent and charges from SCS to Gulf have increased by 82 percent. She pointed out that SCS total billings to the utility operating companies have increased while amounts billed to the non-regulated companies have decreased. (TR 1605-1608; OPC BR 56)
SCS uses three methods to allocate costs to its affiliates: direct assignment, fixed percentage distributions, and direct accumulative distributions. (EXH 138, No. 34) The direct assignment method assigns costs that are incurred solely for the benefit of one utility, the direct accumulative distribution method assigns costs based on work order specific assumptions when no established fixed percentage allocator is available, and the fixed percentage distribution method assigns costs that are incurred for the benefit of two or more affiliates. Witness Dismukes testified that during the test year $5.2 million of expenses were allocated using the direct accumulative distribution method and $40 million were charged using the fixed percentage distribution method. (TR 1608-1610; EXH 138, No. 34)
Witness Dismukes contended that Gulf used allocation factors consisting of statistics that include kilowatt hours (kWh), customers, employees, plant capacity (kW), gas burned (MMBTU), insurance premiums, billed labor, and a financial factor which consists of an equal weighting of fixed assets, operating expenses, and operating revenue. She argued that there are problems with the factors because the data is stale and the factors fail to incorporate benefits the non-regulated companies receive from their association with the regulated operating companies. (TR 1610; OPC BR 56)
Witness Dismukes argued that the allocation factors Gulf used to allocate the projected 2012 expenses were based on data that was three years old. She stated that the allocation factors might be acceptable if the relationship between Gulf and the affiliates remains constant but she asserted that Schedule KHD-6 shows the relationship is not constant and can vary from year to year. She argued that given the total dollars being allocated, a minor change could result in a significantly lower amount of expenses for the test year. For example, if the financial allocator is modified by one percent, the common administrative and general expenses could be reduced by $1 million. Witness Dismukes also argued that SRE was formed in 2010 and purchased a 30 MW solar photovoltaic plant that began commercial operation, and SCS did not allocate any costs to that company for the test year. She contended that costs were overstated for the Company’s projected test year as a result of no cost allocations to SRE and the use of 2009 data to allocate the projected 2012 test year expenses. (TR 1614-1615; OPC BR 57-58)
Witness Dismukes expressed several problems that she has with the financial factor that is used to allocate administrative and general expenses. The factor consists of the average of net fixed assets, operating expenses, and operating revenue, and given the differences between the regulated and non-regulated companies the inclusion of the revenue in the allocation factor overstates the allocations to the regulated companies. To support her assertion witness Dismukes provided a hypothetical scenario in her testimony to show how the costs for the regulated companies would be overstated if Southern Power, an non-regulated affiliate, had a lower revenue per kWh than the operating companies. The hypothetical scenario indicated that if Gulf revenue per kWh in 2010 was 9.88 cents and Southern Power’s wholesale kWh 4.72 cents, costs would be overstated. Other problems were expressed such as the effect the expense factor has when used for the financial allocator. (TR 1615-1617)
To correct the problems witness Dismukes had with the allocation factors, she asserted that the Commission should update the data used in the factors and she identified those factors that she was able to update. She also stated that the financial factor should be adjusted to remove revenue from the composite factor. She pointed to the cost accounting standards that relate to cost allocations to affiliates that were provided by the CASB as an authoritative source. (TR 1618-1619)
FIPUG, FRF, and FEA agreed with OPC’s position. (FIPUR BR 9; FRF BR 18; FEA BR 27)
ANALYSIS
Staff agrees with Gulf that per Rule 25-6.1351(20(g), F.A.C., non-regulated products and services are not subject to price regulation by the Commission, are not included for ratemaking purposes, and are not reported in surveillance. (TR 2341) Staff agrees with OPC that transactions between affiliates and regulated companies should periodically be reviewed to ensure that the regulated companies are not subsidizing the non-regulated companies. OPC provided testimony about Commission Rule 25-6.1351, F.A.C., and staff notes that the Rule establishes cost allocation requirements to ensure proper accounting for affiliate transactions and utility non-regulated activities. Staff also agrees with OPC that cost allocation and pricing methodologies should be periodically examined to ensure they are valid. (TR 1601-1602)
Both OPC and Gulf offered testimony about the NARUC Guidelines and the CASB Standards. Staff notes that the NARUC Guidelines address cost allocations and affiliate transactions and the CASB cost account standards relate to the allocation of costs to affiliates. (TR 1603-1619; TR 2341-2343; TR 2111-2118) However, staff believes that Gulf’s arguments about the relevancy of these guidelines and standards are more persuasive.
Staff notes that three methods are used to allocate costs to affiliates: direct assignment, fixed percentage distributions, and direct accumulative distributions. (EXH 138, No. 34) Staff also notes that the allocation factors consist of statistics that include kWh, customers, employees, kW, MMBTU, insurance premiums, billed labor, and a financial factor which consists of an equal weighting of fixed assets, operating expenses, and operating revenue. (TR 1610; OPC BR 56)
Gulf obtains a variety of professional and technical services from SCS and the costs are allocated based on the services provided and the most cost-causative type allocator identified for that type of service. Based on the scope of services that Gulf receives from SCS, staff believes that the total costs that Gulf has been charged by SCS is not the proper mechanism to determine if the allocation factors should be changed. However, staff notes that the record shows that during the projected test year, Gulf’s transactions with its affiliates are projected to be approximately $155 million with roughly $81 million of the charges from its affiliates included in test year O&M and A&G expenses. Staff also notes that the record shows that 28 percent of the total O&M and A&G expenses are charged from affiliates, and 73 percent are charged from SCS. Further, staff notes that since 2005, charges from SCS to subsidiaries have increased by 57 percent, and charges from SCS to Gulf have increased by 82 percent. (TR 1605-1608; OPC BR 56)
OPC witness Dismukes’ belief that costs were not properly allocated is based on the fact that the total billings to the utility operating companies, and Gulf in particular, have increased while amounts billed to the non-regulated companies have decreased. (TR 1605-1608) OPC witness Dismukes argued that there are problems with the allocation factors used because the data is stale and fails to incorporate benefits the non-regulated companies receive from their affiliation with Gulf. (TR 1610) However, no record evidence was provided by OPC witness Dismukes that supports her assertion that specific costs were misallocated.
OPC witness Dismukes recommended that the factors be modified to remove the revenue component from the allocation factors. Witness Dismukes argued that inclusion of revenue in the factors underallocates costs to the non-regulated companies because new companies such as SRE produced little revenue relative to investment expenses. Staff notes that OPC witness Dismukes’ recommended adjustment to the allocation factors would reduce Gulf’s operating budget by $832,284. (TR 2345-2346)
Gulf’s test year costs were based on 2010 factors that used 2009 data, which were the most current information available to Gulf at the time Gulf prepared the test year data for its original filing in this case. (TR 2343-2344) Staff agrees with Gulf that OPC witness Dismukes’ recommended changes to the allocation factors using some of the updated 2010 data are flawed. Staff believes that if allocation factors are updated and used to calculate the Company’s revenue requirement, all the factors should be updated using the 2010 factors as argued by Gulf witness McMillan. Staff further believes that OPC should not be allowed to pick and chose factors that would result in a reduced revenue requirement.
Finally, staff notes that: (1) the methodology for developing the allocators has not changed since Gulf’s last rate case, (2) the allocators are updated annually based on historical information and approved by SCS and management from the operating companies, (3) the allocators are submitted annually to the FERC for review, and (4) neither the FERC nor the Commission has made any changes to the factors in the last 25 years. (TR 1102; TR 2347) Therefore, staff believes that Gulf’s arguments are sufficiently supported by the record and the methodology and allocation factors SCS uses to allocate costs to Gulf and its other affiliates should not be adjusted as recommended by OPC.
CONCLUSION
Adjustments are not necessary to the allocation factors used to allocate SCS costs to Gulf. The factors are provided annually to the FERC for review, they have been used for over 25 years, they were approved by the Commission in Gulf’s last two rate cases, and neither the FERC nor the Commission auditors have recommended changes to the factors.
Should the Commission remove costs from the 2012 test year for costs associated with SouthernLINC?
Recommendation:
No. The costs are for unique services that Gulf uses to provide prompt, reliable and efficient service to its ratepayers. (Trueblood)
Position of the Parties
GULF:
No. SouthernLINC provides unique communication services to Gulf in support of service crew work management, interoperability between transmission and distribution automation systems, and voice/data communication. SouthernLINC’s service characteristics are vital to Gulf’s operations and its ability to provide reliable and efficient service to its customers.
OPC:
Yes. Southern charges all affiliates for the total SouthernLINC charges that are not able to be recovered through commercial revenues. In 2012, the charges to Gulf Power are projected to increase because of the “larger than anticipated drop in commercial customer revenue.” SouthernLINC is an unregulated affiliate. Its losses should not be subsidized by Gulf Power’s ratepayers. The Commission should remove $294,765 from the test year expenses. See OPC’s position on the capital component in Issue 17.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Southern Company inappropriately charges all affiliates, including the regulated utility companies, for SouthernLINC charges that are not covered by commercial revenues. This results in Gulf subsidizing SouthernLINC, which is inappropriate, contrary to Commission policy, and contrary to the public interest. The Commission should reduce Gulf’s test year expenses by $294,765.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Jacobs testified that through use of wireless technology, Gulf is able to provide better service to its customers by remotely communicating work orders to service vehicles in the field. (TR 476) The expenses in the 2012 test year for SouthernLINC are for unique telecommunication communication services necessary for the continued reliable operation of Gulf’s distribution and transmission system that have no commercial comparison in the marketplace. SouthernLINC markets its services commercially and Gulf and other operating companies of the Southern Company electric system benefit financially from those commercial operations because the contribution to fixed costs from the commercial operations reduces the billing to Gulf and its sister companies. Witness Jacobs asserted that SouthernLINC’s services are billed to Gulf at cost less the contribution to fixed costs obtained from its commercial subscribers. (TR 2283; Gulf BR 64)
Gulf argued that SCS bills Gulf for wireless communication services it uses for its business that are provided by SouthernLINC through its work order system. Gulf stated that approximately five percent of SouthernLINC’s costs were allocated to Gulf based upon SouthernLINC’s total revenue requirements, net of commercial revenues. (EXH 113, No. 63; EXH 117, No. 229; EXH 119, No. 265)
Witness Jacobs contended that OPC acknowledged that profit from SouthernLINC’s commercial aspects declined in 2009 and 2010, which resulted in less of SouthernLINC’s total costs being defrayed. He asserted that Gulf’s customers are not subsidizing the non-regulated operations, but instead, they are benefiting from reduced costs that SouthernLINC charges Gulf for telecommunication services that are vital to its operations. (TR 2284) SouthernLINC was established to provide digital wireless voice and data services to Gulf and its affiliates because there were no alternatives in the commercial market. Prior to SouthernLINC’s 800 MHz telecommunication system that provides push-to-talk communications on a hand-held device that Gulf’s employees can keep with them while working on the electric network, communication was limited and only available from the work vehicle. Witness Jacobs argued that as a result of the services provided by SouthernLINC, functionality was expanded, personal safety and operational productivity improved, and the technology that was developed to meet the needs of the operating companies of the Southern Company electric system was made available to other users to help defray the costs of the system. (TR 2284-2285; EXH 119; Gulf BR 64-65)
Witness Jacobs asserted that SouthernLINC’s network corresponds with the entire Southern Company electric system and enables Gulf to automate its work order dispatch and vehicle location for service crews. He pointed out that as additional smart grid equipment is installed on Gulf’s transmission and distribution systems, SouthernLINC’s interoperability between transmission and distribution automation systems will result in enhanced monitoring, switching, and fault location. (TR 2285; EXH 119)
Witness Jacobs pointed out that Gulf serves DeFuniak Springs, Bonifay, Graceville, Century and other small communities, and in many of these rural communities SouthernLINC is the only wireless service provider. SouthernLINC’s system was designed to meet the rigorous standard of utility construction and each site critical to electric operations has a generator sufficient to power the site for several days, battery backup capabilities, controllers, and base radios. Witness Jacobs maintained that as a result of SouthernLINC’s wireless network infrastructure resiliency, it was operational and Gulf was able to immediately begin restoration efforts after its territory was affected by Hurricane Ivan. He argued that the unique characteristics of SouthernLINC’s network are vital to Gulf’s operations and its ability to provide reliable and efficient service to its customers and the costs are reasonable and prudent. Witness Jacobs further stated that other communication carriers sustained severe damage to their networks after the storm and their customers experienced limited communications for days. (TR 2286-2287; Gulf BR 63)
OPC
OPC witness Dismukes opined the $294,765 included in the test year to support SouthernLINC should not be charged to Gulf. According to Southern Company’s Form 10-K, SouthernLINC is a non-regulated affiliate that provides digital wireless communications to the Southern Company and its subsidiaries, and markets services to the public and telecommunication providers in the Southeast. SouthernLINC’s revenues decreased in 2009 and 2010 as a result of lower average revenue per subscriber and fewer subscribers due to competition. (TR 1630; EXH 191; OPC BR 15) Witness Dismukes asserted that information that Gulf provided indicates that all costs not recovered through commercial revenues are assigned to affiliates, and the 2012 charges to Gulf are projected to increase due to a decrease in commercial revenue. She testified that SouthernLINC’s losses should not be subsidized by Gulf’s ratepayers. (TR 1631; EXH 117, No. 229)
When addressing Issue 17 in its brief, OPC argued that during the period 2008 to 2011, Southern Company’s Form 10-K shows that SouthernLINC’s operating revenues have decreased due to its inability to compete with other wireless providers. OPC further argued that Gulf and the operating companies should not subsidize SouthernLINC by sharing all of the charges not recovered through commercial revenues. (OPC BR 16)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 9; FRF BR 19; FEA BR 27)
ANALYSIS
Gulf witness Jacobs provided extensive testimony explaining how costs are allocated to Gulf and how its ratepayers are not subsidizing SouthernLINC’s losses. Staff notes that SouthernLINC provides unique wireless telecommunication services that are critical to Gulf’s regulated operations, and also markets technology to commercial customers to increase its revenue base and offset costs that otherwise would have to be paid by Gulf and the other operating companies. (TR 2283)
Based on the record, staff believes that projected charges in the 2012 test year are supported by the evidence in this case. Staff also believes that costs are properly charged to Gulf based upon the type of services Gulf receives from SouthernLINC, and that those charges are adequately accounted for through work orders and recorded in the appropriate FERC account.
Staff notes the importance of monitoring the activities of affiliates to ensure that the regulated companies are not subsidizing the non-regulated affiliate companies. However, staff does not believe that Gulf is subsidizing SouthernLINC and agrees with Gulf witness Jacob that revenues from SouthernLINC’s commercial customers are used to defray or reduce the total cost that Gulf and the other operating companies are charged. Thus, staff believes that OPC witness Dismukes’ contention that Gulf is subsidizing SouthernLINC’s losses is not supported by the evidence.
Finally, staff believes that Gulf’s ratepayers benefit from the services that it receives from SouthernLINC that enables Gulf to provide a resilient wireless network and respond more promptly to service problems through an improved communications network.
CONCLUSION
The costs in the 2012 test year are associated with unique services that Gulf uses to provide prompt, reliable and efficient service to its ratepayers. Therefore, they should not be removed from the Company’s projected costs for the test year.
Should the costs related to Work Order 466909, associated with a system-wide asset management system, be removed from operating expenses? (Category 1 Stipulation)
Approved Stipulation:
The costs associated with a system-wide asset management system related to work order 466909 should have been capitalized, rather than expensed, resulting in a reduction to test year jurisdictional O&M of $343,847 ($344,204 system).
DROPPED.
Did Gulf adequately document and justify the costs associated with Work Orders 46EZBL, 46IDMU, 46LRBL, 47VSES, 47VSTB, 47VSTH, 47VSZ1, and 47VSZ5? If not, should the costs related to these work orders be removed from operating expenses?
Recommendation:
Yes. Gulf has provided adequate documentation and justification of the costs associated with Work Orders 46EZBL, 46IDMU, 46LRBL, 47VSES, 47VSTB, 47VSTH, 47VSZ1, and 47VSZ5. The costs associated with these work orders are supported and should not be removed from test year operating expenses. (Mouring)
Position of the Parties
GULF:
Gulf adequately documented and justified the costs associated with Work Orders 46EZBL, 46IDMU, 46LRBL, 47VSES, 47VSTB, 47VSTH, 47VSZ1, and 47VSZ5. In Gulf’s response to OPC’s Request to Produce Documents No. 108, the Company stated that the original approved work orders could not be located, but provided descriptions and justifications for the activities covered by the work orders. The total budgeted amount allocated to Gulf was provided in response to OPC’s Request to Produce Documents No. 34, Attachment E. The allocation methods used for each work order were provided in response to OPC’s Request to Produce Documents No. 34, Attachment B. This same information is summarized in Witness McMillan’s Rebuttal Testimony, Exhibit RJM-2, Schedule 2.
OPC:
No. Because Gulf Power did not justify including the costs of these work orders, the Commission should reduce test year costs by $186,780. Gulf was unable to provide several of the requested Work Orders, which show the purpose of the work order, the method used to allocate costs, and the client company.
FIPUG:
No. Agree with OPC.
FRF:
No. Gulf failed to justify the costs associated with these work orders, and accordingly, the Commission should reduce test year expenses by $186,780.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf has acknowledged that the original approved work orders discussed in this issue could not be located and provided in this case. (EXH 150, p. 55) Gulf witness McMillan testified that these specific work orders had been misplaced as a result of a clerical error, but that detailed information about each work order, how they were accounted for, and how the costs were allocated was available via the Company’s accounting records. (EXH 150, pp. 54-55)
Witness McMillan testified that Work Order 46EZBL relates to the license, IT labor, and resource usage of the eGain software package. (EXH 168, Schedule 2) Witness McMillan went on to explain that the eGain software packages serve to manage incoming customer information requests to the appropriate department. (EXH 168, Schedule 2) Gulf also provided an explanation of how the work was accounted for and the allocation method used to charge Gulf. (Gulf BR 66; EXH 138, No. 34)
Witness McMillan testified that Work Order 46IDMU relates to the IT labor and resource usage related to the Load Data Analysis (LDA) database support. (EXH 168, Schedule 2) Witness McMillan went on to explain that the LDA tool collects data related to metering, weather, interval, customer base load, system hourly load and substation load to be used for analysis and for the calculation of billing rates. (EXH 168, Schedule 2) Gulf also provided an explanation of how the work was accounted for and the allocation method used to charge Gulf. (Gulf BR 66; EXH 138, No. 34)
Witness McMillan testified that Work Order 46LRBL relates to the license, IT labor, and resource usage for the Oracle Utilities Rate Manager software system. (EXH 168, Schedule 2) Gulf went on to explain that this software system provides an automated system which integrates business functions and provides accurate, timely, and competitive response of rate pricing, design, and analysis. (EXH 168, Schedule 2) Gulf also provided an explanation of how the work was accounted for and the allocation method used to charge Gulf. (Gulf BR 66; EXH 138, No. 34)
Witness McMillan testified that Work Orders 47VSTH, 47VSES, 47VSZ5, 47VSTB and 47VSZ1 relate to allocations of Enterprise Solutions Support to Supply Chain Management, which supports various other systems. (EXH 168, Schedule 2) These various other systems provide asset management software used in the Company’s warehouses, the processing of the procurement and payment of goods and services, the front-end imaging system, and initial work-flow system used for invoices and expense requests. (EXH 168, Schedule 2) Gulf also provided an explanation of how the work was accounted for and the allocation method used to charge Gulf. (Gulf BR 66; EXH 138, No. 34)
OPC
OPC witness Dismukes recommended that the costs associated with these work orders be disallowed because OPC believes that Gulf has failed to support the need for these services. (OPC BR 60-61) Witness Dismukes also stated that “support documentation is necessary to satisfy Gulf’s burden of proof,” and disagreed with Gulf witness McMillan’s statement that Company descriptions and spreadsheet explanations should be sufficient. (OPC BR 61; TR 1632-1633)
FIPUG, FRF and FEA have all adopted OPC’s position on this issue. (FIPUG BR 9; FRF BR 19; FEA BR 27)
ANALYSIS
Staff agrees with OPC witness Dismukes that support documentation is necessary when analyzing and evaluating any company’s requested expenses. In this instance, staff believes Gulf has provided sufficient support documentation to establish that these work orders are legitimate. (OPC BR 61; EXH 168, Schedule 2; EXH 138, No. 34; EXH 150, pp. 54-55) Staff disagrees with OPC’s argument that “the Company was unable to provide the Work Orders demonstrating the need, the method used to allocate the costs, and the company(ies) the costs should be charged to.” (TR 1632-1633) Based on the description of services and cost allocation information provided for these work orders, staff believes that these work orders represent normal and prudent operating activities. (EXH 168, Schedule 2; EXH 138, No. 34; EXH 150, pp. 54-55)
CONCLUSION
Based on the above, staff believes that Gulf has adequately documented and justified the costs associated with Work Orders 46EZBL, 46IDMU, 46LRBL, 47VSES, 47VSTB, 47VSTH, 47VSZ1, and 47VSZ5. Therefore, staff recommends that the costs related to these work orders not be removed from operating expenses.
Should the costs related to Work Order 471701, associated with a Securities and Exchange Commission inquiry, be removed from operating expenses?
Recommendation:
No. The costs related to Work Order 471701 are not associated with an SEC inquiry, but rather are related to the Company’s Comptroller organization. The costs associated with Work Order 471701 are prudent and should be allowed. (Mouring)
Position of the Parties
GULF:
No. The work order form submitted for this item was an outdated form. This work order is no longer used for an SEC inquiry, and the work order number has been reused by the SCS Comptroller organization. The test year amount includes various special projects, including Enterprise Solutions transition and implementation, and the costs incurred were necessary, prudent and in the interest of Gulf’s customers.
OPC:
Yes. Looking at this accounting-comptroller work order, it is not clear what service is being provided to Gulf and its customers or if the description remains valid today. In the absence of supporting documentation showing that the costs booked benefit Gulf and its customers, test year expenses should be reduced by $116,841.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Because Gulf’s work order does not document what service is being provided to Gulf and Gulf’s customers and does not document what, if any, benefits were provided to Gulf and its customers by the work charged, the Commission should reduce Gulf’s test year expenses by $116,841.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan testified that the costs associated with this work order are related to the Company’s Comptroller organization for special projects and that the reference to an SEC inquiry is the result of an outdated work order form. (TR 2349) Witness McMillan went on to elaborate that the special projects include the transition and implementation of new accounting, finance, and treasury infrastructure associated with the Company’s Enterprise Solutions project, accounting research on new FASB regulations, as well as other various need-based special projects. (EXH 119, No. 269; EXH 150, pp. 56-57) Gulf argues that these costs are necessary, prudent, and in the interest of Gulf’s customers, and are anticipated to continue in the future. (Gulf BR 66-67)
OPC
OPC witness Dismukes argued that the costs associated with this work order are related to an SEC inquiry of the Southern Electric System that was initiated in 1989, and that it is not clear what service is being provided to Gulf and it customers today. (TR 1633) Witness Dismukes challenged Gulf witness McMillan’s rebuttal, stating that the Company’s response was “vague and insufficient” and underscored OPC’s position that more information is needed about how the Company charges these costs and how the customers benefit from them. (OPC BR 61) OPC goes on to assert that in the absence of any supporting documentation for the work orders, the costs should be removed from the test year. (TR 1633)
FIPUG, FRF and FEA have all adopted OPC’s position on this issue. (FIPUG BR 9; FRF BR 19; FEA BR 28)
ANALYSIS
Gulf provided Work Order 471701, which lists the description of services as “Accumulate cost associated with the SEC inquiry of the Southern Electric System” which OPC used as the foundation of its argument that the costs associated with this work order should be removed from the test year operating expenses. (EXH 141, No. 108; TR 1633) Gulf rebutted OPC’s argument by explaining that the work order was simply outdated and that the costs were in fact related to the Company’s Comptroller organization. (TR 2349) Gulf also provided additional testimony about the current charges associated with Work Order 471701 and why it was necessary and in the interest of Gulf’s customers. (EXH 150, pp. 56-57; Gulf BR 66-67; EXH 117, No. 229) Witness McMillan went on to elaborate that the special projects include the transition and implementation of new accounting, finance, and treasury infrastructure associated with the Company’s Enterprise Solutions project, accounting research on new FASB regulations, as well as other various need-based special projects. (EXH 119, No. 269; EXH 150, pp. 56-57)
CONCLUSION
Staff agrees with OPC witness Dismukes, that on its surface, an adjustment appears warranted for Work Order 471701, if it were in fact related to an SEC inquiry of the Southern Electric System that was initiated in 1989. However, based on the Company’s explanation discussed above, staff believes that the Company has supported the costs associated with Work Order 471701 as being necessary and prudent. As such, staff recommends that the costs related to Work Order 471701 not be removed from operating expenses, though staff would suggest that the Company consider no longer using this outdated work order for activities that are unrelated to an SEC inquiry to avoid any confusion in the future.
Should the Commission adjust operating expenses for the costs related to Work Order 473401, related to a benefit’s review that does not appear to occur annually?
Recommendation:
No. Benefit review activities are varied and they are conducted each year. Therefore, the operating expenses should not be amortized over two years. (Trueblood)
Position of the Parties
GULF:
No. A number of benefits reviews are conducted on a recurring basis or an as-needed basis at various times throughout the years. Although the specific benefits reviews covered by this work order take place every other year, there are other normal benefits review activities that do not fall during the test year. The amount included in the test year is representative of an on-going level of benefits review activity.
OPC:
Yes. This 2011 work order relates to consulting funds for an outside benefits review which apparently was increased because it did not occur annually. Because the review will not reoccur annually, the cost should be amortized over two years. The corresponding adjustment is a reduction of $18,067 to test year expenses.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Because the benefit review that is the subject of this work order does not occur annually, the cost should be amortized over two years. The Commission should accordingly reduce Gulf’s test year expenses by $18,067.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf’s witness McMillan summarized that the activities relating to this work order are necessary and the appropriate cost allocation factors were used to assign costs to Gulf. (TR 2349) He asserted that benefit reviews are conducted on a recurring basis, even though the benefit review activities covered by Work Order 473401 takes place every other year. Witness McMillan testified that there are other normal benefit review activities that did not occur during the test year and the amount included in the test year should not be amortized over two years because it represents an on-going level of benefit review activity. (TR 2350; EXH 119, No. 279; EXH 150; Gulf BR 67) He asserted that normal benefit activities are performed by human resources that include analyzing and evaluating compensation packages in relation to the market. Witness McMillan further argued that the work order that OPC witness Dismukes selected included a specific survey, however, there are other benefit review activities similar to the survey that are ongoing. (EXH 150, p. 60)
Gulf described the benefit reviews as outside consulting activities performed by Southern Company’s human resources executive management. (EXH 117, No. 229) Gulf argued that since February 2009, five benefits reviews have been conducted on a varied basis. The benefit review activities included: (1) assessment of the potential impact of market changes and regulatory filing requirements on projected accounting costs, (2) assessment of projected postretirement benefit funding costs, (3) study of Total Rewards, (4) compliance review of the Department of Health and Human Services’ Early Retiree Reinsurance Program (ERRP), and (5) implementation of the benefit reviews. The documentation showed that $69,402 was expensed in 2008, $93,618 in 2009, $114,628 in 2010, and $88,567 for the period January through September 2011 for benefit review activities under Work Order 473401. (EXH 119)
OPC
OPC witness Dismukes argued the expenses in Work Order 473401 relate to consulting funds for an outside benefits review that does not occur annually therefore the amount should be amortized over two years and $18,067 should be removed from the test year. (TR 1633-1634; OPC BR 62) Witness Dismukes also stated that some of the service company specific work orders should be removed from the test year because they lacked supporting details. (TR 1643)
In its brief, OPC argued that while Gulf’s witness McMillan admitted that the benefit review for the 2011 Work Order does not take place each year, he stated that other benefit reviews are conducted on an as-needed basis through the years. OPC stated that witness McMillan’s analysis did not identify the associated costs that are included in the test year and for that reason his argument fails. (OPC BR 62)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 9; FRF BR 19; FEA BR 28)
ANALYSIS
The Parties agree that the benefit review in the 2011 Work Order does not occur every year. The facts presented regarding the benefit review activity covered in Work Order 473401 indicate that normal benefit review activity is not limited solely to the benefit reviews that occur every other year. Gulf’s benefit review activity is varied and it has been performed by Southern Company’s human resources management each year since February 2009.
Staff notes that OPC witness Dismukes’ recommendation and adjustment regarding the benefit review covered in the 2011 Work Order 473401 appears to be based primarily on the fact that the benefit review occurs every other year. Gulf argued that other normal benefit activities are ongoing and that the 2012 test year costs represents an ongoing level of benefit review activity. To support its argument, Gulf provided documentation showing that since February 2009, benefit review activities have been varied and conducted each year.
Based on the record, staff believes that benefit review activities are varied and are conducted on a recurring basis. Because the activities are ongoing, staff was not persuaded by OPC’s argument that Gulf’s explanation fails because costs for the 2012 test year were not identified.
CONCLUSION
Benefit review activities are varied and occur each year. Thus, staff recommends the Commission not require that the operating expenses be amortized over two years. As a result, no adjustment related to Work Order 473401 is warranted.
Should the costs related to Work Order 49SWCS, related to a customer summit that is only held every other year, be removed from operating expenses? (Category 1 Stipulation)
Approved Stipulation:
The costs related to Work Order 49SWCS for a biannual customer summit should be amortized over two years. This results in a reduction to test year jurisdictional O&M of $19,450 ($20,130 system).
Should the costs related to Work Order 4Q51RC and a formerly CWIP classified Work Order 4QPA01, be removed from operating expenses?
Recommendation:
No. The costs are ongoing and pertain to software maintenance and enhancements used to manage the railcar maintenance program and the Control System Integrity tool used to manage and document compliance requirements resulting from the North American Electric Reliability Corporation (NERC) Cyber Security Standard. The costs included for the 2012 test year are reasonable and prudent and thus should not be removed from operating expenses. (Trueblood)
Position of the Parties
GULF:
No. Work Order 4Q51RC covers the on-going annual software costs, including maintenance and enhancements, associated with a new application that is necessary to effectively and efficiently manage the railcar maintenance program. Work Order 4QPA01 covers the ongoing support expenses associated with the control system integrity (CSI) which is used to manage and document the compliance requirements resulting from the NERC Cyber Security Standards.
OPC:
Yes. There is no evidence that these items should be expensed rather than capitalized, and also no evidence they are recurring in nature. Test year expenses should be reduced by $20,102 and $102,411, respectively.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Test year expenses should be reduced by $20,102 and $102,411, respectively.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
This issue addresses software and enhancements in Work Order 4Q51RC, and a formerly CWIP classified Work Order, W4QPA01, that Gulf asserts should be expensed. Gulf witness McMillan asserted that these work orders cover ongoing software costs associated with a new application necessary for managing the railcar maintenance program, and ongoing expenses related to control system integrity (CSI). (TR 2352)
Witness McMillan testified that the railcar software system manages railroad and private repair shop maintenance invoices mandated by railroad standards for railcar use, and provides information to audit maintenance invoices, automate payments, and to provide repair histories for the railcar fleet. He argued that the charges for this system are related to necessary ongoing support and enhancements for the new software application. The charges are recurring and they are expensed because they did not meet the capitalization threshold. He further asserted that the CSI tool allows Gulf to manage and document the compliance requirements resulting from the NERC Cyber Security Standards and when the CSI tool is placed in service at the end of 2011, the depreciation expense will be billed to the Company and booked to expense in 2012. (TR 2352; EXH 119, Nos. 275-276; EXH 141, No. 108; Gulf BR 68)
Witness McMillan testified that the new software application for managing the railcar maintenance program is a third-party software package that was budgeted for 2012, which is the test year. (EXH 150) Witness McMillan stated that the in-service date included in the 2011 budget was December 2011. He further stated that the anticipated in-service date has been moved beyond the 2012 test year and is now expected to be placed in-service in 2013. However, witness McMillan argued that while specific dollars are not expected to be expensed in the 2012 test year, the costs have been assigned to other activities covered in this work order that represent ongoing costs. He later clarified that the new system is budgeted to a fuel account related to fuel handling and the costs were not included in the fuel clause adjustment as he testified earlier. In a late-filed exhibit witness McMillan stated that since the costs were not recovered in the fuel clause, they are included in the Company’s base rate request. (EXH 196, No. 3; Gulf BR 68)
Gulf explained that the increase in the amount budgeted from 2011 to 2012 is primarily due to approximately $20,000 of railcar software enhancement maintenance expenditures being moved from Plant (rate base) to O&M (expense). The difference in the budgeted amounts for CSI from 2011 to 2012 are due to increased product rates for leased dedicated servers and personal computers, and the reclassification of expenses from CWIP to O&M expense. (EXH 117, No. 229)
OPC
OPC witness Dismukes testified that the Company’s explanation for the increase in the expense amount from the 2011 to the 2012 budget was due to a formerly capitalized item for Work Order 4Q51RC and a formerly CWIP classified Work Order 4QPA01 being moved to expense. She asserted the Company failed to demonstrate why these costs should be expensed instead of capitalized and provided no evidence to show that these costs are recurring and should be included in test year expenses. (TR 1634; OPC BR 62)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 10; FRF BR 20; FEA BR 28)
ANALYSIS
The items covered by the two work orders addressed in this issue are capitalized items that Gulf wants to move from plant to O&M expense. Staff believes the record supports Gulf’s argument that the maintenance and enhancement costs for the software are ongoing and recurring.
Staff notes that the in-service date for the new application for the railcar and CSI tool was December 2011 and the Company has now moved that date beyond the 2012 test year to 2013. Staff recognizes that during the implementation stages of a project the targeted in-service date may change. Staff also believes that it is reasonable to expect that some expenses associated with a new application being ready to be placed in-service are ongoing.
Staff notes that no party presented strong arguments or extensive evidence to support its position on this issue. In contrast, staff believes the explanation and documentation provided by Gulf are sufficient to support its position that the costs associated with the implementation of the new application are ongoing and should remain in the 2012 expenses.
CONCLUSION
The costs are ongoing and pertain to software maintenance and enhancements used to manage the railcar maintenance program and the CSI tool used to manage and document compliance requirements resulting from the NERC Cyber Security Standard. The costs included for the 2012 test year are reasonable and prudent and thus should not be removed from operating expenses.
Should operating expenses be adjusted to remove public relations expenses charged by SCS?
Recommendation:
No. Operating expenses should not be adjusted to remove public relations expenses charged by SCS. (Mouring)
Position of the Parties
GULF:
No. This work order covers internal company publications that educate employees about industry, local and company issues, making them better equipped to serve customers. It also includes external public relations messages that are used to communicate billing, safety, and energy efficiency information to Gulf’s customers. This helps customers by providing information on alternative ways to receive and pay bills, ways to prevent accidental injuries, and ways to use energy more efficiently, resulting in value and savings to the customer.
OPC:
Yes. The Commission typically disallows expenses that are public relations oriented and image-enhancing, finding that they benefit stockholders, not customers. Gulf Power failed to demonstrate that such expenses benefit customers. Based on past Commission precedent, test year expenses should be reduced by $17,482.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Consistent with the Commission’s long-standing policy of disallowing expenses that are image-enhancing for the benefit of the Company’s shareholders, the Commission should reduce Gulf’s test year expenses by $17,482.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan testified that the expenses related to SCS Work Order 474401, relating to internal company publications and external public relations messages should not be removed from test year expenses. (EXH 119, No. 268) Gulf asserted that these internal publications involve educating employees about various industry, local, and Company issues, making its employees better equipped to serve its customers. (EXH 119, No. 268; EXH 150, p. 64; Gulf BR 69) Witness McMillan went on to explain that the external publications serve to inform Gulf’s customers about billing, safety, and energy efficiency matters as well as to help coordinate with Gulf’s other operating companies regarding sharing and not duplicating costs. (EXH 119, No. 268; EXH 150, p. 64) Gulf testified that these external customer publications help its customers to find alternative ways to receive and pay bills, prevent accidental injuries, and use energy more efficiently which provides value to its customers. (TR 2351)
OPC
OPC witness Dismukes testified that the Commission has typically disallowed expenses that are public relations oriented, finding that they benefit stockholders, not customers. (TR 1635) Witness Dismukes went on to assert that Gulf has failed to demonstrate that these activities benefit the customers in this case. (OPC BR 63) OPC believes that these costs are based on image-enhancing activities and that test year expenses should be reduced by $17,482. (TR 1636; OPC BR 63)
FIPUG, FRF, and FEA have adopted OPC’s position on this issue. (FIPUG BR 10; FRF BR 20; FEA BR 28)
ANALYSIS
Staff disagrees with OPC witness Dismukes’ characterization of the costs associated with Work Order 474401 being exclusively beneficiary to shareholders. (TR 1635) Staff believes that based on the description of services provided by the Company for Work Order 474401, and the testimony provided by Gulf witnesses, the Company has supported these expenses. (TR 2351; Gulf BR 69) Staff believes that both the internal publications and external publications described by Gulf witness McMillan directly benefit their customers. As such, staff recommends that no adjustment is necessary to remove public relations expenses charged by SCS.
CONCLUSION
Based on the above, staff recommends that no adjustment is necessary to remove public relations expenses charged by SCS associated with Work Order 474401.
Should operating expenses be adjusted to remove legal expenses in Work Orders 473ECO and 473ECS charged by SCS?
Recommendation:
No. The operating expenses should not be adjusted to remove the legal expenses. SCS is the service company that provides legal advice to Gulf and the other subsidiaries of the Southern Company and the expenses charged to Gulf are for legal work that Gulf receives necessary to ensure compliance with rules and regulations affecting its operation that ultimately benefits the ratepayers. (Trueblood)
Position of the Parties
GULF:
No. The Chief Operating Officer and External Affairs functions provide services to Gulf, and any related legal advice is budgeted in these work orders. Each of these functions requires legal advice to ensure compliance with rules, regulations, contracts, and agreements. These activities benefit ratepayers.
OPC:
Yes. These work orders relate to Chief Operating Officer legal expenses and External Affairs legal matters. Gulf has not demonstrated that the costs charged to these two accounts benefit ratepayers. Test year expenses should be reduced by $33,690.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Because Gulf has not demonstrated that these legal expenses benefit customers, the Commission should reduce Gulf’s test year expenses by $33,690.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan asserted that Work Orders 473ECO and 473ECS cover functions that require legal work necessary to comply with rules, regulations, contracts and agreements, that ultimately benefits its ratepayers. The legal work is provided by the chief operating officer and external affairs office and the related expenses are budgeted in these work orders. (TR 2350; EXH 119, No. 280) Gulf clarified that Work Order 473ECS reflects the total external affairs expenses budgeted and the expenses incurred are actually charged to a number of specific orders that share in the overall budget. (EXH 119, No. 281; Gulf BR 70)
Witness McMillan testified that legal advice is sought regarding many things, such as environmental laws and electric-related matters debated in Washington. The ratepayers benefit from the legal advice Gulf receives that ensures compliance with the laws and regulations affecting its operation. Witness McMillan asserted that everything Gulf does to ensure its business operates efficiently and cost-effectively is for the benefit of the ratepayers. (EXH 150. pp. 61-63; Gulf BR 70)
OPC
OPC witness Dismukes testified that Work Orders 473ECO and 473ECS relate to the chief operating officer and external affairs legal expenses and the Company has not clearly shown how these costs benefits ratepayers. She asserted that the expenses should not be included in the test year unless the Company can demonstrate how the services received from the expenses are beneficial to the ratepayers. (TR 1637; OPC BR 64)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 10; FRF BR 20; FEA BR 28)
ANALYSIS
Gulf receives legal advice from the chief operating officer and the external affairs functions that are covered in the two work orders addressed in this issue. Staff notes that SCS, the service company, charges the expenses for the legal work provided to Gulf to the accounts set up in Work Order 473ECO and Work Order 473ECS. Staff notes that the legal expenses budgeted in the work orders for the projected test year 2012 are $34,866, which is a $1,014 increase over the 2011 budgeted amount of $33,852. (EXH 51)
Staff believes the legal fees for the Company are reasonable. Staff also believes that the explanation and documentation provided support Gulf’s assertion that the ratepayers indirectly benefits from the legal advice it receives. Based on the evidence presented, staff believes the projected 2012 expenses of $33,690 ($34,866 system) are reasonable and prudent.
CONCLUSION
An adjustment to the operating expenses to remove the legal expenses is not warranted. SCS provides legal advice to Gulf and the other subsidiaries of the Southern Company. The expenses charged to Gulf are for legal work that Gulf receives to ensure compliance with rules and regulations affecting its operation that ultimately benefits ratepayers.
DROPPED PER STIPULATION.
DROPPED PER STIPULATION.
Should operating expenses be adjusted to remove investor relations expenses related to Work Order 471501 charged by SCS?
Recommendation:
No. An adjustment should not be made to operating expenses to remove the investor relations costs that SCS charges Gulf. The stockholders and the ratepayers benefit from the investor relations program and the Company should be allowed to include reasonable expenses in the 2012 test year. (Trueblood)
Position of the Parties
GULF:
No. Investor Relations works with investors to preserve the value of Gulf’s securities and to ensure continuous access to capital at favorable rates for the benefit of Gulf and our customers. This work order provides an on-going investor relations program to facilitate informed relationships with existing and potential investors in system equity and debt securities. This ensures that the Company’s securities are fully valued by the investment community through regular communications that provide updates on the financial condition and plans of the Company. This type of Investor Relations activity is an essential function for any company with publicly traded securities.
OPC:
Yes. Consistent with prior Commission practice, test year operating expenses should be reduced by $96,851 to remove the costs of shareholder services, which benefit stockholders, not ratepayers.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. Because the expenses that are the subject of this work order represent costs of shareholder services, which benefits shareholders but not customers, the Commission should reduce Gulf’s test year expenses by $96,851.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Witness McMillan testified that investor relations works to preserve the value of Gulf’s securities and to ensure continuous access to capital at favorable rates for the benefit of Gulf and its customers. Through Work Order 471501, the Company has an ongoing investor relations program with current and potential investors in system equity and debt securities that ensures that the Company’s securities are fully valued by the investment community. Witness McMillan further argued that investor relations activities are essential for any company with publicly traded securities. (TR 2351; EXH 117, No. 229; EXH 119, No. 270; Gulf BR 70)
Witness McMillan stated that SCS works as Gulf’s agent and interacts with individuals who are involved in the capital markets to ensure that Gulf has access to cost effective or adequate investment sources. Gulf’s ratepayers benefit from SCS’ interactions with individuals in the investment community that result in lower costs for Gulf’s debt sales and adequate access to money necessary to capitalize the Company’s business. Witness McMillan asserted that investor relations facilitates these benefits by answering questions potential investors have regarding investment securities. (EXH 150, pp. 64-65)
Gulf indicated that $99,955 has been budgeted for investor relations general expenses for the 2012 test year through this work order. (EXH 117, No. 229) Documentation was provided that reflected that the Company expensed $87,502 in 2008, $71,923 in 2009, $85,066 in 2010 and $64,000 for the period of January through September 2011 for investor relations activities. (EXH 117, No. 270)
In its brief, Gulf argued that the expenses related to this work order were included in the Company’s last rate case and the 2012 test year amount is reasonable and prudent. (Gulf BR 71)
OPC
Witness Dismukes argued that the investor relations expenses are shareholders expenses that should be moved below-the-line for ratemaking purposes because they benefit the stockholders not the ratepayers. (OPC BR 65) She asserted that the Commission has removed shareholder costs in a prior rate case[34] and should continue its practice by removing the investor relations expenses of $96,851 from the 2012 test year. (TR 1637) To support her assertion, witness Dismukes provided the following excerpt from Commission Order No. PSC-96-1320-FOF-WS:
Through the ROE leverage formula, we have allowed recovery of costs associated with being a publicly traded utility. Specifically, in the calculation of the appropriate cost of equity, we recognized an additional 25 basis points to the otherwise determined cost of equity to provide for these costs. To ask SSU’s ratepayer to pay 25 basis points on ROE in addition to the amount requested by SSU would be duplicative. We also question whether the benefits SSU receives from MP&L are worth $208,776 to the ratepayers in Florida. Consequently, we shall disallow all of the utility’s requested shareholder services expenses of $208,776.
(TR 1637)
Witness Dismukes further argued that a similar adjustment was appropriate in the instant case because investor relations expenses benefit shareholders as opposed to ratepayers. In its brief, OPC presented a new argument that companies are compensated for investor relations costs through the rate of return on equity. (OPC BR 65)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 10; FRF BR 21; FEA BR 28)
ANALYSIS
Gulf’s investor relations program is budgeted through Work Order 471501 and conducted by staff of SCS, a subsidiary of the Southern Company, that provides a variety of services to Gulf. The investor relations program is ongoing and requires interaction with current and potential investors to ensure that the Company’s securities are fully valued by the investment community. (TR 2351; EXH 117, No. 229; EXH 119, No. 270; Gulf BR 70)
Staff notes that documentation was provided showing the expenses the Company has incurred for investor relations activities for the years 2008, 2009, 2010, and January through September 2011. Staff believes investor relations benefits the ratepayers through the Company’s access to capital at favorable rates. It is reasonable for a company with publicly traded securities to have an investor relations program and the Company should be allowed to include the associated expenses above-the-line for ratemaking purposes. Based on the evidence presented, staff believes that both the stockholders and the ratepayers benefit from the investor relations program activities and the costs are reasonable and prudent. (TR 2351; EXH 119, No. 270)
Staff notes that the Commission has on a case-by-case basis allowed investor relations expenses in prior rate cases,[35] where the record showed that ratepayers benefited from these activities. Staff also notes that the Commission has, as OPC witness Dismukes argued, disallowed these expenses in the rate case cited by OPC. Staff, however, believes the circumstances in the case cited by OPC are sufficiently different from those presented by Gulf in this proceeding.
Staff notes that in its brief, OPC raised the argument for the first time that companies are generally compensated for investor relations expenses through the rate of return on equity. (OPC BR 65) However, OPC did not argue that Gulf has been compensated for its investor relations expenses in this case through the rate of return on equity and the assertion is not supported by any evidence in the record.
CONCLUSION
No adjustment should be made to operating expenses related to this issue. The stockholders and the ratepayers benefit from the investor relations program and the Company should be allowed to include reasonable expenses in the 2012 test year.
What is the appropriate amount of advertising expenses for the 2012 projected test year? (Category 2 Stipulation)
Approved Stipulation:
The appropriate amount of advertising expenses for the 2012 projected test year is $1,132,000 ($1,132,000 system).
Should interest on deferred compensation be included in operating expenses?
Recommendation:
Yes. The Company should be allowed to include interest on the 2012 projected deferred compensation balance at a rate sufficient to cover the opportunity cost of the balance. Therefore, staff recommends that interest be calculated at a 3.12 percent rate resulting in an adjusted deferred compensation expense of $163,390 ($166,726 system). Therefore, the interest on deferred compensation should be reduced by $191,669 ($195,583 system). (Trueblood)
Position of the Parties
GULF:
Yes. The deferred compensation plan provides a market interest rate to compensate participants for the opportunity cost of deferring income into the future.
OPC:
No. Gulf has projected interest expense with an estimated 2012 prime rate of 6.78% on deferred compensation presumably for executives or senior level employees. Gulf has not documented or justified why interest is being paid, how the deferred compensation amounts resulted, or why such a high rate of interest should be passed on to Gulf’s ratepayers. Test year expenses should be reduced by $362,309 ($355,059 jurisdictional).
FIPUG:
No. Agree with OPC.
FRF:
No. Gulf’s customers should not be required to pay the interest costs of a deferred compensation program that benefits a limited number of Gulf’s upper management personnel. Moreover, Gulf has not justified the high interest rate on these amounts. Accordingly, the Commission should reduce Gulf’s 2012 test year expenses by $355,059 on a jurisdictional basis.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf offers an unfunded Deferred Compensation Plan (Plan) to its employees whose yearly earnings are $100,000 or more. The Plan allows eligible employees to defer earned income and certain taxes until a specific date or retirement. The Plan is subject to applicable provisions of the Employee Retirement Income Security Act of 1974. (TR 2001-2002; TR 2034-2035; EXH 113, No. 10; Gulf BR 72-73)
Gulf witness Kilcoyne testified regarding the Company’s deferred compensation plan, how the interest rate was determined, and why the interest should be included in the 2012 test year expenses. (TR 2001-2003) Witness Kilcoyne asserted that the participants, customers, and the Company benefit from the Plan. The Plan allows participants to exercise retirement and tax planning options and the Company to have the deferred funds available for other uses. The Plan offers a competitive compensation and benefit package to attract and help retain talented employees.
Witness Kilcoyne asserted that the deferred compensation interest is paid according to the Plan Prospectus and appropriately compensates the participants for the opportunity costs of the funds that are available to the Company in the form of working capital. She argued that this aspect of Gulf’s compensation benefits customers by assisting Gulf in retaining and attracting qualified managerial employees. (TR 2002)
She stated that Gulf pays a market interest rate on the deferred earnings to compensate the participants for the opportunity cost of deferring their income to a future date. The interest rate is established by the Plan Prospectus as the Prime Rate published monthly in the Wall Street Journal. Witness Kilcoyne argued that the budgeted interest rate was derived from Moody’s Analytics 2010, Prime Rate, which was current at the time the 2012 budget was prepared. She asserted that the budgeted interest of $362,309 should not be removed because the participants should receive interest on their deferred compensation. (TR 2002; Gulf BR 73)
Gulf noted that the Deferred Compensation Plan consists of two investments: (1) the Prime Rate Equivalent, and (2) the Southern Company Stock Equivalent. Any gains or losses for Gulf’s participants are recorded quarterly. (EXH 113, No. 11) Gulf provided information that reflected actual O&M expenses for interest on deferred compensation at $52,507 for 2009, $276,409 for 2010, $121,192 for 2011, and a forecasted amount of $362,309 for test year 2012. (EXH 113, No. 10) A derivation of Other Employee Benefits was also provided showing the calculation for the deferred compensation interest projected for the 2012 test year. The Company also explained that the interest on deferred compensation increased by $85,900 primarily because of the Moody’s Prime Rate of 6.78 percent, which was used for the 2012 projections, and to a lesser extent a 3 percent merit salary increase. (EXH 115, No. 184)
Witness Kilcoyne presented arguments regarding Gulf’s at-risk and variable pay programs. As support for using at-risk and variable pay, she asserted that deferred compensation is a part of an overall compensation approach that is market competitive and necessary to attract and retain employees. (TR 1983-1984; Gulf BR 72-73)
OPC
OPC witness Ramas stated that OPC asked Gulf to provide a breakdown of the projected 2012 Other Employee Benefits costs of $815,104, and to explain the increase above the test year amount. The response showed that the interest on deferred compensation in the amount of $362,309 is based on a 6.78 percent interest rate being applied to the 2012 year end balance of $5,343,788. (TR 1481-1482)
Witness Ramas argued the Company failed to discuss why interest is paid on the deferred compensation balances or how the balance resulted. She opined that the interest payments pertain to executives and senior level employees that have chosen to defer income with a generous interest rate of 6.78 percent. Moreover, she argued that the interest costs have not been justified and should not be included and passed on to the ratepayers. (TR 1882-1483; EXH 153, p. 60)
In its brief, OPC argued that the interest on deferred compensation is an executive perquisite and an unnecessary luxury that should be funded by the shareholder, if continued by Gulf. (OPC BR 65)
FIPUG, FRF, and FEA support OPC’s position. (FIPUG BR 10; FRF BR 21; FEA BR 28)
ANALYSIS
OPC witness Ramas argued the costs projected for the interest on deferred compensation is based on a generous rate and should be removed because the Company failed to justify why the costs should be included and why the interest rate should be 6.78 percent.
Gulf explained how the interest rate for the deferred compensation interest was determined, how the balance resulted, how the interest was calculated, and why the interest should be paid. Staff noted that the interest increased by $85,000 from 2010 to 2012 primarily as a result of the 6.78 percent rate used to calculate the interest on the deferred compensation balances.
Staff believes the Company should be allowed to include interest sufficient to cover the opportunity cost of the deferred compensation. However, staff agrees with OPC that the 6.78 percent interest rate is somewhat high considering the 30-Year U.S. Treasury rate was 3.12 percent on November 10, 2011. (EXH 136, No. 65) Gulf testified that the 6.78 percent interest rate was derived from the May 2010 Moody’s Analytics, which is now Moody’s Economy.com. (TR 2002-2003; Gulf BR 73) Staff reviewed the May 2010 Blue Chips Financial Forecasts for Moody’s Economy.com and calculated an average rate of 3.75 percent for the Second Quarter 2010 through the Third Quarter 2011. Staff notes that the 6.78 percent rate was not in the May 2010 Blue Chip Forecast for Moody’s Economy.com.
In staff’s opinion, the 30-Year U.S. Treasury rate of 3.12 percent on November 10, 2011, is the more appropriate interest rate for calculating the deferred compensation interest. The projected 2012 year end deferred compensation balance is $5,343,788. Applying the November 10, 2011 U.S. Treasury rate of 3.12 percent to this balance results in interest of $166,726 instead of the $362,309 that was proposed by the Company. Accordingly, staff believes that interest should be reduced by $195,583, which is the difference between the $362,309 proposed by Gulf and the $166,726 based on the current estimate of the applicable interest rate.
Table 66-1
|
Interest on Deferred Compensation |
||
|
|
Staff’s Calculation |
Gulf’s Calculation |
|
Projected 2012 Year End Balance |
$5,343,788 |
$5,343,788 |
|
Moody’s Analytics 2012 Prime Rate |
3.12% |
6.78% |
|
Adjusted Projected 2012 Deferred Compensation Interest Expense |
$166,726 |
$362,309 |
|
Jurisdictional Amount |
$163,390 |
$355,059 |
CONCLUSION
Staff believes the Company should be allowed to include interest on the 2012 projected deferred compensation balance at a rate sufficient to cover the opportunity cost of the balance. Therefore, staff recommends that the interest be calculated based on the 30-Year U.S. Treasury rate of 3.12 percent on November 10, 2011. The calculation results in an adjusted jurisdictional deferred compensation of expense of $163,390. Therefore, interest on deferred compensation should be reduced by $191,669 ($195,583 system).
Should SCS Early Retirement Costs be included in operating expenses?
Recommendation:
No. SCS Early Retirement Costs of $49,338 ($50,340 system) should not be included in operating expenses. (Wright)
Position of the Parties
GULF:
Yes. This expense is a cost of providing Gulf’s electric service. It was incurred as part of SCS early retirement initiatives during the 1980s and 1990s that lowered overall SCS costs, including those paid by Gulf customers. Gulf’s customers, having saved from these early retirements, should pay the continuing obligation associated with these early retirements. This SCS expense is not different from the expenses for other SCS benefit programs, and so it is properly included in operating expenses.
OPC:
No. Gulf neither explained nor supported what the “SCS Early Retirement” accrual was for or why it should be passed on to Gulf’s ratepayers. Test year expenses should be reduced by $50,340.
FIPUG:
No. Agree with OPC.
FRF:
No. Gulf failed to justify its request that Gulf customers be required to pay for these early retirement costs, which are associated with early retirement benefits provided to Southern Company Services employees who have not worked for SCS since the 1980s and 1990s, and further failed to even explain how Gulf’s customers benefit from services provided by the SCS employees. Accordingly, the Commission should reduce Gulf’s test year expenses by $50,340.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf witness Kilcoyne testified that the charge for SCS Early Retirement is an expense specifically associated with the benefits provided to a closed group of former SCS employees who terminated early as part of early retirement initiatives, during the 1980s and 1990s, that were intended to lower overall SCS costs, including those attributable to Gulf’s customers. (TR 2003, Gulf BR 74) Witness Kilcoyne stated that this expense is no different from the expense for other SCS benefit programs, and as such it should be included in the cost of service. (Gulf BR 75)
OPC witness Ramas testified that the Company only provided the monthly 2010 actual accrual for “SCS Early Retirement” of $4,195 and indicated that the same $50,340 annual amount was budgeted for 2012. (TR 1483) Witness Ramas stated that “[T]here is no further discussion regarding what the SCS Early Retirement accrual was for or why it should be passed on to Gulf’s ratepayers.” Witness Ramas recommended that the $50,340 amount be removed. (TR 1483)
FIPUG, FRF, FEA all agreed with OPC that the $50,340 should be removed from operating expenses. (FIPUG BR 10; FRF BR 21; FEA BR 28)
ANALYSIS
Staff agrees with OPC that the SCS Early Retirement accrual of $50,340 should not be included in test year expenses. In response to OPC discovery, the Company stated that the 2010 monthly accrual was $4,195, or $50,340 annually, and no change was made for the budgeted amount for 2012. (EXH 115) Witness Kilcoyne explained that the charge is for SCS employees who terminated early during the 1980s and 1990s and the intention was to lower overall SCS costs, including those attributable to Gulf’s customers. (TR 2003) The Company provided no additional information regarding how the early retirements lowered overall SCS costs or who exactly these employees were. Staff recommends excluding $49,338 ($50,340 system) from 2012 O&M expense.
CONCLUSION
Staff recommends removing $49,338 ($50,340 system) in SCS Early Retirement Costs from 2012 O&M expense.
Should Executive Financial Planning Expenses be included in operating expenses? (Category 1 Stipulation)
Approved Stipulation:
Executive Financial Planning Expenses should not be included in operating expenses. In the course of responding to discovery, Gulf identified $48,000 ($48,000 system) of executive financial planning expenses that Gulf agrees need to be removed from operating expenses and consequently reflected in the adjustments to NOI.
Are Gulf's proposed increases to average salaries for Gulf appropriate?
Recommendation:
The general increases for covered employees and the merit increases for non-covered employees should be considered reasonable. Staff addresses the increase of 159 full time employees (FTEs) from 2010 to 2012 in Issue 70 and the variable or incentive compensation in Issue 71. (Wright)
Position of the Parties
GULF:
Yes. Gulf’s salary programs fall well within market norms and are not excessive in design or level of pay. These programs are necessary to attract, retain, and motivate employees. Retaining, attracting and motivating employees benefits customers through preserving a skilled and capable work force that provides exceptional customer service.
OPC:
No. See OPC’s position on Issue 70.
FIPUG:
No. In these difficult economic times, when many people in northwest Florida are out of work, these increases are out of step with economic reality. Agree with OPC that these expenses should be reduced by $3,195,627.
FRF:
No.
FEA:
No. Please refer to FEA’s response to Issue 70.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf included in its 2012 projected budget, base payroll costs of $103,333,012, variable payroll costs of $16,464,470, and fringe benefit costs of $31,096,355 for total payroll and benefit costs of $150,893,837. (EXH 21) Witness McMillan testified that the work force included in Gulf’s 2012 test year is 1,489 Full Time Equivalents (FTEs), which includes 159 additional FTEs. (TR 1090) Witness McMillan explained that by year end 2010, due to extraordinary efforts to reduce costs and defer a rate case, Gulf’s work force had declined to a level of 1,330 FTEs. (TR 1090) Gulf contended that it proposed a very modest increase in average salaries for the 2012 test period. Gulf explained that MFR C-35 included a projected increase in average salary from 2010 to 2012 of only $413 per employee, which equates to a total percentage increase in average salary over two years of only .005 percent. (Gulf BR 75)
Gulf witness Kilcoyne testified that OPC’s recommended adjustments represent a 13.7 percent reduction in total compensation paid to Gulf’s work force in 2012. Witness Kilcoyne explained that Gulf’s projected total compensation for 2012 of $119,797,482 and witness Ramas’ proposed reductions would result in total compensation of $103,333,012 or a 13.7 percent drop in projected 2012 compensation. (TR 1982) Witness Kilcoyne stated that Gulf paid $107,897,170 of compensation to its employees in 2010 and with witness Ramas’ adjustments, Gulf’s 2012 level of compensation would be lower than 2010, when Gulf had an intentionally reduced its work force. (TR 1982)
Gulf witness Wathen, a Director with Towers Watson, a professional services company that advises organizations on all aspects of their compensation programs, stated “Overall, our analysis indicates that Gulf’s compensation programs are comparable to and competitive with market practices of other similarly sized utilities.” (TR 2068) Witness Wathen testified that the programs at Gulf fall well within market norms and are not excessive in design or level of pay. (TR 2068) He stated that Gulf’s compensation philosophy targets base salary and at-risk compensation at the 50th percentile of similarly sized utilities. (TR 2068) Witness Wathen stated that Towers Watson examined the proxy disclosures for 19 publicly-traded utilities comparable in size to Southern Company and 13 utilities comparable in size to Gulf. (TR 2068 – 2069) Witness Wathen concluded that Gulf’s total compensation philosophy aligns well with peer practices as a majority of the utility peers target the market 50th percentile for some or all pay elements. (TR 2069) Witness Wathen testified that Gulf’s Performance Pay Program design is comparable to and competitive with short-term at-risk compensation designs of the market perspectives examined and the Company’s long-term at-risk compensation program design, reflecting annual grants of stock options and performance shares, to be competitive with the market perspectives examined. (TR 2071-2072)
OPC
OPC witness Ramas recommended a reduction of 91 employees to Gulf’s projected increase in the number of employees of 159, which would result in a reduction to O&M payroll expense of $3,195,627. In addition, witness Ramas recommended eliminating all of the incentive compensation that is paid to Gulf’s employees which would result in a reduction to O&M payroll expense of $12,623,632. Her recommendations are described in more detail in issues 70 and 71, respectively.
FIPUG
FIPUG agreed with OPC that these expenses should be reduced by $3,195,627 because in these difficult times, when many people in northwest Florida are out of work, these increases are out of step with economic reality. (FIPUG BR 10)
FRF & FEA
FRF and FEA stated that the salary increases were not appropriate. (FRF BR 69; FEA BR 29)
ANALYSIS
Gulf’s base payroll is projected to increase by $9,813,114 from 2010 ($93,519,898) to 2012 ($103,333,012). Approximately $7.8 million of the forecasted increase is due to the addition of 159 FTEs. (EXH 115) The remaining $2 million increase in base payroll from 2010 through 2012 is a result of contractually-required general increases of base payroll for covered (union) employees of 2.25 percent in 2011 and 2.35 percent in 2012. (EXH 115) Payroll increases in base payroll for non-covered employees was 2.5 percent (merit budget) in March 2011 and 2.5 percent (merit budget) in March 2012. (EXH 115) None of Gulf’s employees experienced a merit increase or general increase (union employees) in 2009. (EXH 115) Variable payroll was projected to increase $2,087,198 from 2010 ($14,377,272) to 2012 ($16,464,470), of which $702,387 was due to Gulf’ proposed additional 159 FTEs. (EXH 115) The remaining increase in variable compensation between 2010 and 2012 was attributable to Gulf projecting that it will achieve better performance on the performance indicators for short term variable compensation than in 2010. Gulf stated that its performance under the performance measures used for variable compensation was lower than Gulf had typically achieved, therefore, Gulf forecasted an improvement in performance. (EXH 115)
Witness Kilcoyne’s Exhibit SRK-1, page 1 of 2, shows for Gulf overall, the average actual salary of $66,512 as of September 1, 2011 is 4.6 percent below the median market salary of $67,490, after the increases in base salaries described above. (EXH 160) Staff recommends, therefore, that the general increases for covered employees and the merit increases for non-covered employees be considered reasonable. Staff addresses the increase of 159 FTEs from 2010 to 2012 in Issue 70 and the variable or incentive compensation in Issue 71.
CONCLUSION
The general increases for covered employees and the merit increases for non-covered employees should be considered reasonable. Staff addresses the increase of 159 FTEs from 2010 to 2012 in Issue 70 and the variable or incentive compensation in Issue 71.
Are Gulf's proposed increases in employee positions for Gulf appropriate?
Recommendation:
No. Staff recommends an increase of 115 employees, which is 44 less than the Company’s requested increase of 159 employees. This results in a reduction in Operation and Maintenance (O&M) expense of $1,515,243 ($1,546,022 system). (Wright)
Position of the Parties
GULF:
Yes. The 159 additional positions are justified in the testimony of various Gulf witnesses, most of those positions have been filled, and most of the remaining positions are expected to be filled by the early 2012.
OPC:
No. Gulf projected 159 additional employees (a 12% increase) between year ended December 31, 2010 and beginning of the 2012 test year. Since its last rate case, Gulf’s vacancy rate has consistently ranged from 5.08% to 6.10% below budget. For the 6-month period ended June 30, 2011, Gulf’s average employee complement was 9.81% below budget. It is unrealistic and unreasonable to assume that Gulf will fill 100% of its budgeted employee positions by January 2012 or that Gulf will maintain a 0% vacancy factor throughout the entire test year. Using the employee count as of June 30, 2011, Gulf’s total employee count should be limited to 1,398 employees in the test year. Gulf’s expenses should be reduced by $3,195,627.
FIPUG:
No. See Issue No. 69.
FRF:
No. Gulf has overstated the number of employees for the 2012 test year and accordingly has overstated labor expenses. The Commission should reduce Gulf’s 2012 test year expenses by $3,195,627.
FEA:
No.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan stated that Gulf’s budget assumed a full work force complement for the test year. (TR 1090) Witness McMillan explained that due to extraordinary efforts to reduce costs and defer a rate case, Gulf’s work force had declined to a level of 1,330 FTE positions. (TR 1090) He testified that the work force included in Gulf’s 2012 test year was 1,489 employees and that over 95 percent (152 FTEs) are justified in the testimony of Gulf witnesses Neyman, Moore, Caldwell, and Grove. (TR 1090)
Although the Commission made a hiring lag adjustment in Gulf’s last rate case, witness McMillan testified that the Company believed a hiring lag adjustment was inappropriate for several reasons in the current case. (TR 1090-1091) He stated that such an adjustment assumed that if a position is not filled, the associated funds will not be spent and that a hiring lag adjustment assumed that labor costs should be looked at in isolation. (TR 1091) Witness McMillan contended that resources can and will be redeployed from one budget category to another to meet customers’ needs and it is therefore unlikely that any funds available from unfilled positions would result in lower total O&M expense. (TR 1091)
Gulf witness Neyman stated that Gulf had 193 FTEs in Customer Accounts at the end of 2010 and there are 200 FTEs budgeted in the Customer Accounts function for 2012, resulting in a net increase of 7 FTEs. (TR 674) Witness Neyman explained that there was a decrease of 18 FTEs as a result of efficiencies gained by implementing the Advanced Metering Infrastructure (AMI) initiative. In addition to the 18 FTEs eliminated, 9 contractor positions were also eliminated that were not included in the FTE numbers. (TR 674-675) Witness Neyman explained, offsetting these reductions were increases in FTEs due to 6 vacancies at the end of 2010 and 19 new positions in the Customer Service Center (CSC). (TR 675) Witness Neyman testified that 16 of the 19 FTEs are customer service representatives in the CSC and 3 of the FTEs are for a supervisor, administrative assistant and quality assurance analyst to support the additional customer service representatives. (TR 675-676) Witness Neyman explained that Gulf’s service level goal is to answer 80 percent of customers’ calls within 30 seconds and that this goal was not met in 2009 or 2010. (TR 675-676, Gulf BR 77) Witness Neyman stated that currently four of the 19 positions remain vacant. (TR 2263, Gulf BR 78)
Gulf witness Neyman stated that there are 128 FTEs included in Gulf’s Customer Service and Information (CS&I) budget in 2012, and that Gulf had 93 FTEs included in CS&I at the end of 2010. Gulf, therefore, had included an increase of 35 FTEs in its 2012 budget as compared to the end of 2010. (TR 676) Witness Neyman testified that the net increase of 35 FTEs in CS&I can be categorized in three areas: Demand-side Management (DSM), vacancies, and new positions. She stated that 28 of the 35 FTEs are attributable to the recent DSM Plan filed by Gulf and approved by the Commission in Docket No. 100154-EG, via Order No. PSC-11-0114-PAA-EG. (TR 677) Witness Neyman explained that of the 28 FTEs, the costs associated with 26.5 FTEs will be recovered through the ECCR clause. The costs associated with 1.5 of the FTEs are in the O&M budget. (TR 677) Witness Neyman stated 4 of the additional FTEs are necessary and support the Company’s activities in Forecasting, Mass Markets, and Lighting and the costs are split with 1 FTE budgeted to ECCR and 3 to O&M. Witness Neyman explained that the remaining 3 FTEs are for new positions to support Gulf’s customers in the areas of lighting and electric vehicles. She stated that 1 is budgeted for capital expenditures and the other 2 are in the O&M budget. (TR 678) She stated that all the positions in Gulf’s CS&I are filled. (TR 2263)
Gulf witness Moore testified the Distribution department increased its employee complement from 358 FTEs in December 2010 to 403 budgeted FTEs for 2012, or an increase of 45 FTEs. (TR 575) Witness Moore explained that these 45 positions are entry level positions, and they consist of 32 Utility persons, 10 Engineers in Training (EITs), and 3 Fleet positions. (Gulf BR 77) He stated that 36 of the 45 FTEs are for vacancies existing at the end of 2010 and 9 FTEs are new positions. Witness Moore explained that there were so many unfilled positions at the end of 2010 because Gulf was making every effort to keep expenditures low in an attempt to avoid a base rate proceeding from 2008 through 2010 and there was an unusually high turnover of Distribution employees during 2010 with 12 engineering positions leaving Gulf. (TR 576) Witness Moore stated that the 10 entry level EITs have been filled. (TR 576) Witness Moore explained that the 32 Utility person positions go through a thorough training program and it is not uncommon to lose some of the new entries in the program. (TR 578) He stated that because of the length of the program, usually 7 years from Apprentice to top-level Journeyman classification, Gulf has increased the line services positions to ensure an adequate number of qualified Journeyman Line Technicians. (TR 579, Gulf BR 77) Witness Moore stated that the 3 additional budgeted Fleet positions consist of 2 mechanics and 1 administrative assistant. (TR 579)
Gulf witness Caldwell testified that Gulf’s Transmission work force was projected to grow by 13 positions from the end of the 2010 level of 92 FTEs to the 2012 test year level of 105 FTEs. (TR 510) Witness Caldwell explained that the Company performed an organizational study and restructured Transmission to better align the departments, improve management of the construction program, and enhance the ability to maintain the transmission facilities. (TR 510) Witness Caldwell stated that at the end of 2010, Transmission had 8 FTE vacancies which included 1 new position, Security Coordinator, which had been approved but not yet filled. (TR 511) He stated that of the remaining 7 vacancies, 3 were on hold pending reorganization, and 4 vacancies were due to attrition. The 2012 Transmission budget assumed that all of these vacancies will be filled in 2012. (TR 511) Witness Caldwell testified that the 2012 budget also included 5 new positions to address right-of-way issues and the Transmission construction program. (TR 511)
Gulf witness Grove testified that, at the end of 2010, Gulf had 342 FTEs in the Production function. For purposes of the test year, Gulf budgeted labor costs equivalent to 394 FTEs. (TR 888) Witness Grove stated that at Plant Crist, there were 15 vacancies at the end of 2010 as well as 5 new positions. (TR 890) Witness Grove stated that 7 of the Plant Crist positions will either be charged to capital projects or the ECCR and that it is Gulf’s intent to fill all 20 positions.
Witness Grove stated that there were 23 vacancies at Plant Smith at the end of 2010 and that all are included in Gulf’s 2012 O&M budget. He stated that Gulf had filled or is in the process of filling all except 2 vacancies. Witness Grove explained that 8 of the 23 positions are for entry level Utility persons. (TR 890)
Witness Grove stated that there were 26 filled positions at Plant Scholz and in 2012 Gulf had budgeted a full complement or 34 positions. (TR 891) Witness Grove testified that, due to uncertainty with environmental regulations, Gulf had chosen not to fill 8 positions until there is more clarity about prospective environmental regulations. (TR 891) He stated that at the end of 2010 there was also 1 vacant position, the Renewable Energy Manager, at the Power Generation Office. (TR 889) Witness Grove testified that by December 31, 2011, Gulf expected to fill 42 of the 52 positions. Gulf’s current budget projects a net increase of 42 positions from year end 2010, or a reduction of 10 positions from the 2011 budget cycle estimate. He stated that the labor dollars for those 10 FTEs have been redirected to contract labor due to the pending environmental regulations. (TR 2457-2458)
OPC
OPC witness Ramas stated that it is not reasonable to assume that 100 percent of the budgeted employee positions will be filled by the start of the 2012 test year and that the level will be maintained throughout the test year. (TR 1465) Witness Ramas testified that it is not the norm for a company to experience a 0 percent vacancy rate and to have filled its full budgeted employee complement for any given month, let alone an entire year. (TR 1466) She stated that for the nine-year period 2002 through 2010, the average vacancy factor was 5.1 percent and that over the last five years, 2006 through 2010, the average vacancy factor was 6.1 percent. (TR 1466, OPC BR 66) Witness Ramas stated that Gulf had projected that its employee complement will increase by 159 employees from 1,330 as of December 31, 2010 to 1,489 employees before the start of the test year. (TR 1466) Witness Ramas added that the employee count increased by 33 employees to 1,365 as of June 30, 2011 and that is still 124 employees below the budgeted level of 1,489. (TR 1467)
OPC witness Ramas recommended that Gulf’s proposed increase of 159 employees from the actual December 31, 2010 level be reduced by 91 positions, thereby allowing 68 additional positions, or 42.8 percent of the proposed employee increase level. (TR 1468, OPC BR 67) She stated that this would allow for the inclusion in the projected test year costs of 1,398 employees, which is 33 additional employees above the actual June 30, 2011 or 68 additional employees above the December 31, 2010 level of 1,330. (TR 1468, OPC BR 67) Witness Ramas explained that she applied the average vacancy factor actually experienced by Gulf during the five-year period 2006 through 2010 of 6.1 percent to Gulf’s budgeted 2012 test year employee complement of 1,489, resulting in a recommended test year employee complement of 1,398 employees or 68 above the actual December 31, 2010 employee level, 33 of which have already been filled as of June 30, 2011. (TR 1469) As noted above, witness Ramas’ recommended increase of 68 employees represents 42.8 percent of the Company’s requested increase in employees of 159. As shown on Exhibit 35, Schedule C-3, page 1 of 2, witness Ramas applied the 42.8 percent to the Company’s total increase in expenses of $5,586,761 to arrive at a recommended increase in labor costs of $2,391,134. Witness Ramas’ recommended reduction in test year labor costs was $3,195,627 ($5,586,761 less $2,391,134).
FEA
FEA witness Meyer stated that he believed that Gulf’s annualized payroll (including benefits) should be reduced by approximately $5.2 million. (TR 1754, FEA BR 29) Witness Meyer explained that, in Gulf’s last rate case, Gulf requested 1,367 FTEs but that Gulf had not operated at 1,367 employees in any year over the past decade. (TR 1756) Witness Meyer stated that at the end of March 31, 2011, Gulf employed 1,334 employees and at the end of June 30, 2011, Gulf employed 1,365 employees. (TR 1756) Witness Meyer stated that he believed Gulf’s annualized payroll expense should be based on Gulf’s latest known level of employees of 1,365. (TR 1756) Witness Meyer provided a summary of the increased number of employees which showed that 73 employees are related to recovery clauses and capital costs while the remaining 86 employees are related to O&M. Witness Meyer assumed that all growth from December 31, 2010 (1,330 employees) to June 30, 2011 (1,365 employees) or 35 employees would be assigned to the O&M function. (TR 1756 – 1757) He then multiplied the 51 unfilled position (86 less 35) by Gulf’s 2012 average employee budgeted wage and benefit level of $101,339 to arrive at his $5.2 million adjustment.
FEA modified its recommendation based on Exhibit 217 produced by Gulf, which listed Gulf’s FTEs as of December 12, 2011, for the Production, Transmission, and Distribution functions. (FEA BR 31) FEA stated that Exhibit 217 showed that Gulf was 40 FTEs under its 2012 budgeted increase in employees of 159. In addition, FEA’s brief pointed out that witness Neyman testified that she still had 4 unfilled service center employee positions. (FEA BR 31) FEA recommended that the Commission adjust Gulf’s proposed level of labor expenses to reflect the 44 unfilled positions. FEA explained that the average cost of new employee’s wages and benefits presented in witness Ramas' testimony was $60,800. FEA’s brief explained that by applying the $60,800 to the 44 unfilled positions and adjusting out the cost for clauses and capital cost (37 percent of the total cost), resulted in an expense adjustment of $1,685,376. (FEA BR 32) FEA also stated that if Gulf can demonstrate that the 10 positions transferred to Production contract labor decreased its original labor expense adjustment, included in its rate case, then it would recommend an adjustment of $1.3 million based on 34 unfilled positions. (FEA BR 31-32)
FIPUG
FIPUG agreed with OPC that these expenses should be reduced by $3,195,627 because in these difficult economic times, when many people in northwest Florida are out of work, these increases are out of step with economic reality. (FIPUG BR 10)
FRF
FRF stated that Gulf had overstated the number of employees for the 2012 test year and accordingly had overstated labor expenses and, therefore, the Commission should reduce Gulf’s 2012 test year expenses by $3,195,627. (FRF BR 21)
ANALYSIS
Witness McMillan testified that, as of September 30, 2011, Gulf had an employee complement of 1,391 FTEs. (TR 2354) Witness McMillan explained that 27 of the 159 positions had not been filled by the middle of October, which included 10 positions at Gulf’s power plants that have been eliminated in the final 2012 budget and replaced by an increased allowance for contract labor. (TR 2354) Gulf produced Exhibit 217 which reported actual FTEs as of December 12, 2011, for Production, Transmission, and Distribution and revealed 25 unfilled positions in the Production function, 3 unfilled positions in the Transmission function, and 12 unfilled positions in the Distribution function for a total of 40 unfilled positions. (EXH 217) Exhibit 217 also reported current 2012 budget FTEs that showed 10 FTEs less in the Production function. However, as explained by witness Grove, the current 2012 budget moved these 10 FTEs to contract labor due to pending environmental regulations. As stated by witness Neyman, there are 4 unfilled positions in the Customer Service Center which results in a total of 44 unfilled positions.
Witness McMillan provided a hiring lag adjustment based on the estimated employee turnover during the year, times the average time it takes to fill a vacant position, times the average salary. (TR 2356) Witness McMillan stated that the calculation of average employee turnover and the time required to fill these positions, by employee classification, was based on data for 2008 through 2010. Witness McMillan further explained that the average salary is based on actual 2011 salaries by employee classification. (TR 2356) Witness McMillan’s hiring lag adjustment is $448,069 or $439,149 after applying a jurisdictional factor as agreed to by witness McMillan. (TR 2381) Staff believes that, at a minimum, the $439,149 reduction should be made by the Commission to payroll expense. Staff notes that in Gulf’s last rate case, Order No. PSC-02-0787-FOF-EI, a hiring lag adjustment of $323,635 ($330,628 system) was made to reduce O&M expense.
Staff believes it is appropriate to make an adjustment to payroll expense based on the latest actual FTEs as of December 12, 2011, as shown on Exhibit 217. As explained above, Exhibit 217 shows 40 unfilled positions as of December 12, 2011, when compared to the FTEs in the 2012 test year MFRs for the Production, Transmission, and Distribution functions. Staff would also include the 4 unfilled positions in the Customer Service Center for a total of 44 unfilled positions. Staff does not believe it is appropriate to look at the FTEs in the current 2012 budget which reflected 10 Production FTEs moved to contract labor. Staff believes that all the changes in all the accounts would have to be examined in an updated budget. The FTEs that are included in the 2012 budget and MFRs should be the FTEs that are used to determine the appropriate number of employees to be included in the test year. The 44 unfilled positions are demonstrated below:
Table 70-1
|
Comparison of 2012 Budgeted Employee Increases to December 12, 2011 Employee Increases |
|||
|
Function |
2012 Budget Increases |
12/12/11 Levels |
Unfilled Positions at 12/12/11 |
|
Customer Accounts |
7 |
3 |
4 |
|
Customer Service and Information |
35 |
35 |
0 |
|
Distribution |
45 |
33 |
12 |
|
Transmission |
13 |
10 |
3 |
|
Production |
52 |
27 |
25 |
|
Corporate Support |
7 |
7 |
0 |
|
Total |
159 |
115 |
44 |
Staff points out that the Company has a documented history of the actual number of employees being below the budgeted average number of employees for each year 2002 through 2010 as demonstrated in witness Ramas’ Schedule C-3, p. 2 of 2. (EXH 35) Staff believes, therefore, that the likelihood of the actual number of employees for 2012 being below the budget level of 1,489 employees is extremely high. The average percentage that the actual number of employees have been below the average budgeted number of employees was 5.1 percent for the period 2002 through 2009. (EXH 35) Applying the 5.1 percent to the 2012 budgeted number of FTEs of 1,489, results in a difference of 75 employees between the actual and budgeted number of FTEs for 2012. Staff believes that its recommended reduction of 44 employees is, therefore, conservative.
Staff recommends an increase of 115 FTEs be included in the 2012 test period, which is 44 less than the Company’s requested increase of 159 FTEs. Staff’s recommended level of employees of 115 FTEs represents 72.33 percent of the Company’s requested 159 FTEs. Staff used a 27.67 percent (44/159) reduction factor in determining its recommended adjustment as follows:
Table 70-2
|
Employee Increase Adjustment |
|||
|
Description |
Amount |
Employee Adjustment Factor (44/159) |
Recommended O&M Expense Reduction |
|
Base Payroll |
$4,387,785 |
27.67% |
$1,214,230 |
|
Medical and Other Group Insurance |
$956,289 |
27.67% |
264,633 |
|
Employee Savings Plan |
$242,687 |
27.67% |
67,159 |
|
Total included in 2012 O&M expense |
$5,586,761 |
27.67% |
$1,546,022 |
|
Jurisdictional Factor |
----- |
----- |
0.9800918 |
|
Jurisdictional Reduction to O&M expense |
----- |
----- |
$1,515,243 |
CONCLUSION
Based on the discussion above, staff recommends a reduction in O&M expense of $1,515,243 ($1,546,022 system) which reflects a decrease of 44 employees from Gulf’s 2012 budgeted increase of 159 employees. The $1,515,243 recommended reduction to O&M expense, therefore, is based on a 115 employee increase rather than the Company’s requested 159 employee increase from 2010 to 2012.
How much, if any, of Gulf’s proposed Incentive Compensation expenses should be included in operating expenses?
Recommendation:
The amount of Gulf’s proposed Incentive Compensation expenses that should be included in operating expenses is $10,070,813 ($10,275,377 system), which is $2,301,505 ($2,348,255 system) less than Gulf’s requested jurisdictional amount of Incentive Compensation included in O&M expense of $12,372,318 ($12,623,632 system). In addition, O&M expense related to stock based compensation of $1,523,599 ($1,554,547 system) should be removed. Related reductions to plant in service of $543,431 ($555,175 system), accumulated depreciation of $19,148 ($19,598 system), depreciation expense of $19,202 ($19,598 system), and payroll taxes of $9,187 ($9,351 system) should be made. (Wright)
Position of the Parties
GULF:
All of Gulf’s employee compensation should be included in operating expenses, including all incentive or variable compensation. Gulf’s total compensation approach, including variable compensation, was approved in Gulf’s last case and remains the same. Gulf’s compensation program is appropriately targeted at the median of the market and has allowed Gulf to retain valuable and attract new employees necessary to serve customers. Gulf’s use of variable compensation aligns the interests of employees with customers and shareholders, making employees accountable for their performance. The proposed disallowance of variable compensation lacks any market analysis; it is based on an erroneous premise that it does not serve customers; and it completely fails to account for the adverse effects of such a disallowance on customers.
OPC:
Test Year expenses include $12,623,632 for incentive compensation plans, all of which should be removed and funded by shareholders. The Stock Option Expense, Performance Share Program, and Performance Dividend Program focus on shareholder return goals and are provided to upper level employees only. The Performance Pay Program (“PPP”) is weighted 2/3 on shareholder financial benefits and 1/3 on operational goals. The PPP target awards range from 5% to 60% of base pay, depending on the employee’s pay grade. No PPP awards are given unless Southern’s earnings per share (“EPS”) exceed the prior year’s dividends, clearly a shareholder only benefit. Test year costs should be reduced an additional $2,259,624 to remove the stock based compensation allocated to Gulf by SCS.
FIPUG:
All incentive compensation in the test year should be disallowed. If the payment of such extra compensation is important to Gulf, such payments should be funded by shareholders not ratepayers.
FRF:
None. For purposes of setting Gulf’s rates in this docket, the Commission should disallow all of Gulf’s claimed test year incentive compensation expenses because Gulf’s incentive plans are designed to benefit shareholders and not customers, and dependent on first meeting shareholder goals. If Gulf wishes to make such incentive compensation payments, they should be funded by shareholders because the compensation is so heavily dependent on Gulf’s and Southern Company’s earnings. The Commission should reduce Gulf’s test year expenses by $12,623,632, and should further reduce test year expenses by an additional $2,259,624 to remove stock-based compensation allocated to Gulf by Southern Company Services.
FEA:
FEA adopts the position of FIPUG.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness McMillan included $16,464,470 in variable payroll in MFR Schedule C-35 which represents incentive compensation included in the 2012 test year. (EXH 7, Schedule C-35) The $16,464,470 consisted of the following programs:
Table 71-1
|
Gulf’s Incentive Compensation Programs and 2012 Amounts |
||
|
Incentive Compensation Program |
2012 Amounts |
Percentage |
|
Performance Pay Program |
$13,632,643 |
82.80% |
|
Stock Option Expense |
724,990 |
4.40% |
|
Performance Share Program |
1,097,321 |
6.67% |
|
Performance Dividend Program |
1,007,516 |
6.12% |
|
Cash/Spot Awards |
2,000 |
0.01% |
|
Total |
$16,464,470 |
100.00% |
Gulf witness Wathen, a Director with Towers Watson, a professional services company that advises organizations on all aspects of their compensation programs, stated, “[O]verall, our analysis indicates that Gulf’s compensation programs are comparable to and competitive with market practices of other similarly sized utilities.” (TR 2068, Gulf BR 87) Witness Wathen testified that the programs at Gulf fall well within market norms and are not excessive in design or level of pay. (TR 2068) He stated that Gulf’s compensation philosophy targets base salary and at-risk compensation at the 50th percentile of similarly sized utilities. (TR 2068) Witness Wathen stated that Towers Watson examined the proxy disclosures for 19 publicly-traded utilities comparable in size to Southern Company and 13 publicly-traded utilities comparable in size to Gulf. (TR 2068-2069) Witness Wathen concluded that Gulf’s total compensation philosophy aligns well with peer practices as a majority of the utility peers target the market 50th percentile for some or all pay elements. (TR 2069) Witness Wathen testified that Gulf’s Performance Pay Program design is comparable to and competitive with short-term at-risk compensation designs of the market perspectives examined and the Company’s long-term at-risk compensation program design. Gulf’s annual grants of stock options and performance shares is competitive with the market perspectives examined. (TR 2071-2072)
OPC
OPC witness Ramas explained that of the total $16,464,470 in incentive compensation, $594,954 was removed by the Company as part of its net operating income adjustments and exclusions, resulting in $15,869,516 being incorporated in the adjusted 2012 test year. (TR 1470) Witness Ramas included the following table in her testimony:
Table 71-2
|
Breakdown of the Incentive Compensation 2012 Amounts |
||||
|
Income Program Costs in Test Year |
Total Amount |
NOI Adjs./Exclusions |
Net Amount in Test Year |
Percentage |
|
Operation and Maintenance Expenses |
$12,893,352 |
($494,410) |
$12,395,942 |
78.11% |
|
Capital |
2,978,595 |
0 |
2,978,595 |
18.77% |
|
Clearing |
494,979 |
0 |
494,979 |
3.12% |
|
Below-the-Line |
97,544 |
(97,544) |
0 |
0.00% |
|
Total |
$16,464,470 |
($594,954) |
$15,869,516 |
100.00% |
Witness Ramas stated that, as shown above, of the total projected incentive compensation plan costs, $12,395,942 remained in O&M expense in the filing and that the clearing costs of $494,979 are allocated between O&M expense and capital in the test year. (TR 1470) Witness Ramas explained that the bulk of the projected incentive compensation plan fell within the Performance Pay Program (PPP) ($13.6 million), which is Gulf’s annual incentive compensation plan and is short-term in nature. (TR 1474, OPC BR 70) Witness Ramas further explained that all regular and full-time employees and most part-time employees, with a few exceptions, are eligible to participate in the PPP. (TR 1475) Witness Ramas stated that the Target Award as a percentage of an employee’s base salary varies from 5 percent for bargaining unit employees, 10 percent for the remaining non-exempt employees and exempt employees with salary grades 1 through 5, and for salary grade 6 employees, the Target Award increases to 12.5 percent of base salary. (TR 1475) Witness Ramas further stated that for employees falling within grade levels 7 through 15, the Target Award ranges from 25 percent to 60 percent, depending on the grade. (TR 1475)
Witness Ramas stated that the performance goals that were used to evaluate the payout levels for the PPP plan are one-third based on Gulf’s achieved ROE, one third based on Southern Company’s earnings per share, and the remaining one-third based on the Business Units’ operational goals, which are specific to Gulf. (TR 1475) Witness Ramas explained that prior to any PPP awards being made, Southern Company’s earnings per share must exceed the prior year’s dividends. (TR 1475, OPC BR 71) Witness Ramas contended that the primary drivers and key focus of the program are financial goals that benefit Southern Company’s shareholders, not Gulf’s ratepayers. (TR 1477) Witness Ramas recommended that the PPP program costs be disallowed in its entirety because she stated that it is not reasonable to expect ratepayers to fund incentive plans that almost entirely benefit the shareholders of Southern Company. (TR 1477)
Witness Ramas also discussed the long-term incentive compensation programs in her testimony including the Stock Option Program, the Performance Share Program, and the Performance Dividend Program. (TR 1471-1474) Witness Ramas explained that under the Stock Option Program, a long-term performance target percentage of base pay is established for each eligible employee based on his/her grade level and that the number of stock options granted is dependent on this long-term performance target percentage and allocation, and on the fair value of a stock option on the date of grant. (TR 1471) Witness Ramas stated that the incentive compensation program budgeted by the Company for 2012 for the Stock Option Program was $724,990. (TR 1471-1472) Witness Ramas argued that the costs associated with the Stock Option Program should not be passed on to the Company’s ratepayers because it encourages certain senior level employees of Southern Company and its subsidiaries, including Gulf, to increase the stock price of Southern Company on behalf of the Company’s investors. She stated that the full focus of this program is on shareholders and not the customers. (TR 1472)
Witness Ramas stated that the Performance Share Program rewards achievement of total shareholder return goals and those employees may receive shares of Southern Company stock dependent on a three-year total shareholder return versus industry peers. (TR 1473) Witness Ramas explained that a target percentage of base pay is established for each eligible employee based on his/her grade level for target level performance and this target percentage may be allocated between stock options and performance shares. (TR 1473)
Witness Ramas argued that the costs associated with the performance share program should not be passed on to Gulf’s customers because the total goal associated with the program is focused on shareholder returns. (TR 1473) Witness Ramas stated that the complete focus of this program is on benefitting shareholders and not ratepayers and therefore, the costs forecasted for the program for 2012 of $1,097,321 should be disallowed. (TR 1472-1473)
Witness Ramas described the Performance Dividend Program as being phased out and being replaced with the Performance Share Program previously discussed. (TR 1473) Witness Ramas stated that the focus on this program is again on shareholder returns as it is based entirely on Southern Company’s dividend paid during the year and the four-year total shareholder return goals as compared to industry peers. Witness Ramas recommended that the full projected costs of $1,007,516 be disallowed because this program does not benefit ratepayers and instead should be funded by the Southern Company’s shareholders who are the beneficiaries and prime focus of the goals within the plans. (TR 1474)
Witness Ramas recommended that 100 percent of the total Incentive Compensation Costs be disallowed or $12,623,632. In addition, Witness Ramas recommended that related plant-in-service costs should be reduced by $1,217,206 and depreciation expense and accumulated depreciation each should be reduced by $42,967. (TR 1479)
OPC also recommended reducing test year costs by an additional $2,259,624 to remove the stock based compensation allocated to Gulf by SCS because Gulf provided no evidence explaining how allocating SCS Stock Based Compensation benefits the Florida ratepayers. (OPC BR 78)
FIPUG, FRF & FEA
FIPUG stated that all incentive compensation in the test year should be disallowed and funded by shareholders not ratepayers. (FIPUG BR 10) FRF stated that, for purposes of setting Gulf’s rates, the Commission should disallow all of Gulf’s claimed test year incentive compensation expenses because Gulf’s incentive plans are designed to benefit shareholders and not customers, and dependent on first, meeting shareholder goals. FRF recommended that the Commission reduce Gulf’s test year expenses by $12,623,632 and should reduce test year expenses by an additional $2,259,624 to remove stock-based compensation allocated to Gulf by SCS. (FRF BR 22) FEA agrees with FIPUG’s position. (FEA BR 33)
ANALYSIS
OPC witness Ramas recommended that 100 percent of the incentive compensation be disallowed and funded by shareholders, resulting in Gulf’s adjusted test year expenses being reduced by $12,623,632 and plant in service being reduced by $1,217,206. In addition, witness Ramas reduced depreciation expense and accumulated depreciation each by $42,967. (TR 1479) OPC also recommended that test year costs be reduced an additional $2,259,624 to remove the stock based compensation allocated to Gulf by SCS. (OPC BR 68)
Witness Ramas testified that, in Order No. PSC-10-0131-FOF-EI, the Commission disallowed Progress Energy Florida, Inc.’s incentive compensation plan costs, as the Commission stated that incentive compensation provided no benefit to the ratepayers.[36] (TR 1478) Witness Ramas also stated that in Order No. PSC-09-0283-FOF-EI, the Commission ruled that incentive compensation should be directly tied to the results of TECO and not to the diversified interest of its parent company TECO energy.[37] (TR 1478) Witness Ramas explained that the Commission disallowed the portion of the incentive compensation that was tied to the parent company’s results. (TR 1478) OPC also pointed out that in Order No. PSC-10-0153-FOF-EI, the Commission found that FPL’s executive incentive compensation was designed to benefit the value of shares and that incentive compensation payments effectively became base salary because FPL consistently achieved 30 to 40 percent above baseline year after year. As a result, the Commission reduced the amount of executive incentive compensation borne by customers.[38] (OPC BR 77)
OPC witness Ramas’ proposed elimination of incentive compensation includes both the Performance Pay Program, which is short-term in nature and available to all full-time employees, and long-term programs, consisting of the Stock Option Program, Performance Share Program, and the Performance Dividend Program. The long-term programs are only for Pay Grade 7 employees and above. In addition, there are Cash/Spot Awards for Call Center personnel that meet All Connect transfer goals. As shown in Table 71-1 above, the bulk of the incentive compensation consists of the Performance Pay Program in the amount of $13,632,643 or 82.8 percent of the total amount of $16,464,470. The long-term incentive compensation programs total $2,829,827 or 17.19 percent for the 2012 test year, which include the Stock Option Program ($724,990), the Performance Share Program ($1,097,321), and the Performance Dividend Program ($1,007,516).
OPC asserted that, for the PPP program, overall company performance is tied two-thirds to financial goals and one-third to operational goals and by designing the PPP program to emphasize company financial goals, Gulf has possibly created an incentive to management level employees to focus on achieving the financial goals of the company without sufficient incentives to maintain a proper focus upon achieving operational goals. (OPC BR 71) OPC noted that the operational employees do not have nearly as much incentive compensation at risk as do the management level employees and that the individual decisions of non-management operational employees do not have that great of an individual effect on achieving financial goals. (OPC BR 72)
OPC also explained that while it is recommending that Southern Company shareholders pay for the incentive pay programs, OPC is not advocating that incentive compensation be reduced or eliminated. Nowhere in the testimony of witness Ramas did she advocate that Gulf should stop paying incentive compensation. (OPC BR 73)
Gulf witness Kilcoyne stated several reasons why she disagreed with witness Ramas’ recommended disallowance. Witness Kilcoyne pointed out that witness Ramas did not consider whether Gulf’s compensation plan is competitive and successful in retaining existing employees and attracting new employees. (TR 1983) Witness Kilcoyne stated that witness Ramas’ recommendation to disallow every dollar of “at-risk” or variable compensation is based on her mistaken belief that Gulf’s at-risk compensation is designed to benefit only shareholders. (TR 1983) Witness Kilcoyne contended that Gulf’s compensation plan benefits customers as well as shareholders and that witness Ramas did not appear to realize the adverse impact her compensation adjustments would have on Gulf’s ability to succeed in retaining and attracting qualified employees. (TR 1983-1984) Witness Kilcoyne stated that witness Ramas’ adjustments imply that she may not understand the desirability of having performance based compensation and that witness Ramas did not address the serious consequences of her recommended adjustments. Finally, witness Kilcoyne believed that witness Ramas’ disallowance of variable compensation is at odds with prior Commission practice. (TR 1984)
Gulf witness Kilcoyne argued that the three goals used to measure performance all benefit Gulf’s ratepayers. (TR 1987) Witness Kilcoyne contended that Gulf earning a fair rate of return on equity helps maintain the Company’s financial integrity, which, in turn, helps Gulf access capital markets to raise capital at a lower cost. (TR 1987) Witness Kilcoyne argued that Gulf’s trigger for the variable compensation plan, that Southern Company earnings must exceed the prior year’s dividends, is not used to benefit shareholders, but to assure there are funds available to maintain customer operations. Witness Kilcoyne stated that this trigger gives management the discretion to meet the immediate needs of customers and investors before providing variable compensation. (TR 1988) Witness Kilcoyne took issue with witness Ramas’ statement that “the large emphasis on equity and earnings could shift focus away from operations in order to help the Company achieve its earnings targets,” and stated that there is no data to support that assertion. (TR 1989)
Gulf witness Kilcoyne also did not agree with witness Ramas’ characterization of variable compensations as extra pay. (TR 1989) Witness Kilcoyne stated that it is one component of an overall total compensation program, and at Gulf, all employees have compensation at-risk. (TR 1989) Witness Kilcoyne testified that Gulf’s average salary would decline more than $11,000 from 2010 levels if incentive compensation was totally eliminated. (TR 1983)
Gulf witness Deason stated that at-risk compensation costs are currently being recovered in Gulf’s rates. (TR 2090) Witness Deason stated that witness Ramas’ recommendation to disallow at-risk compensation costs are inconsistent with sound regulatory policy and basic principles of ratemaking, are contrary to Commission precedent, are based on simplistic assumptions that are not factually correct, and, if accepted, would be detrimental to the long term interests of Gulf’s customers. (TR 2091) Witness Deason argued that witness Ramas made no allegations nor presented any evidence that the overall compensation paid to Gulf employees is unnecessary or unreasonable. (TR 2092) Witness Deason stated that witness Ramas’ recommendation is further flawed because she made no analysis of the reasonableness of the net amount of compensation that remained after at-risk compensation is eliminated. (TR 2093) Witness Deason concluded that witness Ramas’ testimony is totally devoid of any consideration of reasonableness regarding either the overall amount of compensation or of the net amount that witness Ramas has recommended. (TR 2093)
Witness Deason stated that in two previous Gulf rate cases, cost recovery for at-risk compensation was allowed and that a prior Florida Power Corporation rate case also provided for cost recovery of incentive (at-risk) compensation. Witness Deason added that, in a Tampa Electric Company (TECO) rate case, the Commission found that TECO’s total compensation package was set near the median level of benchmarked compensation and allowed recovery of incentive compensation that was directly tied to results of TECO. (TR 2095) Witness Deason argued that witness Ramas’ analysis is flawed because no attempt was made to compare the total compensation paid to Gulf executives or employees to the market for similar services, duties, activities and responsibilities. (TR 2097) Witness Deason contended that the focus of any disallowance should be how much is paid, not how it is paid. (TR 2097) Witness Deason stated that a compensation structure that pays employees regardless of performance diminishes managements’ leverage to motivate and focus employees on appropriate goals. (TR 2098)
Gulf witness Deason testified that accepting witness Ramas’ recommendation would require Gulf to either renege on its obligations to employees or deny Gulf a reasonable opportunity to earn its authorized rate of return. (TR 2099) Witness Deason stated that a Utility earning a reasonable profit is beneficial for both its shareholders and its customers and, therefore, financial goals used to establish compensation levels are also beneficial to customers. (TR 2100) Witness Deason contended that the Commission at no time has denied cost recovery of 100 percent of at-risk compensation. (TR 2103)
Staff believes that both Gulf and OPC made valid points with regard to incentive compensation. Staff recognizes that the financial incentives that Gulf employs as part of its incentive compensation plans may benefit ratepayers if they result in Gulf having a healthy financial position that allows the Company to raise funds at a lower cost than it otherwise could. Staff also believes there is validity in having incentive compensation more closely aligned with the Company’s operations rather than Southern Company’s financial position. In response to a question from the bench about the incentive programs being tied to Southern Company stock performance and whether Gulf’s customers would get an additional benefit if Gulf’s performance measures were incorporated into these programs, witness Kilcoyne answered that Gulf would have to look at that since its stock is wholly-owned by Southern Company and Gulf had never analyzed this issue in that manner. (TR 2052)
Staff recommends that the short-term incentive compensation test year amounts related to the PPP be included in O&M expense, but the test year amounts related to the long-term incentive compensation plans be disallowed for ratemaking purposes. Gulf’s long-term incentive compensation plans are designed to benefit Gulf’s 119 employees in management that are Pay Grade 7 and above and are exclusively tied to financial goals of Southern Company. (EXH 160) The short-term PPP is based on performance measures that are the same for all Gulf employees, though the awards differ depending on the category of employment, as described previously. Staff notes that excluding long-term incentive compensation would be similar to the treatment of incentive compensation in Tampa Electric Company’s (TECO’s) and Florida Power & Light’s (FPL’s) last rate cases. In Order No. PSC-09-0283-FOF-EI, it was determined that the incentive compensation should be directly tied to the results of TECO and not to the interests of its parent company, TECO Energy. In Order No. PSC-10-0153-FOF-EI, the Commission eliminated 100 percent of FPL’s executive incentive compensation.
Gulf’s recommended PPP incentive compensation to be allowed in O&M expense is based on a total Goal Factor of 125 percent for the 2012 budget and is calculated in the following manner:
Table 71-3
|
Total Goal Factor for the Performance Pay Program |
|
|
Gulf’s assumptions and calculations |
|
|
Operational Goals (1/3 weight) |
50.00% (1/3 x 150%) |
|
Gulf Return on Equity (1/3 weight) |
41.67% (1/3 x 125%) |
|
Southern Company EPS goal (1/3 weight) |
33.33% (1/3 x 100%) |
|
Total Goal Factor |
125.00% |
Though one-third of the PPP Total Goal Factor relies on Southern Company’s earnings per share, staff believes that it is appropriate to recognize some benefit to the ratepayers for Southern Company maintaining a healthy financial position. Staff believes that including Gulf’s return on equity rather than Southern Company’s should have an even more direct affect on employee performance. Staff believes that, since all of Gulf’s employees participate in the PPP program, it has a more direct impact on the operations and well-being of the Company. In contrast, the long-term incentive programs are more narrow in focus as they only apply to Pay Grades 7 and above which affects only 119 employees out of 1,379 (as of September 2011) and are tied to the stock price of Southern Company or Shareholder Return Goals of Southern Company only. Staff does recommend excluding a portion ($122,229) of the PPP incentive program cost for 2012 based on the exclusion of 44 out of the 159 FTE increases (27.67 percent), as discussed in Issue 70. Removing $122,229 in PPP costs results in an estimated reduction in payroll taxes of $9,187 ($9,351 system).
Staff’s incentive compensation adjustment is calculated as follows:
Table 71-4
|
Breakdown of the 2012 Net Incentive Compensation Amounts |
||
|
Description |
Net Amount in the Test Year |
Percentage |
|
O&M |
$12,395,942 |
78.11 |
|
Capital |
2,978,595 |
18.77 |
|
Clearing |
494,979 |
3.12 |
|
Total |
$15,869,516 |
100.00 |
(EXH 115)
Table 71-5
|
Staff’s Incentive Compensation Adjustment by Program |
|
|
|
Incentive Amounts Subject to Removal |
|
Performance Pay Program |
$122,229 |
|
Stock Option Expense |
724,990 |
|
Performance Share Program |
1,097,321 |
|
Performance Dividend Program |
1,007,516 |
|
Total |
$2,952,056 |
Table 71-6
|
Breakdown of Staff’s Incentive Compensation Adjustment |
||
|
Description |
Percentage Applied |
Incentive Amounts by Category |
|
O&M |
78.11 |
$2,305,900 |
|
Capital |
18.77 |
554,080 |
|
Clearing |
3.12 |
92,076 |
|
Total |
100.00 |
$2,952,056 |
Table 71-7
|
Allocation of Clearing Amounts Between O&M and Capital |
|
|
Clearing Amounts ($2,952,056 times 3.12 percent) |
$92,076 |
|
Percentage charged to O&M |
46% |
|
Clearing Amount Charged to O&M |
$42,355 |
|
|
|
|
Clearing Amounts |
$92,076 |
|
Percentage charged to Capital |
54% |
|
Clearing Amount Charged to Capital |
$49,721 |
|
|
|
|
Staff O&M Adjustment ($2,305,900 + $42,355 system) |
$2,348,255 |
|
Staff Jurisdictional O&M Adjustment ($2,348,255 x 0.9800918) |
$2,301,505 |
Staff recommends excluding $2,301,505 ($2,348,255 system) in incentive compensation from O&M expense as shown above.
Staff believes that after removing the long-term incentive pay, salaries for Pay Grades 7 and above are still within a reasonable range. Based on witness Kilcoyne’s Exhibit SRK-1, Schedule 1, External Market Analysis as of September 2011, page 1 of 2 (EXH 160), the average target salary for Pay Grade 7 and above including base salary plus only the short-term incentive compensation is $159,105 which is 5 percent above the median market of $151,582.
Comparing the $159,105 target base salary plus short-term incentive compensation to the market salary including the market median base plus the short-term median target and long-term median target compensation of $169,076 shows that the $159,105 salary is only 5.9 percent below the median market target. In comparison, Exhibit SRK-1, Schedule 1 shows Gulf’s Covered employees’ target salaries are 7.5 percent below the median market salary and Gulf’s employees in Pay Grades 1 through 6 target salaries are 3.5 percent below the median market salaries. (EXH 160) Staff believes that even after removing the long-term compensation from the employees in Pay Grades 7 and above, these employees’ salaries would still be at a reasonable level as compared to other Gulf employees’ salaries and to the median market salaries.
Staff believes that OPC’s recommended adjustment to exclude all incentive compensation is unreasonable and, as Gulf witness Kilcoyne stated, would result in an average salary below 2010 levels. (TR 1982) Excluding all of the short-term incentive compensation along with the long-term compensation would put all of Gulf’s employees target salaries well below the median market salaries (base plus short-term incentive compensation), as shown on Exhibit SRK-1, page 2 of 2, including a negative 6.2 percent for nonexempt, noncovered jobs, a negative 12 percent for covered union jobs, a negative 13.2 percent for exempt jobs (Pay Grades 1-6), and a negative 19.2 percent for management, Pay Grade 7 and above. (EXH 160) Excluding both short-term and long-term incentive compensation would result in Gulf’s Pay Grade 7 and above target salaries being in a negative 27.6 percent position as compared to median market salaries (base plus short-term and long-term incentive compensation).
Removing staff’s $2,952,056 recommended gross incentive compensation adjustment shown above from Gulf’s gross total payroll amount of $119,797,482, shown on MFR Schedule C-35 (EXH 21), would result in a total payroll amount of $116,845,426. Dividing the $116,845,426 by the number of employees recommended by staff in issue 70 of 1,445 results in an average gross salary of $80,862, which is still above Gulf’s gross average salary of $80,455 shown in MFR Schedule C-35 for 2012.
OPC also recommended that test year costs be reduced an additional $2,259,624 to remove the stock based compensation allocated to Gulf by SCS. (OPC BR 78) Staff agrees that these stock based compensation amounts should also be removed to be consistent with the long-term incentive compensation adjustment recommended by staff. Staff recommends removing $18,961 related to working capital, $657,500 related to capital costs, and $1,554,547 related to the stock based compensation allocated to Gulf by SCS included in O&M expense. The impact of removing these costs, along with the previously recommended reductions in incentive compensation results in the following O&M and related adjustments:
Table 71-8
|
Breakdown of Incentive Compensation Adjustment |
|
|
Reduction in O&M expense |
|
|
O&M Adjustment to Incentive compensation |
$2,348,255 |
|
Jurisdictional Factor |
0.9800918 |
|
Jurisdictional O&M Adjustment |
$2,301,505 |
|
|
|
|
Stock Based Compensation allocated by SCS to O&M |
$1,544,547 |
|
Jurisdictional Factor |
0.9800918 |
|
Jurisdictional O&M Adjustment |
$1,523,599 |
|
|
|
|
Total Staff Adjustment to Capital ($554,080 + $49,721) |
$603,801 |
|
Percentage not Clause related or CWIP |
75% |
|
Capital in Plant-in-Service |
$452,851 |
|
Stock Based compensation allocated from SCS |
657,500 |
|
Total Adjustment to Capital |
$1,110,351 |
|
|
|
|
Reduction in Plant at 50% |
$555,175 |
|
Jurisdictional Factor |
0.9788452 |
|
Jurisdictional Plant-in Service Adjustment |
$543,431 |
|
|
|
|
Related Depreciation Expense |
$555,175 |
|
Average Test Year Depreciation rate |
3.53% |
|
Depreciation expense |
$19,598 |
|
Jurisdictional Factor |
0.9798128 |
|
Jurisdictional Depreciation Adjustment |
$19,202 |
|
|
|
|
Reduction to Accumulated Depreciation |
$19,598 |
|
Jurisdictional Factor |
0.9770686 |
|
Jurisdictional Accumulated Depreciation Adjustment |
$19,148 |
|
|
|
|
Reduction in PPP Costs |
$122,229 |
|
FICA Employee Tax Rate |
7.65% |
|
Reduction in Payroll Taxes |
$9,351 |
|
Jurisdictional Factor |
0.9824645 |
|
Jurisdictional Payroll Taxes Adjustment |
$9,187 |
In summary, staff believes that long-term incentive compensation and a portion of the PPP short-term incentive compensation be removed in the amount of $2,301,505 ($2,348,255 system) which results in $10,070,813 ($10,275,377 system) of incentive compensation being included in operating expenses. In addition, O&M expense related to stock based compensation of $1,523,599 ($1,554,547 system) should be removed. Related reductions to plant in service of $543,431 ($555,175 system), accumulated depreciation of $19,148 ($19,598 system), depreciation expense of $19,202 ($19,598 system) and payroll taxes of $9,187 ($9,351 system) should be made.
CONCLUSION
Staff recommends including in operating expenses incentive compensation of $10,070,813 ($10,275,377 system) which is $2,301,505 ($2,348,255 system) less than Gulf’s requested jurisdictional amount of incentive compensation included in O&M expense of $12,372,318 ($12,623,632 system). In addition, O&M expense related to stock based compensation of $1,523,599 ($1,544,547 system) should be removed. Related reductions to plant in service of $543,431 ($555,175 system), accumulated depreciation of $19,148 ($19,598 system), depreciation expense of $19,202 ($19,598 system) and payroll taxes of $9,187 ($9,351 system) should also be made.
What is the appropriate amount of allowance for employee benefit expense be adjusted?
Recommendation:
Employee benefit expense is discussed in Issues 66, 67, 68, 70 and 71. Any adjustments recommended by staff have been made in those issues and no further adjustments are necessary. (Wright)
Position of the Parties
GULF:
The appropriate amount of employee benefit expense to include in operating expenses for the 2012 test year is $26,281,520 ($26,816,341 system). This amount includes adjustments to Gulf’s original request to remove additional Executive Financial Planning expenses in accordance with the stipulation on Issue 68.
OPC:
OPC’s recommended adjustments to employee benefits have been incorporated into our positions on Issues 66, 67, 68, 70 and 71.
FIPUG:
Agree with OPC.
FRF:
See positions on Issues 66, 67, 68, 70, and 71.
FEA:
Yes, consistent with FEA’s position on payroll discussed in Issue 70.
Staff Analysis:
The merits of this issue have been discussed previously in Issues 66-68 and 70-71, and staff recommends no further adjustments. Employee benefit expense is discussed in Issues 66, 67, 68, 70 and 71. Any adjustments recommended by staff have been made in those issues and no further adjustments are necessary.
What is the appropriate amount of Other Post Employment Benefits Expense for the 2012 projected test year? (Category 2 Stipulation)
Approved Stipulation:
The appropriate amount of Other Post Employment Benefits Expense is $3,759,786 ($3,840,710 system).
What is the appropriate amount of Gulf's requested level of Salaries and Employee Benefits for the 2012 projected test year?
Recommendation:
The appropriate amount of Salaries and Employee Benefits for the 2012 projected test year is $104,570,479 ($106,695,530 system). (Wright)
Position of the Parties
GULF:
The appropriate amount of Salaries and Employee Benefits to include in operating expenses for the 2012 test year is $110,151,832 ($112,390,277 system). This amount includes adjustments to Gulf’s original request to remove additional Executive Financial Planning expenses in accordance with the stipulation on Issue 68.
OPC:
See OPC’s positions on issues 68 through 73.
FIPUG:
Agree with OPC.
FRF:
See positions on Issues 68 through 73.
FEA:
Yes, consistent with FEA’s position on payroll discussed in Issue 70.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in Issues 66, 67, 69, 70, 71 and 72, the appropriate amount of Gulf’s requested level of Salaries and Employee Benefits for the 2012 projected test year is $104,570,479 ($106,695,530 system). The following is a summary of staff ‘s adjustments to Salaries and Benefits by issue:
Table 74-1
|
Recommended Adjustments to Salaries and Benefits Expense |
||
|
Description |
System |
Jurisdictional |
|
Company Salaries and Benefits |
$112,438,277 |
$110,199,833 |
|
Issue 66 – Interest on Deferred Compensation |
(195,583) |
(191,669) |
|
Issue 67 – SCS Early Retirement Costs |
(50,340) |
(49,338) |
|
Issue 68 – Executive Financial Planning |
(48,000) |
(48,000) |
|
Issue 70 – Increase in Employee Positions |
(1,546,022) |
(1,515,243) |
|
Issue 71 – Incentive Compensation |
(2,348,255) |
(2,301,505) |
|
Issue 71 – Stock Based Compensation allocated to Gulf from SCS |
(1,554,547) |
(1,523,599) |
|
Total Staff Reductions |
(5,742,747) |
(5,629,354) |
|
Staff Recommended Salaries and Benefits |
$106,695,530 |
$104,570,479 |
What is the appropriate amount of Pension Expense for the 2012 projected test year? (Category 2 Stipulation)
Approved Stipulation:
The appropriate amount of Pension Expense for the 2012 projected test year is $2,676,982 ($2,731,358 system).
What is the appropriate amount of accrual for storm damage for the 2012 projected test year?
Recommendation:
Staff recommends that the appropriate amount of accrual for storm damage for the 2012 project test year is $3,365,709 ($3,500,000 system). Therefore, the accrual should be reduced by $3,173,382 ($3,300,000 system). (L'Amoreaux, Slemkewicz)
Position of the Parties
GULF:
$6,539,091 ($6,800,000 system). Gulf’s property damage accrual is based on Ms. Erickson’s expert opinion which was heavily influenced by a Commission required storm study. That study uses a statistical model to consider a range of potential hurricane characteristics and corresponding losses and then computes Gulf’s expected annual damage. Since Gulf’s current approved accrual level is below the amount expected to be charged to the reserve each year based on the storm study, Gulf requested the accrual be increased. This is in line with the Commission’s framework of (1) an accrual adjusted over time as circumstances change; (2) a storm reserve adequate to accommodate most, but not all storm years; (3) and a provision that goes beyond the reserve.
OPC:
Gulf’s requested increase in the annual accrual is excessive and unjustified based on the historical charges to the reserve, the storm standards established for Florida electric utilities, and the storm hardening measures implemented after 2005. Gulf’s unreliable storm study included extraordinary storm repair costs which historically have been recovered by surcharge mechanisms. The annual storm accrual should be reduced to $600,000, which reflects a decrease to O&M expense of $6.2 million ($5,962,113 jurisdictional). The storm reserve has almost reached the specific target range that was previously authorized by the Commission and is sufficiently funded to cover ordinary storm costs that are likely to occur based on recent history excluding the extraordinary storm costs incurred in 2004-2005.
FIPUG:
The accrual should not be increased. See Issue No. 27.
FRF:
No more than $600,000 per year. Given Gulf’s existing reserve and the ready availability of rate relief to address unusually high storm restoration costs, and recognizing current economic conditions, the Commission should consider reducing the accrual to zero.
FEA:
Yes, consistent with FEA’s response to Issue 27.
Staff Analysis:
This issue is a fall-out issue. Based on staff’s recommendation in Issue 27 that the accrual should not be increased from its present level, the appropriate amount of the annual storm damage accrual for the projected 2012 test year is $3,365,709 ($3,500,000 system). Therefore, Gulf’s proposed accrual of $6,539,091 ($6,800,000 system) should be reduced by $3,173,382 ($3,300,000 system)
Table 76-1
|
2012 Projected Test Year – Annual Storm Damage Accrual (System Amounts) |
||||||
|
Description |
Gulf |
OPC |
FIPUG |
FRF |
FEA |
Staff |
|
Issue 27- Requested annual accrual |
$6,800,000 |
$600,000 |
$3,500,000 |
No more than $600,000 |
No more than $5,000,000 |
$3,500,000 |
Should an adjustment be made to remove Gulf's requested Director's & Officer's Liability Insurance expense?
Recommendation:
Yes. Staff recommends that Director’s & Officer’s Liability Insurance be reduced by $58,133 ($59,384 system) to share the cost equally between both the shareholders and the customers. (Mouring)
Position of the Parties
GULF:
No. The appropriate amount for Directors & Officers (“D&O”) Liability Insurance expense of $116,265 ($118,767 system) is included in the 2012 projected test year. D&O Liability Insurance helps to retain and recruit qualified and competent directors and officers who provide needed expertise in running a utility, both financially and operationally. Having a well-run utility benefits ratepayers and having adequate liability coverage helps protect the assets of the Company from lawsuits that could divert capital to cover any losses.
OPC:
Consistent with recent Commission decisions, Directors and Officers liability insurance should be reduced by $59,384 or 50% of the identified 2012 projected test year expense ($58,196 jurisdictional). This expense protects shareholders from the decisions they made when they hired the Company’s Board of Directors and the Board of Directors in turn hired the officers of the Company. The question is whether this cost that the Company has elected to incur as a business expense is for the benefit of shareholders and/or ratepayers. The benefit of this insurance clearly inures primarily to shareholders.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. The Commission should reduce test year expenses by $58,196 on a retail jurisdictional basis.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Erickson addressed Director’s & Officer’s Liability Insurance (D&O) expense by asserting that D&O Liability Insurance is used primarily for the benefit of the customers, and that D&O Liability Insurance represents a normal cost of providing service. (TR 2294, Gulf BR 102) Witness Erickson went on to explain that D&O Liability Insurance is necessary for the Company to attract and retain competent and skilled directors and officers, which ensures proper management and oversight of the Company, which in turn benefits the customers. (TR 2294)
Gulf witness Deason reiterated witness Erickson’s assertion regarding D&O Liability Insurance being a reasonable and necessary cost of doing business for any publicly-held company. (TR 2108) Witness Deason also testified that “[A]dequate liability coverage gives directors and officers the level of comfort necessary to enable them to make forward-looking decisions that will provide operational and cost-efficiency benefits for customers.” (TR 2108) Witness Deason reaffirmed two recent Commission decisions in which this Commission has acknowledged the need for D&O Liability Insurance.[39] (TR 2109-2110) He concluded that any disallowances to a reasonable and necessary business expense would constitute a “backdoor approach” to reducing a company’s authorized ROE. (TR 2110)
OPC
OPC witness Schultz testified that D&O Liability Insurance primarily benefits shareholders and that it has been his experience that in most cases where a legal suit is filed, the primary litigant is the shareholder. (TR 1566-1568; EXH 154, p. 28) Witness Schultz recognized that D&O Liability Insurance does provide some benefit to the customers and thus recommended that the $118,767 included O&M expense associated with D&O Liability Insurance be split evenly between the shareholders and companies, resulting in a reduction of $59,384 ($118,767/2) to O&M expense. (EXH 154, p. 29; TR 1568)
ANALYSIS
The primary argument related to D&O Liability Insurance rests on who benefits from the Company’s decision to acquire it, the shareholders, the customers, or both. Staff agrees with Gulf in that D&O Liability Insurance is prudent and necessary for a publicly held company to have, and that it ensures the Company will be able to attract and retain skilled leadership. (TR 2294-2295, TR 2108-2109) However, staff also agrees with OPC’s argument that Gulf’s shareholders also receive a benefit from having D&O Liability Insurance. (TR 1566-1568) Staff recommends that, consistent with the Commission’s prior decision in the Progress Energy Florida case,[40] the cost of D&O Liability Insurance should be a shared cost.
CONCLUSION
Based on the above, staff believes that both the shareholders and the customers receive benefit from D&O Liability Insurance and that the associated cost should reflect this fact. As such, staff recommends that D&O Liability Insurance expense be reduced by $58,133 ($59,384 system) to share the cost equally between the shareholders and the customers.
What is the appropriate amount of accrual for the Injuries & Damages reserve for the 2012 projected test year? (Category 2 Stipulation)
Approved Stipulation:
The appropriate amount for the injuries and damages reserve accrual of $1,566,288 jurisdictional ($1,600,000 system) is included in the 2012 projected test year.
What is the appropriate amount of Gulf's tree trimming expense for the 2012 projected test year?
Recommendation:
The appropriate amount of tree trimming expense for the 2012 projected test year is $4,918,154. (L'Amoreaux)
Position of the Parties
GULF:
The appropriate amount of Gulf's tree trimming expense for the 2012 test year is $4,918,154. This level of funding is necessary to allow Gulf Power to meet its three-year main line and four-year lateral maintenance trim cycles as filed in its Commission approved storm hardening plan.
OPC:
Gulf’s projected $4.918 million for distribution tree trimming in 2012 should be reduced by $386,834 (jurisdictional) to reflect a level of $4,531,320. Subsequent to Docket No. 060198-EI (the storm hardening docket), Gulf has averaged $4.3 million of tree trimming expense. Limiting maintenance in previous years, for whatever reason, is no justification for passing the catch up costs on to ratepayers on a continuing basis. Gulf’s increase in projected spending increase for the rate case should not be approved. An adjustment is required to reflect the level of spending the Company is actually performing in its attempt to comply with the Storm Hardening Requirements approved by the Commission in Docket No. 060198-EI.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of jurisdictional distribution tree-trimming expenses for the 2012 test year is $4,531,320, which represents a reduction of jurisdictional test year expenses of $386,384. Gulf’s requested amount of $4,918,000 is unreasonably high, and unreasonably greater than it average tree-trimming expenses of $4.3 million per year incurred since 2007.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Moore testified regarding Gulf’s requested amount for tree trimming expense for the 2012 projected test year. He stated:
Gulf’s distribution Vegetation Management activity ($4,918,000) includes expenses to clear, trim, and maintain distribution right of way. Gulf’s Vegetation Management activities are related to Gulf’s Commission approved Vegetation Management Plan in Order No. PSC-06-0947-PAA-EI, Docket No. 060198-EI. This Plan includes a combination of a 3-year trim cycle on all main line feeders, a 6-year cycle on laterals, and an annual cycle of inspections and corrections on main line feeders to ensure the approved cycles are achieved.
(TR 564)
As a result of Gulf’s experience with its trim cycle approved in the 2007 storm hardening plan, Gulf determined that it was necessary to shorten the lateral trim cycle from six to four years. In 2010, Gulf submitted and the Commission approved Gulf’s updated storm hardening plan for the years 2010 through 2012. This updated plan incorporated a four-year lateral and three-year main line feeder trim cycle. (TR 2468) Gulf witness Moore stated that the difference between the 2012 test year requested amount of $4.9 million and the $4.1 million average from 2007 to 2009 is the amount necessary for Gulf to stay on the new trim cycle for laterals approved by the Commission in Gulf’s most recent storm hardening plan. (TR 2469)
OPC
OPC witness Schultz proposed a reduction to Gulf’s 2012 projected test year tree trimming expense. He recommended a reduction of $386,834 on a jurisdictional basis. (TR 1558) Schultz argued that:
The total approved spending beginning in 2007 would equate to $4.7 million. Since the approval of the incremental vegetation management costs, the Company has average $4,293,262 as shown on Exhibit HWS-1, Schedule C-2. Limiting maintenance in previous years, for whatever reason, is no justification for passing the catch up costs on to ratepayers. Therefore, the Company’s sudden increase in spending when a rate case is being filed should not be the basis for the amount to be recovered from ratepayers prospectively. An adjustment is required to reflect the level of spending the Company is actually performing in its attempt to comply with the Storm Hardening Requirements approved by the Commission in Docket No. 060198-EI.
(TR 1559)
FIPUG, FRF, and FEA took the same position as OPC, but offered no arguments on this issue. (FIPUG BR 11; FRF BR 23; FEA BR 33)
ANALYSIS
Gulf’s updated storm hardening plan was approved by the Commission November 15, 2010.[41] In the updated plan, the Commission approved Gulf’s proposal to reduce its trim cycle for laterals from a six-year cycle to a four-year cycle. Although the Commission approved the shorter cycle, it was left to the Company’s discretion regarding how this change would be implemented.
Gulf witness Moore explained that OPC witness Schultz’s calculation for tree trimming expense is flawed. During three of the four years calculated by witness Schultz, Gulf had a longer trim cycle for laterals. Witness Schultz’s calculation would be correct only if the Commission did not approve the shorter trim cycle for lateral lines in Gulf’s most recent storm hardening plan in 2010 However, since the Commission did approve a shorter trim cycle, the annual expense for tree trimming would be expected to increase due to the more frequent tree trimming of vegetation on lateral lines to comply with the plan. (TR 2468-2469)
OPC’s analysis did not account for the most recent Commission approved storm hardening plan in Docket No. 100265-EI. As such, staff believes that pertinent information was left out of OPC’s calculations. OPC witness Schultz did not account for the shorter trim cycle for lateral lines in Gulf’s current vegetation management plan. The four-year average calculation performed by witness Schultz included three years of data from the period where Gulf was on the longer trim cycle. Witness Schultz’s proposed adjustment, thus, understates tree trimming expense and therefore, his adjustment should not be adopted.
Staff believes Gulf’s proposed 2012 projected tree trimming expense is reasonable. Gulf explained that the decreased trim cycle for laterals accounts for the increased expense. In addition, Gulf’s requested amount will allow the Company to achieve the new trim cycle for laterals in the allotted time frame. (TR 2469)
CONCLUSION
Staff recommends that the Commission approve Gulf’s proposed tree trimming expense for the 2012 projected test year. The appropriate amount of Gulf’s tree trimming expense for the 2012 projected test year is $4,918,154.
DROPPED PER STIPULATION.
DROPPED.
DROPPED.
DROPPED.
What is the appropriate amount of production plant O&M expense?
Recommendation:
The appropriate amount of production plant O&M expense is $105,269,794 ($108,847,728 system), which is $1,973,704 ($2,040,787 system) less than the Company’s requested $107,243,499 ($110,888,515 system). (Ma)
Position of the Parties
GULF:
Gulf’s request of $107,243,000 ($110,880,000 system) for production O&M expense is the appropriate amount to effectively maintain and operate Gulf’s generating fleet. In 2009 and 2010, to help delay a rate case, Gulf was able to maintain and operate the generating fleet through extraordinary but prudent management of limited resources. This included production O&M expense levels below budget and reduced staff levels. However, beginning in 2010, Gulf could no longer maintain and operate its fleet with such reduced resources without jeopardizing customer service. The production O&M expense requested for the 2012 test year is reasonable and necessary to provide a reliable and efficient generating fleet that minimizes cost, and it is representative of costs in future years.
OPC:
The appropriate amount of production plant O&M expense is $99,212,245, which is $11,675,270 less than the Company’s requested $110,887,515. The appropriate jurisdictional adjustment is a reduction of $11,291,492. Gulf’s projected 2012 expense is 19.38% higher than the 2010 expense and significantly higher than the historical 5-year average. Further, Gulf stated that it has not deferred any maintenance and the explanations to support the increase are inadequate.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of Gulf’s test year production plant O&M expense is $99,212,245.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
The Company requested $110,887,515 for production plant O&M expense according to the Company’s 2012 test year budget, which is approximately 19 percent higher than the 2010 expense level. In his testimony, Gulf witness Grove asserted that expense requirements have significantly changed since the prior rate case and that, “the historical average levels of Production Plant O&M expenses for the years 2006 through 2010 are not representative of Gulf’s going forward level of Production Plant O&M expenses.” (TR 852) Witness Grove continued by listing five primary factors driving the production plant O&M expense increase after 2010:
First . . . the age of Gulf's generation fleet is increasing, and with age, greater levels of maintenance are necessary to maintain or improve generating unit performance. Second, there are a number of costs in the Production function that are simply increasing at a rate higher than the Consumer Price Index (CPI), the general measure of inflation. Third, Gulf has a generating unit (Smith Unit 3) that was relatively new in the 2006-2010 time-periods and required very little O&M expense. Fourth, Gulf has one new unit (Perdido) that was not constructed and operational until October 2010. Fifth, Gulf worked very hard during the 2009-2010 time frames to avoid asking for base rate relief . . . However, the historical level of expenses is not sustainable without affecting the reliability and efficiency of our fleet.
(TR 853)
OPC
OPC’s proposed 2012 Production Plant O&M expense was based on a calculated escalation factor, effectively levelizing the overall cost. OPC used the historical five-year average from 2006 to 2010 as a starting point and escalated the value by two years to project a 2012 Production Plant O&M expense.
OPC witness Schultz began his calculations by averaging the total Production Plant O&M expenses over the 2006-2010 time period, resulting in $85,487,069. This value was increased by a 5.5 percent escalation factor in two iterations to represent 2011 and 2012. Witness Schultz explained how he calculated and justified the escalation factor of 5.5 percent in the his testimony:
The 5.5% increase is the actual net increase from 2008 to 2010. I regard this as more than reasonable since . . . costs over the past five years have increased as well as decreased resulting in a simple average annual increase 2.24%.
(TR 1565)
Witness Schultz finalized his calculations by making adjustments for labor costs:
After escalating the average costs, I added the Company increase in labor, using the Company’s 2012 labor of $30,828,000 and subtracting the five year average labor of $26,765,000. The average was calculated from Company Exhibit No. (RWG-1), Schedule 7 . . . The result is a recommended Production O&M expense of $99,212,245.
(TR 1565)
OPC’s calculations are summarized in Table 84-1 below.
Table 84-1
|
OPC’s Calculations |
|
|
2006-2010 Average Production O&M Expense |
$85,487,069 |
|
Escalation Factor |
5.5% |
|
Projected 2011 Budget |
$90,188,858 |
|
Projected 2012 Budget |
$95,149,245 |
|
Labor Adjustment |
+$4,063,000 |
|
Adjusted Total Production O&M Expense |
$99,212,245 |
|
Total Adjustment to Gulf’s Request |
-$11,675,270 |
FIPUG, FRF and FEA agreed with OPC. (FIPUG BR 11; FRF BR 24; FEA BR 33)
ANALYSIS
Witness Schultz did not provide any justification as to why the difference between 2008 and 2010 values was used to calculate the escalation factor. Additionally, the net increase percentage between the 2008 and 2010 Production Plant O&M expense is actually 5.05 percent, not 5.5 percent as indicated previously. Witness Schultz also did not provide any explanation as to why a labor adjustment was applied, or to the method in which it was applied. Furthermore, the five year average of the overall Production Plant cost of $85,487,069 already included baseline labor costs. The addition of the Company’s budgeted 2012 labor amount of $30,828,000 and subtraction of the five-year average labor of $26,756,000 resulted in double-counting the labor portion of the expenses.
Even excluding the errors in OPC’s calculations, staff does not agree with OPC’s method of computing a projected 2012 Production Plant O&M expense based on the averaging of historical levels. OPC’s process lacks adequate justification, is inconsistent in specific values chosen, and the overall nature of projecting annual costs using a randomly selected escalation percent is unnecessarily arbitrary and is not indicative of actual O&M costs going forward.
However staff does believe that an adjustment is warranted to Production Plant O&M expense because of extraordinary items of maintenance whose costs and frequency have been shown to be inconsistent on an annual basis. Although staff recognizes the validity of several of Gulf witness Grove’s justifications, staff has concerns regarding the significant increase of the Production Plant O&M expense after 2010. (EXH 18, Schedule 7) Specifically, staff recommends an adjustment to the Production Plant O&M costs related to the Smith Unit 3 Heat Recovery Steam Generation (HRSG) unit and other non-recurring costs. Staff’s approach incorporates these non-recurring items of maintenance to calculate a Production Plant O&M expense for the test year that better represents Gulf’s expected annual expenditures on a going-forward basis.
Smith 3 HRSG Unit
In Gulf’s response to staff’s Thirteenth Set of Interrogatories, No. 144(c), Gulf explained the increase in O&M costs of the Smith 3 Unit in further detail. Gulf stated that, “the major item driving up costs is maintenance related to the Heat Recovery Steam Generator and structures.” (EXH 97) These costs are summarized on an annual basis in Table 84-2 below. (EXH 109)
Table 84-2
he chart illustrates a significant increase in costs beginning in 2010 and a 2012 test year expense of $1,454,220, whereas the costs prior to 2010 were consistently under $500,000. According to Gulf’s filings in response to staff’s Twenty Sixth Set of Interrogatories, No. 313, the significant increase is a result of replacing and maintaining the HRSG’s valves and piping as well as the HRSG structure and lagging. (EXH 109) No further explanation was given by witness Grove as to the specific procedures, frequency, and importance of these generic items of maintenance. Therefore, staff is concerned that these procedures, although necessary for the Smith Unit 3 HRSG, may not be annually recurring items of maintenance and may consequently not be acceptable as an annually recurring O&M expense.
Staff addressed the Smith Unit 3 HRSG cost concerns by averaging the historical and budgeted six-year costs of the HRSG from 2006 to 2011. Data points prior to 2006 were omitted from the calculation because no costs for the Smith Unit 3 HRSG were recorded for these years of operation. The average cost was calculated to be $1,011,233, which is a $442,987 reduction from Gulf’s test year budget of $1,454,220. Staff believes this method provides protection from over-budgeting HRSG items of maintenance that have not been justified as necessary or to recur annually, while still providing an expense amount that considers the rise in costs related to the maintenance and operation of the HRSG unit.
Plant Daniel Unit 1 Nose Arch Repair
According to witness Grove, Gulf has scheduled plant outages in 2012 for Plant Crist Unit 6, Plant Crist Unit 7, Plant Scholz Unit 1, Plant Smith Unit 2, Plant Daniel Unit 1, and Plant Daniel Unit 2. (TR 871; TR 872) Witness Grove explained why items not included in the prior test year resulted in benchmark variances, of which the nose arch repair of the boiler of Plant Daniel Unit 1 was identified as one of these items with cost of repairs of approximately $3.2 million. (TR 872; TR 873) In response to staff’s Thirteenth Set of Interrogatories, No. 152, Gulf specified, “the existing nose arch has been in service for 34 years, and we expect a similar life after these repairs are complete.” (EXH 97) Witness Grove confirmed that the extent of the repairs on the nose arch is a “singular event” and that “[Gulf doesn’t] expect another three million dollar repair . . .” (EXH 148) Witness Grove does contend that although these costs may not occur at Plant Daniel Unit 1 to such an extent, other outage items of the same one-time frequency may occur at other generation plants in future years. However, witness Grove did not detail or affirm these costs or demonstrate they will occur with any certainty. No substantial evidence supports witness Grove’s claims, and should there be any year such substantial repairs not occur, ratepayers will be overpaying by approximately $3.2 million.
In order to account for staff’s concerns about overbudgeting for the boiler nose arch repair of Plant Daniel Unit 1, staff averaged the five-year budgeted outage expense for Plant Daniel Unit 1 from 2011 to 2015. (EXH 18) This is illustrated in Table 84-3 below.
Table 84-3
|
Plant Daniel Unit 1 Budgeted Outage Expenses |
|
|
2011 |
$3,511,000 |
|
2012 |
$6,147,000 |
|
2013 |
$6,274,000 |
|
2014 |
$3,522,000 |
|
2015 |
$3,319,000 |
|
Average |
$4,549,200 |
Staff used the budgeted outage expenses rather than historical, because historical outage costs have significantly fluctuated on an annual basis, as reflected in Gulf’s response to staff’s Thirteenth Set of Interrogatories, No. 143. (EXH 97) Due to this degree of volatility, these amounts would be a poor representation of expected costs going forward. The average outage expense from 2011 through 2015 was calculated to be $4,549,200. Using this amount in place of the budgeted 2012 outage expense of $6,147,000 results in a $1,597,800 reduction. Staff believes that this amount levelizes the costs of any one-incident items, such as the nose arch, in order to protect ratepayers from over budgeted maintenance, while providing adequate cost recovery for the Company and is a closer representation of the outage expenses of Plant Daniel Unit 1 going forward.
Overall Adjustment
As a result of staff’s recommended adjustments related to the HRSG unit and Plant Daniel Unit 1 items of maintenance, the adjustment from Gulf’s budgeted 2012 Production Plant O&M expense of $107,243,499 ($110,888,515 system) is a reduction of $1,973,704 ($2,040,787 system) or a total of $105,269,794 ($108,847,728 system). These recommended adjustments are summarized in Table 84-4 below.
Table 84-4
|
Staff Adjustments |
||
|
|
System |
Jurisdictional |
|
Gulf’s Proposed 2012 Budget for Production Plant O&M |
$110,888,515 |
$107,243,499 |
|
Staff’s HRSG Item Adjustment |
($442,987) |
($428,425) |
|
Staff’s Plant Daniel Unit 1 Outage Adjustment |
($1,597,800) |
($1,545,279) |
|
Staff’s Adjusted 2012 Budget for Production Plant O&M |
$108,847,728 |
$105,269,794 |
CONCLUSION
Based on staff’s recommended adjustments, the appropriate amount of Production Plant O&M expense is $105,269,794 ($108,847,728 system). This amount accounts for adjustments of the Plant Daniel Unit 1 boiler nose arch repair by levelizing its cost over the average of historical and budgeted outage expenses. It also accounts for adjusting the Smith 3 HRSG Unit costs to a historical five-year average. Staff believes levelizing the costs of these extensive, non-recurring items protects the ratepayers from an over-budgeted maintenance expense, while still providing sufficient funds for the Company to recover a fair amount representing expected annual costs on a going-forward basis.
What is the appropriate amount of Gulf's transmission O&M expense? (Category 2 Stipulation)
Approved Stipulation:
The appropriate amount of Gulf’s transmission O&M expense is $11,226,000 ($11,609,000 system).
What is the appropriate amount of Gulf’s distribution O&M expense?
Recommendation:
The appropriate amount of Gulf’s distribution O&M expense is $41,538,000 ($41,596,000 system). (L'Amoreaux, Ma)
Position of the Parties
GULF:
The total requested distribution O&M expenses for the 2012 test year of $41,538,000 ($41,596,000 system) are reasonable and necessary. The distribution expenses for the 2012 test year are necessary for Gulf to continue to provide reliable electric service to its customers and are lower than the level approved in Gulf’s last rate case when adjusted for customer growth and inflation since that case (typically referred to as the Commission benchmark). The 2012 test year expenses are also representative of levels that will continue to be incurred going forward.
OPC:
See OPC’s positions and arguments on Issues 79 and 80.
FIPUG:
Agree with OPC.
FRF:
Gulf’s test year distribution O&M should be reduced by $386,834 on a jurisdictional basis to reduce Gulf’s overstated tree-trimming expenses. This issue may also be impacted by the Commission’s decision regarding Issue 80, which is the subject of a pending motion for approval of partial settlement agreements.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
This issue is a fall-out issue. Based on a previously approved stipulation and staff’s recommendation in Issue 79, the appropriate amount of distribution O&M expense for the 2012 projected test year is $41,538,000 ($41,596,000 system).
Table 86-1
|
2012 Projected Test Year – Distribution O&M expense |
|||
|
Description |
Gulf |
OPC |
Staff |
|
Proposed Distribution O&M expense |
$41,538,000 |
$41,538,000 |
$41,538,000 |
|
Issue 79: Tree Trimming Expense |
$0 |
($386,384) |
$0 |
|
Issue 80: Pole-line Inspection Expense |
Dropped per stipulation |
Dropped per stipulation |
Dropped per stipulation |
|
|
|
|
|
|
Total |
$41,538,000 |
$41,151,616 |
$41,538,000 |
DROPPED.
What is the appropriate amount of Rate Case Expense for the 2012 projected test year?
Recommendation:
The appropriate amount of rate case expense is $2,800,000. As discussed in Issue 28, staff is recommending that this amount be amortized over a four-year period. (Mouring)
Position of the Parties
GULF:
Gulf’s requested amount of rate case expense of $2,800,000 ($2,800,000 system) is reasonable and appropriate. The appropriate amortization period for rate case expense is four years, which is consistent with the amortization period approved by the Commission in Gulf's last rate case.
OPC:
Gulf’s rate case expense should be decreased at least by $482,273. Gulf overstated its estimates for meals and hotel expenses by $102,273. Adjustments are also appropriate to remove $321,000 in SCS charges for information technology, human resources, and accounting functions performed in-house at Gulf, and the cost of service study performed by SCS in addition to outside consultant charges. Gulf has not shown that the SCS costs are incremental to costs already projected to be allocated or charged to Gulf from SCS during the test year. Finally, $59,000 of projected overtime labor should be removed as labor costs should already be provided for in Gulf’s 2012 budget incorporated in the filing.
FIPUG:
Agree with OPC.
FRF:
The Commission should reduce Gulf’s claimed rate case expense by $482,273.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf witness Erickson testified that the Company proposed a total estimated rate case expense of $2,800,000, to be amortized over a four-year period beginning in 2012. (TR 958) The details of the Company’s requested $2,800,000 rate case expense are shown on MFR Schedule C-10. (EXH 7)
The Company stated that during the course of this rate case, it had already exceeded the amount of rate case expense that was initially requested due to the “incredible volume of discovery” and “the number of issues we would need to defend.” (TR 2316) Gulf also provided an updated schedule which reflected the actual rate case expense incurred through October 31, 2011 and a revised estimate to complete this case totaling $3,750,215. The revised estimate included reductions to Meals and Travel estimates to reflect five days of hearing instead of ten. (EXH 108, No. 309) Gulf stated that, although it has already exceeded the $2,800,000 requested rate case expense shown on MFR Schedule C-10, it is only seeking the original amount of $2,800,000. (TR 2316; TR 2317; EXH 7; Gulf BR 108-110)
OPC
OPC witness Ramas stated that the Company’s estimates for Meals and Travel as well as many of the items included in Other Expenses are “excessive and/or unsupported.” (TR 1484) Witness Ramas stated that the Company’s requested amount assumed 60 people attending the hearing for 10 days, which is excessive and unreasonable. (TR 1486) OPC stated that a more appropriate estimate for Meals and Travel should be based on 34 people attending 5 days of hearings. (TR 1487) Witness Ramas has also identified several items listed as Other Expenses in the Company’s requested amount that OPC believes are unsupported. (TR 1488) OPC argued that $222,000 associated with a cost of service study performed by SCS is excessive because it is in addition to amounts charged by outside consultants in this case. (TR 1488) OPC argued that charges from SCS for IT, Human Resources, and Accounting services are unsupported and that “there has been no showing that additional support from SCS specific to the rate case in these areas are needed” and recommended removing an additional $99,000.[42] (TR 1488; EXH 35, Schedule C-6) Witness Ramas has also removed $59,000 of Other Expenses, related to overtime labor, arguing that these costs are already reflected in the test year and are not incremental to costs already considered in rates. (TR 1513; OPC BR 85-88)
In total, witness Ramas has proposed that Gulf’s requested rate case expense amount of $2,800,000 be reduced by $482,273 ($102,273 for Meals and Travel and $380,000 for Other Expenses). (EXH 35, Schedule C-6; TR 1489) OPC recommended adjustments to rate case expense would decrease the annual amortization amount by $120,586. (TR 1489)
FIPUG,[43] FRF and FEA have all adopted OPC’s position on this issue. (FRF BR 24; FEA BR 34)
ANALYSIS
MFR Schedule C-10 shows a total requested rate case expense of $2,800,000, to be amortized over a four-year period which yields an annual amortization expense of $700,000. (EXH 7) The treatment of the unamortized rate case expense, as it pertains to working capital, is addressed in Issue 28.
Gulf submitted updated support for its rate case expense that included actual costs incurred through October 31, 2011, and a revised estimate to complete this rate case. (EXH 108, No. 309) In its revised estimate to complete this rate case, Gulf reflected increases to both Outside Consultants and Outside Legal Services and reductions to both Meals and Travel and Other Expenses as a result of a five day hearing and a current estimate of those expected to attend the hearing. (EXH 108, No. 309) Witness Erickson went on to state that “some categories of expense may be over and some may be under the original estimate, but in total, Gulf will incur incremental expense directly related to this rate case in excess of $2.8 million.” (TR 2295) Staff has reviewed the Company’s requested amounts for Outside Consultants and Outside Legal Services and believes that given the scope and scale of discovery that has been propounded by staff and the intervenors, the amounts shown on Exhibit 108 for Outside Consultants and Outside Legal Services are reasonable and prudently incurred.
In its revised estimates, Gulf reduced its estimated total expense for Meals and Travel by $45,702 ($175,000-$129,298) to reflect five days of hearings and current estimates of people attending. (EXH 7, Schedule C-10; EXH 108, No. 309) OPC witness Ramas recommended reducing the Company’s estimated number of hearing days from ten to five to reflect the five days scheduled for hearing in this case. (TR 1487) Witness Ramas also recommended reducing the number of people attending the hearing, based on allowing one support staff person for each of the 17 Company witnesses in this proceeding, or 34 people. (TR 1487) Witness Ramas went on to state that although certain people will be required to stay for the entire duration of the hearing, it is unlikely that all of the Company’s witnesses will need to attend all five days of the hearing. (TR 1487) Based on witness Ramas’ recommended adjustments to the number of hearing days and people attending the hearing and corresponding adjustments to rental vehicles, OPC’s total recommended reduction to Meals and Travel expense is $102,273. (TR 1487; EXH 35, Schedule C-6) Staff is persuaded by OPC’s arguments that both Gulf’s initial and revised estimates are overstated, and that the methodology used by OPC witness Ramas in calculating a prudent and reasonable amount of expense for Meals and Travel is appropriate and reflects a more accurate estimate of costs incurred.
Regarding the $222,000 related to a cost of service study performed by SCS in preparation of this case, Gulf witness Erickson stated that there is no duplication of costs being requested and that Gulf had SCS perform the study because it was less expensive than having witness O’Sheasy’s firm perform the study, disputing OPC witness Ramas’ assertion that the costs associated with this study are not already reflected in the amount to be charged to Gulf by SCS in the projected test year. (TR 2296; TR 1488) Witness Erickson also addressed OPC witness Ramas’ proposed adjustments related to overtime costs and additional IT, human resources, and accounting services provided by SCS, citing the incremental costs incurred in association with responding to discovery and the technical support needed during the final hearing. (TR 2296) Although staff believes that adjustments should be made to the Company’s requested level of Meals and Travel as well as Other Expenses, staff notes that Gulf is not seeking recovery of rate case expense above the originally requested amount of $2,800,000 despite the fact that expenses for Outside Consultants and Outside Legal Services are estimated to exceed the originally requested amount. (TR 2317; EXH 7; EXH 108, No. 309)
Table 88-1
|
Rate Case Expense |
|||||
|
|
Original Filing MFR C-10 |
Gulf Updates |
Company Updated Filing |
Staff Adjustments |
Staff Adjusted |
|
Outside Consultants |
$725,000 |
$184,078 |
$909,078 |
0 |
$909,078 |
|
Outside Legal Services |
$1,475,000 |
$842,988 |
$2,317,988 |
0 |
$2,317,988 |
|
Meals and Travel |
$175,000 |
($45,702) |
$129,298 |
($46,489) |
$82,809 |
|
Other Expenses |
$425,000 |
($31,149) |
$393,851 |
0 |
$393,851 |
|
Total Expense |
$2,800,000 |
$950,215 |
$3,750,215 |
($46,489) |
$3,703,726 |
(EXH 7, Schedule C-10; EXH 108, No. 309.)
CONCLUSION
Based on an analysis of the updated amount of rate case expense, staff believes that the Company will incur expenses in excess of the $2,800,000 that is being sought for inclusion in this proceeding. Therefore, staff recommends that rate case expense be set at $2,800,000 with a four-year amortization period. The annual amortization amount should be $700,000 ($2,800,000/4).
What is the appropriate amount of uncollectible expense for the 2012 projected test year?
Recommendation:
The appropriate amount of uncollectible expense for the 2012 projected year is $4,003,000 ($4,003,000 system). Therefore, the Company’s uncollectible expense for the 2012 projected test year should be reduced by $340,000 ($340,000 system). The appropriate bad debt rate is 0.3061 percent rather than Gulf’s proposed rate of 0.3321 percent. (Trueblood)
Position of the Parties
GULF:
The amount of uncollectible expense of $4,143,000 ($4,143,000 system) included in the 2012 projected test year is appropriate for purposes of determining base rate revenue requirements.
OPC:
The appropriate amount of uncollectible expense is $3,997,000. Gulf’s projected 2012 projected bad debt factor of 0.3321% is not consistent with its historical bad debt rate, which averaged 0.3056% for 2007-2010. This 4-year average is higher than the 2010 rate realized by Gulf of 0.2937%, the year of the Gulf oil spill. Gulf has provided no information in its filing or testimony regarding how the factor was determined or the assumptions used. This unsupported projection should be replaced with a historical 4-year average of bad debt expense, resulting in a reduction of $346,000. The bad debt factor should also be adjusted to calculate the NOI multiplier.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of uncollectible expense for the 2012 test year is $3,997,000.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf’s witness Erickson asserted its 2012 Uncollectible Account Expense of $4,143,000 is representative of its uncollectible account expense on a going forward basis. She stated that Gulf’s revenue and projected bad debt factors for 2011 through 2015 were provided in the O&M budget that was the basis for the Company’s 2012 test year. She also pointed out that a .24 percent write-off was approved in 2002 as a percent of revenue, which is the industry standard for measuring bad debt. (TR 970; EXH 19)
Gulf’s actual write-offs for 2008, 2009, and 2010 have increased because of a weak economy, which has resulted in utility bills not being paid as individuals were adversely affected by unemployment, foreclosures, and other financial stress. Gulf’s net write-offs for 2009 were 0.33 percent and its projected write-offs for the 2012 test year are 0.32 percent. Witness Erickson asserted that Gulf uses consistent policies to mitigate risk and she stated that based on a plan to increase collection efforts by field representatives, Gulf made a $206,000 adjustment to decrease its uncollectible expense. She maintained that Gulf also uses credit scores and collects deposits for residential, commercial, and industrial classes based on creditworthiness. Witness Erickson further stated that customers are called and informed that bills must be paid to avoid disconnection, and Gulf monitors collection-related statistics. (TR 971-972; Gulf BR 111)
Witness Erickson argued that Uncollectible Accounts expenses do not track with the Consumer Price Index (CPI) and she confirmed that the write-offs listed in MFR Schedule C-11 are net write-offs. (TR 972; EXH 7, MFR Schedule C-11 and C-41; EXH 113) In a discovery response, Gulf provided the actual amount of write-offs, recoveries, and associated revenues for the period 2006 through July 2011. The bad debt accruals and balances were also provided. (EXH 115; EXH 120)
Finally, witness Erickson testified that Gulf’s base rates have not increased in a decade. She stated that Gulf’s total revenue and bad debt factor increased and resulted in a higher overall level of uncollectible expenses because the expenses outpaced the O&M benchmark by nearly $2 million, despite enhanced collection efforts. (TR 976)
OPC
OPC witness Ramas asserted that Gulf used a bad debt factor of .3321 percent to calculate the $4,137,000 of uncollectible expense included in the 2012 test year. As a result, she recommended a $206,000 adjustment to the Company’s requested amount. She argued that the bad debt factor the Company provided for the years 2007 through 2010 was calculated as the net uncollectible write-offs to gross revenue for retail sales of electricity. The bad debt factors range from a low of 0.2804 percent to a high of 0.3323 percent in 2009, and the factor for 2010, the year of the BP Oil Spill, was 0.2937 percent. (TR 1462-1463; OPC BR 88)
Witness Ramas testified that Gulf failed to provide explanations in its filing or its witness’ testimony to show how the bad debt factors were determined, how the 2011 and 2012 projections were calculated, or how the amount was determined. She stated the projected revenue, write-offs, and bad debt factors for 2011 through 2015 provided by Gulf’s witness Erickson lacked support showing how the calculations were made or what assumptions were used. (TR 1463)
Witness Ramas argued that Gulf’s projected bad debt factor varies from year to year. Gulf’s documentation included bad debt factors for the years 2007 through 2010, and a projected 2012 bad debt factor of 0.3321 percent. Based on the information provided by Gulf for the historical years of 2007 to 2010, witness Ramas calculated the projected 2012 bad debt factor, which is a four-year average bad debt factor of 0.3056 percent.
OPC witness Ramas asserted that the 0.3056 percent factor is higher than Gulf’s actual 2010 rate and asserted that it is appropriate to reflect a normalized level on a going forward basis. Further, she argued that the 0.3056 percent rate should be used instead of Gulf’s 0.3321 percent rate. The four-year average bad debt rate of 0.3056 percent would result in projected net write-offs of $3,997,000, and an additional reduction of $346,000 from the amount in the filing. (TR 1463; EXH 153, pp. 51-59) Finally, witness Ramas asserted that she is not removing the $206,000 uncollectible expense adjustment reflected in Gulf’s filing because it resulted from increased collection efforts that were not present during the historical period of 2007 through 2010. (TR 1464; OPC BR 89)
FIPUG, FRF, and FEA support OPC’s position and recommended adjustment. (FIPUG BR 11; FRF BR 24; FEA BR 34)
ANALYSIS
Staff notes that in the Company’s MFR Schedule C-11, Gulf calculated a projected 2012 test year bad debt factor of 0.3321 percent, and included the bad debt factors for the historical years of 2007 through 2010. Bad debt factors for Gulf’s historical years and the 2012 test year were determined by dividing the retail net write-offs listed in column 3 of MFR Schedule C-11 by the adjusted gross revenues listed in column 6 of that schedule. Staff further notes that the information Gulf used to calculate the projected 2012 bad debt factor was based on projected figures, not historical data.
OPC recommended a 4-year average bad debt factor be used to normalize the level of bad debt on a going forward basis. Staff agrees with OPC that a 4-year average bad debt factor based on net write-offs and gross revenue is reasonable to determine the appropriate level of bad debt for the 2012 test year. Staff notes that OPC used the information provided in Gulf’s MFR Schedule C-11 for the historical years of 2007 through 2010 to calculate its recommended 4-year average 2012 bad debt factor of .3056 percent.
Although staff agrees that the 2012 bad debt factor should be determined based on a 4-year average of the historical years of 2007 through 2010 as proposed by OPC, instead of a single year forecast as proposed by Gulf, staff believes the bad debt factor should be calculated using the net write-offs listed in column three and the adjusted gross revenue listed in column 6 of MFR Schedule C-11. It appears that the bad debt factor calculated by OPC was determined by dividing the sum of the bad debt factors listed in column 7 of Schedule C-11 for the historical years by 4, which resulted in an inappropriate projected bad debt factor of 0.3056 percent, a projected net write-off of $3,997,000, and a resultant adjustment of $346,000.
Staff calculated a 2012 bad debt factor of 0.3061 percent. The factor was determined by using the actual net write-offs and adjusted gross revenue for the years 2007 through 2010, which results in a net write-off of 4,003,000 and an additional adjustment of $340,000 to the Company’s projected write-off of $4,343,000 that are listed in its initial filing. The table below shows the information used to calculate the 2012 bad debt factor of 0.3061 percent recommended by staff.
Table 89-1
|
Calculation of 2012 Bad Debt Factor for Uncollectible Account Expense[44] |
|||||
|
(1) Year |
(2) Retail Net Write-Offs |
(3) Retail Gross Revenues From Sales of Electricity |
(4) Gulf’s Bad Debt Factors (2) / (3) |
(5) OPC’s Bad Debt Factor (2) / (3) |
(6) Staff’s Bad Debt Factor (2) / (3) |
|
2007 |
$2,883,000 |
1,028,209,000 |
0.2804% |
|
|
|
2008 |
$3,416,000 |
1,080,602,000 |
0.3161% |
|
|
|
2009 |
$4,029,000 |
1,212,400,000 |
0.3323% |
|
|
|
2010 |
$3,806,000 |
1,295,892,000 |
0.2937% |
|
|
|
2007-2010 Totals |
14,134,000 |
4,617,103,000 |
|
|
|
|
2012 |
$4,003,000 |
1,307,803,000 |
0.3321% |
0.3056% |
0.3061% |
CONCLUSION
The appropriate amount of uncollectible expense for the 2012 projected year is $4,003,000 ($4,003,000 system). Therefore, the Company’s uncollectible expense for the 2012 projected test year should be reduced by $340,000 ($340,000 system). The appropriate bad debt factor is 0.3061 percent rather than Gulf’s proposed rate of 0.3321 percent.
Is Gulf's requested level of O&M Expense in the amount of $282,731,000 ($288,474,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate level of O&M Expense for the 2012 projected test year is $270,518,130 ($275,951,748 system). This is a reduction of $12,212,870 ($12,522,252 system). (Mouring)
Position of the Parties
GULF:
No. The appropriate amount of O&M expense for the 2012 test year is $282,320,000 ($288,062,000 system). This amount includes adjustments to Gulf’s original request to reflect the approved stipulations on Issues 53, 58 and 68.
OPC:
No. After OPC’s recommended adjustments, the appropriate amount is $246,132,000.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate allowable level of O&M Expense for the 2012 test year is no more than $246,132,000.
FEA:
No. The appropriate amount should encompass FEA’s adjustments.
Staff Analysis:
This is a fallout issue. Based of staff’s recommendations, the appropriate level of O&M Expense for the 2012 projected test year is $270,518,130 ($275,951,748 system). This is a reduction of $12,212,870 ($12,522,252 system). (See Schedule 3)
What is the appropriate amount of depreciation and fossil dismantlement expense for the 2012 projected test year?
Recommendation:
The appropriate amount of depreciation and fossil dismantlement expense for the 2012 projected test year is $95,245,749 ($97,242,435 system). (Ollila, Slemkewicz)
Position of the Parties
GULF:
The appropriate depreciation and amortization of property, including fossil dismantlement expense, for the 2012 test year is $96,432,000 ($98,469,000 system). This amount includes adjustments to Gulf’s original request to reflect the non-AMI meter adjustments addressed in the stipulation on Issue 20, the ECCR adjustments addressed in the stipulation on Issue 44, and the Crist turbine upgrades discussed in Issues 8 and 9.
OPC:
See Issue 92.
FIPUG:
Agree with OPC.
FRF:
Incorporated in Issue 92.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
Based on stipulations and staff’s recommendations in other issues, the appropriate amount of depreciation and fossil dismantlement expense for the 2012 projected test year is $95,245,749 ($97,242,435 system), an increase of $65,749 ($101,435 system).
Table 91-1
|
2012 Test Year – Depreciation & Fossil Dismantlement Expense - Jurisdictional |
||
|
Description |
Gulf |
Staff |
|
Depreciation & Fossil Dismantlement Expense |
$95,180,000 |
$95,180,000 |
|
Issue 9: Turbine Upgrade |
2,161,000 |
934,000 |
|
Issue 12: Capitalized Incentive Compensation |
0 |
(42,049) |
|
Issue 14: Transmission Capital Additions |
0 |
0 |
|
Issue 20-S: Non-AMI Meter Amortization |
(886,000) |
(886,000) |
|
Issue 22: Construction Work in Progress |
0 |
102,000 |
|
Issue 44-S: ECCR Revenues and Expenses |
(23,000) |
(23,000) |
|
Issue 71: Incentive compensation adjustments |
0 |
(19,202) |
|
Total Adjustments |
1,252,000 |
65,749 |
|
Adjusted Total |
$96,432,000 |
$95,245,749 |
Is Gulf's requested level of Depreciation and Amortization Expense in the amount of $87,804,000 ($89,613,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate level of Depreciation and Amortization Expense for the 2012 projected test year is $95,245,749 ($97,242,435 system). (Mouring, Ollila)
Position of the Parties
GULF:
No. The number cited in this issue is the depreciation and fossil dismantlement amount for 2011, and does not include amortization of investment tax credits. The appropriate Depreciation and Amortization expense for the 2012 test year is $95,478,000 ($97,495,000 system). This amount includes both the adjusted depreciation and fossil dismantlement amount from Issue 93 and the amortization of investment tax credits.
OPC:
No. In its supplemental filing to include the Crist turbine upgrade projects, Gulf increased its depreciation expense request by $2,161,000 ($2,237,000 system). The appropriate amount is $95,694,000, which reflects a reduction to Gulf’s updated requested balance of $1,647,000. On a jurisdictional basis, depreciation expense should be reduced by $378,000 for transmission and $42,967 for incentive compensation plant-related adjustments. The requested increase in depreciation expense for the Christ turbine upgrades should be reduced by $1,227,000 from $2,161,000 to $934,000.
FIPUG:
No. Agree with OPC.
FRF:
No.
FEA:
FEA has resolved the AMI meter adjustment. FEA adopts the position of OPC.
Staff Analysis:
This is a fallout issue. Based of staff’s recommendations in previous issues, the appropriate level of Depreciation and Amortization Expense for the 2012 projected test year is $95,246,155 ($97,242,850 system) as shown in Table 92-1.
Table 92-1
|
2012 Test Year – Depreciation and Amortization Expense – Jurisdictional |
||
|
Description |
Gulf |
Staff |
|
Depreciation & Amortization Expense |
$95,180,000 |
$95,180,000 |
|
Amortization of ITCs |
(954,000) |
(In Issue 95) |
|
Issue 9: Turbine Upgrade |
2,161,0000 |
934,000 |
|
Issue 12: Capitalized Incentive Compensation |
0 |
(42,049) |
|
Issue 20-S: Non-AMI Meter Amortization |
(886,000) |
(886,000) |
|
Issue 22: Construction Work in Progress |
0 |
102,000 |
|
Issue 44-S: ECCR Adjustment Error |
(23,000) |
(23,000) |
|
Issue 71: Incentive Compensation |
0 |
(19,202) |
|
Total Adjustments |
298,000 |
65,749 |
|
Adjusted Accumulated Depreciation & Amortization |
$95,478,000 |
$95,245,749 |
What is the appropriate amount of Taxes Other Than Income Taxes for the 2012 projected test year?
Recommendation:
The appropriate amount of Taxes Other Than Income for the 2012 projected test year is $28,743,813 ($29,445,649 system), a decrease of $19,187 ($19,351 system). (Mouring)
Position of the Parties
GULF:
The appropriate amount of Taxes Other Than Income Taxes for the 2012 test year is $28,753,000 ($29,455,000 system). This amount includes an adjustment to Gulf’s original request to reflect the ECCR adjustment addressed in the stipulation on Issue 44.
OPC:
The appropriate amount of taxes other than income should be $27,977,000. This reflects a reduction to Gulf’s requested balance of $786,000 jurisdictional for OPC’s recommended incentive compensation adjustment.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of Taxes Other Than Income Taxes for the 2012 test year is $27,977,000.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in other issues and the stipulation in Issue 44, Taxes Other Than Income for the 2012 projected test year should be decreased by $19,187 ($19,351 system) for an adjusted total of $28,743,813 ($29,445,649 system). (See Schedule 3)
Is it appropriate to make a parent debt adjustment per Rule 25-14.004, Florida Administrative Code?
Recommendation:
Yes. Jurisdictional income tax expense should be decreased by $1,063,595 ($2,125,860 system) to reflect the parent debt adjustment required by Rule 25-14.004, F.A.C. (Springer)
Alternative Recommendation: No. Gulf has effectively rebutted the presumption that a parent debt adjustment should be made pursuant to Rule 14.004, F.A.C. (Cicchetti)
Position of the Parties
GULF:
No. Gulf has rebutted the presumption that parent company debt has been invested in Gulf by demonstrating that the equity contributions from Southern Company since the date of the last rate case, in which no parent debt adjustment was made, have been supported by dividends paid to Southern by Gulf.
OPC:
Yes. Gulf has not overcome the rebuttable presumption required by Commission rule and failed to show that the Southern’s investment in Gulf is not made in the same ratios. The fact that no adjustment was made in the last rate case is not persuasive, especially since circumstances have changed. The argument that Gulf’s dividends exceeded Southern’s equity infusions fails because dollars cannot be traced. Southern’s capital structure, after elimination of subsidiary debt, has outstanding debt and without an all equity parent capital structure, a PDA is appropriate for Gulf. Gulf’s attempt to change the jurisdictional factor should be rejected. Income tax expenses should be reduced by $2,126,000 ($1,766,000 jurisdictional).
FIPUG:
Yes. Agree with OPC. Gulf has failed to rebut the presumption in the rule.
FRF:
Yes.
FEA:
FEA takes no position on this issue.
Staff Analysis:
This issue addresses the appropriateness of making a Parent Debt Adjustment per Rule 25-14.004, F.A.C.
PARTIES’ ARGUMENTS
Gulf
Gulf witness Teel stated that no funds provided by Southern Company debt have been invested in the equity of Gulf. (TR 205) Witness Teel further explained that, since Gulf’s last rate case, Gulf has received $459 million in equity investment from Southern Company and has paid $655 million in dividends to Southern Company which is $196.8 million above Southern Company’s equity investment in Gulf. (TR 205) Witness Teel stated that, prior to the last rate case:
. . . Southern issued long-term debt during the growth of Southern Electric International, which was ultimately spun-out of Southern in 2001 as Mirant Corporation. Second, Southern’s commercial paper borrowings, both now and at the time of the last rate case, are used to support parent-level expenditures. They are not used as a source of funds for investments in the operating companies. Finally, the Commission did not find it necessary to make a parent company adjustment during Gulf’s last rate case.
(TR 208)
Witness Teel indicated that imputing the tax benefits of Southern Company’s debt to Gulf is effectively assuming Gulf has more debt in its own capital structure than actually exists. Witness Teel further indicated the adjustment would decrease the return on equity by approximately 25 basis points below the level the Commission otherwise determines to be appropriate. (TR 209)
Gulf witness Deason stated the parent debt adjustment causes a discrepancy between the amount of debt used to determine a regulated utility’s cost of capital and the amount of debt used to determine the regulated utility’s income tax expense. (TR 2137) To further support his position, witness Deason cited, as follows, the recommendation of technical staff in Docket No. 870386-PU, in which the Commission considered repealing Rule 25-14.004, F.A.C.:
The parent company debt adjustment necessarily assumes the debt of the parent company funds the equity of the utility subsidiary. This is known as double leverage. We believe that the capital structure found reasonable by the Commission should determine the interest used for tax purposes. This is known as interest reconciliation. It makes no sense to use one interest amount for capital structure and another for tax purposes. In developing capital structure, the parent subsidiary relationship is reviewed. The key is the reasonableness of the utility’s capital structure.
All parties in proceedings before this Commission are offered the opportunity to provide expert testimony regarding the appropriate level of income tax expense, capital structure and rate of return. All appropriate adjustments may be made without invoking Rule 25-14.004. Because Rule 25-14.004 is unnecessary it should be repealed.
(TR 2140-2141, emphasis supplied)
Finally, witness Deason addressed OPC witness Woolridge’s conclusion that witness Teel’s rebuttal is not persuasive because it is impossible to trace dollars. Witness Deason stated:
I find his reasoning curious. While stating it is impossible to trace dollars, he ignores the reality that the presumption in the rule and his own conclusion are exactly that, a tracing of dollars from parent debt (Southern) to subsidiary equity (Gulf). I agree that these dollars from Southern to Gulf cannot be traced or proven with certainty, hence the presumption. However, if one is to rebut the presumption which is based on tracing, one has to engage in similar “tracing” to show that the dollars were not, or more likely not, to have been invested in Gulf’s equity. By his dividend analysis, Mr. Teel shows it is more likely that Southern debt was not invested in Gulf’s equity. Dr. Woolridge makes no such analysis to rebut Mr. Teel’s assertion. He simply relies on arguments that say the presumption can never be rebutted.
(TR 2142)
OPC
In its post hearing brief, OPC disagreed with Gulf’s rationale for not applying the parent debt adjustment. OPC argued that:
Dividends in excess of equity infusions between Gulf and Southern for Gulf’s chosen time frame do not rebut the presumption of the rule, especially since Mr. Teel reached back only as far as Gulf’s last rate case. On cross-examination Mr. Teel stated that the reason Gulf chose the period back to the last rate case to study the level of dividends exceeding equity infusions was because a PDA was not made in the last rate case and circumstances have not changed since then. Mr. Teel admitted that depending on the time frame that is chosen, the dividend-to-equity infusion analysis could look very different.
(OPC BR 92)
Additionally, OPC argued that in several recent cases the Commission has found that the companies have not successfully rebutted the presumption that the parent debt adjustment should be applied. Witness Woolridge identified four proceedings (three since 2009) in which the Commission required a parent debt adjustment be made. (OPC BR 91)
Finally, OPC argued that the jurisdictional separation factor used to calculate the final dollar amount of the adjustment should be the jurisdictional separation factor listed in MFR C-4 and not the jurisdictional separation factor indicated by Gulf witness McMillan in his rebuttal testimony.
FIPUG and FRF agreed with OPC that the parent debt adjustment should be made. FEA took no position on this issue. (FIPUG BR 12; FRF BR 25; FEA BR 34)
PRIMARY STAFF ANALYSIS
Rule 25-14.004, F.A.C., states that “the income tax expense of a regulated company shall be adjusted to reflect the income tax expense of the parent debt that may be invested in the equity of the subsidiary where a parent-subsidiary relationship exists and the parties to the relationship join in the filing of a consolidated income tax return.” Further, Rule 25-14.004(3), F.A.C., states that “it shall be a rebuttable presumption that a parent’s investment in any subsidiary or in its own operations shall be considered to have been made in the same ratios as exist in the parent’s overall capital structure.” Rule 25-14.004(4), F.A.C., provides that:
The adjustment shall be made by multiplying the debt ratio of the parent by the debt cost of the parent. This product shall be multiplied by the statutory tax rate applicable to the consolidated entity. This result shall be multiplied by the equity dollars of the subsidiary, excluding its retained earnings. The resulting dollar amount shall be used to adjust the income tax expense of the utility.
In MFR Schedule C-4, Gulf provided the information necessary to calculate the parent debt adjustment, but did not include an adjustment to income tax expense to reflect the parent debt in the calculation of its requested revenue requirement. The Company provided the following information:
Table 94-1
|
Parent Debt Adjustment Calculation |
|
|
Debt Ratio of the parent |
14.56% |
|
Debt Cost Rate of the parent |
3.8% |
|
Consolidated Statutory Tax Rate |
38.575% |
|
Subsidiary Equity |
$1,001,996,000 |
In a ruling, cited by witness Woolridge, that a parent debt adjustment was required in the case involving Indiantown Company, Inc., the Commission stated:
Based on our analysis, the rule requires that a parent debt adjustment be made in this proceeding. Further, the rule does not allow for specific identification of debt from the parent to the subsidiary utility. Since the utility is included in the consolidated income tax returns of the parent, we believe that it would be very difficult to prove specific identification to only the utility. Rule 25-14.004(3), Florida Administrative Code, states that it shall be a rebuttable presumption that a parent=s investment in any subsidiary or in its own operations shall be considered to have been made in the same ratios as exist in the parent=s overall capital structure.[45]
Rule 25-14.004, F.A.C., is based on the premise that debt at the parent level supports a portion of the parent’s equity investment in the subsidiary. Because the interest expense on such debt is deductible by the parent for income tax purposes, the income tax expense of the regulated subsidiary should also be reduced by the same tax effect. The reduction in income tax expense enjoyed by the parent should be shared with the regulated subsidiary and the ratepayers. Primary staff agrees with OPC that the Company has not effectively rebutted the presumption that the parent debt adjustment should be applied in this case. Primary staff believes that Gulf has not demonstrated that the investment made by Southern Company in Gulf can be attributed to any source other than the general funds of the parent.
Accordingly, staff believes that the parent debt adjustment should be applied in this case, and that the elements of the computation should be based on the projected test year capital structures of Southern Company and Gulf. Staff’s calculation of the system income tax expense reduction is as follows:
Table 94-2
|
Parent Debt Adjustment – Recommended Amount |
|||
|
Debt Ratio of parent |
|
.1456 |
|
|
Debt Cost Rate of parent |
X |
.038 |
|
|
|
= |
.0055 |
|
|
Consolidated Tax Rate |
X |
.38575 |
|
|
|
= |
.0021216 |
|
|
Subsidiary Equity |
X |
$1,001,996 |
(in 000s) |
|
Parent Debt Adjustment |
= |
$2,126 |
(in 000s) |
In MFR Schedule C-4, p. 5, Gulf provided the information to calculate a jurisdictional separation factor for income taxes of .500312. Staff recommends the jurisdictional separation factor be applied between the total company and the retail jurisdiction consistent with Commission practice in recent cases.[46] Applying this factor to the adjustment calculated above results in a jurisdictional adjustment of $1,063,593 (2,125,860 x .500312).
PRIMARY STAFF CONCLUSION
The Company has not effectively rebutted the presumption that a parent debt adjustment should be applied pursuant to Rule 25-14.004, F.A.C. Accordingly, the appropriate jurisdictional adjustment is a reduction of income tax expense in the amount of $1,063,593.
ALTERNATIVE STAFF ANALYSIS
In practice, the Parent Debt Rule, Rule 25-14.004, F.A.C., imputes the tax benefit of debt issued by a utility’s parent company to a regulated utility subsidiary based on the assumption that the parent company invested the proceeds of its debt in the regulated subsidiary’s equity in direct proportion to the debt in the parent company’s capital structure. On its face, the Parent Debt Adjustment Rule is inconsistent with the Commission’s long-standing practice of determining allowable utility taxes on a stand-alone basis. Referring to the staff recommendation in Docket No. 870386- PU, witness Deason stated:
The technical staff argued that ratepayers should pay the taxes associated with or receive the tax benefit of only the items that are included in the cost of service and net operating income directly attributable to them.
(TR 2139)
Additionally, witness Deason pointed out several questionable assumptions necessary to justify implementation of the rule. Witness Deason explained that even though ratepayers are not obligated to pay the interest on the parent company’s debt in rates, the tax deduction associated with the parent company’s debt is imputed to the benefit of ratepayers. Consequently, the amount of debt used to determine the regulated utility’s capital structure is different than the amount of debt used to determine the regulated utility’s interest expense. (TR 2137) Although the Commission reconciles the amount of interest expense allowed in rates to the amount of debt in the capital structure, a different amount of interest expense is used to determine interest expense for tax purposes. (TR 2140)
Witness Deason further explained that the rule calls for this adjustment regardless of the appropriateness of the regulated utility’s capital structure and that the rule implies the regulated utility should have issued more debt than it did. (TR 2144-2145) Witness Deason cited staff’s recommendation in Docket No. 870386-PU which observed that all parties in proceedings before the Commission are offered the opportunity to provide expert testimony regarding the appropriate level of income tax expense, capital structure and rate of return and that all appropriate adjustments can be made without invoking Rule 25-14.004, F.A.C. (TR 2140-2141) Furthermore, witness Deason indicated that the parent debt adjustment will reduce Gulf’s achieved net operating income and return on equity. (TR 2145)
As cited above, witness Teel presented a dividend and equity infusion analysis that indicated, since Gulf’s last rate case, Gulf has paid dividends to Southern Company in excess of $196 million more than Southern Company has invested in Gulf’s common equity. Witness Deason stated Southern Company had only short-term commercial paper outstanding at the time of Gulf’s last rate case. (EXH 212) Witness Teel stated:
Gulf has been a net returner of capital to Southern, not a net recipient. Thus Gulf itself has effectively provided the funding for Southern’s equity investment in Gulf with its own internally generated funds.
Witness Woolridge’s position regarding the parent debt adjustment and his position regarding witness Teel’s dividend analysis is stated in his testimony:
Given the Commission’s recent decisions in dockets involving Tampa Electric, Peoples Gas and Progress Energy Florida, the existence of debt in Southern Company’s capital structure, and the impossibility of tracing funds to specific equity issuances, a parent debt adjustment is appropriate in this case.
(TR 1731)
Alternative staff agrees with witness Deason that “if one is to rebut the presumption which is based on tracing, one has to engage in similar tracing to show that the dollars were not, or more likely not, to have been invested in Gulf’s equity.” Alternative staff also agrees with witness Teel that although funds are fungible, “if exact tracing were required, the presumption in the rule would effectively be irrebuttable. This cannot be what the Commission intended.”
The record indicates that Southern Company did not have long-term debt outstanding to invest in Gulf’s equity at the time of Gulf’s last rate case. Since Gulf’s last rate case, the record evidence indicates Gulf paid dividends to Southern Company of $196 million more than Southern Company invested in the equity of Gulf. In addition, based on its mix of equity and debt, staff believes Gulf has a reasonable capital structure. Although funds cannot be traced, it is more logical to assume that Southern Company returned dividend dollars to Gulf to maintain an appropriate level of equity in Gulf than to assume Southern Company issued debt to invest in Gulf’s equity. As stated by the Company, “the Commission should consider the evidence presented to rebut the presumption, the reasonableness of Gulf’s capital structure, and the impact of making the adjustment on Gulf’s opportunity to actually achieve the return on equity that the Commission ultimately determines to be reasonable.” (Gulf BR 117) Alternative staff believes the preponderance of the evidence indicates Gulf effectively has rebutted the presumption that Southern Company invested debt dollars in Gulf’s common equity in direct proportion to the percent of debt in Southern Company’s parent only capital structure. Consequently, alternative staff recommends no parent debt adjustment be made in this case.
ALTERNATIVE CONCLUSION
Gulf has effectively rebutted the presumption that a parent debt adjustment should be made pursuant to Rule 25-14.004, F.A.C.
What is the appropriate amount of Income Tax expense for the 2012 projected test year?
Recommendation:
The appropriate amount of Total Income Tax expense for the 2012 projected test year is $18,640,023 ($20,772,112 system), an increase of $4,360,023 ($3,403,112 system). (Mouring, Springer, Cicchetti)
Position of the Parties
GULF:
The appropriate amount of Income Tax expense for the 2012 test year is $15,249,000 ($18,323,000 system). This amount includes adjustments to Gulf’s original request to reflect the income tax effect of depreciation on the Crist 6 and 7 turbine upgrade and the income tax effect of the stipulations on Issues 20, 44, 53, 58 and 68. It also includes the impact of interest synchronization resulting from the rate base changes associated with these items, the rate base stipulations on Issues 18, 20, 21 and 26, and the updated long-term and short-term debt rates from the stipulations on Issues 35 and 36.
OPC:
Based on OPC’s recommended adjustments, the appropriate amount of test year income tax expense before any revenue increase should be 29,877,000.
FIPUG:
Agree with OPC.
FRF:
The appropriate amount of test year Income Tax expense is $29,877,000.
FEA:
The appropriate amount should reflect FEA’s proposed adjustments.
Staff Analysis:
This is a fallout issue based on the outcome of other adjustments made in this case. Adjustments to expenses will increase/decrease the Income Tax expense based on the statutory income tax rate of 38.575 percent. The Income Tax expense for the 2012 projected test year should be $18,640,023 ($20,772,112 system), an increase of $4,360,023 ($3,403,112 system) to the Company’s filed amount of $14,280,000 ($17,369,000). (See Schedule 3) The primary staff recommendation in Issue 94 was used in the calculation of this issue.
Is Gulf’s requested level of Total Operating Expenses in the amount of $420,954,000 ($432,449,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate level of Total Operating Expenses for the 2012 projected test year is $413,147,715 ($423,411,944 system), a decrease of $7,806,285 ($9,037,056 system). (Mouring)
Position of the Parties
GULF:
No. The appropriate amount of Total Operating Expenses for the 2012 test year is $421,800,000 ($433,335,000 system). This amount includes adjustments to Gulf’s original request to reflect the impact of the Crist 6 and 7 turbine upgrades, the effect of the approved stipulations, and the related income tax and interest synchronization impacts as quantified in Issue 95.
OPC:
No. Gulf’s supplemental filing increases its requested operating expenses by $816,000 to $421,770,000, after OPC’s recommended adjustments, the appropriate total operating expenses should be $398,726,000 (jurisdictional).
FIPUG:
Agree with OPC.
FRF:
No. The maximum appropriate level of allowable jurisdictional Total Operating Expense for the 2012 test year is $398,726,000.
FEA:
No. The appropriate amount should reflect FEA’s proposed adjustments.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in previous issues, the appropriate level of Total Operating Expenses for the 2012 projected test year is $413,147,715 ($423,411,944 system), a decrease of $7,806,285 ($9,037,056 system). (See Schedule 3)
Is Gulf's projected Net Operating Income in the amount of $60,955,000 ($66,862,000 system) for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate Net Operating Income for the 2012 projected test year is $68,761,285 ($75,899,056 system), an increase of $7,806,285 ($9,037,056 system). (Mouring)
Position of the Parties
GULF:
No. The appropriate amount of Net Operating income for the 2012 test year is $60,109,000 ($65,976,000 system). This amount includes adjustments to Gulf’s original request to reflect the impact of the Crist 6 and 7 turbine upgrades, the effect of the approved stipulations, and the related income tax and interest synchronization impacts.
OPC:
No. Gulf’s supplemental filing increases its projected Net Operating Income by $816,000 to $61,771,000. After OPC’s recommended adjustments, the appropriate jurisdictional net operating income is $85,293,000.
FIPUG:
No. Agree with OPC.
FRF:
No. The appropriate level of jurisdictional NOI for the 2012 test year is $85,293,000.
FEA:
No. The appropriate net operating income should reflect FEA’s proposed adjustments.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in previous issues, the appropriate Net Operating Income for the 2012 projected test year is $68,761,285 ($75,899,056 system), an increase of $7,806,285 ($9,037,056 system). (See Schedule 3)
What is the appropriate revenue expansion factor and the appropriate net operating income multiplier, including the appropriate elements and rates for Gulf?
Recommendation:
The appropriate revenue expansion factor and net operating income multiplier is 61.912 percent and 1.634179, respectively, for the 2012 projected test year. The appropriate elements and rates are shown on Table 98-1. (Mouring)
Position of the Parties
GULF:
The appropriate revenue expansion factor is 61.1768 and the appropriate net operating income multiplier is 1.634607 as identified on MFR C-44.
OPC:
The appropriate net operating income multiplier should be 1.634173. This reflects the OPC’s recommended adjustment to replace the Company’s proposed bad debt rate of 0.3321% with a more appropriate rate of 0.3056%.
FIPUG:
Agree with OPC.
FRF:
The appropriate NOI multiplier is 1.634173.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
As discussed in Issue 89, staff is recommending an uncollectible expense rate of 0.3061 percent for the 2012 projected test year. Based on staff’s recommended uncollectible expense rate, the appropriate revenue expansion factor and net operating income multiplier are 61.1928 percent and 1.634179, respectively for the 2012 projected test year. The appropriate elements and rates are shown below:
Table 98-1
|
Revenue Expansion Factor and Net Operating Income Multiplier Calculation |
|||
|
Line No. |
Description |
(%) As Filed |
(%) Adjusted |
|
1 |
Revenue Requirement |
100.0000 |
100.0000 |
|
2 |
Regulatory Assessment Fee |
(0.0720) |
(0.0720) |
|
3 |
Bad Debt Rate |
(0.3321) |
(0.3061) |
|
4 |
Net Before Income Tax |
99.5959 |
99.6219 |
|
5 |
Combined State/Federal Income Tax @ 38.575% |
(38.4191) |
(38.4291) |
|
6 |
Revenue Expansion Factor |
61.1768 |
61.1928 |
|
|
|
|
|
|
7 |
NOI Multiplier (100/61.1928) |
1.634607 |
1.634179 |
Is Gulf's requested annual operating revenue increase of $93,504,000 for the 2012 projected test year appropriate?
Recommendation:
No. The appropriate annual operating revenue increase for the 2012 projected test year is $62,336,258. As discussed in Issue 9, a $4,021,905 step increase, effective January 1, 2013, is also recommended. (Mouring)
Position of the Parties
GULF:
No. The revised requested annual operating revenue increase for the 2012 test year and for future years is $98,351,000, before a one-time reduction for 2012 of $3,485,000 in the form of an ECRC credit. This amount includes reductions to Gulf’s original request totaling $3,194,000 to reflect the impact of the approved stipulations. It also includes an increase of $8,041,000 associated with moving the Crist 6 and 7 Turbine Upgrades from ECRC into base rates on an annualized basis. To prevent over-recovery in 2012, Gulf proposes a one-time ECRC credit of $3,485,000 ($4,303,000 annualized) so that the total recovered from customers in 2012 will reflect the 13-month average balance of plant in service.
OPC:
No. Gulf’s Supplemental filing increases the amount of annual operating revenue increase from $93,504,000 to $101,618,000. OPC’s recommended adjustments, including OPC’s recommended impacts associated with the Crist turbine upgrades, results in the appropriate revenue increase of $17,191,000.
FIPUG:
No. Agree with OPC.
FRF:
No. Including the impacts of adding the Crist turbine upgrades into base rates using the conventional average test year approach, allowing Gulf to earn the reasonable return on equity of 9.25%, and making the other adjustments advocated by witnesses for the Consumer Intervenors, the Commission should allow Gulf Power Company to increase its base rates for the 2012 test year by $17,191,000 per year.
FEA:
No. The appropriate revenue increase should reflect FEA’s proposed adjustments.
Staff Analysis:
This is a fallout issue. Based on staff’s recommendations in previous issues, the appropriate annual operating revenue increase for the 2012 projected test year is $62,336,258. Staff has also recommended a $4,021,905 step increase, effective January 2013, in Issue 9. The calculations of the 2012 operating revenue increase and the 2013 step increase are shown on the attached Schedules 5 and 6.
Cost of Service and Rate Design
Should Gulf’s proposal to eliminate the Interruptible Standby Service (ISS) rate schedule be approved? (Category 1 Stipulation)
Approved Stipulation:
Gulf’s proposal to eliminate the Interruptible Standby Service (ISS) rate schedule not be approved. Based on agreement reached with the intervenors, Gulf withdraws its proposal.
Should Gulf’s proposal to modify the Residential Service Variable Pricing (ISS) rate schedule be approved? (Category 2 Stipulation)
Approved Stipulation:
Gulf’s proposal to modify the Residential Service Variable Pricing (RSVP) rate schedule to use the Energy Conservation Cost Recovery clause to achieve the price differentials among the pricing tiers appropriately complements the program’s objectives and should be approved.
Should the maximum kW usage level to qualify for the GS rate be increased from 20 kW to 25 kW? (Category 2 Stipulation)
Approved Stipulation:
The maximum kW usage level to qualify for the GS rate should be increased from 20 kW to 25 kW. Approximately 12% of the GSD customers have billing demands from 20 kW to 24 kW. These customers generally achieve a demand of 20 to 24 kW one or two times a year, frequently during the winter months, but do not consistently achieve billing demands above 20 kW throughout the year. Under the proposed change, these smaller customers would be eligible for, and have the opportunity to choose, Rate GS, which does not include a demand charge component. Affording these smaller customers the opportunity to choose a non-demand rate should improve customer satisfaction.
Should Gulf’s new critical peak pricing option for customers taking service on the commercial time-of-use rates GSDT and LPT be approved? (Category 1 Stipulation)
Approved Stipulation:
Gulf’s new critical peak pricing option for customers taking service on the commercial time-of-use rates GSDT and LPT should be approved with modifications to reflect the following:
Gulf Power agrees to add the following language to Rate Schedules GSDT and LPT in the “Determination of Critical Peak Period” provision in each of these rate schedules.
The total number of critical peak periods may not exceed one per day, and may not exceed four per week. Conditions which may result in the designation of a critical peak period by the Company include, but are not limited to:
i. A temperature forecast for the Company’s service area that is above 95°F or below 32°F.
ii. Real-Time-Prices that exceed certain thresholds.
iii. Projections of system peak loads that exceed certain thresholds.
Should the minimum kW demand to qualify for the Real Time Pricing (RTP) rate schedule be reduced from 2,000 kW to 500 kW? (Category 1 Stipulation)
Approved Stipulation:
The minimum kW demand to qualify for the Real Time Pricing (RTP) rate schedule should be reduced from 2,000 kW to 500 kW. The 2,000 kW applicability threshold has been in place since the initial implementation of Real Time Pricing at Gulf in 1995. More than half the customers who meet the 2,000 kW threshold avail themselves of Real Time Pricing. Gulf’s experience, metering and billing abilities, and the diversity of customers indicate it is time to open it up to more and smaller customers. Gulf presently has about 300 to 350 customers who would meet the 500 kW threshold. (OPC and FEA do not affirmatively stipulate this issue but take no position on the issue.)
Should the minimum kW demand for new load to qualify for the Commercial/Industrial Service Rider (CISR) be reduced form 1,000 kW to 500 kW? (Category 1 Stipulation)
Approved Stipulation:
The minimum kW demand for new load to qualify for the Commercial/Industrial Service Rider (CISR) should be reduced from 1,000 kW to 500 kW. This change is to simplify the minimum size requirement by making the Qualifying Load to be 500 kW in all cases. The current size requirement treats new load and retained load differently. The simplification will make the rate easier for customers to understand and for Gulf to administer. (OPC and FEA do not affirmatively stipulate this issue but take no position on the issue.)
What is the appropriate cost of service methodology to be used in designing Gulf's rates? (Stipulation)
What is the appropriate treatment of distribution costs within the cost of service study? (Stipulation)
If a revenue increase is granted, how should it be allocated among the customer classes? (Stipulation)
Approved Stipulation:
The following stipulation was approved at the January 10, 2012, Commission Conference:
The enumerated cost of service and rate design Issue Nos. 106, 107, and 108 shall be resolved by the Commission's acceptance and approval of the methodology filed by Gulf in this proceeding as Attachment A to MFR Schedule E-l and in the Exhibit MTO-2 solely for use in designing rates in this case. Distribution costs are either assigned, where possible, or allocated to Rate Class. Demand-related distribution costs at Level 3 are allocated on a Coincident Peak Demand (CP) Level 3 allocator. Demand-related distribution costs at Levels 4 and 5 are allocated on, their respective level, Non-Coincident Peak Demand (NCP) allocator. An example of a Level 3 Distribution Common Demand-related Investment is Account 362 - Station Equipment, which is allocated to Rate Class on a Level 3 CP demand allocator. An example of a Level 4 and Level 5 Common Distribution Demand-related Investment is Account 365 - Overhead Conductors. This Account has both Level 4 and Level 5 Common Investment. The Level 4 Common Investment is allocated to Rate Class on a Level 4 NCP demand allocator, and the Level 5 Common is allocated to Rate Class on a Level 5 NCP demand allocator. Customer-related Distribution costs are at both Level 4 and Level 5. These customer-related costs are allocated on their respective Level average number of customers' allocator. An example of Level 5 Distribution Customer-related Investment is Account 365 - Overhead Conductors. This customer-related investment at Level 5 is allocated to Rate Class on the average number of customers at Level 5. Note: Where cost must be divided into demand and customer component, the cost of service methodology filed by Gulf in this proceeding as Attachment A to MFR Schedule E-l and in the Exhibit MTO-2 may be used in this case. The increase should be spread among the rate classes as shown in MFR E-8 of Gulf’s filing.
What are the appropriate customer charges and should Gulf’s proposal to rename the customer charge “Base Charge” be approved?
Recommendation:
Gulf’s proposal to rename the customer charge “Base Charge” should be approved. The appropriate customer charges are a fall-out issue and will be decided at the March 12, 2012, Commission Conference. (Draper)
Position of the Parties
GULF:
The appropriate customer charges based on Gulf’s original filing are shown in the table included as part of the discussion below. These charges are subject to revision to reflect the impact, if any, of additional adjustments identified by Gulf in other issues. The customer charge should be renamed “Base Charge.” This change in terminology better reflects the purpose of this monthly, fixed charge.
OPC:
No position.
FIPUG:
No position.
FRF:
No position.
FEA:
FEA takes no position on this issue.
Staff Analysis:
Gulf witness Thompson testified that the customer charge should be renamed “Base Charge.” (TR 1248) Customer charges, or base charges, which are a fixed amount each month, reflect the costs of supplying service that do not vary with usage. (TR 1246) Witness Thompson explained that this change in terminology better reflects the purpose of this monthly fixed charge. (TR 1248) Finally, witness Thompson stated that this charge exists to reflect the fact that a certain base level of costs is incurred by Gulf to provide electricity independent of the amount of service consumed. (TR 1248)
In response to staff discovery, Gulf stated that customer misconceptions and aversion to the term customer charge cause Gulf to propose this change and that relabeling this rate component a Base Charge should help avoid the source of customer dissatisfaction and improved customer acceptance. (EXH 102)
OPC, FIPUG, FRF, and FEA took no position on Gulf’s proposal to rename the customer charge Base Charge.
Gulf’s proposal to rename the customer charge “Base Charge” should be approved. The appropriate customer charges are a fall-out issue and will be decided at the March 12, 2012, Commission Conference.
What are the appropriate demand charges?
Recommendation:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference. (Draper)
Position of the Parties
GULF:
The appropriate demand charges based on Gulf’s original filing are listed in the table included as part of the discussion below. These charges are subject to revision to reflect the impact, if any, of additional adjustments identified by Gulf in other issues.
OPC:
No position.
FIPUG:
No position.
FRF:
No position.
FEA:
FEA takes no position on this issue.
Staff Analysis:
This a fall-out issue and will be decided at the March 12, 2012, Commission Conference.
What are the appropriate energy charges?
Recommendation:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference. (Draper)
Position of the Parties
GULF:
The appropriate energy charges based on Gulf’s original filing are listed in the table included as part of the discussion below. These charges are subject to revision to reflect the impact, if any, of additional adjustments identified by Gulf in other issues.
OPC:
No position.
FIPUG:
No position.
FRF:
No position.
FEA:
FEA takes no position on this issue.
Staff Analysis:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference.
What are the appropriate charges for the outdoor service (OS) lighting rate schedules?
Recommendation:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference. (Kummer)
Position of the Parties
GULF:
The appropriate charges for the outdoor service (OS) are those shown in the Rate Schedule OS found in Schedule 3 of Exhibit 25, attached to the testimony of Mr. Thompson.
OPC:
No position.
FIPUG:
No position.
FRF:
No position.
FEA:
FEA takes no position on this issue.
Staff Analysis:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference.
Should Gulf’s proposal to adjust annually existing lighting fixtures prices be approved?
Recommendation:
No. Staff recommends the Commission reject Gulf’s proposal to change how its existing lighting fixtures or associated facilities are priced. (Kummer)
Position of the Parties
GULF:
Yes. Lighting technology changes, vendor changes, and material costs frequently render prices of existing fixtures stale. The ability to re-price existing fixtures, up or down, as costs change would benefit lighting customers. This proposal would allow Gulf Power to adjust the prices of fixtures as emerging technologies or other forces drive costs down in the market, thus benefitting Gulf’s lighting customers. Similarly, if costs increase, the associated price increases are implemented gradually on an annual basis.
OPC:
No position.
FIPUG:
No position.
FRF:
No position.
FEA:
FEA takes no position on this issue.
Staff Analysis:
This issue addresses Gulf’s request to re-price outdoor lighting fixtures or associated facilities on an annual basis for all lighting customers.
PARTIES’ ARGUMENTS
Gulf requested Commission approval to annually re-price its existing lighting fixtures or associated facilities. Gulf currently has the ability to price new lighting options to customers without filing amendments to its tariffs through the use of its currently approved Form 4. Gulf proposed reviewing the existing tariffed lighting fixtures or associated facilities on an annual basis. If, as a result of the annual review, there is a change of 10 percent or more in either direction in any of the base rate charges, Gulf will automatically re-price the existing fixtures or associated facilities. Gulf’s Form 4 (Tariff Sheet No. 7.13), is a currently approved lighting template that allows Gulf to offer new lighting options to customers without filing amendments to its tariffs; but does not extend to its existing priced fixtures and or associated facilities. Gulf proposed extending Form 4 to re-price existing lighting fixtures or associated facilities.
Gulf witness Thompson stated in his direct testimony that “Lighting technology changes, vendor changes, and material costs frequently render prices of existing fixtures stale.” (TR 1261) Witness Thompson further stated that “the ability to re-price existing fixtures, up or down, as costs change would benefit lighting customers. This proposal would allow Gulf to adjust the prices of fixtures as emerging technologies or other forces drive costs down in the market, thus benefitting Gulf’s lighting customers. Similarly, if costs increase the associated prices increases are implemented gradually on an annual basis.” (TR 1261)
No other party took a position on this issue.
ANALYSIS
Staff has several issues with Gulf’s request. First, Gulf has not shown that fixtures or associated facilities have volatile price swings that may cause rate shock to customers to warrant the re-pricing. Second, Gulf’s re-pricing method could create potential revenue shortfalls in the future. Third, staff believes that granting the proposed annual re-pricing could pose additional concerns for lighting customers such as rate uncertainty and customer dissatisfaction.
Average Change in Price
On average, based on Gulf’s requested increase, the difference between the existing prices versus the proposed prices for lighting or associated facilities result in an increase of approximately 28 percent. The 28 percent average increase translates to an approximate change of 2.8 percent a year in lighting fixtures or associated facilities over the ten year period since Gulf’s last rate case. This is far below the 10 percent trigger level proposed by Gulf. In addition, witness Thompson stated labor rates, man-hours, etc. would not be updated and would not drive price adjustments, thereby supporting the notion that the average change in price is not significant, nor influenced by drivers known for causing varying price changes over short periods of time. (EXH 87)
Potential for Revenue Shortfall
Gulf’s proposed method of re-pricing as described in an illustrative example provided by witness Thompson raise concerns that there is the potential to create revenue shortfall from this method. The illustrative example given by witness Thompson states:
A fixture that costs $650 (Gulf Power’s acquisition cost) is priced using Form 4. The resulting monthly price for this fixture is $12.92. In a subsequent annual review the fixture cost is $450. The use of Form 4 then results in the monthly price being $9.62 or a 25.5% reduction. The price of these fixtures, including those already in service, would then be changed and the customer would be charged $9.62 per unit each month.
(EXH 87)
In an illustrative example, the prices of the fixtures have decreased, resulting in a decreased charge for that year. However; Gulf has already booked similar lighting fixtures or associated facilities at the higher price of $650 (which would be considered as a sunk cost), Over time, reducing the rate to recover only $450 cost for both new and in-place units will create a revenue shortfall, as the $450 price will not cover the $650 booked cost. This shortfall could negatively impact Gulf’s earnings. Any revenue shortfalls would eventually be made up by either Gulf’s ratepayers, shareholders, or both, negating any short term benefit received by customers.
Potential Rate Uncertainty and Customer Dissatisfaction
Most lighting contracts have a minimum term of two to five years with a three month noticing period for termination. Re-pricing lighting fixtures or associated facilities annually for existing contracts could create adverse financial impacts for customers who signed a contract for a fixed pricing option. Although Gulf’s example contemplates a price decrease, witness Thompson noted that prices may increase as well. (TR 1261) The proposal does not contain any protection for existing customers if prices increase above originally contracted rates. Witness Thompson stated during cross examination that customers who did not wish to pay a higher price for existing facilities would be required to pay a termination fee to exit an existing contract early. (TR 1281) Witness Thompson also stated that the process for noticing customers of price changes under the annual review has not yet been determined. (TR 1280)
Once a contract with fixed prices is signed, customers have an expectation that contract rates will be stable for the contract period, based on the terms of the contract, and that they will have adequate notice before changes are made. Having rates that potentially fluctuate in either direction on a yearly basis, with no set noticing requirement, does not support customer expectations and therefore may lead to customer dissatisfaction.
Gulf, as well as other utilities, have been allowed to negotiate rates for new fixtures or technologies not specifically listed in its tariffs. Customers who agree to these contracts are aware from the beginning that prices may fluctuate. Rates for existing lighting fixtures are shown in the respective lighting tariff sheets and customers have an expectation that those rates will remain in effect for the term of the contract unless changed by the Commission. Base rate charges have mechanisms in place that allow a utility to petition the Commission for approval to change its rates at any time. The utility also bears the responsibility to demonstrate to the Commission that the requested rates are fair, just, and reasonable. Furthermore, allowing Gulf to automatically re-price its existing lighting or associated facilities on an annual basis potentially conflicts with Section 366.06(1) F.S., which states:
A public utility shall not, directly or indirectly, charge or receive any rate not on file with the Commission for the particular class or service involved, and no change shall be made in any schedule. All applications for changes in rates shall be made to the Commission in writing under rules and regulations prescribed, and the Commission shall have the authority to determine and fix fair, just, and reasonable rates that may be requested, demanded, charged, or collected by any public utility for service.
CONCLUSION
Staff has reviewed all documents submitted in support of Gulf’s proposal. Staff does not believe that Gulf has demonstrated sufficient need for annual price changes, nor compelling benefits to customers, to justify a move to annual review of lighting fixture prices. Staff believes annual re-pricing is not only unnecessary from a cost basis, but that any potential benefit would be short term. In addition, such an approach could have negative impacts on the customers in the long run. Staff recommends the Commission reject Gulf’s proposal to change how its existing lighting fixtures or associated facilities are priced.
What are the appropriate charges under the Standby and Supplementary Service (SBS) rate schedule?
Recommendation:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference. (Draper)
Position of the Parties
GULF:
The appropriate charges under Rate Schedule SBS are listed below. These charges are subject to revision to reflect the impact, if any, of additional adjustments identified by Gulf in other issues.
OPC:
No position.
FIPUG:
The Commission should follow prior policy in setting standby rates.
FRF:
No position.
FEA:
FEA adopts the position of FIPUG.
Staff Analysis:
This is a fall-out issue and will be decided at the March 12, 2012, Commission Conference.
What are the appropriate transformer ownership discounts?
Recommendation:
Staff recommends the Commission set transformer ownership discounts equal to the Company’s Minimum Distribution System unit cost for transformation service for the GSD/GSDT, LP/LPT, SBS primary (100-499 KW and 500-7,499 KW), and SBS transmission (500-7,499 KW) rate classes. The recommended transformer ownership discounts for these rate classes are a fallout of the final revenue requirements.
For Gulf’s PX/PXT and SBS “Transmission - 7500 KW and above” rate classes, staff recommends that the Commission set the transformer ownership discounts equal to Gulf’s current transformer ownership discounts due to the lack of updated available unit cost data. The current discounts are -$0.18/kw/mo for the PX/PXT classes and -$0.07/kw/mo for the SBS “Transmission - 7500 KW and above” rate class. (McNulty)
Position of the Parties
GULF:
The appropriate discounts are shown in the table included as part of the discussion below. When new rates become effective in this case, it will have been approximately 10 years since the voltage discounts were adjusted in Gulf’s last rate case. Customers who own, operate, and maintain voltage transformation facilities need to be able to rely on consistency in the relationship between the charges in the rate(s) and the discounts available as they make decisions as to whether or not to provide their own voltage transformation.
OPC:
No position.
FIPUG:
No position.
FRF:
No position.
FEA:
FEA takes no position on this issue.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf developed its proposed transformer ownership discounts by increasing the discount for each applicable rate class by the percentage increase in its proposed demand charge for each of the affected rate classes. (Gulf BR 128; EXH 86, BSP 91) The proposed discounts are identified in the table below. (Gulf BR 128)
Table 115-1
|
Gulf’s Proposed Transformer Ownership Discounts |
|||
|
Rate Schedule |
Contract Level |
Voltage Discount ($/KW/Month) |
Voltage Level |
|
GSD/GSDT |
N/A |
($0.49) |
Primary |
|
LP/ LPT |
N/A |
($0.64) |
Primary |
|
LP/LPT |
N/A |
($0.81) |
Transmission |
|
PX/PXT |
N/A |
($0.22) |
Transmission |
|
SBS |
1 – 499 KW |
($0.44) |
Primary |
|
SBS |
500 – 7,499 KW |
($0.84) |
Primary |
|
SBS |
500 – 7,499 KW |
($0.98) |
Transmission |
|
SBS |
7,500 KW - above |
($0.13) |
Transmission |
|
Source - Gulf BR 128 |
|||
Gulf is proposing this approach to setting transformer ownership discounts in order to preserve the relationship between the magnitude of the transformer ownership discounts and the associated demand charges. Gulf stated that this approach differs somewhat from the approach utilized in the last rate case. (Gulf BR 129) The approach used in the last rate case was to set transformer discounts based on the cost of providing transformation service. In Docket No. 010949-EI, the revenue requirement for transformation service was determined by specified rate class groupings (e.g. GSD/GSDT). Such revenue requirements were divided by the appropriate billing units at the primary and secondary distribution levels to determine the unit cost of transformation. This unit cost of transformation was the basis for the approved transformer discounts. (EXH 99, BSP 430-440)
In this proceeding, Gulf argued that customers who own, operate, and maintain their own voltage transformation facilities need to be able to rely on consistency in the relationship between their rate(s) and the discounts available as they make decisions as to whether to provide their own voltage transformation. (Gulf BR 128-129) Gulf stated that its motivation for structuring the transformer ownership discounts in the manner proposed is to ensure that customers who have invested in their own voltage transformation facilities in reliance on Gulf’s existing ownership discounts do not see those expected savings eroded as a result of base rate increases. (TR 1273) Gulf also stated that customers who are considering investing in their own voltage transformation facilities may be discouraged from doing so if it appears that savings associated with then-existing ownership discounts will be eroded as a result of future base rate increases. (Gulf BR 129)
Gulf stated that the two approaches for establishing transformer discounts yield very similar results for the GSD/GSDT and LP/LPT rate classes. Gulf noted that its approach yields a higher transformer ownership discount under Rate Schedule SBS (Standby or Supplementary Service), but the Company argued that the continuity offered through Gulf’s proposal provides a more reasonable price (discount) to SBS customers. Gulf described its SBS customers as large customers who own their own generation but who nevertheless need backup service from Gulf. (Gulf BR 129)
Other Parties
No party other than Gulf took a position on this issue.
ANALYSIS
Gulf’s transformer discounts were determined in Gulf’s last rate case based on the unit cost incurred to provide transformation services for GSD/GSDT, LP/LPT, PX/PXT, and SBS rate classes. See Order No. PSC-02-0787-FOF-EI, issued June 10, 2002, In re: Request for rate increase by Gulf Power, p. 98 and Order No. 23573, issued October 3, 1990, In re: Petition of Gulf Power Company’s for increase in its rates and charges, p. 57. (EXH 99, BSP 430-440) In Order No. 23573, Gulf proposed adjusting the discounts by any variance of the demand and energy charges from unit costs. The Commission agreed with staff that the adjustment for variance from unit costs proposed by Gulf was an unnecessary complication.
Gulf’s argument to allow the transformer discounts to increase in accordance with the percentage increase in demand charges would be a departure from the Commission’s prior actions in establishing such discounts. In a Tampa Electric Company (TECO) rate proceeding, the Commission approved cost-based transformer ownership discounts for the primary and subtransmission levels, using embedded cost of transformation and calculating an annual revenue requirement for the Company’s transformation equipment.[47] This basis for establishing the level of TECO’s transformation ownership discounts was affirmed by the Commission in June 2008.[48] The Commission approved Florida Power and Light’s (FPL) transformation rider credits based on the avoided cost of distribution secondary transformers in FPL’s most recent rate case.[49]
In this docket, Gulf provided discovery responses showing the costs of providing transformation services under two different cost of service methods, one based on the Minimum Distribution System cost of service methodology, or MDS, and the other based on Non-Minimum Distribution System cost of service methodology, or Non-MDS. (EXH 99, BSP 430-440) The current transformer ownership discounts, the proposed transformer ownership discounts, the MDS unit cost of transformation, and the Non-MDS unit costs of transformation are shown in Table 115-2.
Table 115-2
|
Gulf’s Transformer Discounts and Unit Costs |
|||||
|
A |
B |
C |
D |
E |
F |
|
Rate Schedule and Voltage Level |
Contract Level |
Gulf’s Current Discount ($/KW/MO) |
Gulf Proposed Discount ($/KW/MO) |
Unit Cost per MDS ($/KW/MO) |
Unit Cost per Non-MDS ($/KW/MO) |
|
GSD/GSDT – Primary |
N/A |
($0.44) |
($0.49) |
($0.32) |
($0.45) |
|
LP/ LPT – Primary |
N/A |
($0.53) |
($0.64) |
($0.45) |
($0.64) |
|
LP/LPT – Transmission |
N/A |
($0.67) |
($0.81) |
($0.61) |
($0.81) |
|
PX/PXT - Transmission * |
N/A |
($0.18) |
($0.22) |
No data (billing units = 0) |
No data (billing units = 0) |
|
SBS – Primary |
1 – 499 KW |
($0.27) |
($0.44) |
($0.09) |
($0.15) |
|
SBS – Primary |
500 – 7,499 KW |
($0.41) |
($0.84) |
($0.09) |
($0.15) |
|
SBS – Transmission |
500 – 7,499 KW |
($0.48) |
($0.98) |
($0.11) |
($0.17) |
|
SBS – Transmission * |
7,500 KW – above |
($0.07) |
($0.13) |
No data (billing units = 0) |
No data (billing units = 0) |
|
Source, Columns C and D - EXH 7, MFR E-14, pp. 16, 18, 20, 40, 44, 51, and 49. Source, Columns E and F - EXH 99, BSP 430-440 * Gulf indicated it has no transmission customers for these specific rate classes and thus the Company presented no unit cost data for such rate classes. (EXH 99, BSP 437 and 439) |
|||||
Gulf agreed that its response to the methodology previously adopted by the Commission provided a reasonable cost basis for transformer ownership discounts. (EXH 99, BSP 435, 441) Gulf witness Thompson agreed that the cost-based method and Gulf’s proposed method based on the percentage increase in demand charges were both reasonable and that either method was acceptable because they yielded results that were “pretty close.” (TR 1274)
As shown in Table 115-2, the unit costs of voltage transformation under MDS are lower than the unit costs of voltage transformation under Non-MDS. In addition, the unit costs of transformation under MDS are lower than current transformer discounts because the current transformer discounts were approved on the basis of the Non-MDS cost of service methodology in the last rate case. Also, Table 115-2 shows that the transformer ownership discounts based on the MDS cost of service study are significantly below Gulf’s proposed transformer ownership discounts for all rate classes for which cost data is available. These differences are based on as-filed cost information rather than the costs the Commission may ultimately approve, which may further impact the differential between Gulf’s requested transformer ownership discounts and the cost of transformer ownership discounts.
Staff believes that the Commission should continue to require a cost basis for Gulf’s transformer ownership discounts. Transformer ownership discounts in excess of the Company’s transformation unit costs may lead to offsetting increases in Gulf’s base rates so that the Company can recover its full revenue requirement. Staff’s basic concern is that any discounts offered above the Company’ cost of service is expected to result in cross-subsidies. Staff does not agree with Gulf’s witness Thompson that transformer ownership discounts must increase with Gulf’s proposed rate increases to prevent the erosion of customers’ expected savings from installing and maintaining their own transformers. (TR 1273) Base rates recover a myriad of costs, comprised mostly of costs other than transformation service. Gulf’s rate relationship argument is not sufficient to justify deviating from the Commission practice of cost based discounts.
CONCLUSION
Staff recommends the Commission set Gulf’s transformer ownership discounts equal to the Company’s Minimum Distribution System unit cost for transformation service for the GSD/GSDT, LP/LPT, SBS primary (100-499 KW and 500-7,499 KW), and SBS transmission (500-7,499 KW) rate classes. (EXH 99, BSP 430-440) Transformer ownership discounts have historically been based on avoided cost of providing transformation service rather than, as proposed by Gulf, relative changes in demand charges. The calculation of the transformer ownership discounts should be based on Gulf’s MDS cost of service methodology in order to be consistent with the Commission’s January 10, 2012, approval of the Motion for Approval of Partial Settlement Agreements submitted by Gulf on behalf of itself and other signatories. The actual adjustments to Gulf’s proposed transformer ownership discounts are a fallout of the final revenue requirements.
For Gulf’s PX/PXT and SBS “Transmission - 7500 KW and above” rate classes, staff recommends that the Commission set the transformer ownership discounts equal to Gulf’s current transformer ownership discounts due to the lack of updated available unit cost data. The current transformer ownership discounts are -$0.18/kw/mo for the PX/PXT classes and -$0.07/kw/mo for the SBS “Transmission - 7500 KW and above” rate class. (EXH 7, pp. 20 and 49 of 108)
What is the appropriate minimum monthly bill demand charges under the PX and PXT rate schedules? (Category 2 Stipulation)
Approved Stipulation:
The appropriate minimum monthly bill demand charges under the PX and PXT rate schedules are $11.90/KW/month for PX and $11.99/KW/month for PXT. These minimum bill provisions have been developed using the FPSC approved method for determining them. These charges are subject to revision to reflect the impact, if any, of additional adjustments identified in other issues and the final rates established for the PX and PXT rate schedules.
Should any of the $38,549,000 interim rate increase granted by Order No. PSC-11-0382-PCO-EI be refunded to the ratepayers?
Recommendation:
No. Further, upon expiration of the period for appeal, the corporate undertaking should be released. (Mouring, Slemkewicz)
Position of the Parties
GULF:
No. None of the $38,549,000 interim rate increase granted by Order No. PSC-11-0382-PCO-EI should be refunded.
OPC:
Yes. Gulf should be required to refund, with interest, the difference between the Commission approved $38.5 million interim increase and the $17.2 million OPC recommended final increase.
FIPUG:
Yes. Agree with OPC.
FRF:
Yes. The amount to be refunded is the difference between the amount collected by Gulf by virtue of the interim rate increase granted and the amount that Gulf would have collected if it had implemented new rates to recover an annual increase in operating revenues of $17.191 million.
FEA:
FEA adopts the position of OPC.
Staff Analysis:
PARTIES’ ARGUMENTS
Gulf
Gulf contends that no refund of the interim rate increase is warranted. Any interim rate increase refund should be calculated in accordance with Section 366.071(4), F.S., which states in part:
Any refund ordered by the commission shall be calculated to reduce the rate of return of the public utility during the pendency of the proceeding to the same level within the range of the newly authorized rate of return which is found fair and reasonable on a prospective basis, . . .
Gulf argues that the focus must be on the rate of return that was actually earned during the pendency of the proceeding. (Gulf BR 130-131)
OPC
OPC contends that Gulf should be required to refund the $21.3 million difference between the $38.5 million interim rate increase and its recommended $17.2 million final rate increase. (OPC BR 94)
FIPUG, FRF and FEA agreed with OPC’s position on this issue. (FIPUG BR 13; FRF BR 28; FEA BR 36)
ANALYSIS
By Order No. PSC-11-0382-PCO-EI, issued September 12, 2011, the Commission authorized the collection of interim rates, subject to refund, pursuant to Section 366.071, F.S. The approved interim revenue increase was $38,549,000, or 8.882 percent, based on a test year ended March 31, 2011. The overall rate of return (ROR) used to calculate the interim rate increase was 6.45 percent using a 10.75 percent ROE.
Staff agrees with Gulf that Section 366.071(4), F.S., provides that the amount of any interim rate increase refund should be calculated based on the actual earnings of the Company during the time that interim rates were in effect. In this proceeding, the interim rate collection period is from September 2011 through March 2012. The test period for establishment of the interim increase was the 12-month period ended March 31, 2011. Gulf’s approved interim rates did not include any provisions for pro forma or projected operating expenses or plant. The interim increase was designed to allow recovery of actual interest costs, and the lower limit of the last authorized range for return on equity.
Because the interim rate collection period continues through March 2012, staff has used the actual 12-month period ended November 30, 2011, as a proxy for determining whether any refund is warranted. Per Gulf’s November 2011 Earnings Surveillance Report (ESR), Gulf achieved a 4.55 percent ROR which resulted in an earned ROE of 5.80 percent. Staff has made a revenue adjustment of $12,850,000 [$38,549,000 x (4/12)] to this period to recognize the remaining collection period months of December 2011 through March 2012. Staff also reviewed the recommended adjustments for the full case to identify any that might impact the interim collection period. Staff identified the North Escambia County plant site (Issue 24) and incentive compensation (Issue 71) as adjustments that should be included in the interim rate refund calculation. After making these adjustments, the adjusted ROR is 5.27 percent resulting in an adjusted ROE of 7.67 percent. In Issues 37 and 38, staff has recommended an ROR of 6.39 percent and an ROE midpoint of 10.25 percent. Based on comparing the interim rate collection period ROR (5.27 percent) and ROE (7.67 percent) with the recommended ROR (6.39 percent) and ROE (10.25 percent), staff recommends that no interim rate increase refund is required. Further, upon expiration of the period for appeal, the corporate undertaking should be released.
Table 117-1
|
Interim Rate Increase Refund Calculation |
||||
|
|
Net Operating Income |
Rate Base |
Achieved ROR |
Achieved ROE |
|
November 2011 ESR as Filed |
$72,481,202 |
$1,591,779,161 |
4.55% |
5.80% |
|
Staff Adjustments: |
|
|
|
|
|
Remaining Interim Rate Increase (December 2011 – March 2012) (Net of Tax) |
$7,864,000 |
0 |
----- |
----- |
|
Incentive Compensation (Issue 71) (Net of Tax) |
$2,367,008 |
($524,283) |
----- |
----- |
|
North Escambia County Plant Site (Issue 24) |
0 |
($22,660,000) |
----- |
----- |
|
Staff Adjusted Total |
$82,712,210 |
$1,568,594,878 |
5.27% |
7.67% |
|
Staff Recommendation |
----- |
----- |
6.39% (Issue 38) |
10.25% (Issue 37) |
CONCLUSION
As shown in Table 117-1, staff has calculated that Gulf’s achieved ROR and ROE for the interim rate collection period will be less than the recommended ROR and ROE for the full case. Therefore, staff recommends that no interim rate increase refund is required. Further, upon expiration of the period for appeal, the corporate undertaking should be released.
Should Gulf be required to file, within 60 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records which will be required as a result of the Commission's findings in this rate case? (Category 1 Stipulation)
Approved Stipulation:
Gulf shall file, within 90 days after the date of the final order in this docket, a description of all entries or adjustments to its annual report, rate of return reports, and books and records which will be required as a result of the Commission’s findings in this case.
Should this docket be closed?
Recommendation:
The docket should be closed after the time for filing an appeal has run. (Klancke, Barrera, Young)
Position of the Parties
GULF:
Yes. The docket should be closed after the time for filing an appeal has run.
OPC:
No position.
FIPUG:
Yes, after Gulf has filed and received approval for any new rates approved by the Commission in this docket, and after all appeals have been completed or the time for filing an appeal has expired.
FRF:
Yes, after Gulf has filed and received approval for any new rates approved by the Commission in this docket, and after all appeals have been completed or the time for filing an appeal has expired, this docket should be closed.
FEA:
FEA adopts the position of FIPUG.
Staff Analysis:
The docket should be closed 32 days after issuance of the order, to allow the time for filing an appeal to run.
